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 As filed with the Securities and Exchange Commission on September 1, 2011 

Registration No. 333-173808

 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

 
Amendment No. 4 to

Form S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933

 
WPX Energy, Inc.
(Exact name of registrant as specified in its charter)

 

Delaware	 	1311	 	45-1836028	
(State or other jurisdiction of
Incorporation or organization)	 	(Primary Standard Industrial
Classification Code Number)	 	(I.R.S. Employer
Identification Number)	

One Williams Center
Tulsa, Oklahoma 74172-0172
(918) 573-2000
(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)
 
James J. Bender, Esq.
General Counsel and Corporate Secretary
One Williams Center, Suite 4900
Tulsa, Oklahoma 74172-0172
(918) 573-2000
(Name, address, including zip code, and telephone number, including area code, of agent for service)

 
 
Copies to:

Richard M. Russo
Robyn E. Zolman
Gibson, Dunn & Crutcher LLP
1801 California Street, Suite 4200
Denver, CO 80202	 	J. Michael Chambers
Ryan J. Maierson
Latham & Watkins LLP
717 Texas Avenue, 16th floor
Houston, TX 77002	

Approximate date of commencement of proposed sale to the public:   As soon as practicable after the effective date of this registration statement.
 
If any of the securities being registered on this Form are being offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box:   o
 
If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.   o
 
If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.   o
 
If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.   o
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer  o	 	Accelerated filer  o	 	Non-accelerated filer  þ
(Do not check if a smaller reporting company)	 	Smaller reporting company  o	

The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until this registration statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

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The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.	
 
Subject to Completion, dated September 1, 2011

PROSPECTUS

           Shares

 
WPX Energy, Inc.
 
Class A Common Stock

This is the initial public offering of Class A common stock of WPX Energy, Inc. We are offering           shares of our Class A common stock. No public market currently exists for our Class A common stock.
 
Following this offering, we will have two classes of authorized common stock, Class A common stock and Class B common stock. All of our shares of Class B common stock will be held by The Williams Companies, Inc. (“Williams”). The rights of holders of shares of Class A common stock and Class B common stock will be identical, except with respect to voting and conversion rights. Each share of Class A common stock will be entitled to one vote per share. Each share of Class B common stock will be entitled to ten votes per share and will be convertible at any time at the election of Williams into one share of Class A common stock. Our Class B common stock will automatically convert into shares of Class A common stock in certain circumstances.

Our Class A common stock has been approved for listing on the New York Stock Exchange under the symbol “WPX.”

We anticipate that the initial public offering price will be between $      and $      per share.
 
Investing in our Class A common stock involves risks. See “Risk Factors” beginning on page 17 of this prospectus .

 	 	Per Share	 	 	Total	 	
Price to the public	 	$	         	 	 	$	         	 	
Underwriting discounts and commissions	 	$	 	 	 	$	 	 	
Proceeds to us (before expenses)	 	$	 	 	 	$		 	

We have granted the underwriters a 30-day option to purchase up to an additional      shares of Class A common stock on the same terms and conditions set forth above if the underwriters sell more than      shares of Class A common stock in this offering. Any shares of Class A common stock issued pursuant to this option will not increase the total number of shares of common stock outstanding after this offering, but rather the number of shares of Class B common stock owned by Williams will be reduced share for share by the number of shares of Class A common stock issued pursuant to such option, thus reducing Williams’ ownership interest in us. We will distribute the net proceeds from the sale of shares of Class A common stock pursuant to this option to Williams as part of our restructuring transactions described herein. Williams is deemed to be an underwriter with respect to any shares of Class A common stock issued pursuant to this option.
 
Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed on the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.
 
Barclays Capital, on behalf of the underwriters, expects to deliver the shares on or about          , 2011.

				
Barclays Capital	Citigroup	J.P. Morgan	BofA Merrill Lynch	

 
				
Deutsche Bank Securities	Goldman, Sachs & Co.	Morgan Stanley	Wells Fargo Securities	

 
			
Credit Suisse	RBC Capital Markets	Scotia Capital	
		
UBS Investment Bank	Howard Weil Incorporated	
 
Prospectus dated          , 2011

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TABLE OF CONTENTS

 	 	 	 	 	
 	 	Page	
 		
CERTAIN DEFINITIONS	 	 	iii	 	
PROSPECTUS SUMMARY	 	 	1	 	
RISK FACTORS	 	 	17	 	
FORWARD-LOOKING STATEMENTS	 	 	43	 	
USE OF PROCEEDS	 	 	45	 	
DIVIDEND POLICY	 	 	46	 	
CAPITALIZATION	 	 	47	 	
DILUTION	 	 	48	 	
SELECTED HISTORICAL COMBINED FINANCIAL DATA	 	 	49	 	
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	 	 	51	 	
BUSINESS	 	 	76	 	
MANAGEMENT	 	 	106	 	
EXECUTIVE COMPENSATION	 	 	112	 	
PRINCIPAL STOCKHOLDER	 	 	145	 	
ARRANGEMENTS BETWEEN WILLIAMS AND OUR COMPANY	 	 	146	 	
OTHER RELATED PARTY TRANSACTIONS	 	 	153	 	
DESCRIPTION OF OUR CONCURRENT FINANCING TRANSACTIONS	 	 	156	 	
DESCRIPTION OF CAPITAL STOCK	 	 	157	 	
SHARES ELIGIBLE FOR FUTURE SALE	 	 	164	 	
CERTAIN U.S. FEDERAL INCOME TAX CONSIDERATIONS	 	 	166	 	
UNDERWRITING	 	 	170	 	
LEGAL MATTERS	 	 	178	 	
EXPERTS	 	 	178	 	
WHERE YOU CAN FIND MORE INFORMATION	 	 	178	 	
INDEX TO FINANCIAL STATEMENTS	 	 	F-1	 	
  EX-1.1	
  EX-10.1	
  EX-23.2	
  EX-23.3	
  EX-23.4	
  EX-23.5	

 

 
 
You should rely only on the information contained in this document or any free writing prospectus prepared by or on behalf of us. We have not authorized anyone to provide you with information that is different. This document may only be used where it is legal to sell these securities. The information in this document may only be accurate on the date of this document.

 
 
Dealer Prospectus Delivery Obligation
 
Until          , 2011 (the 25th day after the date of this prospectus), all dealers that effect transactions in our common shares, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealer’s obligation to deliver a prospectus when acting as an underwriter and with respect to unsold allotments or subscriptions.
 
Industry and Market Data
 
We obtained the market and competitive position data used throughout this prospectus from our own research, surveys or studies conducted by third parties and industry or general publications. Industry publications and surveys generally state that they have obtained information from sources believed to be reliable, but do not guarantee the accuracy and completeness of such information. While we believe that each of these studies and publications is reliable and have no reason to believe they are inaccurate or incomplete, neither we nor the underwriters have independently verified such data and neither we nor the underwriters make any representation as to the accuracy of such information. Similarly, we believe our internal research is reliable but it has not been verified by any independent sources.

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CERTAIN DEFINITIONS
 
The following oil and gas measurements and industry and other terms are used in this prospectus. As used herein, production volumes represent sales volumes, unless otherwise indicated.
 
Bakken Shale —means the Bakken Shale oil play in the Williston Basin and can include the Upper Three Forks formation.
 
Barrel —means one barrel of petroleum products that equals 42 U.S. gallons.
 
BBtu —means one billion BTUs.
 
BBtu/d —means one billion BTUs per day.
 
Bcfe —means one billion cubic feet of gas equivalent determined using the ratio of one barrel of oil or condensate to six thousand cubic feet of natural gas.
 
Bcf/d —means one billion cubic feet per day.
 
Boe —means barrels of oil equivalent.
 
Boe/d —means barrels of oil equivalent per day.
 
British Thermal Unit or BTU —means a unit of energy needed to raise the temperature of one pound of water by one degree Fahrenheit.
 
FERC —means the Federal Energy Regulatory Commission.
 
Fractionation —means the process by which a mixed stream of natural gas liquids is separated into its constituent products, such as ethane, propane and butane.
 
LOE —means lease and other operating expense excluding production taxes, ad valorem taxes and gathering, processing and transportation fees.
 
Mbbls —means one thousand barrels.
 
Mboe/d —means thousand barrels of oil equivalent per day.
 
Mcf —means one thousand cubic feet.
 
Mcfe —means one thousand cubic feet of gas equivalent using the ratio of one barrel of oil or condensate to six thousand cubic feet of natural gas.
 
MMbbls —means one million barrels.
 
MMboe —means one million barrels of oil equivalent.
 
MMBtu —means one million BTUs.
 
MMBtu/d —means one million BTUs per day.
 
MMcf —means one million cubic feet.
 
MMcf/d —means one million cubic feet per day.
 
MMcfe —means one million cubic feet of gas equivalent using the ratio of one barrel of oil or condensate to six thousand cubic feet of natural gas.
 
MMcfe/d —means one million cubic feet of gas equivalent per day using the ratio of one barrel of oil or condensate to six thousand cubic feet of natural gas.
 
NGLs —means natural gas liquids; natural gas liquids result from natural gas processing and crude oil refining and are used as petrochemical feedstocks, heating fuels and gasoline additives, among other applications.

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PROSPECTUS SUMMARY
 
This summary highlights certain information contained elsewhere in this prospectus. This summary is not complete and does not contain all of the information that you should consider before investing in our Class A common stock. You should read this entire prospectus carefully, including the risks discussed under “Risk Factors” and the financial statements and notes thereto included elsewhere in this prospectus. Some of the statements in this summary constitute forward-looking statements. See “Forward-Looking Statements.”
 
Except where the context otherwise requires or where otherwise indicated, (1) all references to “Williams” refer to The Williams Companies, Inc., our parent company, and its subsidiaries, other than us, and (2) all references to “WPX Energy,” “WPX,” the “Company,” “we,” “us” and “our” refer to WPX Energy, Inc. and its subsidiaries.
 
Overview
 
We are an independent natural gas and oil exploration and production company engaged in the exploitation and development of long-life unconventional properties. We are focused on profitably exploiting our significant natural gas reserve base and related NGLs in the Piceance Basin of the Rocky Mountain region, and on developing and growing our positions in the Bakken Shale oil play in North Dakota and the Marcellus Shale natural gas play in Pennsylvania. Our other areas of domestic operations include the Powder River Basin in Wyoming and the San Juan Basin in the southwestern United States. In addition, we own a 69 percent controlling ownership interest in Apco Oil and Gas International, Inc. (“Apco”), which holds oil and gas concessions in Argentina and Colombia and trades on the NASDAQ Capital Market under the symbol “APAGF.”

We have built a geographically diverse portfolio of natural gas and oil reserves through organic development and strategic acquisitions. For the five years ended December 31, 2010, we have grown production at a compound annual growth rate of 12 percent. As of December 31, 2010, our proved reserves were 4,473 Bcfe, 59 percent of which were proved developed reserves. Average daily production for the month of July 2011 was 1,294 MMcfe/d. Our Piceance Basin operations form the majority of our proved reserves and current production, providing a low-cost, scalable asset base.

The following table provides summary data for each of our primary areas of operation as of December 31, 2010, unless otherwise noted.

 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Estimated Net	 	 	July 2011	 	 	 	 	 	2011 Budget Estimate	 	 	 	 	
 	 	Proved Reserves	 	 	Average Daily	 	 	 	 	 	 	 	 	Drilling	 	 	 	 	
 	 	 	 	 	% Proved	 	 	Net Production	 	 	 	 	 	 	 	 	Capital(2)	 	 	PV-10(3)	 	
Basin/Shale	 	Bcfe	 	 	Developed	 	 	(MMcfe/d)(1)	 	 	Net Acreage	 	 	Gross Wells	 	 	(Millions)	 	 	(Millions)	 	
 		
Piceance Basin	 	 	2,927	 	 	 	53	%	 	 	745	 	 	 	211,000	 	 	 	376	 	 	$	575	 	 	$	2,707	 	
Bakken Shale(4)	 	 	136	 	 	 	11	%	 	 	31	 	 	 	89,420	 	 	 	41	 	 	 	260	 	 	 	399	 	
Marcellus Shale	 	 	28	 	 	 	71	%	 	 	14	 	 	 	99,301	 	 	 	62	 	 	 	170	 	 	 	29	 	
Powder River Basin	 	 	348	 	 	 	75	%	 	 	235	 	 	 	425,550	 	 	 	411	 	 	 	70	 	 	 	317	 	
San Juan Basin	 	 	554	 	 	 	79	%	 	 	143	 	 	 	120,998	 	 	 	51	 	 	 	40	 	 	 	477	 	
Apco(5)	 	 	190	 	 	 	60	%	 	 	49	 	 	 	404,304	 	 	 	37	 	 	 	30	 	 	 	358	 	
Other(6)	 	 	290	 	 	 	72	%	 	 	77	 	 	 	327,390	 	 	 	94	 	 	 	85	 	 	 	257	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	 	4,473	 	 	 	59	%	 	 	1,294	 	 	 	1,677,963	 	 	 	1,072	 	 	$	1,230	 	 	$	4,544	 	

 

 
			
(1)		Represents average daily net production of our continuing operations for the month of July 2011.	

			
(2)		Based on the midpoint of our estimated capital spending range.	
 		
(3)		PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure of Discounted Future Net Cash Flows (“Standardized Measure”), the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our oil and natural gas assets. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities. For a	

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		definition of PV-10 and a reconciliation of PV-10 to Standardized Measure, see “—Summary Combined Historical Operating and Reserve Data—Non-GAAP Financial Measures and Reconciliations” below.	
 		
(4)		Our estimated net proved reserves in the Bakken Shale have not been audited by independent reserve engineers.	
 		
(5)		Represents approximately 69 percent of each metric (which corresponds to our ownership interest in Apco) except Percent Proved Developed, Gross Wells and Drilling Capital.	

			
(6)		Other includes Barnett Shale, Arkoma and Green River Basins and miscellaneous smaller properties. July 2011 average daily net production excludes Arkoma production of approximately nine MMcfe/d as our Arkoma Basin operations were classified as held for sale and reported as discontinued operations as of June 30, 2011.	

In addition to our exploration and development activities, we engage in natural gas sales and marketing. See “Business—Gas Management.”
 
Bakken Shale and Marcellus Shale Acquisitions
 
An important part of our strategy to grow our business and enhance shareholder value is to acquire properties complementary to our existing positions as well as undeveloped acreage with significant resource potential in new geographic areas. Our management team applies a disciplined approach to making acquisitions and evaluates potential acquisitions of oil and gas properties based on three key criteria: (i) a location in the core of a large, unconventional resource area, (ii) the availability of contiguous, scalable acreage positions and (iii) the ability to replicate our cost-efficient model. In 2010, we invested approximately $1.7 billion on properties in the Bakken Shale and Marcellus Shale that met these criteria. Approximately 35 percent of our 2011 drilling capital budget will be dedicated to our Bakken Shale and Marcellus Shale properties, and our management currently expects approximately 47 percent of our 2012 drilling expenditures to be dedicated to properties in these regions.
 
Bakken Shale
 
We have acquired 89,420 net acres in the Williston Basin in North Dakota that is prospective for oil in the Bakken Shale. We acquired substantially all of this acreage in December 2010 through the acquisition of Dakota-3 E&P Company LLC for $949 million in cash. Our entry into the Bakken Shale oil play is part of our strategy to diversify our commodity exposure through the addition of oil and liquids-rich development opportunities to our portfolio.
 
Currently, we have three rigs operating on our Bakken Shale acreage. We expect to double our level of drilling activity to six rigs by early 2012, subject to permitting, rig availability and the then prevailing commodity price environment. Since acquiring this acreage, we have drilled 10 operated wells on our Bakken Shale properties; nine Middle Bakken formation wells and one Three Forks formation well. Five of these wells have been completed and connected to sales, with initial 30 day production rates ranging from 750 Boe/d to 1,100 Boe/d.
 
Marcellus Shale
 
Our 99,301 net acres in the Marcellus Shale were acquired through two key transactions and additional leasing activities. In June 2009, we entered into a drill to earn agreement with Rex Energy Corporation in Pennsylvania’s Westmoreland, Clearfield and Centre Counties. We have acquired and operate approximately 22,000 net acres pursuant to such agreement. Following this initial venture, in July 2010, we acquired 42,000 net acres primarily located in Susquehanna County in northeastern Pennsylvania for $599 million. In addition, during 2010 we spent a total of $164 million to acquire additional unproved leasehold acreage positions in the Marcellus Shale.
 
Currently, we have four rigs operating in the Marcellus Shale. We expect to increase our level of drilling activity to eight to nine rigs by the end of 2012 and continue to increase drilling activity thereafter, subject to permitting, rig availability and the then prevailing commodity price environment.

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Our Business Strategy
 
Our business strategy is to increase shareholder value by finding and developing reserves and producing natural gas, oil and NGLs at costs that generate an attractive rate of return on our investment.

 	•   	Efficiently Allocate Capital for Optimal Portfolio Returns.   We expect to allocate capital to the most profitable opportunities in our portfolio based on commodity price cycles and other market conditions, enabling us to continue to grow our reserves and production in a manner that maximizes our return on investment. In determining which drilling opportunities to pursue, we target a minimum after-tax internal rate of return on each operated well we drill of 15 percent. While we have a significant portfolio of drilling opportunities that we believe meet or exceed our return targets even in challenging commodity price environments, we are disciplined in our approach to capital spending and will adjust our drilling capital expenditures based on our level of expected cash flows, access to capital and overall liquidity position. For example, in 2009 we demonstrated our capital discipline by reducing drilling expenditures in response to prevailing commodity prices and their impact on these factors.	
 		
 	•   	Continue Our Cost-Efficient Development Approach.   We focus on developing properties where we can apply development practices that result in cost efficiencies. We manage costs by focusing on establishing large scale, contiguous acreage blocks where we can operate a majority of the properties. We believe this strategy allows us to better achieve economies of scale and apply continuous technological improvements in our operations. We intend to replicate these cost-efficient approaches in our recently acquired growth positions in the Bakken Shale and the Marcellus Shale.	
 		
 	•   	Pursue Strategic Acquisitions with Significant Resource Potential.   We have a history of acquiring undeveloped properties that meet our disciplined return requirements and other acquisition criteria to expand upon our existing positions as well as acquiring undeveloped acreage in new geographic areas that offer significant resource potential. This is illustrated by our recent acquisitions in the Bakken Shale and the Marcellus Shale. We seek to continue expansion of current acreage positions and opportunistically acquire acreage positions in new areas where we feel we can establish significant scale and replicate our cost-efficient development approach.	
 		
 	•   	Target a More Balanced Commodity Mix in Our Production Profile.   With our Bakken Shale acquisition in December 2010 and our liquids-rich Piceance Basin assets, we have a significant drilling inventory of oil- and liquids-rich opportunities that we intend to develop rapidly in order to achieve a more balanced commodity mix in our production. We refer to the Piceance Basin as “liquids-rich” because our proved reserves in that basin consist of “wet,” as opposed to “dry,” gas and have a significant liquids component. Our current estimated proved reserves of NGLs and condensate in the Piceance Basin are 95 MMbbl and 3 MMbbl, respectively. We will continue to pursue other oil- and liquids-rich organic development and acquisition opportunities that meet our investment returns and strategic criteria.	
 		
 	•   	Maintain Substantial Financial Liquidity and Manage Commodity Price Sensitivity.   We plan to conservatively manage our balance sheet and maintain substantial liquidity through a mix of cash on hand and availability under our credit facility. In addition, we have engaged and will continue to engage in commodity hedging activities to maintain a degree of cash flow stability. Typically, we target hedging approximately 50 percent of expected revenue from domestic production during a current calendar year in order to strike an appropriate balance of commodity price upside with cash flow protection, although we may vary from this level based on our perceptions of market risk. At July 31, 2011, our estimated domestic natural gas production revenues were 67 percent hedged for 2011 and 48 percent hedged for 2012. Estimated domestic oil production revenues were 48 percent hedged for 2011 and 49 percent hedged for 2012 as of the same date.	

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Our Competitive Strengths
 
We have a number of competitive strengths that we believe will help us to successfully execute our business strategies:

 	•   	A Leading Piceance Basin Cost Structure.   We have a large position in the lower cost valley area of the Piceance Basin, which we believe provides us economies associated with lower elevation drilling and large contiguous operations, allowing us to continuously drive down operating costs and increase efficiencies. The existing substantial midstream infrastructure in the Piceance Basin contributes to our cost-efficient structure and provides take-away capacity for our natural gas and NGLs. Because of this cost-efficient structure in the Piceance Basin, we have the ability to generate returns that we believe are in excess of those typically associated with Rockies producers.	
 		
 	•   	Attractive Asset Base Across a Number of High Growth Areas.   In addition to our large scale Piceance Basin properties, our assets include emerging, high growth opportunities such as our Bakken Shale and Marcellus Shale positions. Based on our subsurface geological and engineering analysis of available well data, we believe our Bakken Shale and Marcellus Shale positions are located in core areas of these plays, which have associated historic drilling results that we believe offer highly attractive economic returns.	
 		
 	•   	Extensive Drilling Inventory.   As of December 31, 2010, we have identified approximately 2,900 proved undeveloped drilling locations. We have budgeted drilling approximately 500 gross operated wells during 2011. We have established significant scale in each of our core areas of operation that support multi-year development plans and allow us to optimally leverage our cost-efficient development approach. Our drilling inventory provides opportunities across diverse geographic markets and products including natural gas, oil and NGLs.	
 		
 	•   	Significant Operating Flexibility.   In the Piceance Basin, Bakken Shale and Marcellus Shale, our three primary basins, we operate substantially all of our production. We expect approximately 91 percent of our projected 2011 domestic drilling capital will be spent on projects we operate. We believe acting as operator on our properties allows us to better control costs and capital expenditures, manage efficiencies, optimize development pace, ensure safety and environmental stewardship and, ultimately, maximize our return on investment. As operator, we are also able to leverage our experience and expertise across all basins and transfer technology advances between them as applicable. In addition, substantially all of our Piceance Basin properties are held by producing wells, which allows us to adjust our level of drilling activity in response to changing market conditions.	
 		
 	•   	Significant Financial Flexibility.   Our capital structure is intended to provide a high degree of financial flexibility to grow our asset base, both through organic projects and opportunistic acquisitions. Immediately following the completion of this offering, we expect to have $2.0 billion of liquidity, comprised of availability under our $1.5 billion credit facility and approximately $500 million of cash on hand. We believe our pro forma level of debt to proved reserves is low relative to a majority of other publicly traded, independent oil and gas producers.	
 		
 	•   	Management Team with Broad Unconventional Resource Experience.   Our management and operating team has significant experience acquiring, operating and developing natural gas and oil reserves from tight-sands and shale formations. Our Chief Executive Officer and his direct reports have in excess of 238 collective years of experience running large scale drilling programs and drilling vertical and horizontal wells requiring complex well design and completion methods. Our team has demonstrated the ability to manage large scale operations and apply current technological successes to new development opportunities. We have deployed members of our successful Piceance Basin, Powder River Basin and Barnett Shale teams to the Bakken Shale and Marcellus Shale teams to help replicate our cost-efficient model and to apply our highly specialized technical expertise in the development of those resources.	
 
Our Relationship with Williams
 
We are currently a wholly-owned subsidiary of The Williams Companies, Inc., an integrated energy company with 2010 consolidated revenues in excess of $9 billion that trades on the New York Stock Exchange

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(“NYSE”) under the symbol “WMB.” We were formed in April 2011 to hold Williams’ exploration and production business and to effect this offering and the related transactions.
 
Upon the completion of this offering, we will be a public company, and investors in this offering will own all of our outstanding Class A common stock. Williams will not own any of our Class A common stock, but will directly own all of our outstanding Class B common stock, which will represent approximately           percent of the total shares of common stock outstanding and approximately           percent of the combined voting power of all outstanding classes of our common stock, or approximately           percent and           percent, respectively, if the underwriters exercise their option to purchase additional Class A common shares in full. As a result, Williams will have the ability to elect all of the members of our board of directors and to determine the outcome of other matters submitted to a vote of our stockholders. For a discussion of related risks, please read “Risk Factors—Risks Related to Our Relationship with Williams.”
 
We intend to distribute to Williams a substantial portion of the proceeds we receive in this offering and our concurrent sale of debt securities. See “Use of Proceeds.” Williams has advised us that it intends to use the funds it receives from the proceeds of this offering and our concurrent sale of debt securities to repay a portion of its indebtedness, and that following the completion of this offering, it intends to distribute all of the shares of our common stock that it owns through a tax-free distribution, or spin-off, to Williams’ stockholders. The determination of whether, and if so, when, to proceed with the spin-off is entirely within the discretion of Williams, although Williams has indicated its intention to complete the spin-off in 2012 and to convert its Class B common shares to Class A common shares immediately prior to such spin-off, assuming such conversion would not jeopardize the ability to consummate the tax-free distribution or the tax-free treatment of any related restructuring transaction undertaken by Williams. Williams has the sole discretion to determine the form, the structure and all other terms of any transactions to effect the spin-off. If Williams does not proceed with the spin-off, it could elect to dispose of our Class B common stock, or the Class A common stock into which the Class B common stock is convertible, in a number of different types of transactions, including additional public offerings, open market sales, sales to one or more third parties or split-off offerings that would allow Williams’ stockholders the opportunity to exchange Williams shares for shares of our common stock or a combination of these transactions. Except for the “lock-up” period described under “Underwriting,” Williams is not subject to any contractual obligation to maintain its Class B share ownership. For more information on the potential effects of Williams’ disposition of our common stock by means of the anticipated spin-off or otherwise, please read “Risk Factors—Risks Related to Our Relationship with Williams.”
 
We currently depend on Williams for a number of administrative functions. Prior to the completion of this offering, we will enter into agreements with Williams related to the separation of our business operations from Williams. These agreements will be in effect as of the completion of this offering and will govern various interim and ongoing relationships between Williams and us, including the extent and manner of our dependence on Williams for administrative services following the completion of this offering. Under the terms of these agreements, we are entitled to the ongoing assistance of Williams only for a limited period of time following the spin-off. For more information regarding these agreements, see “Arrangements Between Williams and Our Company” and the historical combined financial statements and the notes thereto included elsewhere in this prospectus. All of the agreements relating to our separation from Williams will be made in the context of a parent-subsidiary relationship and will be entered into in the overall context of our separation from Williams. The terms of these agreements may be more or less favorable to us than if they had been negotiated with unaffiliated third parties. See “Risk Factors—Risks Related to Our Relationship with Williams—We may have potential business conflicts of interest with Williams regarding our past and ongoing relationships, and because of Williams’ controlling ownership in us, the resolution of these conflicts may not be favorable to us.”
 
Our planned two-step separation process ((1) our initial public offering and concurrent sale of debt securities, including a distribution of a portion of the proceeds to Williams, followed by (2) a spin-off of our common stock in the form of a distribution by Williams to its stockholders) provides us with capital and enables Williams to repay debt while simultaneously achieving the benefits of our complete separation from Williams in a tax-efficient manner. In addition, we believe that our separation from Williams will enable us to realize the following benefits:

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 	•   	Focused management attention.   Our separation from Williams will allow us to focus managerial attention solely on our business, resulting in stream-lined decision making, more efficient deployment of resources and increased operational flexibility.	
 		
 	•   	Direct access to the debt and equity capital markets.   As a separate public company, we will have direct access to the capital markets, thereby enabling us to optimize our capital structure to meet the specific needs of our business.	
 		
 	•   	Enhancing our market recognition with investors.   We believe our simpler corporate structure with a single business segment will allow us to fit more purely into an exploration and production investor sector and attract pure play investors.	
 		
 	•   	Improving our ability to pursue acquisitions.   As a stand alone exploration and production company, we will be better positioned to use our equity securities as capital in pursuing merger and acquisition activities. However, we will be subject to certain requirements, such as (1) prior to the spin-off to Williams’ shareholders of its retained shares in us, Williams must satisfy certain 80% ownership thresholds and (2) after the spin-off, we must avoid a 50% or greater change in our ownership in transactions related to the spin-off. Both of these limitations are necessary in order to maintain the tax-free treatment of our separation from Williams. See “Risk Factors—Risks Related to our Relationship with Williams—Our agreements with Williams may limit our ability to obtain additional financing or make acquisitions,” and “Risk Factors—Risks Related to our Relationship with Williams—Our tax sharing agreement with Williams may limit our ability to take certain actions and may require us to indemnify Williams for significant tax liabilities.”	
 
Our Restructuring
 
Prior to the completion of this offering:

 	•  	Williams will contribute and transfer to us the assets and liabilities associated with our business and will contribute to our capital all intercompany debt associated with our business;	
 		
 	•  	we will effect a recapitalization whereby the outstanding shares of our common stock, all of which are owned by Williams, will be reclassified into     shares of Class B common stock in exchange for all of the assets (net of the liabilities assumed and the cash we distribute to Williams) contributed to us by Williams, and a new Class A common stock will be authorized; and	
 		
 	•  	we will amend and restate our certificate of incorporation and bylaws.	
 
We refer to these transactions as our “restructuring transactions.”
 
Concurrent Financing Transactions
 
On June 3, 2011, we entered into a new five-year $1.5 billion senior unsecured revolving credit facility agreement (the “Credit Facility”), which will become effective upon the completion of this offering and for which we will pay associated financing costs. Concurrently with or shortly following the consummation of this offering, we expect to issue up to $1.5 billion aggregate principal amount of senior unsecured notes (the “Notes”) and pay associated financing costs. The offering of our Class A common stock is not contingent upon the effectiveness of the Credit Facility or the completion of the offering of the Notes. See “Description of Our Concurrent Financing Transactions” for a more detailed description of these transactions.
 
Risk Factors
 
Investing in our Class A common stock involves substantial risk. You should carefully consider all of the information in this prospectus and, in particular, you should evaluate the risk factors and other cautionary statements set forth under “Risk Factors” beginning on page 17 in deciding whether to invest in our Class A common stock. In particular:

 	•  	Our business requires significant capital expenditures and we may be unable to obtain needed capital or financing on satisfactory terms.	
 		
 	•  	Failure to replace reserves may negatively affect our business.	
 		
 	•  	Exploration and development drilling may not result in commercially productive reserves.	

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 	•  	Estimating reserves and future net revenues involves uncertainties. Decreases in natural gas and oil prices, or negative revisions to reserve estimates or assumptions as to future natural gas and oil prices may lead to decreased earnings, losses or impairment of natural gas and oil assets.	
 		
 	•  	Prices for natural gas, oil and NGLs are volatile, and this volatility could adversely affect our financial results, cash flows, access to capital and ability to maintain our existing business.	
 		
 	•  	Our business depends on access to natural gas, oil and NGL transportation systems and facilities.	
 		
 	•  	Our risk management and measurement systems and hedging activities might not be effective and could increase the volatility of our results.	
 		
 	•  	Our operations are subject to operational hazards and unforeseen interruptions for which they may not be adequately insured.	
 		
 	•  	Our operations are subject to governmental laws and regulations relating to the protection of the environment, including with respect to hydraulic fracturing, which may expose us to significant costs and liabilities and could exceed current expectations.	
 		
 	•  	Certain of our properties, including our operations in the Bakken Shale, are located on Native American tribal lands and are subject to various federal and tribal approvals and regulations, which may increase our costs and delay or prevent our efforts to conduct planned operations.	
 		
 	•  	Our acquisition attempts may not be successful or may result in completed acquisitions that do not perform as anticipated.	
 		
 	•  	Our historical and pro forma combined financial information may not be representative of the results we would have achieved as a stand-alone public company and may not be a reliable indicator of our future results.	
 		
 	•  	As long as we are controlled by Williams, your ability to influence the outcome of matters requiring stockholder approval will be limited.	
 
Principal Executive Offices
 
WPX was incorporated under the laws of the State of Delaware in April 2011 and, until the completion of this offering, will be a wholly-owned subsidiary of Williams. Our principal executive offices are located at One Williams Center, Tulsa, Oklahoma 74172. Our telephone number is 918-573-2000. Our website address will be www.wpxenergy.com. Information contained on our website is not incorporated by reference into this prospectus, and you should not consider information on our website as part of this prospectus.

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The Offering

Issuer		WPX Energy, Inc.	
 		
Class A common stock offered		           shares.	
 		
Common stock outstanding after this offering:			
 		
  Class A common stock		           shares, or           shares if the underwriters exercise their option to purchase additional Class A common shares in full.	
 		
  Class B common stock		           shares, or           shares if the underwriters exercise their option to purchase additional Class A common shares in full.	
 		
  Total common stock		           shares. Any shares of Class A common stock issued pursuant to the underwriters’ option to purchase additional Class A common shares will not increase the total number of shares of common stock outstanding after this offering, but rather the number of shares of Class B common stock owned by Williams will be reduced share for share by the number of shares of Class A common stock issued pursuant to such option. Williams is deemed to be an underwriter with respect to any shares of Class A common stock issued pursuant to such option.	
 		
Common stock to be held by Williams after this offering:			
 		
  Class A common stock		None.	
 		
  Class B common stock		           shares, or           shares if the underwriters exercise their option to purchase additional Class A common shares in full.	
 		
Common stock voting rights:			
 		
  Class A common stock		One vote per share on all matters to be voted on by stockholders, representing in aggregate approximately           percent of the combined voting power of our outstanding common stock, or           percent if the underwriters exercise their option to purchase additional Class A common shares in full.	
 		
  Class B common stock		Ten votes per share on all matters to be voted on by stockholders, representing in aggregate approximately           percent of the combined voting power of our outstanding common stock, or           percent if the underwriters exercise their option to purchase additional Class A common shares in full.	
 		
Use of proceeds		We estimate that our net proceeds from the sale of shares of Class A common stock in this offering, after deducting estimated underwriting discounts and commissions and estimated offering expenses, will be approximately $      million ($      million if the underwriters exercise their option to purchase additional Class A common shares in full), assuming the shares are offered at $      per share of Class A common stock, which is the midpoint of the estimated offering price range set forth on the cover page of this prospectus. We expect to retain approximately $500 million of the net proceeds from this offering. At current commodity prices, we expect as much as 50 percent of these proceeds could be used for capital expenditures for drilling and facilities projects, with the remainder available to provide additional liquidity and for acquisition, exploration and general corporate purposes. As part of our restructuring transactions, the remainder of the net proceeds of this	

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		offering will be distributed to Williams. Williams is deemed to be an underwriter with respect to any shares of Class A common stock issued pursuant to the underwriters’ option to purchase additional Class A common shares. See “Use of Proceeds.”	
 		
Dividend policy		We do not anticipate paying any dividends on our common stock in the foreseeable future. See “Dividend Policy.”	
 		
Exchange Listing		We have been approved to list our shares of Class A common stock on the NYSE under the symbol “WPX.”	
 
Unless we specifically state otherwise, all information in this prospectus regarding our Class A common stock:

 	•  	gives effect to our restructuring transactions;	
 		
 	•  	assumes no exercise by the underwriters of their option to purchase additional Class A common shares; and	
 		
 	•  	excludes shares of Class A common stock reserved for issuance, if any, under equity incentive plans.	

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Summary Combined Historical and Unaudited Pro Forma Combined Financial Data
 
Set forth below is our summary combined historical and unaudited pro forma combined financial data for the periods indicated. The historical unaudited combined financial data for the six months ended June 30, 2011 and 2010 and balance sheet data as of June 30, 2011 have been derived from our unaudited condensed combined financial statements included in this prospectus. The unaudited condensed combined financial statements have been prepared on the same basis as our audited combined financial statements, except as stated in the related notes thereto, and include all normal recurring adjustments that, in the opinion of management, are necessary to present fairly our financial condition and result of operations for such periods. The results of operations for the six months ended June 30, 2011 presented below are not necessarily indicative of results for the entire fiscal year. The historical financial data for the years ended December 31, 2010, 2009 and 2008 and the balance sheet data as of December 31, 2010 and 2009 have been derived from our audited combined financial statements included in this prospectus.
 
The pro forma financial data was prepared as if the transactions described below had occurred as of January 1, 2010. The pro forma financial data gives effect to the following transactions:

 	•  	the completion of our restructuring transactions;	
 		
 	•  	the receipt of approximately $704 million from the sale of shares of Class A common stock offered by us at an assumed initial public offering price of $      per share, which is the midpoint of the estimated offering price range set forth on the cover page of this prospectus, after deducting estimated underwriting discounts and commissions and estimated offering expenses payable by us;	
 		
 	•  	the receipt of approximately $1.5 billion from our expected offering of the Notes, after deducting the discounts of the initial purchasers of the Notes and the expenses payable by us in connection with such offering; and	
 		
 	•  	the distribution of approximately $1.7 billion to Williams from the combined net proceeds from this offering and the expected offering of the Notes in connection with our restructuring transactions.	
 
You should read the following summary financial data in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our historical and pro forma financial statements and related notes thereto appearing elsewhere in this prospectus.
 
The unaudited pro forma combined financial data does not purport to represent what our financial position and results of operations actually would have been had the restructuring transactions occurred on the dates indicated or to project our future financial performance.

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 	 	Pro Forma Six	 	 	Pro Forma	 	 	Historical Six	 	 	 	 	
 	 	Months Ended	 	 	Year Ended	 	 	Months	 	 	Historical Year Ended	 	
 	 	June 30,	 	 	December 31,	 	 	Ended June 30,	 	 	December 31,	 	
 	 	2011	 	 	2010	 	 	2011	 	 	2010	 	 	2010	 	 	2009	 	 	2008	 	
 	 	(Millions)	 	 	 	 	
 		
Statement of Operations Data:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Revenues, including affiliate(1)	 	$	1,974	 	 	$	4,034	 	 	$	1,974	 	 	$	2,068	 	 	$	4,034	 	 	$	3,681	 	 	$	6,184	 	
Costs and expenses:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Lease and facility operating, including affiliate	 	 	140	 	 	 	286	 	 	 	140	 	 	 	132	 	 	 	286	 	 	 	263	 	 	 	272	 	
Gathering, processing and transportation, including affiliate	 	 	240	 	 	 	326	 	 	 	240	 	 	 	145	 	 	 	326	 	 	 	273	 	 	 	229	 	
Taxes other than income	 	 	76	 	 	 	125	 	 	 	76	 	 	 	73	 	 	 	125	 	 	 	93	 	 	 	254	 	
Gas management (including charges for unutilized pipeline capacity)	 	 	762	 	 	 	1,771	 	 	 	762	 	 	 	934	 	 	 	1,771	 	 	 	1,495	 	 	 	3,248	 	
Exploration	 	 	33	 	 	 	73	 	 	 	33	 	 	 	18	 	 	 	73	 	 	 	54	 	 	 	37	 	
Depreciation, depletion and amortization	 	 	452	 	 	 	875	 	 	 	452	 	 	 	433	 	 	 	875	 	 	 	887	 	 	 	738	 	
Impairment of producing properties and costs of acquired unproved reserves	 	 	—	 	 	 	678	 	 	 	—	 	 	 	—	 	 	 	678	 	 	 	15	 	 	 	—	 	
Goodwill impairment	 	 	—	 	 	 	1,003	 	 	 	—	 	 	 	—	 	 	 	1,003	 	 	 	—	 	 	 	—	 	
General and administrative, including affiliate	 	 	135	 	 	 	253	 	 	 	135	 	 	 	122	 	 	 	253	 	 	 	251	 	 	 	247	 	
Gain on sale of contractual right to international production payment	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(148	)	
Other—net	 	 	5	 	 	 	(19	)	 	 	5	 	 	 	3	 	 	 	(19	)	 	 	33	 	 	 	6	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total costs and expenses	 	 	1,843	 	 	 	5,371	 	 	 	1,843	 	 	 	1,860	 	 	 	5,371	 	 	 	3,364	 	 	 	4,883	 	
Operating income (loss)	 	 	131	 	 	 	(1,337	)	 	 	131	 	 	 	208	 	 	 	(1,337	)	 	 	317	 	 	 	1,301	 	
Interest expense, including affiliate	 	 	(52	)	 	 	(103	)	 	 	(97	)	 	 	(50	)	 	 	(124	)	 	 	(100	)	 	 	(74	)	
Interest capitalized	 	 	8	 	 	 	16	 	 	 	8	 	 	 	8	 	 	 	16	 	 	 	18	 	 	 	20	 	
Investment income and other	 	 	12	 	 	 	21	 	 	 	12	 	 	 	11	 	 	 	21	 	 	 	8	 	 	 	22	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income (loss) from continuing operations before income taxes	 	 	99	 	 	 	(1,403	)	 	 	54	 	 	 	177	 	 	 	(1,424	)	 	 	243	 	 	 	1,269	 	
Provision (benefit) for income taxes	 	 	35	 	 	 	(142	)	 	 	19	 	 	 	62	 	 	 	(150	)	 	 	94	 	 	 	452	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income (loss) from continuing operations(2)	 	 	64	 	 	 	(1,261	)	 	 	35	 	 	 	115	 	 	 	(1,274	)	 	 	149	 	 	 	817	 	
Loss from discontinued operations(3)	 	 	(8	)	 	 	(8	)	 	 	(8	)	 	 	(1	)	 	 	(8	)	 	 	(7	)	 	 	(87	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income (loss)	 	$	56	 	 	$	(1,269	)	 	 	27	 	 	 	114	 	 	 	(1,282	)	 	 	142	 	 	 	730	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Less: Net income attributable to noncontrolling interests	 	 	 	 	 	 	 	 	 	 	5	 	 	 	4	 	 	 	8	 	 	 	6	 	 	 	8	 	

Net income (loss) attributable to WPX Energy	 	 	 	 	 	 	 	 	 	$	22	 	 	$	110	 	 	$	(1,290	)	 	$	136	 	 	$	722	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income (loss) from continuing operations per share(4):	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Basic and diluted	 	$	 	 	 	$	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	

 
			
(1)		Includes gas management revenues of $745 million and $922 million for the six months ended June 30, 2011 and 2010, respectively and $1,742 million, $1,456 million and $3,241 million for the year ended December 31, 2010, 2009 and 2008, respectively. These revenues were offset by the gas management expenses shown in the table above. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations.”	
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(2)		Loss from continuing operations in 2010 includes $1.7 billion of impairment charges related to goodwill, producing properties in the Barnett Shale and costs of acquired unproved reserves in the Piceance Basin. Income from continuing operations in 2008 includes a $148 million gain related to the sale of a right to an international production payment. See Notes 6 and 14 of Notes to Combined Financial Statements for further discussion of asset sales, impairments and other accruals in 2010, 2009 and 2008.	
 		
(3)		Loss from discontinued operations includes our Arkoma operations which were classified as held for sale in the first half of 2011 and activities associated with Williams’ former power business that was substantially disposed of in 2007. The loss in 2008 includes a $148 million pre-tax impairment of the Arkoma producing properties.	
 		
(4)		Historical earnings per share are not presented since the Company’s common stock was not part of the capital structure of Williams for the periods presented.	

 	 	Pro Forma	 	 	Historical	 	 	Historical	 	
 	 	At June 30,	 	 	At June 30,	 	 	At December 31,	 	
 	 	2011	 	 	2011	 	 	2010	 	 	2009	 	
 	 	(Millions)	 	
 		
Balance Sheet Data:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash and cash equivalents	 	$	538	 	 	$	36	 	 	$	37	 	 	$	34	 	
Properties and equipment, net	 	 	8,654	 	 	 	8,654	 	 	 	8,449	 	 	 	7,662	 	
Total assets	 	 	10,415	 	 	 	9,895	 	 	 	9,846	 	 	 	10,553	 	
Unsecured notes payable to Williams—current	 	 	—	 	 	 	—	 	 	 	2,261	 	 	 	1,216	 	
Senior unsecured notes	 	 	1,500	 	 	 	—	 	 	 	—	 	 	 	—	 	
Total equity	 	 	5,843	 	 	 	6,869	 	 	 	4,500	 	 	 	5,405	 	
Total liabilities and equity	 	 	10,415	 	 	 	9,895	 	 	 	9,846	 	 	 	10,553	 	

 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Pro Forma	 	 	 	 	 	 	 	 	 	 	
 	 	Six Months	 	 	Pro Forma	 	 	 	 	 	 	 	
 	 	Ended	 	 	Year Ended	 	 	Historical Six Months	 	 	 	 	
 	 	June 30,	 	 	December 31,	 	 	Ended June 30,	 	 	Historical Year Ended December 31,	 	
 	 	2011	 	 	2010	 	 	2011	 	 	2010	 	 	2010	 	 	2009	 	 	2008	 	
 	 	(Millions)	 	
 		
Other Financial Data:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net cash provided by operating activities	 	 	 	 	 	 	 	 	 	$	523	 	 	$	526	 	 	$	1,056	 	 	$	1,181	 	 	$	2,009	 	
Net cash used in investing activities	 	 	 	 	 	 	 	 	 	 	(667	)	 	 	(554	)	 	 	(2,337	)	 	 	(1,435	)	 	 	(2,252	)	
Net cash provided (used) by financing activities	 	 	 	 	 	 	 	 	 	 	143	 	 	 	28	 	 	 	1,284	 	 	 	256	 	 	 	225	 	
Adjusted EBITDAX(1)	 	$	636	 	 	$	1,329	 	 	 	636	 	 	 	678	 	 	 	1,329	 	 	 	1,299	 	 	 	1,970	 	
Capital expenditures	 	 	 	 	 	 	 	 	 	 	(683	)	 	 	(551	)	 	 	(1,856	)	 	 	(1,434	)	 	 	(2,467	)	

 
			
(1)		Adjusted EBITDAX is a non-GAAP financial measure. For a definition of Adjusted EBITDAX and a reconciliation of Adjusted EBITDAX to our net income (loss), see “—Summary Combined Historical Operating and Reserve Data—Non-GAAP Financial Measures and Reconciliations” below.	

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Summary Combined Historical Operating and Reserve Data
 
The following table presents summary combined data with respect to our estimated net proved natural gas and oil reserves as of the dates indicated. Approximately 93 percent of our year-end 2010 U.S. proved reserves estimates were audited by Netherland, Sewell & Associates, Inc. (“NSAI”) and approximately one percent were audited by Miller and Lents, Ltd. (“M&L”). Approximately 96 percent of Apco’s year-end 2010 proved reserves estimates (which constitute approximately 94 percent of our year-end 2010 proved reserves estimates for international properties) were reviewed and certified by Ralph E. Davis Associates, Inc. In the judgment of these independent reserve petroleum engineers, our estimates reviewed in their respective reports are, in the aggregate, reasonable and have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Because our acquisition in the Bakken Shale was completed in late December 2010, our year-end estimated reserves for those properties are based on internal estimates only. All of the reserve estimates mentioned above were prepared in a manner consistent with the rules of the Securities and Exchange Commission (the “SEC”) regarding oil and natural gas reserve reporting that are currently in effect. You should refer to “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Business” when evaluating the material presented below.

 	 	At December 31,	 	
 	 	2010	 	 	2009	 	
 		
Estimated Proved Reserves(1)	 	 	 	 	 	 	 	 	
Natural Gas (Bcf)(2)	 	 	4,214	 	 	 	4,316	 	
Oil (MMbbls)	 	 	43	 	 	 	23	 	
Total (Bcfe)	 	 	4,473	 	 	 	4,452	 	
PV-10 (in millions)	 	$	4,544	 	 	$	2,620	 	
Standardized Measure of Discounted Future Net Cash Flows (in millions)(3)	 	$	3,080	 	 	$	1,923	 	

 
			
(1)		Includes approximately 69 percent of Apco’s reserves, which corresponds to our ownership interest in Apco. Our estimated proved reserves for domestic properties, PV-10 and Standardized Measure were derived using an average price of $3.36 per Mcf of natural gas and $48.63 per barrel of oil during 2009 and $4.31 per Mcf of natural gas and $68.89 per barrel of oil during 2010. Our prices were calculated using the 12-month average, first-of-the-month price for the applicable indices for each basin as adjusted for locational price differentials. The 12-month average beginning of the month price for Apco properties was $1.93 per MMbtu of natural gas and $43.62 per barrel of oil for 2009 and $1.63 per MMbtu of natural gas and $52.11 per barrel of oil for 2010.	
 		
(2)		Net wellhead natural gas reserves at December 31, 2010 and 2009 included approximately 99 MMbbls and 69 MMbbls, respectively, of NGLs to be extracted downstream at processing plants. The gas volume shrink associated with this processing is approximately 216 Bcf and 164 Bcf, respectively, or approximately 4.8 percent and 3.7 percent, respectively, of our total proved reserves volumes.	
 		
(3)		Standardized Measure represents the present value of estimated future cash inflows from proved natural gas and oil reserves, less future development and production costs and income tax expenses, discounted at ten percent per annum to reflect timing of future cash flows and using the same pricing assumptions as were used to calculate PV-10. Standardized Measure differs from PV-10 because Standardized Measure includes the effect of future income taxes. For a reconciliation of the non-GAAP financial measure of PV-10 to Standardized Measure, the most directly comparable GAAP financial measure, see “—Non-GAAP Financial Measures and Reconciliations” below.	

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The following table summarizes our net production for the years indicated.

 	 	Year Ended December 31,	 	
 	 	2010	 	 	2009	 	 	2008	 	
 		
Production Data:	 	 	 	 	 	 	 	 	 	 	 	 	
Natural Gas (MMcf)	 	 	 	 	 	 	 	 	 	 	 	 	
U.S.	 	 	 	 	 	 	 	 	 	 	 	 	
Piceance Basin	 	 	241,371	 	 	 	252,387	 	 	 	240,285	 	
Other(1)	 	 	162,571	 	 	 	171,691	 	 	 	156,497	 	
Argentina(2)	 	 	7,304	 	 	 	7,728	 	 	 	6,392	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	 	411,246	 	 	 	431,806	 	 	 	403,174	 	
Oil (MBbls)	 	 	 	 	 	 	 	 	 	 	 	 	
U.S. 	 	 	857	 	 	 	803	 	 	 	731	 	
Argentina(2)	 	 	2,035	 	 	 	1,998	 	 	 	1,991	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	 	2,892	 	 	 	2,801	 	 	 	2,722	 	
Combined Equivalent Volumes (MMcfe)(2)	 	 	428,598	 	 	 	448,612	 	 	 	419,506	 	
Combined Equivalent Volumes (MBoe)	 	 	71,433	 	 	 	74,769	 	 	 	69,918	 	
Average Daily Combined Equivalent Volumes (MMcfe/d)	 	 	 	 	 	 	 	 	 	 	 	 	
U.S.	 	 	 	 	 	 	 	 	 	 	 	 	
Piceance Basin	 	 	674	 	 	 	703	 	 	 	666	 	
Other(1)	 	 	447	 	 	 	472	 	 	 	430	 	
Argentina(2)	 	 	53	 	 	 	54	 	 	 	50	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	 	1,174	 	 	 	1,229	 	 	 	1,146	 	

 
			
(1)		Excludes production from our Arkoma Basin operations which were classified as held for sale and reported as discontinued operations as of June 30, 2011 and comprised less than one percent of our total production.	
 		
(2)		Includes approximately 69 percent of Apco’s production (which corresponds to our ownership interest in Apco) and other minor directly held interests.	
 
The following tables summarize our domestic sales price and cost information for the years indicated.

 	 	Year Ended December 31,	 	
 	 	2010	 	 	2009	 	 	2008	 	
 		
Realized average price per unit(1):	 	 	 	 	 	 	 	 	 	 	 	 	
Natural gas, without hedges (per Mcf)(2)	 	$	4.33	 	 	$	3.39	 	 	$	6.84	 	
Impact of hedges (per Mcf)(2)	 	 	0.82	 	 	 	1.45	 	 	 	0.09	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Natural gas, with hedges (per Mcf)(2)	 	$	5.15	 	 	$	4.84	 	 	$	6.93	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Oil, without hedges (per Bbl)	 	$	66.32	 	 	$	47.39	 	 	$	84.63	 	
Impact of hedges (per Bbl)	 	 	—	 	 	 	—	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Oil, with hedges (per Bbl)	 	$	66.32	 	 	$	47.39	 	 	$	84.63	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Price per Boe, without hedges(3)	 	$	26.44	 	 	$	20.63	 	 	$	41.52	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Price per Boe, with hedges(3)	 	$	31.32	 	 	$	29.23	 	 	$	42.03	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Price per Mcfe, without hedges(3)	 	$	4.41	 	 	$	3.44	 	 	$	6.92	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Price per Mcfe, with hedges(3)	 	$	5.22	 	 	$	4.87	 	 	$	7.00	 	

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(1)		Excludes our Arkoma Basin operations, which were classified as held for sale and reported as discontinued operations as of June 30, 2011 and comprised less than one percent of our total revenues.	
 		
(2)		Includes NGLs.	
 		
(3)		Realized average prices reflect realized market prices, net of fuel and shrink.	

 	 	Year Ended December 31,	 	
 	 	2010	 	 	2009	 	 	2008	 	
 		
Expenses per Mcfe(1):	 	 	 	 	 	 	 	 	 	 	 	 	
Operating expenses:	 	 	 	 	 	 	 	 	 	 	 	 	
Lifting costs and workovers	 	$	0.46	 	 	$	0.39	 	 	$	0.45	 	
Facilities operating expense	 	 	0.14	 	 	 	0.14	 	 	 	0.15	 	
Other operating and maintenance	 	 	0.05	 	 	 	0.05	 	 	 	0.04	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total LOE	 	$	0.65	 	 	$	0.58	 	 	$	0.64	 	
Gathering, processing and transportation charges	 	 	0.80	 	 	 	0.64	 	 	 	0.57	 	
Taxes other than income	 	 	0.27	 	 	 	0.19	 	 	 	0.60	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Production cost	 	$	1.72	 	 	$	1.41	 	 	$	1.81	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
General and administrative	 	$	0.60	 	 	$	0.56	 	 	$	0.60	 	
Depreciation, depletion and amortization	 	$	2.10	 	 	$	2.03	 	 	$	1.80	 	

 
			
(1)		Excludes our Arkoma Basin operations, which were classified as held for sale and reported as discontinued operations as of June 30, 2011.	
 
Non-GAAP Financial Measures and Reconciliations
 
Adjusted EBITDAX
 
Adjusted EBITDAX is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies.
 
We define Adjusted EBITDAX as earnings before interest expense, income taxes, depreciation, depletion and amortization, exploration expenses and the other items described below. Adjusted EBITDAX is not a measure of net income as determined by United States generally accepted accounting principles, or GAAP.
 
Management believes Adjusted EBITDAX is useful because it allows them to more effectively evaluate our operating performance and compare the results of our operations from period to period and against our peers without regard to our financing methods or capital structure. We exclude the items listed above from net income in arriving at Adjusted EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP or as an indicator of our liquidity. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDAX. Our computations of Adjusted EBITDAX may not be comparable to other similarly titled measures of other companies. We believe that Adjusted EBITDAX is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet debt service requirements.

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The following table presents a reconciliation of the non-GAAP financial measure of Adjusted EBITDAX to the GAAP financial measure of net income (loss).

 	 	Pro Forma Six	 	 	Pro Forma	 	 	Historical	 	 	 	 	
 	 	Months Ended	 	 	Year Ended	 	 	Six Months	 	 	Historical	 	
 	 	June 30,	 	 	December 31,	 	 	Ended June 30,	 	 	Year Ended December 31,	 	
 	 	2011	 	 	2010	 	 	2011	 	 	2010	 	 	2010	 	 	2009	 	 	2008	 	
 	 	(Millions)	 	
 		
Adjusted EBITDAX Reconciliation to Net Income (Loss):	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income (loss)	 	$	56	 	 	$	(1,269	)	 	$	27	 	 	$	114	 	 	$	(1,282	)	 	$	142	 	 	$	730	 	
Interest expense	 	 	52	 	 	 	103	 	 	 	97	 	 	 	50	 	 	 	124	 	 	 	100	 	 	 	74	 	
Provision (benefit) for income taxes	 	 	35	 	 	 	(142	)	 	 	19	 	 	 	62	 	 	 	(150	)	 	 	94	 	 	 	452	 	
Depreciation, depletion and amortization	 	 	452	 	 	 	875	 	 	 	452	 	 	 	433	 	 	 	875	 	 	 	887	 	 	 	738	 	
Exploration expenses	 	 	33	 	 	 	73	 	 	 	33	 	 	 	18	 	 	 	73	 	 	 	54	 	 	 	37	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
EBITDAX	 	 	628	 	 	 	(360	)	 	 	628	 	 	 	677	 	 	 	(360	)	 	 	1,277	 	 	 	2,031	 	
Gain on sale of contractual right to international production payment	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(148	)	
Impairments of goodwill, producing properties and cost of acquired unproved reserves	 	 	—	 	 	 	1,681	 	 	 	—	 	 	 	—	 	 	 	1,681	 	 	 	15	 	 	 	—	 	
Loss from discontinued operations	 	 	8	 	 	 	8	 	 	 	8	 	 	 	1	 	 	 	8	 	 	 	7	 	 	 	87	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Adjusted EBITDAX	 	$	636	 	 	$	1,329	 	 	$	636	 	 	$	678	 	 	$	1,329	 	 	$	1,299	 	 	$	1,970	 	

 
PV-10
 
PV-10 is a non-GAAP financial measure and represents the year-end present value of estimated future cash inflows from proved natural gas and crude oil reserves, less future development and production costs, discounted at 10 percent per annum to reflect the timing of future cash flows and using pricing assumptions in effect at the end of the period. PV-10 differs from Standardized Measure because it does not include the effects of income taxes on future net revenues. Neither PV-10 nor Standardized Measure represents an estimate of fair market value of our natural gas and crude oil properties. PV-10 is used by the industry and by our management as an arbitrary reserve asset value measure to compare against past reserve bases and the reserve bases of other business entities that are not dependent on the taxpaying status of the entity.
 
The following table provides a reconciliation of our Standardized Measure to PV-10 and includes 69 percent of Apco’s metrics, which corresponds to our ownership interest in Apco, and includes our Arkoma Basin operations, which were classified as held for sale and reported as discontinued operations as of June 30, 2011.

 	 	At December 31,	 	
 	 	2010	 	 	2009	 	
 	 	(Millions)	 	
 		
Standardized Measure of Discounted Future Net Cash Flows	 	$	3,080	 	 	$	1,923	 	
Present value of future income tax discounted at 10%	 	 	1,464	 	 	 	697	 	
 	 	 	 	 	 	 	 	 	
PV-10	 	$	4,544	 	 	$	2,620	 	

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RISK FACTORS
 
Investing in our Class A common stock involves substantial risk. You should carefully consider the following risk factors and the other information in this prospectus before investing in our Class A common stock. If any of the following risks actually occur, our business, financial condition, cash flows and results of operations could suffer materially and adversely. In that case, the trading price of our Class A common stock could decline, and you might lose all or part of your investment.
 
Risks Related to Our Business
 
Our business requires significant capital expenditures and we may be unable to obtain needed capital or financing on satisfactory terms.
 
Our exploration, development and acquisition activities require substantial capital expenditures. Historically, we have funded our capital expenditures through a combination of cash flows from operations, capital contributions or borrowings from Williams and sales of assets. Future cash flows are subject to a number of variables, including the level of production from existing wells, prices of natural gas and oil and our success in developing and producing new reserves. If our cash flow from operations is not sufficient to fund our capital expenditure budget, we may have limited ability to obtain the additional capital necessary to sustain our operations at current levels. We may not be able to obtain debt or equity financing on terms favorable to us or at all. The failure to obtain additional financing could result in a curtailment of our operations relating to exploration and development of our prospects, which in turn could lead to a decline in our natural gas and oil production or reserves, and in some areas a loss of properties.
 
Failure to replace reserves may negatively affect our business.
 
The growth of our business depends upon our ability to find, develop or acquire additional natural gas and oil reserves that are economically recoverable. Our proved reserves generally decline when reserves are produced, unless we conduct successful exploration or development activities or acquire properties containing proved reserves, or both. We may not always be able to find, develop or acquire additional reserves at acceptable costs. If natural gas or oil prices increase, our costs for additional reserves would also increase; conversely if natural gas or oil prices decrease, it could make it more difficult to fund the replacement of our reserves.
 
Exploration and development drilling may not result in commercially productive reserves.
 
Our past success rate for drilling projects should not be considered a predictor of future commercial success. Our decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. The new wells we drill or participate in may not be commercially productive, and we may not recover all or any portion of our investment in wells we drill or participate in. Our efforts will be unprofitable if we drill dry wells or wells that are productive but do not produce enough reserves to return a profit after drilling, operating and other costs. The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a project. Further, our drilling operations may be curtailed, delayed, canceled or rendered unprofitable or less profitable than anticipated as a result of a variety of other factors, including:

 	•  	Increases in the cost of, or shortages or delays in the availability of, drilling rigs and equipment, supplies, skilled labor, capital or transportation;	
 		
 	•  	Equipment failures or accidents;	
 		
 	•  	Adverse weather conditions, such as blizzards;	
 		
 	•  	Title and lease related problems;	
 		
 	•  	Limitations in the market for natural gas and oil;	
 		
 	•  	Unexpected drilling conditions or problems;	
 		
 	•  	Pressure or irregularities in geological formations;	

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 	•  	Regulations and regulatory approvals;	
 		
 	•  	Changes or anticipated changes in energy prices; or	
 		
 	•  	Compliance with environmental and other governmental requirements.	
 
We expect to invest approximately 35 percent of our drilling capital during 2011 in two relatively new unconventional projects, the Bakken Shale in western North Dakota and the Marcellus Shale in Pennsylvania. Due to limited production history from the relatively few number of wells drilled in these projects, we are unable to predict with certainty the quantity of future production from wells to be drilled in those projects.
 
If natural gas and oil prices decrease, we may be required to take write-downs of the carrying values of our natural gas and oil properties.
 
Accounting rules require that we review periodically the carrying value of our natural gas and oil properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our natural gas and oil properties. A writedown constitutes a non-cash charge to earnings. For example, as a result of significant declines in forward natural gas prices, we recorded impairments of capitalized costs of certain natural gas properties of $678 million in 2010. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations for the periods in which such charges are taken.
 
Estimating reserves and future net revenues involves uncertainties. Decreases in natural gas and oil prices, or negative revisions to reserve estimates or assumptions as to future natural gas and oil prices may lead to decreased earnings, losses or impairment of natural gas and oil assets.
 
Reserve estimation is a subjective process of evaluating underground accumulations of oil and gas that cannot be measured in an exact manner. Reserves that are “proved reserves” are those estimated quantities of crude oil, natural gas and NGLs that geological and engineering data demonstrate with reasonable certainty are recoverable in future years from known reservoirs under existing economic and operating conditions and relate to projects for which the extraction of hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
 
The process relies on interpretations of available geological, geophysical, engineering and production data. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of developmental expenditures, including many factors beyond the control of the producer. The reserve data included in this prospectus represent estimates. In addition, the estimates of future net revenues from our proved reserves and the present value of such estimates are based upon certain assumptions about future production levels, prices and costs that may not prove to be correct.
 
Quantities of proved reserves are estimated based on economic conditions in existence during the period of assessment. Changes to oil and gas prices in the markets for such commodities may have the impact of shortening the economic lives of certain fields because it becomes uneconomic to produce all recoverable reserves on such fields, which reduces proved property reserve estimates.
 
If negative revisions in the estimated quantities of proved reserves were to occur, it would have the effect of increasing the rates of depreciation, depletion and amortization on the affected properties, which would decrease earnings or result in losses through higher depreciation, depletion and amortization expense. These revisions, as well as revisions in the assumptions of future cash flows of these reserves, may also be sufficient to trigger impairment losses on certain properties which would result in a noncash charge to earnings.
 
The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate.
 
Approximately 41 percent of our total estimated proved reserves at December 31, 2010 were proved undeveloped reserves and may not be ultimately developed or produced. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. The reserve data included in the reserve engineer reports assumes that substantial capital expenditures are required to develop such reserves. We cannot be certain that the estimated costs of the development of these reserves are accurate, that

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development will occur as scheduled or that the results of such development will be as estimated. Delays in the development of our reserves or increases in costs to drill and develop such reserves will reduce the PV-10 value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify our proved reserves as unproved reserves.
 
The present value of future net revenues from our proved reserves will not necessarily be the same as the value we ultimately realize of our estimated natural gas and oil reserves.
 
You should not assume that the present value of future net revenues from our proved reserves is the current market value of our estimated natural gas and oil reserves. For the year ended December 31, 2008, we based the estimated discounted future net revenues from our proved reserves on prices and costs in effect on the day of the estimate in accordance with previous SEC requirements. In accordance with new SEC requirements for the years ended December 31, 2009 and 2010, we have based the estimated discounted future net revenues from our proved reserves on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the preceding twelve months without giving effect to derivative transactions. Actual future net revenues from our natural gas and oil properties will be affected by factors such as:

 	•  	actual prices we receive for natural gas and oil;	
 		
 	•  	actual cost of development and production expenditures;	
 		
 	•  	the amount and timing of actual production; and	
 		
 	•  	changes in governmental regulations or taxation.	
 
The timing of both our production and our incurrence of expenses in connection with the development and production of natural gas and oil properties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value. In addition, the 10 percent discount factor we use when calculating discounted future net revenues may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general.
 
Certain of our domestic undeveloped leasehold assets are subject to leases that will expire over the next several years unless production is established on units containing the acreage.
 
The majority of our acreage in the Marcellus Shale and Bakken Shale is not currently held by production. Unless production in paying quantities is established on units containing these leases during their terms, the leases will expire. If our leases expire and we are unable to renew the leases, we will lose our right to develop the related properties. Our drilling plans for these areas are subject to change based upon various factors, including drilling results, natural gas and oil prices, availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints and regulatory and lease issues.
 
Prices for natural gas, oil and NGLs are volatile, and this volatility could adversely affect our financial results, cash flows, access to capital and ability to maintain our existing business.
 
Our revenues, operating results, future rate of growth and the value of our business depend primarily upon the prices of natural gas, oil and NGLs. Price volatility can impact both the amount we receive for our products and the volume of products we sell. Prices affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital.
 
The markets for natural gas, oil and NGLs are likely to continue to be volatile. Wide fluctuations in prices might result from relatively minor changes in the supply of and demand for these commodities, market uncertainty and other factors that are beyond our control, including:

 	•  	Worldwide and domestic supplies of and demand for natural gas, oil and NGLs;	
 		
 	•  	Turmoil in the Middle East and other producing regions;	
 		
 	•  	The activities of the Organization of Petroleum Exporting Countries;	
 		
 	•  	Terrorist attacks on production or transportation assets;	

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 	•  	Weather conditions;	
 		
 	•  	The level of consumer demand;	
 		
 	•  	Variations in local market conditions (basis differential);	
 		
 	•  	The price and availability of other types of fuels;	
 		
 	•  	The availability of pipeline capacity;	
 		
 	•  	Supply disruptions, including plant outages and transportation disruptions;	
 		
 	•  	The price and quantity of foreign imports of natural gas and oil;	
 		
 	•  	Domestic and foreign governmental regulations and taxes;	
 		
 	•  	Volatility in the natural gas and oil markets;	
 		
 	•  	The overall economic environment;	
 		
 	•  	The credit of participants in the markets where products are bought and sold; and	
 		
 	•  	The adoption of regulations or legislation relating to climate change.	
 
Our business depends on access to natural gas, oil and NGL transportation systems and facilities.
 
The marketability of our natural gas, oil and NGL production depends in large part on the operation, availability, proximity, capacity and expansion of transportation systems and facilities owned by third parties. For example, we can provide no assurance that sufficient transportation capacity will exist for expected production from the Bakken Shale and Marcellus Shale or that we will be able to obtain sufficient transportation capacity on economic terms.
 
A lack of available capacity on transportation systems and facilities or delays in their planned expansions could result in the shut-in of producing wells or the delay or discontinuance of drilling plans for properties. A lack of availability of these systems and facilities for an extended period of time could negatively affect our revenues. In addition, we have entered into contracts for firm transportation and any failure to renew those contracts on the same or better commercial terms could increase our costs and our exposure to the risks described above.
 
We may have excess capacity under our firm transportation contracts, or the terms of certain of those contracts may be less favorable than those we could obtain currently.
 
We have entered into contracts for firm transportation that may exceed our transportation needs. Any excess transportation commitments will result in excess transportation costs that could negatively affect our results of operations. In addition, certain of the contracts we have entered into may be on terms less favorable to us than we could obtain if we were negotiating them at current rates, which also could negatively affect our results of operations.
 
We have limited control over activities on properties we do not operate, which could reduce our production and revenues.
 
If we do not operate the properties in which we own an interest, we do not have control over normal operating procedures, expenditures or future development of underlying properties. The failure of an operator of our wells to adequately perform operations or an operator’s breach of the applicable agreements could reduce our production and revenues or increase our costs. As of December 31, 2010, we were not the operator of approximately 17 percent of our total domestic net production. Apco generally has outside-operated interests in its properties. The success and timing of our drilling and development activities on properties operated by others depend upon a number of factors outside of our control, including the operator’s timing and amount of capital expenditures, expertise and financial resources, inclusion of other participants in drilling wells and use of technology. Because we do not have a majority interest in most wells we do not operate, we may not be in a position to remove the operator in the event of poor performance.

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We might not be able to successfully manage the risks associated with selling and marketing products in the wholesale energy markets.
 
Our portfolio of derivative and other energy contracts includes wholesale contracts to buy and sell natural gas, oil and NGLs that are settled by the delivery of the commodity or cash. If the values of these contracts change in a direction or manner that we do not anticipate or cannot manage, it could negatively affect our results of operations. In the past, certain marketing and trading companies have experienced severe financial problems due to price volatility in the energy commodity markets. In certain instances this volatility has caused companies to be unable to deliver energy commodities that they had guaranteed under contract. If such a delivery failure were to occur in one of our contracts, we might incur additional losses to the extent of amounts, if any, already paid to, or received from, counterparties. In addition, in our business, we often extend credit to our counterparties. We are exposed to the risk that we might not be able to collect amounts owed to us. If the counterparty to such a transaction fails to perform and any collateral that secures our counterparty’s obligation is inadequate, we will suffer a loss. Downturns in the economy or disruptions in the global credit markets could cause more of our counterparties to fail to perform than we expect.
 
Our risk management and measurement systems and hedging activities might not be effective and could increase the volatility of our results.
 
The systems we use to quantify commodity price risk associated with our businesses might not always be followed or might not always be effective. Further, such systems do not in themselves manage risk, particularly risks outside of our control, and adverse changes in energy commodity market prices, volatility, adverse correlation of commodity prices, the liquidity of markets, changes in interest rates and other risks discussed in this prospectus might still adversely affect our earnings, cash flows and balance sheet under applicable accounting rules, even if risks have been identified. Furthermore, no single hedging arrangement can adequately address all commodity price risks present in a given contract. For example, a forward contract that would be effective in hedging commodity price volatility risks would not hedge the contract’s counterparty credit or performance risk. Therefore, unhedged risks will always continue to exist.
 
Our use of hedging arrangements through which we attempt to reduce the economic risk of our participation in commodity markets could result in increased volatility of our reported results. Changes in the fair values (gains and losses) of derivatives that qualify as hedges under GAAP to the extent that such hedges are not fully effective in offsetting changes to the value of the hedged commodity, as well as changes in the fair value of derivatives that do not qualify or have not been designated as hedges under GAAP, must be recorded in our income. This creates the risk of volatility in earnings even if no economic impact to us has occurred during the applicable period.
 
The impact of changes in market prices for natural gas, oil and NGLs on the average prices paid or received by us may be reduced based on the level of our hedging activities. These hedging arrangements may limit or enhance our margins if the market prices for natural gas, oil or NGLs were to change substantially from the price established by the hedges. In addition, our hedging arrangements expose us to the risk of financial loss if our production volumes are less than expected.
 
The adoption and implementation of new statutory and regulatory requirements for derivative transactions could have an adverse impact on our ability to hedge risks associated with our business and increase the working capital requirements to conduct these activities.
 
In July 2010, federal legislation known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) was enacted. The Dodd-Frank Act provides for new statutory and regulatory requirements for derivative transactions, including oil and gas hedging transactions. Among other things, the Dodd-Frank Act provides for the creation of position limits for certain derivatives transactions, as well as requiring certain transactions to be cleared on exchanges for which cash collateral will be required. The final impact of the Dodd-Frank Act on our hedging activities is uncertain at this time due to the requirement that the SEC and the Commodities Futures Trading Commission (“CFTC”) promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. These new rules and regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts or reduce the availability of derivatives. Although we believe the derivative contracts that we enter into should

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not be impacted by position limits and should be exempt from the requirement to clear transactions through a central exchange or to post collateral, the impact upon our businesses will depend on the outcome of the implementing regulations adopted by the CFTC.
 
Depending on the rules and definitions adopted by the CFTC or similar rules that may be adopted by other regulatory bodies, we might in the future be required to provide cash collateral for our commodities hedging transactions under circumstances in which we do not currently post cash collateral. Posting of such additional cash collateral could impact liquidity and reduce our cash available for capital expenditures. A requirement to post cash collateral could therefore reduce our ability to execute hedges to reduce commodity price uncertainty and thus protect cash flows. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable.
 
We are exposed to the credit risk of our customers and counterparties, and our credit risk management may not be adequate to protect against such risk.
 
We are subject to the risk of loss resulting from nonpayment and/or nonperformance by our customers and counterparties in the ordinary course of our business. Our credit procedures and policies may not be adequate to fully eliminate customer and counterparty credit risk. We cannot predict to what extent our business would be impacted by deteriorating conditions in the economy, including declines in our customers’ and counterparties’ creditworthiness. If we fail to adequately assess the creditworthiness of existing or future customers and counterparties, unanticipated deterioration in their creditworthiness and any resulting increase in nonpayment and/or nonperformance by them could cause us to write-down or write-off doubtful accounts. Such write-downs or write-offs could negatively affect our operating results in the periods in which they occur and, if significant, could have a material adverse effect on our business, results of operations, cash flows and financial condition.
 
We face competition in acquiring new properties, marketing natural gas and oil and securing equipment and trained personnel in the natural gas and oil industry.
 
Our ability to acquire additional drilling locations and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing natural gas and oil and securing equipment and trained personnel. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business.
 
Our operations are subject to operational hazards and unforeseen interruptions for which they may not be adequately insured.
 
There are operational risks associated with drilling for, production, gathering, transporting, storage, processing and treating of natural gas and oil and the fractionation and storage of NGLs, including:

 	•  	Hurricanes, tornadoes, floods, extreme weather conditions and other natural disasters;	
 		
 	•  	Aging infrastructure and mechanical problems;	
 		
 	•  	Damages to pipelines, pipeline blockages or other pipeline interruptions;	
 		
 	•  	Uncontrolled releases of natural gas (including sour gas), oil, NGLs, brine or industrial chemicals;	
 		
 	•  	Operator error;	
 		
 	•  	Pollution and environmental risks;	
 		
 	•  	Fires, explosions and blowouts;	
 		
 	•  	Risks related to truck and rail loading and unloading; and	
 		
 	•  	Terrorist attacks or threatened attacks on our facilities or those of other energy companies.	
 
Any of these risks could result in loss of human life, personal injuries, significant damage to property, environmental pollution, impairment of our operations and substantial losses to us. In accordance with

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customary industry practice, we maintain insurance against some, but not all, of these risks and losses, and only at levels we believe to be appropriate. The location of certain segments of our facilities in or near populated areas, including residential areas, commercial business centers and industrial sites, could increase the level of damages resulting from these risks. In spite of our precautions, an event such as those described above could cause considerable harm to people or property and could have a material adverse effect on our financial condition and results of operations, particularly if the event is not fully covered by insurance. Accidents or other operating risks could further result in loss of service available to our customers.
 
We do not insure against all potential losses and could be seriously harmed by unexpected liabilities or by the inability of our insurers to satisfy our claims.
 
We are not fully insured against all risks inherent to our business, including environmental accidents. We do not maintain insurance in the type and amount to cover all possible risks of loss.
 
We currently maintain excess liability insurance with limits of $610 million per occurrence and in the annual aggregate with a $2 million per occurrence deductible. This insurance covers us, our parent, our subsidiaries and certain of our affiliates for legal and contractual liabilities arising out of bodily injury or property damage, including resulting loss of use to third parties. This excess liability insurance includes coverage for sudden and accidental pollution liability for full limits, with the first $135 million of insurance also providing gradual pollution liability coverage for natural gas and NGL operations.
 
Although we maintain property insurance on property we own, lease or are responsible to insure, the policy may not cover the full replacement cost of all damaged assets or the entire amount of business interruption loss we may experience. In addition, certain perils may be excluded from coverage or sub-limited. We may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. We may elect to self insure a portion of our risks. We do not insure our underground pipelines for physical damage, except at certain locations. All of our insurance is subject to deductibles. If a significant accident or event occurs for which we are not fully insured it could adversely affect our operations and financial condition.
 
In addition, any insurance company that provides coverage to us may experience negative developments that could impair their ability to pay any of our claims. As a result, we could be exposed to greater losses than anticipated and may have to obtain replacement insurance, if available, at a greater cost.
 
Potential changes in accounting standards might cause us to revise our financial results and disclosures in the future, which might change the way analysts measure our business or financial performance.
 
Regulators and legislators continue to take a renewed look at accounting practices, financial and reserves disclosures and companies’ relationships with their independent public accounting firms and reserves consultants. It remains unclear what new laws or regulations will be adopted, and we cannot predict the ultimate impact of that any such new laws or regulations could have. In addition, the Financial Accounting Standards Board or the SEC could enact new accounting standards that might impact how we are required to record revenues, expenses, assets, liabilities and equity. Any significant change in accounting standards or disclosure requirements could have a material adverse effect on our business, results of operations and financial condition.
 
Our investments and projects located outside of the United States expose us to risks related to the laws of other countries, and the taxes, economic conditions, fluctuations in currency rates, political conditions and policies of foreign governments. These risks might delay or reduce our realization of value from our international projects.
 
We currently own and might acquire and/or dispose of material energy-related investments and projects outside the United States, principally Argentina and Colombia. The economic, political and legal conditions and regulatory environment in the countries in which we have interests or in which we might pursue acquisition or investment opportunities present risks that are different from or greater than those in the United States. These risks include delays in construction and interruption of business, as well as risks of war, expropriation, nationalization, renegotiation, trade sanctions or nullification of existing contracts and changes in law or tax policy, including with respect to the prices we realize for the commodities we produce and sell. The uncertainty of the legal environment in certain foreign countries in which we develop or acquire projects or make investments could make it more

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difficult to obtain nonrecourse project financing or other financing on suitable terms, could adversely affect the ability of certain customers to honor their obligations with respect to such projects or investments and could impair our ability to enforce our rights under agreements relating to such projects or investments.
 
Operations and investments in foreign countries also can present currency exchange rate and convertibility, inflation and repatriation risk. In certain situations under which we develop or acquire projects or make investments, economic and monetary conditions and other factors could affect our ability to convert to U.S. dollars our earnings denominated in foreign currencies. In addition, risk from fluctuations in currency exchange rates can arise when our foreign subsidiaries expend or borrow funds in one type of currency, but receive revenue in another. In such cases, an adverse change in exchange rates can reduce our ability to meet expenses, including debt service obligations. We may or may not put contracts in place designed to mitigate our foreign currency exchange risks. We have some exposures that are not hedged and which could result in losses or volatility in our results of operations.
 
Our operating results might fluctuate on a seasonal and quarterly basis.
 
Our revenues can have seasonal characteristics. In many parts of the country, demand for natural gas and other fuels peaks during the winter. As a result, our overall operating results in the future might fluctuate substantially on a seasonal basis. Demand for natural gas and other fuels could vary significantly from our expectations depending on the nature and location of our facilities and the terms of our natural gas transportation arrangements relative to demand created by unusual weather patterns.
 
Our debt agreements impose restrictions on us that may limit our access to credit and adversely affect our ability to operate our business.
 
Our Credit Facility contains various covenants that restrict or limit, among other things, our ability to grant liens to support indebtedness, merge or sell substantially all of our assets, make certain distributions and incur additional debt. In addition, our Credit Facility contains financial covenants and other limitations with which we will need to comply. Similarly, the indenture governing the Notes will restrict our ability to grant liens to secure certain types of indebtedness and merge or sell substantially all of our assets. These covenants could adversely affect our ability to finance our future operations or capital needs or engage in, expand or pursue our business activities and prevent us from engaging in certain transactions that might otherwise be considered beneficial to us. Our ability to comply with these covenants may be affected by events beyond our control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, our current assumptions about future economic conditions turn out to be incorrect or unexpected events occur, our ability to comply with these covenants may be significantly impaired.
 
Our failure to comply with the covenants in our debt agreements could result in events of default. Upon the occurrence of such an event of default, the lenders could elect to declare all amounts outstanding under a particular facility to be immediately due and payable and terminate all commitments, if any, to extend further credit. Certain payment defaults or an acceleration under one debt agreement could cause a cross-default or cross-acceleration of another debt agreement. Such a cross-default or cross-acceleration could have a wider impact on our liquidity than might otherwise arise from a default or acceleration of a single debt instrument. If an event of default occurs, or if other debt agreements cross-default, and the lenders under the affected debt agreements accelerate the maturity of any loans or other debt outstanding to us, we may not have sufficient liquidity to repay amounts outstanding under such debt agreements. For more information regarding our anticipated debt agreements, please read “Description of our Concurrent Financing Transactions.”
 
Our ability to repay, extend or refinance our debt obligations and to obtain future credit will depend primarily on our operating performance, which will be affected by general economic, financial, competitive, legislative, regulatory, business and other factors, many of which are beyond our control. Our ability to refinance our debt obligations or obtain future credit will also depend upon the current conditions in the credit markets and the availability of credit generally. If we are unable to meet our debt service obligations or obtain future credit on favorable terms, if at all, we could be forced to restructure or refinance our indebtedness, seek additional equity capital or sell assets. We may be unable to obtain financing or sell assets on satisfactory terms, or at all.

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Difficult conditions in the global capital markets, the credit markets and the economy in general could negatively affect our business and results of operations
 
Our business may be negatively impacted by adverse economic conditions or future disruptions in global financial markets. Included among these potential negative impacts are reduced energy demand and lower commodity prices, increased difficulty in collecting amounts owed to us by our customers and reduced access to credit markets. Our ability to access the capital markets may be restricted at a time when we would like, or need, to raise financing. If financing is not available when needed, or is available only on unfavorable terms, we may be unable to implement our business plans or otherwise take advantage of business opportunities or respond to competitive pressures.
 
We are subject to risks associated with climate change.
 
There is a growing belief that emissions of greenhouse gases (“GHGs”) may be linked to climate change. Climate change and the costs that may be associated with its impacts and the regulation of GHGs have the potential to affect our business in many ways, including negatively impacting the costs we incur in providing our products and services, the demand for and consumption of our products and services (due to change in both costs and weather patterns), and the economic health of the regions in which we operate, all of which can create financial risks.
 
In addition, legislative and regulatory responses related to GHGs and climate change create the potential for financial risk. The U.S. Congress has previously considered legislation and certain states have for some time been considering various forms of legislation related to GHG emissions. There have also been international efforts seeking legally binding reductions in emissions of GHGs. In addition, increased public awareness and concern may result in more state, regional and/or federal requirements to reduce or mitigate GHG emissions.
 
Numerous states have announced or adopted programs to stabilize and reduce GHGs. In addition, on December 7, 2009, the EPA issued a final determination that six GHGs are a threat to public safety and welfare. Also in 2009, the EPA finalized a GHG emission standard for mobile sources. On September 22, 2009, the EPA finalized a GHG reporting rule that requires large sources of GHG emissions to monitor, maintain records on, and annually report their GHG emissions. On November 8, 2010, the EPA also issued GHG monitoring and reporting regulations that went into effect on December 30, 2010, specifically for oil and natural gas facilities, including onshore and offshore oil and natural gas production facilities that emit 25,000 metric tons or more of carbon dioxide equivalent per year. The rule requires reporting of GHG emissions by regulated facilities to the EPA by March 2012 for emissions during 2011 and annually thereafter. We are required to report our GHG emissions to the EPA by March 2012 under this rule. The EPA also issued a final rule that makes certain stationary sources and newer modification projects subject to permitting requirements for GHG emissions, beginning in 2011, under the CAA. Several of the EPA’s GHG rules are being challenged in pending court proceedings, and depending on the outcome of such proceedings, such rules may be modified or rescinded or the EPA could develop new rules.
 
The recent actions of the EPA and the passage of any federal or state climate change laws or regulations could result in increased costs to (i) operate and maintain our facilities, (ii) install new emission controls on our facilities and (iii) administer and manage any GHG emissions program. If we are unable to recover or pass through a significant level of our costs related to complying with climate change regulatory requirements imposed on us, it could have a material adverse effect on our results of operations and financial condition. To the extent financial markets view climate change and GHG emissions as a financial risk, this could negatively impact our cost of and access to capital. Legislation or regulations that may be adopted to address climate change could also affect the markets for our products by making our products more or less desirable than competing sources of energy.
 
Our operations are subject to governmental laws and regulations relating to the protection of the environment, which may expose us to significant costs and liabilities that could exceed current expectations.
 
Substantial costs, liabilities, delays and other significant issues could arise from environmental laws and regulations inherent in drilling and well completion, gathering, transportation, and storage, and we may incur

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substantial costs and liabilities in the performance of these types of operations. Our operations are subject to extensive federal, state and local laws and regulations governing environmental protection, the discharge of materials into the environment and the security of chemical and industrial facilities. These laws include:

 	•  	Clean Air Act (“CAA”) and analogous state laws, which impose obligations related to air emissions;	
 		
 	•  	Clean Water Act (“CWA”), and analogous state laws, which regulate discharge of wastewaters and storm water from some our facilities into state and federal waters, including wetlands;	
 		
 	•  	Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), and analogous state laws, which regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or locations to which we have sent wastes for disposal;	
 		
 	•  	Resource Conservation and Recovery Act (“RCRA”), and analogous state laws, which impose requirements for the handling and discharge of solid and hazardous waste from our facilities;	
 		
 	•  	National Environmental Policy Act (“NEPA”), which requires federal agencies to study likely environment impacts of a proposed federal action before it is approved, such as drilling on federal lands;	
 		
 	•  	Safe Drinking Water Act (“SDWA”), which restricts the disposal, treatment or release of water produced or used during oil and gas development;	
 		
 	•  	Endangered Species Act (“ESA”), and analogous state laws, which seek to ensure that activities do not jeopardize endangered or threatened animals, fish and plant species, nor destroy or modify the critical habitat of such species; and	
 		
 	•  	Oil Pollution Act (“OPA”) of 1990, which requires oil storage facilities and vessels to submit to the federal government plans detailing how they will respond to large discharges, requires updates to technology and equipment, regulation of above ground storage tanks and sets forth liability for spills by responsible parties.	
 
Various governmental authorities, including the U.S. Environmental Protection Agency (“EPA”), the U.S. Department of the Interior, the Bureau of Indian Affairs and analogous state agencies and tribal governments, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly actions. Failure to comply with these laws, regulations and permits may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, the imposition of stricter conditions on or revocation of permits, the issuance of injunctions limiting or preventing some or all of our operations, delays in granting permits and cancellation of leases.
 
There is inherent risk of the incurrence of environmental costs and liabilities in our business, some of which may be material, due to the handling of our products as they are gathered, transported, processed and stored, air emissions related to our operations, historical industry operations, and water and waste disposal practices. Joint and several, strict liability may be incurred without regard to fault under certain environmental laws and regulations, including CERCLA, RCRA and analogous state laws, for the remediation of contaminated areas and in connection with spills or releases of natural gas, oil and wastes on, under, or from our properties and facilities. Private parties may have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage arising from our operations. Some sites at which we operate are located near current or former third-party oil and natural gas operations or facilities, and there is a risk that contamination has migrated from those sites to ours. In addition, increasingly strict laws, regulations and enforcement policies could materially increase our compliance costs and the cost of any remediation that may become necessary. Our insurance may not cover all environmental risks and costs or may not provide sufficient coverage if an environmental claim is made against us.
 
In March 2010, the EPA announced its National Enforcement Initiatives for 2011 to 2013, which includes the addition of “Energy Extraction Activities” to its enforcement priorities list. To address its concerns regarding the pollution risks raised by new techniques for oil and gas extraction and coal mining, the EPA is

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developing an initiative to ensure that energy extraction activities are complying with federal environmental requirements. This initiative could involve a large scale investigation of our facilities and processes, and could lead to potential enforcement actions, penalties or injunctive relief against us.
 
Our business may be adversely affected by increased costs due to stricter pollution control equipment requirements or liabilities resulting from non-compliance with required operating or other regulatory permits. Also, we might not be able to obtain or maintain from time to time all required environmental regulatory approvals for our operations. If there is a delay in obtaining any required environmental regulatory approvals, or if we fail to obtain and comply with them, the operation or construction of our facilities could be prevented or become subject to additional costs.
 
We are generally responsible for all liabilities associated with the environmental condition of our facilities and assets, whether acquired or developed, regardless of when the liabilities arose and whether they are known or unknown. In connection with certain acquisitions and divestitures, we could acquire, or be required to provide indemnification against, environmental liabilities that could expose us to material losses, which may not be covered by insurance. In addition, the steps we could be required to take to bring certain facilities into compliance could be prohibitively expensive, and we might be required to shut down, divest or alter the operation of those facilities, which might cause us to incur losses.
 
We make assumptions and develop expectations about possible expenditures related to environmental conditions based on current laws and regulations and current interpretations of those laws and regulations. If the interpretation of laws or regulations, or the laws and regulations themselves, change, our assumptions may change, and any new capital costs may be incurred to comply with such changes. In addition, new environmental laws and regulations might adversely affect our products and activities, including drilling, processing, storage and transportation, as well as waste management and air emissions. For instance, federal and state agencies could impose additional safety requirements, any of which could affect our profitability.
 
Our exploration and production operations outside the United States are subject to various types of regulations similar to those described above imposed by the governments of the countries in which we operate, and may affect our operations and costs within those countries.
 
Legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.
 
Legislation has been introduced in the United States Congress called the Fracturing Responsibility and Awareness of Chemicals Act (the “FRAC Act”) to amend the SDWA to eliminate an existing exemption for hydraulic fracturing activities from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as require disclosure of the chemical constituents of the fluids used in the fracturing process. Hydraulic fracturing involves the injection of water, sand and additives under pressure into rock formations in order to stimulate natural gas production. We find that the use of hydraulic fracturing is necessary to produce commercial quantities of natural gas and oil from many reservoirs. If adopted, this legislation could establish an additional level of regulation and permitting at the federal level, and could make it easier for third parties opposed to the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect the environment, including groundwater, soil or surface water. At this time, it is not clear what action, if any, the United States Congress will take on the FRAC Act. Scrutiny of hydraulic fracturing activities continues in other ways, with the EPA having commenced a multi-year study of the potential environmental impacts of hydraulic fracturing, the initial results of which are anticipated to be available by late 2012. In addition to the EPA study, the Shale Gas Subcommittee of the Secretary of Energy Advisory Board issued a report on hydraulic fracturing in August 2011, which includes recommendations to address concerns related to hydraulic fracturing and shale gas production, including but not limited to conducting additional field studies on possible methane leakage from shale gas wells to water reservoirs and adopting new rules and enforcement practices to protect drinking and surface waters. The U.S. Government Accountability Office is also examining the environmental impacts of produced water and the White House Counsel for Environmental Quality has been petitioned by environmental groups to develop a programmatic environmental impact statement under NEPA for hydraulic fracturing. Several states have also adopted or considered legislation requiring the disclosure of fracturing fluids and other restrictions on hydraulic fracturing, including states in which we operate (e.g., Wyoming, Pennsylvania, Texas, Colorado, North Dakota and New Mexico). The U.S. Department

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of the Interior is also considering disclosure requirements or other mandates for hydraulic fracturing on federal land, which, if adopted, would affect our operations on federal lands. If new federal or state laws or regulations that significantly restrict hydraulic fracturing are adopted, such legal requirements could result in delays, eliminate certain drilling and injection activities, make it more difficult or costly for us to perform fracturing and increase our costs of compliance and doing business as well as delay or prevent the development of unconventional gas resources from shale formations which are not commercial without the use of hydraulic fracturing.
 
Our ability to produce gas could be impaired if we are unable to acquire adequate supplies of water for our drilling and completion operations or are unable to dispose of the water we use at a reasonable cost and within applicable environmental rules.
 
Our inability to locate sufficient amounts of water, or dispose of or recycle water used in our exploration and production operations, could adversely impact our operations, particularly with respect to our Marcellus Shale, San Juan Basin, Bakken Shale and Piceance Basin operations. Moreover, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of natural gas. The CWA imposes restrictions and strict controls regarding the discharge of produced waters and other natural gas and oil waste into navigable waters. Permits must be obtained to discharge pollutants to waters and to conduct construction activities in waters and wetlands. The CWA and similar state laws provide for civil, criminal and administrative penalties for any unauthorized discharges of pollutants and unauthorized discharges of reportable quantities of oil and other hazardous substances. Many state discharge regulations and the Federal National Pollutant Discharge Elimination System general permits issued by the EPA prohibit the discharge of produced water and sand, drilling fluids, drill cuttings and certain other substances related to the natural gas and oil industry into coastal waters. The EPA has also adopted regulations requiring certain natural gas and oil exploration and production facilities to obtain permits for storm water discharges. Compliance with environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells may increase our operating costs and cause delays, interruptions or termination of our operations, the extent of which cannot be predicted.
 
Legal and regulatory proceedings and investigations relating to the energy industry, and the complex government regulations to which our businesses are subject, have adversely affected our business and may continue to do so. The operation of our businesses might also be adversely affected by changes in regulations or in their interpretation or implementation, or the introduction of new laws, regulations or permitting requirements applicable to our businesses or our customers.
 
Public and regulatory scrutiny of the energy industry has resulted in increased regulations being either proposed or implemented. Adverse effects may continue as a result of the uncertainty of ongoing inquiries, investigations and court proceedings, or additional inquiries and proceedings by federal or state regulatory agencies or private plaintiffs. In addition, we cannot predict the outcome of any of these inquiries or whether these inquiries will lead to additional legal proceedings against us, civil or criminal fines or penalties, or other regulatory action, including legislation or increased permitting requirements. Current legal proceedings or other matters against us, including environmental matters, suits, regulatory appeals, challenges to our permits by citizen groups and similar matters, might result in adverse decisions against us. The result of such adverse decisions, either individually or in the aggregate, could be material and may not be covered fully or at all by insurance.
 
In addition, existing regulations might be revised or reinterpreted, new laws, regulations and permitting requirements might be adopted or become applicable to us, our facilities, our customers, our vendors or our service providers, and future changes in laws and regulations could have a material adverse effect on our financial condition, results of operations and cash flows. For example, several ruptures on third party pipelines have occurred recently. In response, various legislative and regulatory reforms associated with pipeline safety and integrity have been proposed, including new regulations covering gathering pipelines that have not previously been subject to regulation. Such reforms, if adopted, could significantly increase our costs.

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Certain of our properties, including our operations in the Bakken Shale, are located on Native American tribal lands and are subject to various federal and tribal approvals and regulations, which may increase our costs and delay or prevent our efforts to conduct planned operations.
 
Various federal agencies within the U.S. Department of the Interior, particularly the Bureau of Indian Affairs, Bureau of Land Management (“BLM”) and the Office of Natural Resources Revenue, along with each Native American tribe, promulgate and enforce regulations pertaining to gas and oil operations on Native American tribal lands. These regulations and approval requirements relate to such matters as lease provisions, drilling and production requirements, environmental standards and royalty considerations. In addition, each Native American tribe is a sovereign nation having the right to enforce laws and regulations and to grant approvals independent from federal, state and local statutes and regulations. These tribal laws and regulations include various taxes, fees, requirements to employ Native American tribal members and other conditions that apply to lessees, operators and contractors conducting operations on Native American tribal lands. Lessees and operators conducting operations on tribal lands are generally subject to the Native American tribal court system. In addition, if our relationships with any of the relevant Native American tribes were to deteriorate, we could face significant risks to our ability to continue the projected development of our leases on Native American tribal lands. One or more of these factors may increase our costs of doing business on Native American tribal lands and impact the viability of, or prevent or delay our ability to conduct, our natural gas or oil development and production operations on such lands.
 
Tax laws and regulations may change over time, including the elimination of federal income tax deductions currently available with respect to oil and gas exploration and development.
 
Tax laws and regulations are highly complex and subject to interpretation, and the tax laws, treaties and regulations to which we are subject may change over time. Our tax filings are based upon our interpretation of the tax laws in effect in various jurisdictions at the time that the filings were made. If these laws, treaties or regulations change, or if the taxing authorities do not agree with our interpretation of the effects of such laws, treaties and regulations, it could have a material adverse effect on us.
 
Among the changes contained in President Obama’s budget proposal for fiscal year 2012, released by the White House on February 14, 2011, is the elimination of certain U.S. federal income tax provisions currently available to oil and gas exploration and production companies. Such changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties; (ii) the elimination of current expensing of intangible drilling and development costs; (iii) the elimination of the deduction for certain U.S. production activities; and (iv) an extension of the amortization period for certain geological and geophysical expenditures. Members of Congress have introduced legislation with similar provisions in the current session. It is unclear, however, whether any such changes will be enacted or how soon such changes could be effective.
 
The passage of any legislation as a result of the budget proposal or any other similar change in U.S. federal income tax law could eliminate certain tax deductions that are currently available with respect to oil and gas exploration and development. The elimination of such federal tax deductions, as well as any changes to or the imposition of new state or local taxes (including the imposition of, or increases in production, severance, or similar taxes) could negatively affect our financial condition and results of operations.
 
Our acquisition attempts may not be successful or may result in completed acquisitions that do not perform as anticipated.
 
We have made and may continue to make acquisitions of businesses and properties. However, suitable acquisition candidates may not continue to be available on terms and conditions we find acceptable. The following are some of the risks associated with acquisitions, including any completed or future acquisitions:

 	•  	some of the acquired businesses or properties may not produce revenues, reserves, earnings or cash flow at anticipated levels or could have environmental, permitting or other problems for which contractual protections prove inadequate;	
 		
 	•  	we may assume liabilities that were not disclosed to us or that exceed our estimates;	

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 	•  	properties we acquire may be subject to burdens on title that we were not aware of at the time of acquisition or that interfere with our ability to hold the property for production;	
 		
 	•  	we may be unable to integrate acquired businesses successfully and realize anticipated economic, operational and other benefits in a timely manner, which could result in substantial costs and delays or other operational, technical or financial problems;	
 		
 	•  	acquisitions could disrupt our ongoing business, distract management, divert resources and make it difficult to maintain our current business standards, controls and procedures; and	
 		
 	•  	we may issue additional equity or debt securities related to future acquisitions.	
 
Substantial acquisitions or other transactions could require significant external capital and could change our risk and property profile.
 
In order to finance acquisitions of additional producing or undeveloped properties, we may need to alter or increase our capitalization substantially through the issuance of debt or equity securities, the sale of production payments or other means. These changes in capitalization may significantly affect our risk profile. Additionally, significant acquisitions or other transactions can change the character of our operations and business. The character of the new properties may be substantially different in operating or geological characteristics or geographic location than our existing properties. Furthermore, we may not be able to obtain external funding for future acquisitions or other transactions or to obtain external funding on terms acceptable to us.
 
Failure of our service providers or disruptions to our outsourcing relationships might negatively impact our ability to conduct our business.
 
We rely on Williams for certain services necessary for us to be able to conduct our business. Williams may outsource some or all of these services to third parties, and a failure of all or part of Williams’ relationships with its outsourcing providers could lead to delays in or interruptions of these services. Our reliance on Williams and others as service providers and on Williams’ outsourcing relationships, and our limited ability to control certain costs, could have a material adverse effect on our business, results of operations and financial condition.
 
Some studies indicate a high failure rate of outsourcing relationships. A deterioration in the timeliness or quality of the services performed by the outsourcing providers or a failure of all or part of these relationships could lead to loss of institutional knowledge and interruption of services necessary for us to be able to conduct our business. The expiration of such agreements or the transition of services between providers could lead to similar losses of institutional knowledge or disruptions.
 
Certain of our accounting, information technology, application development and help desk services are currently provided by Williams’ outsourcing provider from service centers outside of the United States. The economic and political conditions in certain countries from which Williams’ outsourcing providers may provide services to us present similar risks of business operations located outside of the United States, including risks of interruption of business, war, expropriation, nationalization, renegotiation, trade sanctions or nullification of existing contracts and changes in law or tax policy, that are greater than in the United States.
 
Our assets and operations can be adversely affected by weather and other natural phenomena.
 
Our assets and operations can be adversely affected by hurricanes, floods, earthquakes, tornadoes and other natural phenomena and weather conditions, including extreme temperatures. Insurance may be inadequate, and in some instances, we have been unable to obtain insurance on commercially reasonable terms, or insurance has not been available at all. A significant disruption in operations or a significant liability for which we were not fully insured could have a material adverse effect on our business, results of operations and financial condition.
 
Our customers’ energy needs vary with weather conditions. To the extent weather conditions are affected by climate change or demand is impacted by regulations associated with climate change, customers’ energy use could increase or decrease depending on the duration and magnitude of the changes, leading either to increased investment or decreased revenues.

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Acts of terrorism could have a material adverse effect on our financial condition, results of operations and cash flows.
 
Our assets and the assets of our customers and others may be targets of terrorist activities that could disrupt our business or cause significant harm to our operations, such as full or partial disruption to the ability to produce, process, transport or distribute natural gas, oil, or NGLs. Acts of terrorism as well as events occurring in response to or in connection with acts of terrorism could cause environmental repercussions that could result in a significant decrease in revenues or significant reconstruction or remediation costs.
 
We have identified two material weaknesses in our internal controls over financial reporting. Our failure to achieve and maintain effective internal controls could have a material adverse effect on our business in the future, on the price of our Class A common stock and our access to the capital markets.
 
Although we are not currently subject to the requirements of Section 404 of the Sarbanes-Oxley Act of 2002 (“Sarbanes-Oxley”), during the preparation of our financial statements for each of the three years in the period ended December 31, 2010 and for the three months ended March 31, 2011, two material weaknesses (as defined under Public Company Accounting Oversight Board Standard No. 5) in our internal controls were identified: one relating to the timing of the recognition of certain compression deficiency obligations under compression service agreements, and one reflecting the aggregation of two significant deficiencies relating to aspects of depreciation, depletion and amortization of property, plant and equipment. As a result of these material weaknesses, adjustments to the estimated carrying value of property, plant and equipment aggregating approximately $20 million on a pre-tax basis have been reflected in our financial statements as of December 31, 2010 and adjustments to gathering, processing and transportation expense aggregating approximately $14 million on a pre-tax basis have been reflected in our income statements for the years ended December 31, 2008, 2009 and 2010. We have taken steps to remediate the internal controls related to the material weaknesses, although we cannot provide assurance that these steps will prove to be effective. See Note 2 of Notes to Combined Financial Statements.
 
We cannot be certain that future significant deficiencies or material weaknesses will not develop or be identified. As of December 31, 2012, we will be required to assess the effectiveness of our internal control over financial reporting under Sarbanes-Oxley, and we will be required to have our independent registered public accounting firm audit the operating effectiveness of our internal control over financial reporting. If we or our independent registered public accounting firm were to conclude that our internal control over financial reporting was not effective, investors could lose confidence in our reported financial information, the price of our Class A common stock could decline and access to the capital markets or other sources of financing could be limited.
 
Risks Related to Our Relationship with Williams
 
We may not realize the potential benefits from our separation from Williams.
 
We may not realize the benefits that we anticipate from our separation from Williams. These benefits include the following:

 	•  	allowing our management to focus its efforts on our business and strategic priorities;	
 		
 	•  	enhancing our market recognition with investors;	
 		
 	•  	providing us with direct access to the debt and equity capital markets;	
 		
 	•  	improving our ability to pursue acquisitions through the use of shares of our common stock as consideration; and	
 		
 	•  	enabling us to allocate our capital more efficiently.	
 
We may not achieve the anticipated benefits from our separation for a variety of reasons. For example, the process of separating our business from Williams and operating as an independent public company may distract our management from focusing on our business and strategic priorities. In addition, although we will have direct access to the debt and equity capital markets following the separation, we may not be able to issue debt or equity on terms acceptable to us or at all. The availability of shares of our common stock for use as consideration for acquisitions also will not ensure that we will be able to successfully pursue acquisitions or

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that the acquisitions will be successful. Moreover, even with equity compensation tied to our business we may not be able to attract and retain employees as desired. We also may not fully realize the anticipated benefits from our separation if any of the matters identified as risks in this “Risk Factors” section were to occur. If we do not realize the anticipated benefits from our separation for any reason, our business may be materially adversely affected.
 
Our historical and pro forma combined financial information may not be representative of the results we would have achieved as a stand-alone public company and may not be a reliable indicator of our future results.
 
The historical and pro forma combined financial information that we have included in this prospectus has been derived from Williams’ accounting records and may not necessarily reflect what our financial position, results of operations or cash flows would have been had we been an independent, stand-alone entity during the periods presented or those that we will achieve in the future. Williams did not account for us, and we were not operated, as a separate, stand-alone company for the historical periods presented. The costs and expenses reflected in our historical financial information include an allocation for certain corporate functions historically provided by Williams, including executive oversight, cash management and treasury administration, financing and accounting, tax, internal audit, investor relations, payroll and human resources administration, information technology, legal, regulatory and government affairs, insurance and claims administration, records management, real estate and facilities management, sourcing and procurement, mail, print and other office services, and other services, that may be different from the comparable expenses that we would have incurred had we operated as a stand-alone company. These allocations were based on what we and Williams considered to be reasonable reflections of the historical utilization levels of these services required in support of our business. We have not adjusted our historical or pro forma combined financial information to reflect changes that will occur in our cost structure and operations as a result of our transition to becoming a stand-alone public company, including changes in our employee base, potential increased costs associated with reduced economies of scale and increased costs associated with the SEC reporting and the NYSE requirements. Therefore, our historical and pro forma combined financial information may not necessarily be indicative of what our financial position, results of operations or cash flows will be in the future. For additional information, see “Selected Historical Combined Financial Data” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and our financial statements and related notes included elsewhere in this prospectus.
 
Following this offering, we will continue to depend on Williams to provide us with certain services for our business; the services that Williams will provide to us following the separation may not be sufficient to meet our needs, and we may have difficulty finding replacement services or be required to pay increased costs to replace these services after our agreements with Williams expire.
 
Certain administrative services required by us for the operation of our business are currently provided by Williams and its subsidiaries, including services related to cash management and treasury administration, finance and accounting, tax, internal audit, investor relations, payroll and human resources administration, information technology, legal, regulatory and government affairs, insurance and claims administration, records management, real estate and facilities management, sourcing and procurement, mail, print and other office services. Prior to the completion of this offering, we will enter into agreements with Williams related to the separation of our business operations from Williams, including an administrative services agreement and a transition services agreement. The services provided under the administrative services agreement will commence on the date this offering is completed and terminate upon the earlier of (i) the date immediately prior to the date Williams distributes all of our shares of common stock that it owns to its stockholders (which we refer to as the distribution date) or (ii) sixty days’ notice by Williams if it determines that the provision of such services involves certain conflicts of interest between Williams and us or would cause Williams to violate applicable law. The services provided under the transition services agreement will commence on the distribution date and terminate upon the earlier of (i) one year after the distribution date or (ii) sixty days’ notice by either party. In addition, Williams may immediately terminate any of the services it provides to us under the transition services agreement if it determines that the provision of such services involves certain conflicts of interest between Williams and us or would cause Williams to violate applicable law. We believe it

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is necessary for Williams to provide services for us under the administrative services agreement and the transition services agreement to facilitate the efficient operation of our business as we transition to becoming a stand alone public company. We will, as a result, initially depend on Williams for services following this offering. While these services are being provided to us by Williams, our operational flexibility to modify or implement changes with respect to such services or the amounts we pay for them will be limited. After the expiration or termination of these agreements, we may not be able to replace these services or enter into appropriate third-party agreements on terms and conditions, including cost, comparable to those that we will receive from Williams under our agreements with Williams. Although we intend to replace portions of the services currently provided by Williams, we may encounter difficulties replacing certain services or be unable to negotiate pricing or other terms as favorable as those we currently have in effect. See “Arrangements Between Williams and Our Company—Administrative Services and Transition Services Agreements.”
 
Your investment in our Class A common stock may be adversely affected if Williams does not spin-off the common stock owned by Williams.
 
Williams has advised us that, following the completion of this offering, it intends to spin-off all of the shares of our common stock that it owns to its stockholders. Williams has indicated that it intends to complete the spin-off in 2012 and to convert its Class B common shares to Class A common shares immediately prior to such spin-off, assuming such conversion would not jeopardize the ability to consummate the tax-free spin-off or the tax-free treatment of any related restructuring transaction undertaken by Williams. Williams may decide not to complete this offering or the spin-off if, at any time, Williams’ board of directors determines, in its sole discretion, that this offering or the spin-off is not in the best interests of Williams or its stockholders. Unless and until such a spin-off occurs, we will face the risks discussed in this prospectus relating to our continuing relationship with Williams, including its control of us and potential conflicts of interest between Williams and us. In addition, if a spin-off does not occur, the liquidity of the market for our Class A common stock may be constrained for as long as Williams, or a successor controlling shareholder, continues to hold a significant position in our common stock. A lack of liquidity in the market for our Class A common stock may adversely affect our share price.
 
Our share price may decline because of Williams’ ability to sell shares of our common stock.
 
Sales of substantial amounts of our common stock after this offering, or the possibility of those sales, could adversely affect the market price of our Class A common stock and impede our ability to raise capital through the issuance of equity securities. See “Shares Eligible for Future Sale” for a discussion of possible future sales of our common stock.
 
After the completion of this offering, Williams will own 100% of our outstanding Class B common stock, giving Williams     % of the shares of our outstanding common stock, or     % if the underwriters exercise their option to purchase additional Class A common shares in full. Williams has advised us that it intends to complete the distribution of all of our common stock owned by Williams to its stockholders by the end of 2012. Common stock so distributed will be freely tradable by such Williams stockholders who are not deemed to be our affiliates or are otherwise subject to lock-up agreements.
 
Williams has no contractual obligation to retain its shares of our common stock, except for a limited period described under “Underwriting” during which it will not sell any of its shares of our common stock without the consent of Barclays Capital Inc. until 180 days after the date of this prospectus, subject to extension in certain circumstances. Subject to applicable U.S. federal and state securities laws, after the expiration of this 180-day waiting period (or before, with consent of the underwriters to this offering), Williams may sell any and all of the shares of our common stock that it beneficially owns or distribute any or all of these shares of our common stock to its stockholders. This 180-day waiting period does not apply to the distribution by Williams of its remaining ownership interest in us to its common stockholders. The registration rights agreement described elsewhere in this prospectus grants Williams the right to require us to register the shares of our common stock it holds in specified circumstances. In addition, after the expiration of this 180-day waiting period, we could issue and sell additional shares of our Class A common stock. Any sale by Williams or us of our common stock in the public market, or the perception that sales could occur (for

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example, as a result of the distribution), could adversely affect prevailing market prices for the shares of our common stock.
 
As long as we are controlled by Williams, your ability to influence the outcome of matters requiring stockholder approval will be limited.
 
After the completion of this offering, Williams will not own any shares of our Class A common stock and will own 100% of our outstanding Class B common stock, giving Williams     % of the shares of our outstanding common stock and     % of the combined voting power of our outstanding common stock, or     % and     %, respectively, if the underwriters exercise their option to purchase additional Class A common shares in full. As long as Williams has voting control of our company, Williams will have the ability to take many stockholder actions, including the election or removal of directors, irrespective of the vote of, and without prior notice to, any other stockholder. As a result, Williams will have the ability to influence or control all matters affecting us, including:

 	•  	the composition of our board of directors and, through our board of directors, decision-making with respect to our business direction and policies, including the appointment and removal of our officers;	
 		
 	•  	any determinations with respect to acquisitions of businesses, mergers, or other business combinations;	
 		
 	•  	our acquisition or disposition of assets;	
 		
 	•  	our capital structure;	
 		
 	•  	changes to the agreements relating to our separation from Williams;	
 		
 	•  	our payment or non-payment of dividends on our common stock; and	
 		
 	•  	determinations with respect to our tax returns.	
 
Williams’ interests may not be the same as, or may conflict with, the interests of our other stockholders. As a result, actions that Williams takes with respect to us, as our controlling stockholder, may not be favorable to us. In addition, this voting control may discourage transactions involving a change of control of our company, including transactions in which you, as a holder of our Class A common stock, might otherwise receive a premium for your shares over the then-current market price. Furthermore, Williams is not prohibited from selling a controlling interest in our company to a third party without your approval or without providing for a purchase of your shares. At any time following the completion of this offering and the expiration or waiver of the applicable lock-up period described under “Underwriting,” Williams has the right to spin-off shares of our common stock that it owns to its stockholders. In addition, after the expiration or waiver of the applicable lock-up period described under “Underwriting,” Williams has the right to sell a controlling interest in us to a third party, without your approval and without providing for a purchase of your shares. There is no assurance that Williams will effect the spin-off, and if Williams elects not to effect the spin-off, it could remain our stockholder for an extended or indefinite period of time. In addition, Williams may decide not to complete the spin-off if, at any time, Williams’ board of directors determines, in its sole discretion, that the spin-off is not in the best interests of Williams or its stockholders. As a result, the spin-off may not occur by 2012 or at all. See “Shares Eligible For Future Sale.”
 
We may have potential business conflicts of interest with Williams regarding our past and ongoing relationships, and because of Williams’ controlling ownership in us, the resolution of these conflicts may not be favorable to us.
 
Conflicts of interest may arise between Williams and us in a number of areas relating to our past and ongoing relationships, including:

 	•  	labor, tax, employee benefit, indemnification and other matters arising under agreements with Williams;	
 		
 	•  	employee recruiting and retention;	
 		
 	•  	sales or distributions by Williams of all or any portion of its ownership interest in us, which could be to one of our competitors; and	
 		
 	•  	business opportunities that may be attractive to both Williams and us.	

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We may not be able to resolve any potential conflicts, and, even if we do so, the resolution may be less favorable to us than if we were dealing with an unaffiliated party.
 
Finally, in connection with this offering, we will enter into several agreements with Williams. These agreements will be made in the context of a parent-subsidiary relationship and will be entered into in the overall context of our separation from Williams. The terms of these agreements may be more or less favorable to us than if they had been negotiated with unaffiliated third parties. While we are controlled by Williams, Williams may seek to cause us to amend these agreements on terms that may be less favorable to us than the original terms of the agreement.
 
During the terms of the administrative services agreement and the transition services agreement, and for one year thereafter, neither we nor Williams will be permitted to solicit each other’s employees for employment without the other’s consent.
 
Pursuant to the terms of our amended and restated certificate of incorporation, Williams is not required to offer corporate opportunities to us, and certain of our directors and officers are permitted to offer certain corporate opportunities to Williams before us.
 
Our amended and restated certificate of incorporation provides that, until both (1) Williams and its subsidiaries no longer beneficially own 50% or more of the voting power of all then outstanding shares of our capital stock generally entitled to vote in the election of our directors and (2) no person who is a director or officer of Williams or of a subsidiary of Williams is also a director or officer of ours:

 	•  	Williams is free to compete with us in any activity or line of business;	
 		
 	•  	we do not have any interest or expectancy in any business opportunity, transaction, or other matter in which Williams engages or seeks to engage merely because we engage in the same or similar lines of business;	
 		
 	•  	to the fullest extent permitted by law, Williams will have no duty to communicate its knowledge of, or offer, any potential business opportunity, transaction, or other matter to us, and Williams is free to pursue or acquire such business opportunity, transaction, or other matter for itself or direct the business opportunity, transaction, or other matter to its affiliates; and	
 		
 	•  	if any director or officer of Williams who is also one of our officers or directors becomes aware of a potential business opportunity, transaction, or other matter (other than one expressly offered to that director or officer in writing solely in his or her capacity as our director or officer), that director or officer will have no duty to communicate or offer that business opportunity to us, and will be permitted to communicate or offer that business opportunity to Williams (or its affiliates) and that director or officer will not, to the fullest extent permitted by law, be deemed to have (1) breached or acted in a manner inconsistent with or opposed to his or her fiduciary or other duties to us regarding the business opportunity or (2) acted in bad faith or in a manner inconsistent with the best interests of our company or our stockholders.	
 
At the completion of this offering, our board of directors will include persons who are also directors and/or officers of Williams. In addition, after the completion of the spin-off of our stock to Williams’ stockholders, we expect that our board of directors will continue to include persons who are also directors and/or officers of Williams. As a result, Williams may gain the benefit of corporate opportunities that are presented to these directors.
 
Our agreements with Williams require us to assume the past, present, and future liabilities related to our business and may be less favorable to us than if they had been negotiated with unaffiliated third parties.
 
We negotiated all of our agreements with Williams as a wholly-owned subsidiary of Williams and will enter into these agreements prior to the completion of this offering. If these agreements had been negotiated with unaffiliated third parties, they might have been more favorable to us. Pursuant to the separation and distribution agreement, we have assumed all past, present and future liabilities (other than tax liabilities which will be governed by the tax sharing agreement as described herein; see “Arrangements Between Williams and Our Company—Tax Sharing Agreement”) related to our business, and we will agree to indemnify Williams for these liabilities, among other matters. Such liabilities include unknown liabilities that could be significant.

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The allocation of assets and liabilities between Williams and us may not reflect the allocation that would have been reached between two unaffiliated parties. See “Arrangements Between Williams and Our Company” for a description of these obligations and the allocation of liabilities between Williams and us.
 
Our agreements with Williams may limit our ability to obtain additional financing or make acquisitions.
 
We may engage, or desire to engage, in future financings or acquisitions. However, because our agreements with Williams are designed to preserve the tax-free status of the spin-off and any related restructuring transaction, we will agree to certain restrictions in those agreements that may severely limit our ability to effect future financings or acquisitions. For example, for the spin-off of our stock to Williams’ stockholders to be tax-free to Williams and its stockholders, among other things, Williams must own at least 80% of the voting power of all then outstanding shares of our capital stock entitled to vote generally in the election of directors (and at least 80% of the then outstanding shares of any class of non-voting stock) at the time of the spin-off. In addition, after the spin-off, our stock may not undergo a 50% or greater change of ownership (measured by vote or value) in transactions considered related to the spin-off. Therefore, the tax sharing agreement and the separation and distribution agreement restrict our ability to issue or sell additional common stock or other securities (including securities convertible into our common stock) prior to the spin-off to the extent that such issuances or sales would reduce Williams’ ownership below certain threshold levels, and for a period after the spin-off to the extent that such issuances would cause us to undergo significant ownership changes.
 
In addition, we will agree in the separation and distribution agreement that we will not (without Williams’ prior written consent) take any of the following actions prior to the spin-off:

 	•  	acquire any businesses or assets with an aggregate value of more than $50 million for all such acquisitions;	
 		
 	•  	dispose of any assets with an aggregate value of more than $50 million for all such dispositions; and	
 		
 	•  	acquire any equity or debt securities of any other person with an aggregate value of more than $50 million for all such acquisitions.	
 
The separation and distribution agreement will also provide that for so long as Williams owns 50% or more of the voting power of all then outstanding shares of our capital stock entitled to vote generally in the election of directors, we will not (without the prior written consent of Williams) take any actions that could reasonably result in Williams being in breach or in default under any contract or agreement. Also, for so long as Williams is required to consolidate our results of operations and financial position, we may not incur any additional indebtedness (other than under our Credit Facility and the issuance of the Notes) without the prior written consent of Williams.
 
Our tax sharing agreement with Williams may limit our ability to take certain actions and may require us to indemnify Williams for significant tax liabilities.
 
Under the tax sharing agreement, we will agree to take reasonable action or reasonably refrain from taking action to ensure that the spin-off of our stock to Williams’ stockholders and any related restructuring transaction qualify for tax-free status under section 355 and section 368(a)(1)(D) of the Internal Revenue Code of 1986, as amended (the “Code”) (unless Williams receives a private letter ruling from the Internal Revenue Service (“IRS”) or the IRS issues other guidance that can be relied on conclusively to the effect that a contemplated matter or transaction would not jeopardize such tax-free status of the spin-off and related restructuring transaction). We will also make various other covenants in the tax sharing agreement intended to ensure the tax-free status of the spin-off and any related restructuring transaction. These covenants restrict our ability to sell assets outside the ordinary course of business, to issue or sell additional common stock or other securities (including securities convertible into our common stock), or to enter into certain other corporate transactions. For example, prior to the spin-off, we may not enter into any transactions that would reduce Williams’ ownership to less than 80% of the voting power of all then outstanding shares of our capital stock entitled to vote generally in the election of directors or 80% of the then outstanding shares of any class of non-voting stock. Similarly, after the spin-off, we may not enter into any transaction that would cause us to undergo either a 50% or greater change in the ownership of our voting stock or a 50% or greater change in the ownership (measured by value) of all classes of our stock (in either case, taking into account shares issued in this offering) in transactions considered related to the spin-off.

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See “Arrangements Between Williams and Our Company—Tax Sharing Agreement” for a discussion of these restrictions.
 
Further, under the tax sharing agreement, we are required to indemnify Williams against certain tax-related liabilities incurred by Williams (including any of its subsidiaries) relating to the spin-off of our stock to Williams’ stockholders or relating to any related restructuring transaction undertaken by Williams, to the extent caused by our breach of any representations or covenants made in the tax sharing agreement or the separation and distribution agreement, or made in connection with the private letter ruling or tax opinion. These liabilities include the substantial tax-related liability (calculated without regard to any net operating loss or other tax attribute of Williams) that would result if the spin-off of our stock to Williams’ stockholders failed to qualify as a tax-free transaction.
 
We will not have complete control over our tax decisions and could be liable for income taxes owed by Williams.
 
For so long as Williams continues to own at least 80% of the total voting power and value of our common stock, we and our U.S. subsidiaries will be included in Williams’ consolidated group for U.S. federal income tax purposes. In addition, we or one or more of our U.S. subsidiaries may be included in the combined, consolidated or unitary tax returns of Williams or one or more of its subsidiaries for U.S. state or local income tax purposes. Under the tax sharing agreement, for each period in which we or any of our subsidiaries are consolidated or combined with Williams for purposes of any tax return, Williams will prepare a pro forma tax return for us as if we filed our own consolidated, combined or unitary return, except that such pro forma tax return will only include current income, deductions, credits and losses from us (with certain exceptions), will not include any carryovers or carrybacks of losses or credits and will be calculated without regard to the federal Alternative Minimum Tax. We will reimburse Williams for any taxes shown on the pro forma tax returns, and Williams will reimburse us for any current losses or credits we recognize based on the pro forma tax returns. In addition, by virtue of Williams’ controlling ownership and the tax sharing agreement, Williams will effectively control all of our U.S. tax decisions in connection with any consolidated, combined or unitary income tax returns in which we (or any of our subsidiaries) are included. The tax sharing agreement provides that Williams will have sole authority to respond to and conduct all tax proceedings (including tax audits) relating to us, to prepare and file all consolidated, combined or unitary income tax returns on our behalf (including the making of any tax elections), and to determine the reimbursement amounts in connection with any pro forma tax returns. This arrangement may result in conflicts of interest between Williams and us. For example, under the tax sharing agreement, Williams will be able to choose to contest, compromise or settle any adjustment or deficiency proposed by the relevant taxing authority in a manner that may be beneficial to Williams and detrimental to us. See “Arrangements Between Williams and Our Company—Tax Sharing Agreement.”
 
Moreover, notwithstanding the tax sharing agreement, U.S. federal law provides that each member of a consolidated group is liable for the group’s entire tax obligation. Thus, to the extent Williams or other members of Williams’ consolidated group fail to make any U.S. federal income tax payments required by law, we could be liable for the shortfall. Similar principles may apply for foreign, state or local income tax purposes where we file combined, consolidated or unitary returns with Williams or its subsidiaries for federal, foreign, state or local income tax purposes.

     	If, following the completion of the spin-off of our stock to Williams’ stockholders, there is a determination that the spin-off is taxable for U.S. federal income tax purposes because the facts, assumptions, representations, or undertakings underlying the IRS private letter ruling or tax opinion are incorrect or for any other reason, then Williams and its stockholders could incur significant income tax liabilities, and we could incur significant liabilities.	
 
The spin-off will be conditioned upon, among other things, Williams’ receipt of a private letter ruling from the IRS and an opinion of its outside tax advisor reasonably acceptable to the Williams board of directors, to the effect that the distribution by Williams of the shares of our common stock held by Williams after the offering, and any related restructuring transaction undertaken by Williams, will qualify for U.S. federal income tax purposes as a tax-free transaction under section 355 and section 368(a)(1)(D) of the Code. The ruling and opinion will rely on certain facts, assumptions, representations and undertakings from Williams and us regarding

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the past and future conduct of the companies’ respective businesses and other matters. If any of these facts, assumptions, representations, or undertakings are, or become, incorrect or not otherwise satisfied, Williams and its stockholders may not be able to rely on the private letter ruling and opinion of its tax advisor and could be subject to significant tax liabilities. In addition, notwithstanding the opinion of Williams’ tax advisor, the IRS could conclude upon audit that the spin-off is taxable if it determines that any of these facts, assumptions, representations, or undertakings are, or have become, not correct or have been violated or if it disagrees with the conclusions in the opinion, or for other reasons, including as a result of certain significant changes in the stock ownership of Williams or us after the spin-off. If the spin-off is determined to be taxable for U.S. federal income tax purposes for any reason, Williams and/or its stockholders could incur significant income tax liabilities, and we could incur significant liabilities. For a description of the sharing of such liabilities between Williams and us, see “Arrangements Between Williams and Our Company—Tax Sharing Agreement.”

     	Third parties may seek to hold us responsible for liabilities of Williams that we did not assume in our agreements.	
 
Third parties may seek to hold us responsible for retained liabilities of Williams. Under our agreements with Williams, Williams will agree to indemnify us for claims and losses relating to these retained liabilities. However, if those liabilities are significant and we are ultimately held liable for them, we cannot assure you that we will be able to recover the full amount of our losses from Williams.

     	Our prior and continuing relationship with Williams exposes us to risks attributable to businesses of Williams.	
 
Williams is obligated to indemnify us for losses that a party may seek to impose upon us or our affiliates for liabilities relating to the business of Williams that are incurred through a breach of the separation and distribution agreement or any ancillary agreement by Williams or its affiliates other than us, or losses that are attributable to Williams in connection with this offering or are not expressly assumed by us under our agreements with Williams. Immediately following this offering, any claims made against us that are properly attributable to Williams in accordance with these arrangements would require us to exercise our rights under our agreements with Williams to obtain payment from Williams. We are exposed to the risk that, in these circumstances, Williams cannot, or will not, make the required payment.

     	Our directors and executive officers who own shares of common stock of Williams, who hold options to acquire common stock of Williams or other Williams equity-based awards, or who hold positions with Williams, may have actual or potential conflicts of interest.	
 
Ownership of shares of common stock of Williams, options to acquire shares of common stock of Williams and other equity-based securities of Williams by certain of our directors and officers after this offering, and the presence of directors or officers of Williams on our board of directors could create, or appear to create, potential conflicts of interest when those directors and officers are faced with decisions that could have different implications for Williams than they do for us. Certain of our directors will hold director and/or officer positions with Williams or beneficially own significant amounts of common stock of Williams. See “Management.”
 
In addition, because our board of directors does not intend to form a compensation committee or nominating and governance committee in connection with the completion of this offering, the Williams compensation committee will make recommendations to our board of directors regarding compensation for our directors and officers, which could also create, or appear to create, similar potential conflicts of interest. See “Management” for a description of the extent of the relationship between our directors and officers and directors and officers of Williams.

     	We will be a “controlled company” within the meaning of the NYSE rules and, as a result, will qualify for, and intend to rely on, exemptions from certain corporate governance requirements that provide protection to stockholders of other companies.	
 
After the completion of this offering and prior to the spin-off of our stock to Williams’ stockholders, Williams will own more than 50% of the voting power of all then outstanding shares of our capital stock entitled to vote generally in the election of directors, and we will be a “controlled company” under the NYSE corporate governance standards. As a controlled company, we intend to rely on certain exemptions from the

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NYSE standards that will enable us not to comply with certain NYSE corporate governance requirements, including the requirements that:

 	•  	a majority of our board of directors consists of independent directors;	
 		
 	•  	we have a nominating and governance committee that is composed entirely of independent directors, with a written charter addressing the committee’s purpose and responsibilities;	
 		
 	•  	we have a compensation committee that is composed entirely of independent directors, with a written charter addressing the committee’s purpose and responsibilities; and	
 		
 	•  	we conduct an annual performance evaluation of the nominating and governance committee and compensation committee.	
 
We intend to rely on some or all of these exemptions, and, as a result, prior to the spin-off, you will not have the same protection afforded to stockholders of companies that are subject to all of the NYSE corporate governance requirements.
 
Risks Related to this Offering

     	No market currently exists for our Class A common stock. We cannot assure you that an active trading market will develop for our Class A common stock.	
 
Prior to this offering, there has been no public market for shares of our Class A common stock. We cannot predict the extent to which investor interest in our company will lead to the development of a trading market on the NYSE or otherwise, or how liquid that market might become. If an active market does not develop, you may have difficulty selling any shares of our Class A common stock that you purchase in this initial public offering. The initial public offering price for the shares of our Class A common stock has been determined by negotiations between us and the representatives of the underwriters, and may not be indicative of prices that will prevail in the open market following this offering.

     	If our Class A stock price fluctuates after this offering, you could lose a significant part of your investment.	
 
The market price of our Class A stock may be influenced by many factors, some of which are beyond our control, including those described above in “—Risks Related to Our Business” and the following:

 	•  	the failure of securities analysts to cover our Class A common stock after this offering or changes in financial estimates by analysts;	
 		
 	•  	the inability to meet the financial estimates of analysts who follow our Class A common stock;	
 		
 	•  	strategic actions by us or our competitors;	
 		
 	•  	announcements by us or our competitors of significant contracts, acquisitions, joint marketing relationships, joint ventures or capital commitments;	
 		
 	•  	variations in our quarterly operating results and those of our competitors;	
 		
 	•  	general economic and stock market conditions;	
 		
 	•  	risks related to our business and our industry, including those discussed above;	
 		
 	•  	changes in conditions or trends in our industry, markets or customers;	
 		
 	•  	terrorist acts;	
 		
 	•  	future sales of our Class A common stock or other securities; and	
 		
 	•  	investor perceptions of the investment opportunity associated with our Class A common stock relative to other investment alternatives.	
 
As a result of these factors, investors in our Class A common stock may not be able to resell their shares at or above the initial offering price or may not be able to resell them at all. These broad market and industry factors may materially reduce the market price of our Class A common stock, regardless of our operating performance. In addition, price volatility may be greater if the public float and trading volume of our Class A common stock is low.

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     	Future sales, or the perception of future sales, of our common stock may depress the price of our Class A common stock.	
 
The market price of our Class A common stock could decline significantly as a result of sales of a large number of shares of our common stock in the market after this offering, including shares which might be offered for sale by Williams. The perception that these sales might occur could depress the market price. These sales, or the possibility that these sales may occur, also might make it more difficult for us to sell equity securities in the future at a time and at a price that we deem appropriate.
 
Upon completion of this offering, we will have           shares of Class A common stock (           shares if the underwriters exercise their option to purchase additional Class A common shares in full) and           shares of Class B common stock outstanding (           shares if the underwriters exercise their option to purchase additional Class A common shares in full). The shares of Class A common stock offered in this offering will be freely tradable without restriction under the Securities Act of 1933, as amended (the “Securities Act”), except for any shares of Class A common stock that may be held or acquired by our directors, executive officers and other affiliates, as that term is defined in the Securities Act, which will be restricted securities under the Securities Act. Restricted securities may not be sold in the public market unless the sale is registered under the Securities Act or an exemption from registration is available. We will grant registration rights to Williams with respect to the common stock it owns. Any shares registered pursuant to the registration rights agreement with Williams described in “Arrangements Between Williams and Our Company” will be freely tradable in the public market.
 
In connection with this offering, we, our directors and executive officers, Williams and its directors and executive officers have each agreed to enter into a lock-up agreement and thereby be subject to a lock-up period, meaning that they and their permitted transferees will not be permitted to sell any of the shares of our common stock for 180 days after the date of this prospectus, subject to certain extensions without the prior consent of the underwriters. Although we have been advised that there is no present intention to do so, the underwriters may, in their sole discretion and without notice, release all or any portion of the shares of our common stock from the restrictions in any of the lock-up agreements described above. See “Underwriting.”
 
Also, in the future, we may issue our securities in connection with investments or acquisitions. The amount of shares of our common stock issued in connection with an investment or acquisition could constitute a material portion of our then outstanding shares of our common stock.

     	We will not receive any benefit and accordingly you will suffer increased dilution if the underwriters exercise their option to purchase additional Class A common shares.	
 
If the underwriters exercise their option to purchase additional Class A common shares, all of our net proceeds from the issuance of such shares will be distributed to Williams in connection with our restructuring transactions. Accordingly, we will receive no benefit from the issuance of any shares of our Class A common stock subject to the underwriters’ option to purchase additional Class A common shares.

     	Our costs may increase as a result of operating as a public company, and our management will be required to devote substantial time to complying with public company regulations.	
 
We have historically operated our business as a segment of a public company. As a stand-alone public company, we may incur additional legal, accounting, compliance and other expenses that we have not incurred historically. After this offering, we will become obligated to file with the SEC annual and quarterly information and other reports that are specified in Section 13 and other sections of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). We will also be required to ensure that we have the ability to prepare financial statements that are fully compliant with all SEC reporting requirements on a timely basis. In addition, we will also become subject to other reporting and corporate governance requirements, including certain requirements of the NYSE, and certain provisions of Sarbanes-Oxley and the regulations promulgated thereunder, which will impose significant compliance obligations upon us.
 
Sarbanes-Oxley, as well as new rules subsequently implemented by the SEC and the NYSE, have imposed increased regulation and disclosure and required enhanced corporate governance practices of public companies. We are committed to maintaining high standards of corporate governance and public disclosure, and our efforts to comply with evolving laws, regulations and standards in this regard are likely to result in increased

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marketing, selling and administrative expenses and a diversion of management’s time and attention from revenue-generating activities to compliance activities. These changes will require a significant commitment of additional resources. We may not be successful in implementing these requirements and implementing them could materially adversely affect our business, results of operations and financial condition. In addition, if we fail to implement the requirements with respect to our internal accounting and audit functions, our ability to report our operating results on a timely and accurate basis could be impaired. If we do not implement such requirements in a timely manner or with adequate compliance, we might be subject to sanctions or investigation by regulatory authorities, such as the SEC or the NYSE. Any such action could harm our reputation and the confidence of investors and clients in our company and could materially adversely affect our business and cause our share price to fall.

     	Failure to achieve and maintain effective internal controls in accordance with Section 404 of
Sarbanes-Oxley could have a material adverse effect on our business and stock price.	
 
As a public company, we will be required to document and test our internal control procedures in order to satisfy the requirements of Section 404 of Sarbanes-Oxley, which will require annual management assessments of the effectiveness of our internal control over financial reporting and a report by our independent registered public accounting firm that addresses the effectiveness of internal control over financial reporting. During the course of our testing, we may identify deficiencies which we may not be able to remediate in time to meet our deadline for compliance with Section 404. Testing and maintaining internal control can divert our management’s attention from other matters that are important to the operation of our business. We also expect the new regulations to increase our legal and financial compliance costs, make it more difficult to attract and retain qualified officers and members of our board of directors, particularly to serve on our audit committee, and make some activities more difficult, time consuming and costly. We may not be able to conclude on an ongoing basis that we have effective internal control over financial reporting in accordance with Section 404 or our independent registered public accounting firm may not be able or willing to issue an unqualified report on the effectiveness of our internal control over financial reporting. If we conclude that our internal control over financial reporting is not effective, we cannot be certain as to the timing of completion of our evaluation, testing and remediation actions or their effect on our operations because there is presently no precedent available by which to measure compliance adequacy. If either we are unable to conclude that we have effective internal control over financial reporting or our independent auditors are unable to provide us with an unqualified report as required by Section 404, then investors could lose confidence in our reported financial information, which could have a negative effect on the trading price of our Class A common stock.

     	If securities or industry analysts do not publish research or reports about our business, if they adversely change their recommendations regarding our stock or if our operating results do not meet their expectations, our stock price could decline.	
 
The trading market for our Class A common stock will be influenced by the research and reports that industry or securities analysts publish about us or our business. If one or more of these analysts cease coverage of our company or fail to publish reports on us regularly, we could lose visibility in the financial markets, which in turn could cause our stock price or trading volume to decline. Moreover, if one or more of the analysts who cover our company downgrades our stock or if our operating results do not meet their expectations, our stock price could decline.

     	Investors purchasing Class A common stock in this offering will incur substantial and immediate dilution.	
 
Dilution per share represents the difference between the initial public offering price per share of our Class A common stock and the net tangible book value per share of our common stock upon the completion of this offering. The initial public offering price of our Class A common stock is substantially higher than the net tangible book value per share of our outstanding common stock. Purchasers of our common stock in this offering will incur immediate and substantial dilution of $      per share in the net tangible book value of our common stock from an assumed initial public offering price of $      per share, which is the midpoint of the estimated offering price range set forth on the cover page of this prospectus. This means that if we were to be liquidated immediately after this offering, there might be no assets available for distribution to you after satisfaction of all our obligations to creditors. For a further description of the effects of dilution in the net tangible book value of our common stock, see “Dilution.”

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Further, if we issue additional equity securities to raise additional capital, your ownership interest in our company may be diluted and the value of your investment may be reduced.

     	We do not anticipate paying any dividends on our common stock in the foreseeable future. As a result, you will need to sell your shares of common stock to receive any income or realize a return on your investment.	
 
We do not anticipate paying any dividends on our common stock in the foreseeable future. Any declaration and payment of future dividends to holders of our common stock may be limited by the provisions of the Delaware General Corporation Law. The future payment of dividends will be at the sole discretion of our board of directors and will depend on many factors, including our earnings, capital requirements, financial condition and other considerations that our board of directors deems relevant. As a result, to receive any income or realize a return on your investment, you will need to sell your shares of Class A common stock. You may not be able to sell your shares of Class A common stock at or above the price you paid for them.

     	Provisions of Delaware law, our charter documents and our stockholder rights plan may delay or prevent an acquisition of us that stockholders may consider favorable or may prevent efforts by our stockholders to change our directors or our management, which could decrease the value of your shares.	
 
Section 203 of the Delaware General Corporation Law and provisions in our amended and restated certificate of incorporation and amended and restated bylaws could make it more difficult for a third party to acquire us without the consent of our board of directors. See “Description of Capital Stock—Anti-Takeover Effects of Certificate of Incorporation and Bylaws Provisions.” These provisions include the following:

 	•  	restrictions on business combinations for a three-year period with a stockholder who becomes the beneficial owner of more than 15% of our common stock;	
 		
 	•  	restrictions on the ability of our stockholders to remove directors;	
 		
 	•  	supermajority voting requirements for stockholders to amend our organizational documents; and	
 		
 	•  	a classified board of directors.	
 
Although we believe these provisions protect our stockholders from coercive or otherwise unfair takeover tactics and thereby provide an opportunity to receive a higher bid by requiring potential acquirers to negotiate with our board of directors, these provisions apply even if the offer may be considered beneficial by some stockholders. Further, these provisions may discourage potential acquisition proposals and may delay, deter or prevent a change of control of our company, including through unsolicited transactions that some or all of our stockholders might consider to be desirable. As a result, efforts by our stockholders to change our direction or our management may be unsuccessful.

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FORWARD-LOOKING STATEMENTS
 
Certain matters contained in this prospectus include forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. These forward-looking statements relate to anticipated financial performance, management’s plans and objectives for future operations, business prospects, outcome of regulatory proceedings, market conditions and other matters.
 
All statements, other than statements of historical facts, included in this prospectus that address activities, events or developments that we expect, believe or anticipate will exist or may occur in the future, are forward-looking statements. In some cases, forward-looking statements can be identified by various forms of words such as “anticipates,” “believes,” “seeks,” “could,” “may,” “should,” “continues,” “estimates,” “expects,” “forecasts,” “intends,” “might,” “goals,” “objectives,” “targets,” “planned,” “potential,” “projects,” “scheduled,” “will” or other similar expressions. These forward-looking statements are based on management’s beliefs and assumptions and on information currently available to management and include, among others, statements regarding:

 	•  	Amounts and nature of future capital expenditures;	
 		
 	•  	Expansion and growth of our business and operations;	
 		
 	•  	Financial condition and liquidity;	
 		
 	•  	Business strategy;	
 		
 	•  	Estimates of proved gas and oil reserves;	
 		
 	•  	Reserve potential;	
 		
 	•  	Development drilling potential;	
 		
 	•  	Cash flow from operations or results of operations;	
 		
 	•  	Seasonality of our business; and	
 		
 	•  	Natural gas, crude oil and NGLs prices and demand.	
 
Forward-looking statements are based on numerous assumptions, uncertainties and risks that could cause future events or results to be materially different from those stated or implied in this prospectus. Many of the factors that will determine these results are beyond our ability to control or predict. Specific factors that could cause actual results to differ from results contemplated by the forward-looking statements include, among others, the following:

 	•  	Availability of supplies (including the uncertainties inherent in assessing, estimating, acquiring and developing future natural gas and oil reserves), market demand, volatility of prices and the availability and cost of capital;	
 		
 	•  	Inflation, interest rates, fluctuation in foreign exchange and general economic conditions (including future disruptions and volatility in the global credit markets and the impact of these events on our customers and suppliers);	
 		
 	•  	The strength and financial resources of our competitors;	
 		
 	•  	Development of alternative energy sources;	
 		
 	•  	The impact of operational and development hazards;	
 		
 	•  	Costs of, changes in, or the results of laws, government regulations (including climate change legislation and/or potential additional regulation of drilling and completion of wells), environmental liabilities, litigation and rate proceedings;	
 		
 	•  	Changes in maintenance and construction costs;	
 		
 	•  	Changes in the current geopolitical situation;	
 		
 	•  	Our exposure to the credit risk of our customers;	
 		
 	•  	Risks related to strategy and financing, including restrictions stemming from our debt agreements, future changes in our credit ratings and the availability and cost of credit;	

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 	•  	Risks associated with future weather conditions;	
 		
 	•  	Acts of terrorism; and	
 		
 	•  	Other factors described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Business.”	
 
All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the cautionary statements set forth above. Given the uncertainties and risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement, we caution investors not to unduly rely on our forward-looking statements. Forward-looking statements speak only as of the date they are made. We disclaim any obligation to and do not intend to update the above list or to announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments, except to the extent required by applicable laws. If we update one or more forward-looking statements, no inference should be drawn that we will make additional updates with respect to those or other forward-looking statements.
 
In addition to causing our actual results to differ, the factors listed above and referred to below may cause our intentions to change from those statements of intention set forth in this prospectus. Such changes in our intentions may also cause our results to differ. We may change our intentions, at any time and without notice, based upon changes in such factors, our assumptions, or otherwise.
 
Because forward-looking statements involve risks and uncertainties, we caution that there are important factors, in addition to those listed above, that may cause actual results to differ materially from those contained in the forward-looking statements. These factors are described in “Risk Factors.”

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USE OF PROCEEDS
 
We estimate that our net proceeds from the sale of shares of Class A common stock in this offering, after deducting estimated underwriting discounts and commissions and estimated offering expenses, will be approximately $      million ($      million if the underwriters exercise their option to purchase additional Class A common shares in full), assuming the shares are offered at $      per share of Class A common stock, which is the midpoint of the estimated offering price range set forth on the cover page of this prospectus. We expect to retain approximately $500 million of the net proceeds from this offering; the remaining net proceeds will be distributed to Williams as part of our restructuring transactions. Any shares of Class A common stock issued pursuant to the underwriters’ option to purchase additional Class A common shares will not increase the total number of shares of common stock outstanding after this offering, but rather the number of shares of Class B common stock owned by Williams will be reduced share for share by the number of shares of Class A common stock issued pursuant to such option, thus reducing Williams’ ownership interest in us. We will distribute the net proceeds from the sale of shares of Class A common stock pursuant to this option to Williams as part of our restructuring transactions. Williams is deemed to be an underwriter with respect to any shares of Class A common stock issued pursuant to this option. See “Underwriting.”
 
The approximately $500 million of retained net proceeds will be available to us to fund capital spending and acquisition and exploration opportunities, to provide additional liquidity and for other general corporate purposes. At current commodity prices and drilling costs, as much as 50 percent of the retained net proceeds are expected to be utilized for capital projects, including principally drilling and to a lesser extent the construction of gathering lines, compression facilities and other ancillary infrastructure supporting our drilling program, with the remainder utilized to provide additional liquidity and, if necessary, to fund additional similar activities prior to issuing additional debt securities or borrowing under our Credit Facility. Our ability to access the capital markets could be constrained depending on our credit rating, and we believe it is prudent to maintain sufficient liquidity to fund our drilling plan under reduced commodity prices.
 
Concurrently with or shortly following the completion of this offering, we expect to issue up to $1.5 billion aggregate principal amount of Notes in a private offering exempt from registration under the Securities Act. The Notes will be offered and sold solely to qualified institutional buyers pursuant to Rule 144A and in offshore transactions to persons other than U.S. persons as defined in Regulation S under the Securities Act. As part of our restructuring transactions, all of the net proceeds of the sale of the Notes will be distributed to Williams. Our offering of Class A common stock is not contingent upon the completion of our offering of the Notes.
 
Williams has informed us that it expects to use the net proceeds distributed to it from this offering and the offering of the Notes to repay a portion of its indebtedness.
 
The following table sets forth the anticipated sources and uses of funds we expect to receive from the sale of shares of Class A common stock in this offering and the issuance of the Notes, assuming the underwriters do not exercise their option to purchase additional Class A common shares.

Sources of Funds	 	 	 	 	Uses of Funds	 	 	 	
 		
Estimated net proceeds from the sale of           shares of Class A common stock in this offering(1)	 	$	704	 	 	Retention of approximately $500 million of the estimated net proceeds from the sale of shares of Class A common stock in this offering	 	$	500	 	
 	 	 	 	 	 	Distribution of the remaining estimated net proceeds from the sale of shares of Class A common stock in this offering to Williams(1)	 	 	204	 	
Estimated net proceeds from the issuance of the Notes(2)	 	 	1,479	 	 	Distribution of the estimated net proceeds from the issuance of the Notes to Williams(2)	 	 	1,479	 	
 	 	 	 	 	 	 	 	 	 	 	
Total	 	$	2,183	 	 	 	 	$	2,183	 	

 

			
(1)		Assumes that the shares are offered at $      per share of Class A common stock, which is the midpoint of the estimated offering price range set forth on the cover page of this prospectus.	
 		
(2)		After deducting estimated initial purchasers’ discounts. Assumes the Notes are issued at par.	

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DIVIDEND POLICY
 
We do not anticipate paying any dividends on our common stock in the foreseeable future. We currently intend to retain our future earnings to support the growth and development of our business. The payment of future cash dividends, if any, will be at the discretion of our board of directors and will depend upon, among other things, our financial condition, results of operations, capital requirements and development expenditures, future business prospects and any restrictions imposed by future debt instruments.

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CAPITALIZATION
 
The following table sets forth our cash and cash equivalents and capitalization as of June 30, 2011 on an actual basis and pro forma basis to give effect to:

 	•  	the completion of our restructuring transactions;	
 		
 	•  	the receipt of approximately $704 million from the sale of shares of Class A common stock offered by us at an assumed initial public offering price of $      per share, which is the midpoint of the estimated offering price range set forth on the cover page of this prospectus, after deducting estimated underwriting discounts and commissions and estimated offering expenses payable by us; and	
 		
 	•  	the receipt of approximately $1.5 billion from our expected offering of the Notes, after deducting the discounts of the initial purchasers of the Notes and the expenses payable by us in connection with such offering;	
 		
 	•  	the distribution of approximately $1.7 billion to Williams from the combined net proceeds from this offering and the expected offering of the Notes in connection with our restructuring transactions.	
 
You should read this table in conjunction with “Use of Proceeds,” “Selected Historical Combined Financial Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our historical and unaudited pro forma combined financial statements and related notes included elsewhere in this prospectus.

 	 	 	 	 	 	 	 	 	
 	 	At June 30, 2011	 	
 	 	Historical	 	 	Pro Forma	 	
 	 	(Millions)	 	
 		
Cash and cash equivalents(1)	 	$	36	 	 	$	538	(2)	
 	 	 	 	 	 	 	 	 	
Debt:	 	 	 	 	 	 	 	 	
Senior unsecured credit facility(3)	 	 	—	 	 	 	—	 	
Senior unsecured notes	 	 	—	 	 	 	1,500	 	
 	 	 	 	 	 	 	 	 	
Total debt	 	 	—	 	 	 	1,500	 	
Equity:	 	 	 	 	 	 	 	 	
Owner’s net investment	 	 	6,678	 	 	 	—	 	
Class A common stock, $1.00 par value per share, 1,875,000,000 shares authorized and           shares outstanding	 	 	—	 	 	 	 	 	
Class B common stock, $1.00 par value per share, 500,000,000 shares authorized and           shares outstanding	 	 	—	 	 	 	 	 	
Additional paid-in capital	 	 	—	 	 	 	5,652	 	
Noncontrolling interests	 	 	76	 	 	 	76	 	
Accumulated other comprehensive income	 	 	115	 	 	 	115	 	
 	 	 	 	 	 	 	 	 	
Total equity	 	 	6,869	 	 	 	5,843	 	
 	 	 	 	 	 	 	 	 	
Total capitalization	 	$	6,869	 	 	$	7,343	 	

 

			
(1)		The pro forma cash and cash equivalents balance does not reflect approximately $20 million in cash that Williams will provide to us in connection with certain information technology transition costs we expect to incur following the completion of this offering. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Management’s Discussion and Analysis of Financial Condition and Liquidity—Liquidity.”	

			
(2)		Reflects the retention of $500 million from the sale of Class A common stock in this offering plus advancement by Williams of approximately $2 million for expenses that had not yet been incurred by June 30, 2011, but that will be paid by us in connection with this offering.	

 
			
(3)		Our Credit Facility provides for borrowings of up to $1.5 billion, all of which is expected to be available to us upon the effectiveness of that facility. Our future borrowing capacity may be reduced by letters of credit issued under the Credit Facility. See “Description of our Concurrent Financing Transactions—Credit Facility.”	

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DILUTION
 
If you invest in our Class A common stock, your ownership interest will be diluted to the extent of the difference between the initial public offering price per share of our Class A common stock and the net tangible book value per share of our common stock upon the completion of this offering.

Our net tangible book value represents the amount of our total tangible assets less total liabilities. As of June 30, 2011, after giving effect to our restructuring transactions, our pro forma net tangible book value was approximately $      million, or approximately $      per share based on           shares of our Class B common stock outstanding immediately prior to the completion of this offering. After giving effect to the sale of our shares of Class A common stock at the initial public offering price per share, the completion of the expected offering of the Notes and the distribution to Williams of approximately $1.7 billion from the combined net proceeds from this offering and the expected offering of the Notes, and after deducting estimated underwriting discounts and commissions and estimated offering expenses payable by us (collectively, the “offering transactions”), our pro forma net tangible book value as of June 30, 2011, which we refer to as our pro forma net tangible book value, would have been approximately $      million, or $      per share of our common stock. This represents an immediate dilution of $      per share to new investors purchasing shares of our Class A common stock in this offering.

 	 	 	 	 	 	 	 	 	
Assumed initial public offering price per share	 	 	     	 	 	$	     	 	
Pro forma net tangible book value per share as of June 30, 2011 after giving effect to our restructuring transactions but before giving effect to the offering transactions	 	$	     	 	 	 	 	 	
Change in pro forma net tangible book value per share attributable to the offering transactions, including new investors purchasing shares in this offering	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	
Less: Pro forma net tangible book value per share after giving effect to the offering transactions	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	
Dilution in pro forma net tangible book value per share to new investors	 	 	 	 	 	$	 	 	

 
The foregoing discussion does not give effect to shares of Class A common stock that we will issue if the underwriters exercise their option to purchase additional shares.
 
The following table summarizes the total number of shares of our common stock on an aggregate basis acquired from us, the total consideration and the average price per share. The calculations regarding shares acquired by new investors in this offering reflect an assumed initial public offering price of $      per share, which is the midpoint of the estimated offering price range set forth on the cover page of this prospectus, and do not reflect the estimated underwriting discount and offering expenses.

  	 	 	 	 	 	 	 	Percentage	 	 	 	 	 	 	 	 	Average	 	
 	 	Shares Acquired	 	 	of Voting	 	 	Total Consideration	 	 	Price Per	 	
 	 	Number	 	 	Percent	 	 	Rights	 	 	Amount	 	 	Percent	 	 	Share	 	
 		
Williams	 	 	     	 	 	 	     	%	 	 	     	%	 	$	—	 	 	 	0	%	 	$	—	 	
New investors in this offering	 	 	 	 	 	 	 	 	 	 	 	 	 	 	750	 	 	 	100	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	 	 	 	 	 	100	%	 	 	100	%	 	$	750	 	 	 	100	%	 	$	     	 	

 
If the underwriters exercise their option to purchase additional Class A common shares in full, the following will occur:

 	•  	the number of shares of Class A common stock held by new investors will increase to          , or approximately     % of our total outstanding common stock and approximately     % of the total voting power of our common stock; and	
 		
 	•  	the number of shares of our Class B common stock held by Williams will be reduced to          , or approximately     % of our total outstanding common stock and approximately     % of the total voting power of our common stock.	

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SELECTED HISTORICAL COMBINED FINANCIAL DATA
 
The following tables set forth our selected historical combined financial data for the periods indicated below. The historical unaudited combined financial data for the six months ended June 30, 2011 and 2010 and balance sheet data as of June 30, 2011 have been derived from our unaudited condensed combined financial statements included in this prospectus. The unaudited condensed combined financial statements have been prepared on the same basis as our audited combined financial statements, except as stated in the related notes thereto, and include all normal recurring adjustments that, in the opinion of management, are necessary to present fairly our financial condition and result of operations for such periods. The results of operations for the six months ended June 30, 2011 presented below are not necessarily indicative of results for the entire fiscal year. Our selected historical combined financial data as of December 31, 2010 and 2009 and for the fiscal years ended December 31, 2010, 2009 and 2008 have been derived from our audited historical combined financial statements included elsewhere in this prospectus. Our selected historical combined financial data as of December 31, 2008, 2007 and 2006 and for the years ended December 31, 2007 and 2006 have been derived from our unaudited accounting records not included in this prospectus.
 
The financial statements included in this prospectus may not necessarily reflect our financial position, results of operations and cash flows as if we had operated as a stand-alone public company during all periods presented. Accordingly, our historical results should not be relied upon as an indicator of our future performance.
 
The following selected historical financial and operating data should be read in conjunction with “Use of Proceeds,” “Capitalization,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Arrangements Between Williams and Our Company” and our combined financial statements and related notes included elsewhere in this prospectus.

 	 	Six Months Ended June 30,	 	 	Year Ended December 31,	 	
 	 	2011	 	 	2010	 	 	2010	 	 	2009	 	 	2008	 	 	2007	 	 	2006	 	
 	 	(Millions)	 	
 		
Statement of operations data:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Revenues	 	$	1,974	 	 	$	2,068	 	 	$	4,034	 	 	$	3,681	 	 	$	6,184	 	 	$	4,479	 	 	$	4,627	 	
Income (loss) from continuing operations(1)	 	 	35	 	 	 	115	 	 	 	(1,274	)	 	 	149	 	 	 	817	 	 	 	192	 	 	 	104	 	
Income (loss) from discontinued operations(2)	 	 	(8	)	 	 	(1	)	 	 	(8	)	 	 	(7	)	 	 	(87	)	 	 	146	 	 	 	6	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income (loss)	 	 	27	 	 	 	114	 	 	 	(1,282	)	 	 	142	 	 	 	730	 	 	 	338	 	 	 	110	 	
Less: Net income attributable to noncontrolling interests	 	 	5	 	 	 	4	 	 	 	8	 	 	 	6	 	 	 	8	 	 	 	11	 	 	 	12	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income (loss) attributable to WPX Energy	 	$	22	 	 	$	110	 	 	$	(1,290	)	 	$	136	 	 	$	722	 	 	$	327	 	 	$	98	 	

 

 	 	As of	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	June 30,	 	 	As of December 31,	 	
 	 	2011	 	 	2010	 	 	2009	 	 	2008	 	 	2007	 	 	2006	 	
 		
Balance sheet data	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Notes payable to Williams — current(3)	 	$	—	 	 	$	2,261	 	 	$	1,216	 	 	$	925	 	 	$	656	 	 	$	—	 	
Notes receivable from Williams	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	64	 	
Third party debt	 	 	2	 	 	 	—	 	 	 	—	 	 	 	 	 	 	 	 	 	 	 	34	 	
Total assets	 	 	9,895	 	 	 	9,846	 	 	 	10,553	 	 	 	11,624	 	 	 	10,571	 	 	 	11,223	 	
Total equity(3)	 	 	6,869	 	 	 	4,500	 	 	 	5,405	 	 	 	5,506	 	 	 	4,356	 	 	 	4,376	 	

 

			
(1)		Loss from continuing operations in 2010 includes $1.7 billion of impairment charges related to goodwill, producing properties in the Barnett Shale and costs of acquired unproved reserves in the Piceance Basin. Income from continuing operations in 2008 includes a $148 million gain related to the sale of a right to an international production payment. See Notes 6 and 14 of Notes to Combined Financial Statements for further discussion of asset sales, impairments and other accruals in 2010, 2009 and 2008.	
 		
(2)		Income (loss) from discontinued operations includes our Arkoma operations which were classified as held for sale as of March 31, 2011 and Williams’ former power business that was substantially disposed of in 2007. The activity in 2010 and 2009 primarily relates to the Arkoma operations and the remaining indemnity and	

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		other obligations related to the former power business. Activity in 2008 reflects a $148 million pre-tax impairment charge related to the producing properties in the Arkoma Basin. Activity in 2007 and 2006 primarily reflects the operations of the power business and 2007 includes a pre-tax gain of $429 million associated with the reclassification of deferred net hedge gains from accumulated other comprehensive income (loss) to earnings based on the determination that the hedged forecasted transactions were probable of not occurring due to the sale of Williams’ power business. This gain is partially offset by a pre-tax unrealized mark-to-market loss of $23 million, a $37 million loss from operations and $111 million of pre-tax impairments primarily related to the carrying value of certain derivative contracts.	

			
(3)		On June 30, 2011, all of our notes payable to Williams were cancelled by Williams. The amount due to Williams at the time of cancellation was $2.4 billion and is reflected as an increase in owner’s investment as of June 30, 2011.	

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
 
We are currently a wholly owned subsidiary of The Williams Companies, Inc. and were formed in April 2011 to hold the exploration and production businesses of Williams. We did not have material assets or liabilities as a separate corporate entity until the contribution to us by Williams of the businesses described in this prospectus. Williams previously conducted our businesses through various subsidiaries. This prospectus, including the combined financial statements and the following discussion, describes us and our financial condition and operations as if we had held the subsidiaries that were transferred to us on July 1, 2011 or will be transferred to us prior to completion of this offering for all historical periods presented. The following discussion should be read in conjunction with the selected historical combined financial data and the combined financial statements and the related notes included elsewhere in this prospectus. The matters discussed below may contain forward-looking statements that reflect our plans, estimates and beliefs. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to these differences include, but are not limited to, those discussed below and elsewhere in this prospectus, particularly in “Risk Factors” and “Forward-Looking Statements.”
 
We are an independent natural gas and oil exploration and production company engaged in the exploitation and development of long-life unconventional properties. We are focused on profitably exploiting our significant natural gas reserve base and related NGLs in the Piceance Basin of the Rocky Mountain region, and on developing and growing our position in the Bakken Shale oil play in North Dakota and our Marcellus Shale natural gas position in Pennsylvania. Our other areas of domestic operations include the Powder River Basin in Wyoming and the San Juan Basin in the southwestern United States. In addition, we own a 69 percent controlling ownership interest in Apco, which holds oil and gas concessions in Argentina and Colombia and trades on the NASDAQ Capital Market under the symbol “APAGF.”
 
In addition to our exploration and development activities, we engage in natural gas sales and marketing. Our sales and marketing activities to date include the sale of our natural gas and oil production, in addition to third party purchases and sales of natural gas, including sales to Williams Partners L.P. (NYSE: “WPZ”) (“Williams Partners”) for use in its midstream business. Following the completion of the spin-off of our stock to Williams’ stockholders, we do not expect to continue to provide these services to Williams Partners on a long-term basis. Our sales and marketing activities currently include the management of various natural gas related contracts such as transportation, storage and related hedges. We also sell natural gas purchased from working interest owners in operated wells and other area third party producers. We primarily engage in these activities to enhance the value received from the sale of our natural gas and oil production. Revenues associated with the sale of our production are recorded in oil and gas revenues. The revenues and expenses related to other marketing activities are reported on a gross basis as part of gas management revenues and costs and expenses.
 
Basis of Presentation
 
The combined financial statements included elsewhere in this prospectus have been derived from the accounting records of Williams, principally representing the Exploration & Production segment. We have used the historical results of operations, and historical basis of assets and liabilities of the subsidiaries we do or will own and operate after the consummation of this offering, to prepare the combined financial statements. The following discussion and analysis of results of operations, financial condition and liquidity and critical accounting estimates relates to our current continuing operations and should be read in conjunction with the combined financial statements and notes thereto included in this prospectus.
 
During the first quarter 2011, we initiated a formal process to pursue the divestiture of our holdings in the Arkoma Basin and recorded a pretax impairment charge of $11 million based on an estimated fair value less cost to sell. Our daily Arkoma Basin production is approximately 9 MMcfd, or less than one percent of our total production. As we obtained the requisite approval for disposal and met the other criteria necessary for considering these assets as held for sale and the related operations as discontinued, in the first quarter 2011, we

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have reported our Arkoma operations, including any impairment charges, as discontinued operations for all periods presented. Unless otherwise noted, the following discussion relates to our continuing operations.
 
The Combined Statements of Operations included elsewhere in this prospectus includes allocations of costs for corporate functions historically provided to us by Williams. These allocations include the following costs:
 
Corporate Services.   Represents costs for certain employees of Williams who provide general and administrative services on our behalf. These charges are either directly identifiable or allocated based upon usage factors for our operations. In addition, we receive other allocated costs for our share of general corporate expenses of Williams, which are determined based on our relative use of the service or on a three-factor formula, which considers revenue, properties and equipment and payroll. All of these costs are reflected in general and administrative expense in the Combined Statement of Operations.
 
Employee Benefits and Incentives.   Represents benefit costs and other incentives, including group health and welfare benefits, pension plans, postretirement benefit plans and employee stock-based compensation plans. Costs associated with incentive and stock-based compensation plans are determined on a specific identification basis for certain direct employees. All other employee benefit costs have historically been allocated using a percentage factor derived from a ratio of benefit costs to salary costs for Williams’ domestic employees. These costs are included in lease and facility operating expenses and general and administrative expenses in the Combined Statement of Operations.
 
Subsequent to the completion of this offering, we will be charged for costs related to these corporate services and employee benefits and incentives under an administrative services agreement using methodologies that are consistent with these historic accounting practices.
 
Interest Expense.   Williams utilizes a centralized approach to cash management and the financing of its businesses. Prior to July 2011, cash receipts and cash expenditures for costs and expenses from our domestic operations were transferred to or from Williams on a regular basis and recorded as increases or decreases in the balance due under unsecured promissory notes we had in place with Williams. The notes accrued interest based on Williams’ weighted average cost of debt and such interest was added monthly to the note principal. In June 2011, Williams contributed to our capital all amounts due to it under these notes and prospectively we expect all of the cash receipts and cash expenditures transferred to or from Williams until the completion of this offering will be considered owner’s equity transactions between us and Williams. Subsequent to the completion of this offering, we will maintain separate cash accounts from Williams and our interest expense will relate only to our borrowings (which will consist of the Notes and any amounts drawn under our Credit Facility).
 
Our management believes the assumptions and methodologies underlying the allocation of expenses from Williams are reasonable. However, such expenses may not be indicative of the actual level of expense that would have been or will be incurred by us if we were to operate as an independent, publicly traded company. We will enter into an administrative services agreement and a transition services agreement with Williams that will provide for continuation for some of these services in exchange for fees specified in these agreements. See “Arrangements Between Williams and Our Company.”
 
We believe the assumptions underlying the combined financial statements are reasonable. However, the combined financial statements may not necessarily reflect our future results of operations, financial position and cash flows or what these items would have been had we been a stand-alone company during the periods presented.
 
Overview of the six months ended June 30, 2011 and 2010
 
Domestic production revenues for the first six months of 2011 were higher than the first six months of 2010, primarily because of higher production volumes. Offsetting the impact of higher production volumes was an increase in gathering, processing and transportation expenses due to fees as a result of a new long-term agreement following our fourth quarter 2010 sale of certain gathering and processing assets in the Piceance

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Basin and increases in other expense categories discussed below. Highlights of the comparative periods, primarily related to our production activities, include:

 	 	For the Six Months Ended	 	
 	 	June 30,	 	
 	 	2011	 	 	2010	 	 	% Change	 	
 		
Average daily domestic production (MMcfe/d)	 	 	1,179	 	 	 	1,095	 	 	 	+8	%	
Average daily total production (MMcfe/d)	 	 	1,235	 	 	 	1,151	 	 	 	+7	%	
Domestic production realized average price ($/Mcfe)(1)	 	$	5.46	 	 	$	5.41	 	 	 	+1	%	
Capital expenditures and acquisitions ($ millions)	 	$	683	 	 	$	551	 	 	 	+24	%	
Domestic oil and gas revenues ($ millions)	 	$	1,166	 	 	$	1,072	 	 	 	+9	%	
Revenues ($ millions)	 	$	1,974	 	 	$	2,068	 	 	 	(5	)%	
Operating income ($ millions)	 	$	131	 	 	$	208	 	 	 	(37	)%	

 
			
(1)		Realized average prices include market prices, net of fuel and shrink and hedge gains and losses. The realized hedge gain per Mcfe was $0.66 and $0.64 for the first six months of 2011 and 2010, respectively.	
 
Overview of 2010
 
The effects of the severe economic recession during late 2008 and 2009 eased during 2010. Crude oil and NGL prices have returned to attractive levels, but natural gas prices have remained low. Forward natural gas prices declined during 2010, primarily as a result of significant increases in near- and long-term supplies, which have outpaced near-term demand growth. The decline in forward natural gas prices contributed significantly to impairments we recorded in 2010.
 
In December 2010, we acquired a company that held approximately 85,800 net acres in North Dakota’s Bakken Shale oil play for cash consideration of approximately $949 million. This acquisition diversified our interests into light, sweet crude oil production.
 
In July 2010, we acquired additional leasehold acreage positions in the Marcellus Shale and a five percent overriding royalty interest associated with these acreage positions for cash consideration of $599 million. These acquisitions nearly doubled our net acreage holdings in the Marcellus Shale. During 2010, we also invested a total of $164 million to acquire additional unproved leasehold acreage positions in the Marcellus Shale.
 
In November 2010, we completed the sale of certain gathering and processing assets in the Piceance Basin to Williams Partners for consideration of $702 million in cash and approximately 1.8 million Williams Partners common units. Because the Williams Partners common units received by us in this transaction were intended to be (and have since been) distributed through a dividend to Williams, these units have been presented net within equity. In conjunction with this sale, we entered into a gathering and processing agreement with Williams Partners. Prior periods reflect our costs associated with operating these assets as lease and facility operating costs; depreciation, depletion and amortization; and general and administrative. Our gathering, processing and transportation costs after the sale increased as a result of our new agreement with Williams Partners.
 
Our 2010 operating income (loss) changed unfavorably by $1.7 billion compared to 2009. Operating income (loss) for 2010 includes a $1 billion full impairment charge related to goodwill and $678 million of pre-tax charges associated with impairments of certain producing properties and costs of acquired unproved reserves, while 2009 included an expense of $32 million associated with contractual penalties from the early termination of drilling rig contracts. Partially offsetting these costs is the impact of an improved energy

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commodity price environment in 2010 compared to 2009. Highlights of the comparative periods, primarily related to our production activities, include:

 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Years Ended December 31,	 	
 	 	2010	 	 	2009	 	 	% Change	 	
 		
Average daily domestic production (MMcfe/d)	 	 	1,121	 	 	 	1,175	 	 	 	(5)	%	
Average daily total production (MMcfe/d)	 	 	1,174	 	 	 	1,229	 	 	 	(4)	%	
Domestic production realized average price ($/Mcfe)(1)	 	$	5.22	 	 	$	4.87	 	 	 	+7	%	
Capital expenditures and acquisitions ($ millions)	 	$	2,805	 	 	$	1,434	 	 	 	+96	%	
Domestic oil and gas revenues ($ millions)	 	$	2,136	 	 	$	2,090	 	 	 	+2	%	
Revenues ($ millions)	 	$	4,034	 	 	$	3,681	 	 	 	+10	%	
Operating income (loss) ($ millions)	 	$	(1,337	)	 	$	317	 	 	 	NM	 	

 

 
			
(1)		Realized average prices include market prices, net of fuel and shrink and hedge gains and losses. The realized hedge gain per Mcfe was $0.81 and $1.43 for 2010 and 2009, respectively.	

NM: A percentage calculation is not meaningful due to a change in signs.
 
As a result of significant declines in forward natural gas prices during third quarter 2010, we performed an interim assessment of our capitalized costs related to property and goodwill. As a result of these assessments, we recorded a $503 million impairment charge related to the capitalized costs of our Barnett Shale properties and a $175 million impairment charge related to capitalized costs of acquired unproved reserves in the Piceance Highlands, which were acquired in 2008. Additionally, we fully impaired our goodwill in the amount of $1 billion. These impairments were based on our assessment of estimated future discounted cash flows and other information. See Notes 6 and 14 of Notes to Combined Financial Statements for a further discussion of the impairments.
 
Outlook for 2011

We believe we are well positioned to execute our business strategy of finding and developing reserves and producing natural gas and oil at costs that will generate an attractive rate of return on our incremental development investments. However, a decline in natural gas prices would negatively impact future operating results and increase the risk of nonperformance of counterparties or impairments of long-lived assets.

 
In our assessment for impairment of producing oil and gas properties at December 31, 2010, we noted that approximately 12 percent of our producing assets, primarily located in the Powder River Basin, could be at risk for impairment if the weighted average forward price across all periods used in our cash flow estimates were to decline by approximately 8 to 12 percent, on average, absent changes in other factors impacting estimated future net cash flows. As of June 30, 2011, the impact of changes in forward prices since December 31, 2010 to our cash flow estimates was not indicative of a potential impairment. However, in the period from June 30, 2011 to August 31, 2011, weighted average declines in these forward prices as they relate to the Powder River Basin production projection have at times been as great as six percent. If these forward prices do not recover, we will have to conduct an impairment review of our proved producing oil and gas properties in the Powder River Basin as of September 30, 2011. The net book value of our proved producing assets in the Powder River Basin was approximately $500 million at June 30, 2011. If the recording of an impairment charge becomes necessary as of September 30, 2011, it is reasonably possible that the amount of such charge could be at least $200 million. Any potential interim impairment assessment would include not only a review of forward pricing assumptions but also consideration of other factors impacting estimated future net cash flows, including but not limited to reserve and production estimates, future operating costs, future development costs and production taxes, all of which could impact the need for an impairment, and, if necessary, the amount of such impairment charge.

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We believe that our portfolio of reserves provides an opportunity to continue to grow in our strategic areas, including the Piceance Basin, the Marcellus Shale and the Bakken Shale. We are also focused on developing a more balanced portfolio that may include a larger portion of oil and NGLs reserves and production than we have historically maintained, which we believe will generate long-term, sustainable value for shareholders. Currently, we expect 2011 capital expenditures of approximately $1.3 to $1.6 billion.
 
During late 2010 and 2011, we incurred approximately $8 million of exploratory drilling costs in connection with a well in the Marcellus Shale area of Columbia county, Pennsylvania. Initial results have been inconclusive and we are continuing to assess the reserves and the economic and operating viability of this well. If upon completion of additional testing, we determine that economic reserves are not present, these capitalized costs will be expensed as exploratory dry hole costs. In addition, if such determination were made, we would assess the impact of that decision on our ability to recover the remaining lease acquisition costs associated with this acreage in Columbia county. Such assessment would include our plans to continue drilling in this area. If a determination is made to not continue development in the approximately 7,900 acres associated with this area, we could incur a potential impairment of these costs of up to $40 million.
 
We continue to operate with a focus on increasing shareholder value and investing in our businesses in a way that enhances our competitive position by:

 	•  	Continuing to invest in and grow our production and reserves;	
 		
 	•  	Retaining the flexibility to make adjustments to our planned levels of capital and investment expenditures in response to changes in economic conditions or business opportunities;	
 		
 	•  	Continuing to diversify our commodity portfolio through the development of our Bakken Shale oil play position and liquids-rich basins with high concentrations of NGLs;	
 		
 	•  	Maintaining our industry leadership position in relationship to costs; and	
 		
 	•  	Continuing to maintain an active hedging program around our commodity price risks.	
 
Potential risks or obstacles that could impact the execution of our plan include:

 	•  	Lower than anticipated energy commodity prices;	
 		
 	•  	Lower than expected levels of cash flow from operations;	
 		
 	•  	Unavailability of capital;	
 		
 	•  	Higher capital costs of developing unconventional shale properties;	
 		
 	•  	Counterparty credit and performance risk;	
 		
 	•  	Decreased drilling success;	
 		
 	•  	General economic, financial markets or industry downturn;	
 		
 	•  	Changes in the political and regulatory environments; and	
 		
 	•  	Increase in the cost of, or shortages or delays in the availability of, drilling rigs and equipment, supplies, skilled labor or transportation.	
 
We continue to address certain of these risks through utilization of commodity hedging strategies, disciplined investment strategies and maintaining adequate liquidity. In addition, we utilize master netting agreements and collateral requirements with our counterparties to reduce credit risk and liquidity requirements.
 
Commodity Price Risk Management
 
To manage the commodity price risk and volatility of owning producing gas and oil properties, we enter into derivative contracts for a portion of our future production. For the remainder of 2011, we have the

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following contracts for our daily domestic production, shown at weighted average volumes and basin-level weighted average prices:

 	 	Remainder of 2011 Natural Gas	
 	 	 	 	 	Weighted Average	
 	 	 	 	 	Price ($/MMBtu)	
 	 	Volume	 	 	Floor-Ceiling	
 	 	(BBtu/d)	 	 	for Collars	
 		
Collar agreements — Rockies	 	 	45	 	 	$5.30 - $7.10	
Collar agreements — San Juan	 	 	90	 	 	$5.27 - $7.06	
Collar agreements — Mid-Continent	 	 	80	 	 	$5.10 - $7.00	
Collar agreements — Southern California	 	 	30	 	 	$5.83 - $7.56	
Collar agreements — Northeast	 	 	30	 	 	$6.50 - $8.14	
Fixed price at basin swaps	 	 	385	 	 	$5.22	

 	 	 	 	 	 	 	 	 	
 	 	Remainder of 2011 Crude Oil	 	
 	 	Volume	 	 	Weighted Average	 	
 	 	(Bbls/d)	 	 	Price ($/Bbl)	 	
 		
WTI Crude Oil fixed-price	 	 	4,247	 	 	$	96.31	 	

The following is a summary of our derivative contracts for daily domestic production shown at weighted average volumes and basin-level weighted average prices for the six months ended June 30, 2011 and 2010:

 	 	Natural Gas	
 	 	Six Months Ended June 30,	
 	 	2011	 	2010	
 	 	 	 	 	Weighted	 	 	 	 	Weighted	
 	 	 	 	 	Average Price	 	 	 	 	Average Price	
 	 	 	 	 	($/MMBtu)	 	 	 	 	($/MMBtu)	
 	 	Volume	 	 	Floor-Ceiling	 	Volume	 	 	Floor-Ceiling	
 	 	(BBtu/d)	 	 	for Collars	 	(BBtu/d)	 	 	for Collars	
 		
Collar agreements — Rockies	 	 	45	 	 	$5.30 - $7.10	 	 	100	 	 	$6.53 -$8.94	
Collar agreements — San Juan	 	 	90	 	 	$5.27 - $7.06	 	 	235	 	 	$5.74 - $7.81	
Collar agreements — Mid-Continent	 	 	80	 	 	$5.10 - $7.00	 	 	105	 	 	$5.37 - $7.41	
Collar agreements — Southern California	 	 	30	 	 	$5.83 - $7.56	 	 	45	 	 	$4.80 - $6.43	
Collar agreements — Northeast and other	 	 	30	 	 	$6.50 - $8.14	 	 	25	 	 	$5.61 - $6.85	
NYMEX and basis fixed-price swaps	 	 	360	 	 	$5.22	 	 	120	 	 	$4.41	

 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Crude Oil	 	
 	 	Six Months Ended June 30,	 	
 	 	2011	 	 	2010	 	
 	 	 	 	 	Weighted	 	 	 	 	 	Weighted	 	
 	 	Volume	 	 	Average Price	 	 	Volume	 	 	Average Price	 	
 	 	(Bbls/d)	 	 	($/Bbl)	 	 	(Bbls/d)	 	 	($/Bbl)	 	
 		
WTI Crude Oil fixed-price	 	 	2,367	 	 	 	95.09	 	 	 	—	 	 	 	—	 	

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The following is a summary of our agreements and contracts for daily domestic production shown at weighted average volumes and basin-level weighted average prices for the years ended December 31, 2010, 2009 and 2008:

 	 	2010	 	2009	 	2008	
 	 	 	 	 	Weighted Average	 	 	 	 	Weighted Average	 	 	 	 	Weighted Average	
 	 	 	 	 	Price ($/MMBtu)	 	 	 	 	Price ($/MMBtu)	 	 	 	 	Price ($/MMBtu)	
 	 	Volume	 	 	Floor-Ceiling	 	Volume	 	 	Floor-Ceiling	 	Volume	 	 	Floor-Ceiling	
 	 	(BBtu/d)	 	 	for Collars	 	(BBtu/d)	 	 	for Collars	 	(BBtu/d)	 	 	for Collars	
 		
Collar agreements — Rockies	 	 	100	 	 	$6.53 - $8.94	 	 	150	 	 	$6.11 - $9.04	 	 	170	 	 	$6.16 - $9.14	
Collar agreements — San Juan	 	 	233	 	 	$5.75 - $7.82	 	 	245	 	 	$6.58 - $9.62	 	 	202	 	 	$6.35 - $8.96	
Collar agreements — Mid-Continent	 	 	105	 	 	$5.37 - $7.41	 	 	95	 	 	$7.08 - $9.73	 	 	63	 	 	$7.02 - $9.72	
Collar agreements — Southern California	 	 	45	 	 	$4.80 -$6.43	 	 	—	 	 	—	 	 	—	 	 	—	
Collar agreements — Other	 	 	28	 	 	$5.63 - $6.87	 	 	—	 	 	—	 	 	—	 	 	—	
NYMEX and basis fixed-price swaps	 	 	120	 	 	$4.40	 	 	106	 	 	$3.67	 	 	70	 	 	$3.97	

Additionally, we utilize contracted pipeline capacity to move our production from the Rockies to other locations when pricing differentials are favorable to Rockies pricing. We hold a long-term obligation to deliver on a firm basis 200,000 MMbtu/d of natural gas at monthly index pricing to a buyer at the White River Hub (Greasewood-Meeker, CO), which is a major market hub exiting the Piceance Basin. Our interests in the Piceance Basin hold sufficient reserves to meet this obligation, which expires in 2014.

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Results of Operations
 
Six Month-Over-Six Month Results of Operations
 
The following table and discussion summarize our combined results of operations for the six months ended June 30, 2011 and 2010.

 	 	Historical	 	
 	 	Six Months Ended	 	
 	 	June 30,	 	
 	 	2011	 	 	 	 	 	2010	 	
 	 	(Millions)	 	
 	 	 	 	 	% change	 	 	 	 	
 	 	 	 	 	from 2010	 	 	 	 	
 		
Revenues:	 	 	 	 	 	 	 	 	 	 	 	 	
Oil and gas sales, including affiliate	 	$	1,216	 	 	 	9	%	 	$	1,114	 	
Gas management, including affiliate	 	 	745	 	 	 	(19	)%	 	 	922	 	
Hedge ineffectiveness and mark-to-market gains	 	 	8	 	 	 	(11	)%	 	 	9	 	
Other	 	 	5	 	 	 	(78	)%	 	 	23	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total revenues	 	$	1,974	 	 	 	 	 	 	$	2,068	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Costs and expenses:	 	 	 	 	 	 	 	 	 	 	 	 	
Lease and facility operating, including affiliate	 	 	140	 	 	 	6	%	 	 	132	 	
Gathering, processing and transportation, including affiliate	 	 	240	 	 	 	66	%	 	 	145	 	
Taxes other than income	 	 	76	 	 	 	4	%	 	 	73	 	
Gas management (including charges for unutilized pipeline capacity)	 	 	762	 	 	 	(18	)%	 	 	934	 	
Exploration	 	 	33	 	 	 	83	%	 	 	18	 	
Depreciation, depletion and amortization	 	 	452	 	 	 	4	%	 	 	433	 	
General and administrative, including affiliate	 	 	135	 	 	 	11	%	 	 	122	 	
Other — net	 	 	5	 	 	 	67	%	 	 	3	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total costs and expenses	 	$	1,843	 	 	 	 	 	 	$	1,860	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating income	 	$	131	 	 	 	 	 	 	$	208	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Interest expense, including affiliate	 	 	(97	)	 	 	94	%	 	 	(50	)	
Interest capitalized	 	 	8	 	 	 	—	 	 	 	8	 	
Investment income and other	 	 	12	 	 	 	9	%	 	 	11	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Income from continuing operations before income taxes	 	$	54	 	 	 	 	 	 	$	177	 	
Provision for income taxes	 	 	19	 	 	 	(69	)%	 	 	62	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Income from continuing operations	 	$	35	 	 	 	 	 	 	$	115	 	
Loss from discontinued operations	 	 	(8	)	 	 	NM	 	 	 	(1	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income	 	$	27	 	 	 	 	 	 	$	114	 	
Less: Net income attributable to noncontrolling interests	 	 	5	 	 	 	25	%	 	 	4	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income attributable to WPX Energy	 	$	22	 	 	 	 	 	 	$	110	 	

 

NM: A percentage calculation is not meaningful due to a change in signs, a zero-value denominator or a percentage change greater than 200.
 
The $94 million decrease in total revenues is primarily due to the following:

 	• 	$177 million decrease in gas management revenues primarily due to a 10 percent decrease in average prices on physical natural gas sales and 10 percent lower natural gas sales volumes. We experienced a similar decrease of $172 million in related costs and expenses; and	

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 	• 	$18 million decrease in other revenues primarily related to gathering revenues associated with the gathering and processing assets in Colorado’s Piceance Basin that we sold to Williams Partners in the fourth quarter of 2010.	
 
Partially offsetting these decreases was an increase in oil and gas sales revenues attributable to increased domestic production volumes. Domestic production volumes increased approximately eight percent, resulting in an $82 million revenue increase, while domestic realized average prices (on an Mcfe basis) increased approximately one percent, resulting in a $12 million revenue increase. Oil and gas sales in 2011 and 2010 include approximately $209 million and $136 million, respectively, related to natural gas liquids and approximately $100 million and $25 million, respectively, related to oil and condensate. The increase in NGL revenues is primarily due to higher volumes and prices in our Piceance Basin primarily processed by Williams Partners’ Willow Creek facility. The increase in crude oil and condensate is primarily related to our Bakken properties which were acquired in the fourth quarter of 2010. The increase in crude oil and condensate offset the decrease in realized natural gas prices.
 
The $17 million decrease in costs and expenses is primarily due to the following:

 	• 	$172 million decrease in gas management expenses, primarily due to a 9 percent decrease in average prices on physical natural gas cost of sales and a 10 percent decrease in natural gas sales volumes. This activity represents natural gas purchased in connection with our gas purchase activities for Williams Partners and certain working interest owners’ share of production and to manage our transportation and storage activities. The sales associated with our marketing of this gas are included in gas management revenues. Also included in gas management expenses are $18 million in the first six months of 2011 and $25 million in the first six months of 2010 for unutilized pipeline capacity.	
 
Partially offsetting the decreased costs are increases in costs and expenses, primarily due to the following:

 	• 	$8 million higher lease and facility operating expenses which reflects higher expenses associated with increased workover, water management and maintenance activity, offset by the absence in 2011 of $19 million in expenses associated with the previously owned gathering and processing assets.	
 		
 	• 	$95 million higher gathering, processing, and transportation expenses primarily as a result of fees paid to Williams Partners in 2011 for gathering and processing associated with certain gathering and processing assets in the Piceance Basin that we sold to Williams Partners in the fourth quarter of 2010 and an increase in natural gas liquids volumes processed at Williams Partners’ Willow Creek plant. Our domestic gathering, processing and transportation expenses averaged $1.12 per Mcfe in the first six months of 2011 and $0.73 per Mcfe in the first six months of 2010. In the first six months of 2011, gathering, processing and transportation expenses were $66 million ($0.31/Mcfe) higher due to fees paid to Williams Partners pursuant to the gathering and processing agreement associated with the assets we sold to Williams Partners in the fourth quarter of 2010. During the first six months of 2010, our operating costs were $39 million ($0.20/Mcfe) associated with these assets (primarily reflected in lease and facility operating costs ($19 million) and depreciation, depletion and amortization ($12 million)). These costs are no longer directly incurred as operating costs (but rather as gathering, processing and transportation expenses) as we no longer own or operate these assets. Transportation costs are also higher as a result of the increase in production volumes;	
 		
 	• 	$3 million higher taxes other than income, including severance and ad valorem, primarily due to higher production volumes. Our domestic production taxes averaged $0.31 per Mcfe through June 2011 and $0.33 per Mcfe through June 2010.	
 		
 	• 	$15 million higher exploration expenses primarily due to an increase in impairment, amortization and expiration of unproved leasehold costs. The increase reflects amortization of leasehold acquisition costs associated with the 2010 acquisitions of leaseholds and $5 million related to leases in the Barnett Shale that we now believe are likely to expire in 2011 without further development;	
 		
 	• 	$19 million higher depreciation, depletion and amortization expenses reflects higher production volumes partially offset by the absence of $12 million of depreciation expense related to the assets sold to Williams Partner’s in 2010;	

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 	• 	$13 million higher general and administrative expenses primarily due to higher wages, salary and benefits costs as a result of an increase in the number of employees.	
 
The $77 million decrease in operating income reflects the $94 million decrease in revenues and the previously discussed net changes in costs and expenses.
 
Interest expense increased primarily due to higher average amount outstanding under our unsecured notes payable to Williams.
 
Provision for income taxes decreased due to the decrease in the pre-tax income. See Note 7 of the Notes to Condensed Combined Financial Statements for a discussion of the effective tax rates compared to the federal statutory rate for both periods.
 
Year-Over-Year Results of Operations
 
The following table and discussion summarize our combined results of operations for the years ended December 31, 2010, 2009 and 2008.
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Historical	 	
 	 	Year Ended December 31,	 	
 	 	2010	 	 	 	 	 	2009	 	 	 	 	 	2008	 	
 	 	(Millions)	 	
 	 	 	 	 	% Change	 	 	 	 	 	% Change	 	 	 	 	
 	 	 	 	 	from 2009	 	 	 	 	 	from 2008	 	 	 	 	
Revenues:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Oil and gas sales, including affiliate	 	$	2,225	 	 	 	3	%	 	$	2,168	 	 	 	(25	%)	 	$	2,882	 	
Gas management, including affiliate	 	 	1,742	 	 	 	20	%	 	 	1,456	 	 	 	(55	%)	 	 	3,241	 	
Hedge ineffectiveness and mark-to-market gains and losses	 	 	27	 	 	 	50	%	 	 	18	 	 	 	(38	%)	 	 	29	 	
Other	 	 	40	 	 	 	3	%	 	 	39	 	 	 	22	%	 	 	32	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total revenues	 	$	4,034	 	 	 	 	 	 	$	3,681	 	 	 	 	 	 	$	6,184	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Costs and expenses:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Lease and facility operating, including affiliate	 	$	286	 	 	 	9	%	 	$	263	 	 	 	(3	%)	 	$	272	 	
Gathering, processing and transportation, including affiliate	 	 	326	 	 	 	19	%	 	 	273	 	 	 	19	%	 	 	229	 	
Taxes other than income	 	 	125	 	 	 	34	%	 	 	93	 	 	 	(63	%)	 	 	254	 	
Gas management (including charges for unutilized pipeline capacity)	 	 	1,771	 	 	 	18	%	 	 	1,495	 	 	 	(54	%)	 	 	3,248	 	
Exploration	 	 	73	 	 	 	35	%	 	 	54	 	 	 	46	%	 	 	37	 	
Depreciation, depletion and amortization	 	 	875	 	 	 	(1	%)	 	 	887	 	 	 	20	%	 	 	738	 	
Impairment of producing properties and costs of acquired unproved reserves	 	 	678	 	 	 	NM	 	 	 	15	 	 	 	NM	 	 	 	—	 	
Goodwill impairment	 	 	1,003	 	 	 	NM	 	 	 	—	 	 	 	NM	 	 	 	—	 	
General and administrative, including affiliate	 	 	253	 	 	 	1	%	 	 	251	 	 	 	2	%	 	 	247	 	
Gain on sale of contractual right to international production payment	 	 	—	 	 	 	NM	 	 	 	—	 	 	 	NM	 	 	 	(148	)	
Other — net	 	 	(19	)	 	 	NM	 	 	 	33	 	 	 	NM	 	 	 	6	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total costs and expenses	 	$	5,371	 	 	 	 	 	 	$	3,364	 	 	 	 	 	 	$	4,883	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating income (loss)	 	$	(1,337	)	 	 	 	 	 	$	317	 	 	 	 	 	 	$	1,301	 	
Interest expense, including affiliate	 	 	(124	)	 	 	24	%	 	 	(100	)	 	 	35	%	 	 	(74	)	
Interest capitalized	 	 	16	 	 	 	(11	%)	 	 	18	 	 	 	(10	%)	 	 	20	 	
Investment income and other	 	 	21	 	 	 	163	%	 	 	8	 	 	 	(64	%)	 	 	22	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income (loss) from continuing operations before income taxes	 	$	(1,424	)	 	 	 	 	 	$	243	 	 	 	 	 	 	$	1,269	 	
Provision (benefit) for income taxes	 	 	(150	)	 	 	NM	 	 	 	94	 	 	 	(79	%)	 	 	452	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income (loss) from continuing operations	 	$	(1,274	)	 	 	 	 	 	$	149	 	 	 	 	 	 	$	817	 	
Loss from discontinued operations	 	 	(8	)	 	 	 	 	 	 	(7	)	 	 	 	 	 	 	(87	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income (loss)	 	$	(1,282	)	 	 	 	 	 	$	142	 	 	 	 	 	 	$	730	 	
Less: Net income attributable to noncontrolling interests	 	 	8	 	 	 	33	%	 	 	6	 	 	 	(25	%)	 	 	8	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income (loss) attributable to WPX Energy	 	$	(1,290	)	 	 	 	 	 	$	136	 	 	 	 	 	 	$	722	 	

 

NM: A percentage calculation is not meaningful due to a change in signs, a zero-value denominator or a percentage change greater than 200.

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2010 vs. 2009
 
The increase in total revenues is primarily due to the following:

 	•  	$57 million higher oil and gas sales revenues from an increase of $142 million resulting from a seven percent increase in domestic realized average prices including the effect of hedges, partially offset by a decrease of $97 million associated with a five percent decrease in domestic production volumes sold. Oil and gas revenues in 2010 and 2009 include approximately $282 million and $136 million, respectively, related to NGLs and approximately $57 million and $38 million, respectively, related to condensate; and	
 		
 	•  	$286 million higher gas management revenues primarily from a 21 percent increase in average prices on domestic physical natural gas sales associated with our transportation and storage contracts. There is a similar increase of $276 million in related costs and expenses.	
 
The increase in costs and expenses is primarily due to the following:

 	•  	$23 million higher lease and facility operating expenses due to increased activity and generally higher industry costs. Our average domestic lease and facility operating expenses are $0.65 per Mcfe in 2010 and $0.58 per Mcfe in 2009. The increase in the per unit amount results primarily from an increase in costs incurred to maintain individual well production rates and higher industry costs;	
 		
 	•  	$53 million higher gathering, processing and transportation expenses, primarily as a result of processing fees charged by Williams Partners at its Willow Creek plant for extracting NGLs from a portion of our Piceance Basin gas production. Our domestic gathering, processing and transportation expenses averaged $0.80 per Mcfe in 2010 and $0.64 per Mcfe in 2009. The increase in the per unit amount is primarily a result of the Willow Creek plant going into service in August 2009 resulting in a partial year of processing. This processing provides us additional NGL recovery, the revenues for which are included in oil and gas sales in the Combined Statement of Operations;	
 		
 	•  	$32 million higher taxes other than income, including severance and ad valorem, primarily due to higher average commodity prices (excluding the impact of hedges). Our domestic production taxes averaged $0.27 per Mcfe in 2010 and $0.19 per Mcfe in 2009. The increase in the per unit amount is primarily the result of higher average domestic commodity prices;	
 		
 	•  	$276 million increase in gas management expenses, primarily due to an 18 percent increase in average prices on domestic physical natural gas cost of sales. This activity represents natural gas purchased in connection with our gas purchase activities for Williams Partners and certain working interest owners’ share of production, and to manage our transportation and storage activities. The sales associated with our marketing of this gas are included in gas management revenues. Also included in gas management expenses are $48 million in 2010 and $21 million in 2009 for unutilized pipeline capacity;	
 		
 	•  	$19 million higher exploration expense primarily due to an increase in impairment, amortization and expiration of unproved leasehold costs; and	
 		
 	•  	$1,681 million impairments of property and goodwill in 2010 as previously discussed. In 2009, $15 million of impairments were recorded in the Barnett Shale.	
 
Partially offsetting the increased costs and expenses in 2010 are decreases due to the following:

 	•  	$12 million lower depreciation, depletion and amortization expenses primarily due to lower domestic production volumes; and	
 		
 	•  	Other — net includes $32 million of expenses in 2009 related to penalties from the early release of drilling rigs.	
 
The $1,654 million decrease in operating income (loss) is primarily due to the impairments, partially offset by a seven percent increase in domestic realized average prices on production and the other previously discussed changes in revenues and costs and expenses.

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Interest expense increased primarily due to higher average amounts outstanding under our unsecured notes payable to Williams.
 
Provision (benefit) for income taxes changed favorably due to the pre-tax loss in 2010 compared to pre-tax income in 2009. See Note 10 of Notes to Combined Financial Statements for a reconciliation of the effective tax rates compared to the federal statutory rate for both years.
 
2009 vs. 2008
 
The decrease in total revenues is primarily due to the following:

 	•  	$714 million lower oil and gas sales revenues primarily from a $915 million decrease resulting from a 30 percent decrease in domestic realized average prices, partially offset by an increase of $194 million associated with a seven percent increase in domestic production volumes sold. Oil and gas revenues in 2009 and 2008 include approximately $136 million and $89 million, respectively, related to NGLs and approximately $38 million and $62 million, respectively, related to condensate. While NGL volumes were significantly higher than the prior year, NGL prices were significantly lower;	
 		
 	•  	$1,785 million lower gas management revenues primarily from a 56 percent decrease in average prices on domestic physical natural gas sales associated with our transportation and storage contracts. There is a similar decrease of $1,753 million in related costs and expenses; and	
 		
 	•  	$11 million lower hedge ineffectiveness and mark-to-market gains and losses primarily due to the absence of a $10 million favorable impact in 2008 for the initial consideration of our own nonperformance risk in estimating the fair value of our derivative liabilities.	
 
The decrease in total costs and expenses is primarily due to the following:

 	•  	$161 million lower taxes other than income, including severance and ad valorem, primarily due to 50 percent lower average commodity prices (excluding the impact of hedges), partially offset by higher production volumes sold. The lower operating taxes include a net decrease of $39 million reflecting a $34 million charge in 2008 and $5 million of favorable revisions in 2009 relating to Wyoming severance and ad valorem taxes. Our domestic production taxes averaged $0.19 per Mcfe in 2009 and $0.60 per Mcfe in 2008. The decrease in the per unit amount is primarily the result of lower average commodity prices;	
 		
 	•  	$1,753 million decrease in gas management expenses, primarily due to a 55 percent decrease in domestic average prices on physical natural gas cost of sales, slightly offset by a 2 percent increase in natural gas sales volumes. This decrease is primarily related to the natural gas purchases associated with our previously discussed transportation and storage contracts and is more than offset by a decrease in revenues. Gas management expenses in 2009 and 2008 include $21 million and $8 million, respectively, related to charges for unutilized pipeline capacity. Gas management expenses in 2009 and 2008 also include $7 million and $35 million, respectively, related to lower of cost or market charges to the carrying value of natural gas inventories in storage; and	
 
Partially offsetting the decreased costs and expenses are increases due to the following:

 	•  	$44 million higher gathering, processing and transportation expense primarily due to higher production volumes and the processing fees for NGLs at Williams Partners’ Willow Creek plant, which began processing in August 2009. Our domestic gathering, processing and transportation expenses averaged $0.64 per Mcfe in 2009 and $0.57 per Mcfe in 2008. The increase in the per unit amount is primarily a result of the initiation of processing at the Willow Creek plant in 2009 as previously discussed; and	
 		
 	•  	$17 million higher exploration expense primarily due to an increase in geologic and geophysical services.	
 		
 	•  	$149 million higher depreciation, depletion and amortization expense primarily due to higher capitalized drilling costs from prior years and higher production volumes compared to the prior year. Also, we recorded an additional $17 million of depreciation, depletion and amortization in the fourth	

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 		quarter of 2009 primarily due to new SEC reserves reporting rules. Our proved reserves decreased primarily due to the new SEC reserves reporting rules and the related price impact;	

 	•  	The absence in 2009 of a $148 million gain recorded in 2008 from the sale of our contractual right to a production payment in Peru;	
 		
 	•  	$32 million of expense in 2009 related to penalties from the early release of drilling rigs as previously discussed; and	
 		
 	•  	$15 million of impairment expense in 2009 related to costs of acquired unproved reserves from our 2008 acquisition in the Barnett Shale. This impairment was based on our assessment of estimated future discounted cash flows and additional information obtained from drilling and other activities in 2009.	
 
The $984 million decrease in operating income is primarily due to the 30 percent decrease in realized average domestic prices and the other previously discussed changes in revenues and costs and expenses.
 
Provision (benefit) for income taxes changed favorably primarily due to lower pre-tax income. See Note 10 of Notes to Combined Financial Statements for a reconciliation of the effective tax rates compared to the federal statutory rate for both years.
 
Management’s Discussion and Analysis of Financial Condition and Liquidity
 
Overview
 
In 2010, we continued to focus upon growth through continued disciplined investments in expanding our natural gas, oil and NGL portfolio. Examples of this growth included continued investment in our development drilling programs, as well as acquisitions that expanded our presence in the Marcellus Shale and provided our initial entry into the Bakken Shale areas. These investments were funded through cash flow from operations, advances on our notes payable from Williams and the proceeds from the sale of our Piceance Basin gathering and processing assets to Williams Partners.
 
Our historical liquidity needs have been managed through an internal cash management program with Williams. Daily cash activity from our domestic operations was transferred to or from Williams on a regular basis and was recorded as increases or decreases in the balance due under unsecured promissory notes we had in place with Williams through June 30, 2011 at which time the notes were cancelled by Williams. Any future cash activity is expected to be treated as capital transfers until the Offering. In consideration of our liquidity under these conditions, we note the following:

 	•  	As of June 30, 2011, Williams maintained liquidity through cash, cash equivalents and available credit capacity under credit facilities. Additionally, at that date we had an unsecured credit agreement that served to reduce our margin requirements related to our hedging activities. See additional discussion in the following “—Liquidity” section.	
 		
 	•  	Our credit exposure to derivative counterparties is partially mitigated by master netting agreements and collateral support.	
 		
 	•  	Apco’s liquidity requirements have historically been provided by its cash flows from operations.	
 
Outlook
 
Upon completion of this offering, we expect our capital structure will provide us financial flexibility to meet our requirements for working capital, capital expenditures and tax and debt payments while maintaining a sufficient level of liquidity. We intend to retain approximately $500 million of the net proceeds from this offering and to distribute the remaining net proceeds, along with all of the net proceeds from the offering of the Notes, to Williams. We also expect to have access to our new unsecured $1.5 billion Credit Facility that is expected to become effective at the time this offering is complete. This Credit Facility combined with the $500 million in cash described above and our expected cash flows from operations should be sufficient to allow us to pursue our business strategy and goals for 2011 and 2012.

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If energy commodity prices are lower than we expect for 2011, we believe the effect on our cash flows from operations would be partially mitigated by our hedging program. In addition, we note the following assumptions for 2011:

 	•  	Our capital expenditures are estimated to be between $1.3 billion and $1.6 billion, and are generally considered to be largely discretionary; and	
 		
 	•  	Apco’s liquidity requirements will continue to be provided from its cash flows from operations and available liquidity under its credit facility.	
 
Potential risks associated with our planned levels of liquidity and the planned capital and investment expenditures discussed above include:

 	•  	Sustained reductions in energy commodity prices from the range of current expectations;	
 		
 	•  	Lower than expected levels of cash flow from operations; and	
 		
 	•  	Higher than expected collateral obligations that may be required, including those required under new commercial agreements.	
 
Liquidity
 
We plan to conservatively manage our balance sheet. Subsequent to this offering, we expect to maintain liquidity through a combination of cash on hand and available capacity under our $1.5 billion Credit Facility. In addition, we expect our forecasted levels of cash flow from operations to provide additional liquidity to assist us in meeting our desired level of capital expenditures and working capital requirements. Additional sources of liquidity, if needed, could be sought through bank financings, the issuance of long term debt and equity securities and proceeds from asset sales.
 
Currently we utilize an unsecured credit arrangement in order to reduce margin requirements related to our hedging activities as well as lower transaction fees. We expect that this facility will be terminated concurrently with the completion of this offering and the expected issuance of our Notes and effectiveness of our Credit Facility. Upon termination, we expect we will be able to negotiate agreements with the respective counterparties to our hedging contracts and keep margin requirements, if any, to a minimum.
 
We have certain contractual obligations, primarily interstate transportation agreements, which contain collateral support requirements based on our credit ratings. Because Williams has an investment grade credit rating and guaranteed these contracts, we have not historically been required to provide collateral support. After the completion of this offering, Williams has informed us that it expects it will obtain releases of the guarantees. Depending on our credit rating, we anticipate issuing letters of credit under our Credit Facility of $295 million to satisfy the provisions of these contracts but the amount could be up to $500 million.
 
Our ability to borrow money will be impacted by several factors, including our credit ratings. Credit ratings agencies perform independent analysis when assigning credit ratings. A lower than anticipated initial credit rating or a downgrade of that rating would increase our future cost of borrowing and could result in a requirement that we post additional collateral with third parties, thereby negatively affecting our available liquidity.
 
In conjunction with the completion of this offering, Williams will provide us with approximately $20 million in cash to assist in the funding of certain information technology transition costs and expenses we expect to incur following the completion of this offering. The entire amount we receive from Williams will be recorded as a capital contribution from Williams upon receipt and any future amounts we spend on such information technology transition costs and expenses will be recorded as increases in our assets or expenses depending on the specific nature of the costs.

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Sources (Uses) of Cash
 
Six Months-Over-Six Months
 
The following table and discussion summarize our sources (uses) of cash for the six months ended June 30, 2011 and 2010.

 	 	Six Months	 	
 	 	Ended June 30,	 	
 	 	2011	 	 	2010	 	
 	 	(Millions)	 	
 		
Net cash provided (used) by:	 	 	 	 	 	 	 	 	
Operating activities	 	$	523	 	 	$	526	 	
Investing activities	 	 	(667	)	 	 	(554	)	
Financing activities	 	 	143	 	 	 	28	 	
 	 	 	 	 	 	 	 	 	
Decrease in cash and cash equivalents	 	$	(1	)	 	$	—	 	

 
Operating activities
 
Our net cash provided by operating activities in 2011 decreased from 2010 primarily due to higher operating costs, primarily gathering, processing and transportation costs and higher interest expense and net changes in our operating assets and liabilities.
 
Investing activities
 
Our net cash used by investing activities in 2011 increased from 2010 primarily due to capital expenditures. Expenditures for drilling and completion were approximately $609 million in 2011 and $422 million in 2010.
 
Financing activities
 
Our net cash provided by financing activities in 2011 increased from 2010 primarily due to higher borrowings from Williams to fund our capital expenditures as a result of the decrease in cash provided by operating activities in 2011. Additionally, we incurred $8 million of revolving debt facility costs that relate to the $1.5 billion Credit Facility that is expected to become effective at the time this offering is completed.
 
Year-Over-Year
 
The following table and discussion summarize our sources (uses) of cash for the years ended December 31, 2010, 2009 and 2008.

 	 	Years Ended December 31,	 	
 	 	2010	 	 	2009	 	 	2008	 	
 	 	 	 	 	(Millions)	 	 	 	 	
 		
Net cash provided (used) by:	 	 	 	 	 	 	 	 	 	 	 	 	
Operating activities	 	$	1,056	 	 	$	1,181	 	 	$	2,009	 	
Investing activities	 	 	(2,337	)	 	 	(1,435	)	 	 	(2,252	)	
Financing activities	 	 	1,284	 	 	 	256	 	 	 	225	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Increase (decrease) in cash and cash equivalents	 	$	3	 	 	$	2	 	 	$	(18	)	

 
Operating activities
 
Our net cash provided by operating activities in 2010 decreased from 2009 primarily due to the payments made to reduce certain accrued liabilities affecting our operations.

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Our net cash provided by operating activities in 2009 decreased primarily due to the lower realized energy commodity prices during 2009 when compared to 2008.
 
Investing activities
 
Our net cash used by investing activities in 2010 increased from 2009 primarily due to our capital expenditures related to the acquisition of Marcellus Shale properties and our entry into the Bakken Shale.
 
Significant expenditures include:
 
2010

 	•  	Expenditures for drilling and completion were approximately $950 million.	
 		
 	•  	Our acquisition in July 2010 of properties in the Marcellus Shale for $599 million (see “—Overview of 2010”).	
 		
 	•  	Our acquisition in December 2010 of oil and gas properties in the Bakken Shale for $949 million (see “—Overview of 2010”).	
 		
 	•  	The sale in November 2010 of certain gathering and processing assets in the Piceance Basin to Williams Partners for $702 million in cash and approximately 1.8 million Williams Partners common units, which units were subsequently distributed to Williams.	
 
2009

 	•  	Expenditures for drilling and completion were approximately $1.0 billion.	
 		
 	•  	A $253 million payment for the purchase of additional properties in the Piceance Basin.	
 
2008

 	•  	Expenditures for drilling and completion were approximately $1.65 billion.	
 		
 	•  	Acquisitions of certain interests in the Piceance Basin for $285 million. A third party subsequently exercised its contractual option to purchase a 49 percent interest in a portion of the acquired assets for $71 million.	
 		
 	•  	Our sale of a contractual right to a production payment in Peru for $148 million.	
 
Financing activities
 
Our net cash provided by financing activities in 2010 increased from 2009 primarily due to higher borrowings from Williams to fund our capital expenditures, including those related to the acquisition of Marcellus Shale properties and our acquisition in the Bakken Shale.
 
Off-Balance Sheet Financing Arrangements
 
We had no guarantees of off-balance sheet debt to third parties or any other off-balance sheet arrangements at June 30, 2011 and December 31, 2010.

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Contractual Obligations
 
The table below summarizes the maturity dates of our contractual obligations at June 30, 2011, including obligations related to discontinued operations.

 	 	July 1 -	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	December 31,	 	 	2012 -	 	 	2014 -	 	 	 	 	 	 	 	
 	 	2011	 	 	2013	 	 	2015	 	 	Thereafter	 	 	Total	 	
 	 	(Millions)	 	
 		
Long-term debt	 	$	—	 	 	$	2	 	 	$	—	 	 	$	—	 	 	$	2	 	
Operating leases and associated service commitments	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Drilling rig commitments(1)	 	 	77	 	 	 	215	 	 	 	115	 	 	 	—	 	 	 	407	 	
Other	 	 	4	 	 	 	8	 	 	 	5	 	 	 	16	 	 	 	33	 	
Transportation and storage commitments(2)	 	 	102	 	 	 	423	 	 	 	343	 	 	 	633	 	 	 	1,501	 	
Natural gas purchase commitments(3)	 	 	90	 	 	 	425	 	 	 	376	 	 	 	880	 	 	 	1,771	 	
Oil and gas activities(4)	 	 	114	 	 	 	372	 	 	 	152	 	 	 	232	 	 	 	870	 	
Other long-term liabilities, including current portion:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Physical and financial derivatives(5)(6)	 	 	315	 	 	 	1,071	 	 	 	897	 	 	 	3,947	 	 	 	6,230	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	$	702	 	 	$	2,516	 	 	$	1,888	 	 	$	5,708	 	 	$	10,814	 	

 

			
(1)		Includes materials and services obligations associated with our drilling rig contracts.	
 		
(2)		Excludes additional commitments totaling $240 million associated with projects for which the counterparty has not yet received satisfactory regulatory approvals.	
 		
(3)		Purchase commitments are at market prices and the purchased natural gas can be sold at market prices. The obligations are based on market information as of June 30, 2011 and contracts are assumed to remain outstanding for their full contractual duration. Because market information changes daily and is subject to volatility, significant changes to the values in this category may occur. Certain parties have elected to convert their gas purchase agreements to firm gathering and processing agreements, which services will be provided by an affiliate of ours. WPX Energy’s gas purchase obligations amounting to $900 million will terminate at the effective date of the new agreements.	
 		
(4)		Includes gathering, processing and other oil and gas related services commitments. Excluded are liabilities associated with asset retirement obligations, which total $309 million as of June 30, 2011. The ultimate settlement and timing can not be precisely determined in advance; however, we estimate that less than 10% of this liability will be settled in the next five years.	
 		
(5)		Includes $5.5 billion of physical natural gas derivatives related to purchases at market prices. The natural gas expected to be purchased under these contracts can be sold at market prices, largely offsetting this obligation. The obligations for physical and financial derivatives are based on market information as of June 30, 2011, and assume contracts remain outstanding for their full contractual duration. Because market information changes daily and is subject to volatility, significant changes to the values in this category may occur.	
 		
(6)		Expected offsetting cash inflows of $3.5 billion at June 30, 2011, resulting from product sales or net positive settlements, are not reflected in these amounts. In addition, product sales may require additional purchase obligations to fulfill sales obligations that are not reflected in these amounts.	
 
Effects of Inflation
 
Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy. Operating costs are influenced by both competition for specialized services and specific price changes in natural gas, oil, NGLs and other commodities. We tend to experience inflationary pressure on the cost of services and equipment as increasing oil and gas prices increase drilling activity in our areas of operation.
 
Environmental
 
We are subject to the Clean Air Act (“CAA”) and to the Clean Air Act Amendments of 1990 (“1990 Amendments”), which added significantly to the existing requirements established by the CAA. Pursuant to

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requirements of the 1990 Amendments and EPA rules designed to mitigate the migration of ground-level ozone (“NOx”), we are planning installation of air pollution controls on existing sources at certain facilities in order to reduce NOx emissions. For many of these facilities, we are developing more cost effective and innovative compressor engine control designs.

In March 2008, the EPA promulgated a new, lower National Ambient Air Quality Standard (“NAAQS”) for NOx. Within two years, the EPA was expected to designate new eight-hour ozone non-attainment areas. However, in September 2009, the EPA announced it would reconsider the 2008 NAAQS for NOx to ensure that the standards were clearly grounded in science and were protective of both public health and the environment. As a result, the EPA delayed designation of new eight-hour ozone non-attainment areas under the 2008 standards until the reconsideration is complete. In January 2010, the EPA proposed to further reduce the NOx NAAQS from the March 2008 levels. The EPA has indicated that it will finalize this standard during 2011. Designation of new eight-hour ozone non-attainment areas are expected to result in additional federal and state regulatory actions that will likely impact our operations and increase the cost of additions to property, plant and equipment — net on the Combined Balance Sheet. We are unable at this time to estimate the cost of additions that may be required to meet this new regulation.

Under the CAA, the EPA must review and if appropriate revise New Source Review Standards every eight years. EPA has agreed to a proposed consent decree to revise the leak detection and repair requirements for oil and gas facilities. Under the consent agreement, EPA must finalize those rules by November 2011.
 
Additionally, in August 2010, the EPA promulgated National Emission Standards for Hazardous Air Pollutants (“NESHAP”) regulations that will impact our operations. Furthermore, the EPA promulgated the Greenhouse Gas (“GHG”) Mandatory Reporting Rule on October 30, 2009, which requires facilities that emit 25,000 metric tons or more of carbon dioxide equivalent per year from stationary fossil fuel combustion sources to report GHG emissions to the EPA annually beginning September 30, 2011 for calendar year 2010. On November 30, 2010, the EPA issued additional regulations that expand the scope of the Mandatory Reporting Rule to include fugitive and vented greenhouse gas emissions effective January 1, 2011. Facilities that emit 25,000 metric tons or more carbon dioxide equivalent per year from stationary fossil-fuel combustion and fugitive/vented sources combined will be required to report GHG combustion and fugitive/vented emissions to the EPA annually beginning March 31, 2012, for calendar year 2011.
 
In February 2010, the EPA promulgated a final rule establishing a new one-hour nitrogen dioxide NAAQS. The effective date of the new nitrogen dioxide standard was April 12, 2010. This new standard is subject to numerous challenges in the federal court. We are unable at this time to estimate the cost of additions that may be required to meet this new regulation.
 
Our facilities and operations are also subject to the Clean Water Act (“CWA”) and implementing regulations of the EPA and the U.S. Army Corps of Engineers (“Corps”). On April 27, 2011, the EPA and the Corps released new draft guidance governing federal jurisdiction over wetlands and other “isolated waters.” They would, if adopted, significantly expand federal jurisdiction and permitting requirements under the CWA. Additionally, the draft guidance addresses the expanded scope of the CWA’s key term “waters of the United States” to all CWA provisions, which prior guidance limited to Section 404 determinations. We are unable at this time to estimate the cost that may be required to meet this proposed guidance.
 
Quantitative and Qualitative Disclosures About Market Risk
 
Interest Rate Risk
 
Historically, our current interest rate risk exposure was substantially mitigated through our cash management program and the effects of our intercompany note with Williams. The Notes will be fixed rate debt in order to mitigate the impact of fluctuations in interest rates and we expect that any borrowings under our Credit Facility could be at a variable interest rate and could expose us to the risk of increasing interest rates. See Note 4 of Notes to Combined Financial Statements.

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Commodity Price Risk
 
We are exposed to the impact of fluctuations in the market price of natural gas, NGLs and crude oil, as well as other market factors, such as market volatility and energy commodity price correlations. We are exposed to these risks in connection with our owned energy-related assets, our long-term energy-related contracts and our proprietary trading activities. We manage the risks associated with these market fluctuations using various derivatives and nonderivative energy-related contracts. The fair value of derivative contracts is subject to many factors, including changes in energy commodity market prices, the liquidity and volatility of the markets in which the contracts are transacted and changes in interest rates. See Note 15 of Notes to Combined Financial Statements.
 
We measure the risk in our portfolios using a value-at-risk methodology to estimate the potential one-day loss from adverse changes in the fair value of the portfolios. Value at risk requires a number of key assumptions and is not necessarily representative of actual losses in fair value that could be incurred from the portfolios. Our value-at-risk model uses a Monte Carlo method to simulate hypothetical movements in future market prices and assumes that, as a result of changes in commodity prices, there is a 95 percent probability that the one-day loss in fair value of the portfolios will not exceed the value at risk. The simulation method uses historical correlations and market forward prices and volatilities. In applying the value-at-risk methodology, we do not consider that the simulated hypothetical movements affect the positions or would cause any potential liquidity issues, nor do we consider that changing the portfolios in response to market conditions could affect market prices and could take longer than a one-day holding period to execute. While a one-day holding period has historically been the industry standard, a longer holding period could more accurately represent the true market risk given market liquidity and our own credit and liquidity constraints.
 
We segregate our derivative contracts into trading and nontrading contracts, as defined in the following paragraphs. We calculate value at risk separately for these two categories. Contracts designated as normal purchases or sales and nonderivative energy contracts have been excluded from our estimation of value at risk.
 
We have policies and procedures that govern our trading and risk management activities. These policies cover authority and delegation thereof in addition to control requirements, authorized commodities and term and exposure limitations. Value-at-risk is limited in aggregate and calculated at a 95 percent confidence level.
 
Trading
 
Our trading portfolio consists of derivative contracts entered into for purposes other than economically hedging our commodity price-risk exposure. The fair value of our trading derivatives was a net asset of $1 million at June 30, 2011 and a net asset of $2 million at December 31, 2010. The value at risk for contracts held for trading purposes was less than $1 million at June 30, 2011, December 31, 2010 and December 31, 2009.
 
Nontrading
 
Our nontrading portfolio consists of derivative contracts that hedge or could potentially hedge the price risk exposure from our natural gas purchases and sales. The fair value of our derivatives not designated as hedging instruments was a net asset of $4 million and $16 million at June 30, 2011 and December 31, 2010, respectively.
 
The value at risk for derivative contracts held for nontrading purposes was $29 million at June 30, 2011, $24 million at December 31, 2010, and $34 million at December 31, 2009. During the year ended December 31, 2010, our value at risk for these contracts ranged from a high of $33 million to a low of $21 million. The decrease in value at risk from December 31, 2009 primarily reflects the realization of certain derivative positions and the market price impact, partially offset by new derivative contracts.
 
Certain of the derivative contracts held for nontrading purposes are accounted for as cash flow hedges. Of the total fair value of nontrading derivatives, cash flow hedges had a net asset value of $182 million and $266 million as of June 30, 2011 and December 31, 2010, respectively. Though these contracts are included in our value-at-risk calculation, any changes in the fair value of the effective portion of these hedge contracts would generally not be reflected in earnings until the associated hedged item affects earnings.

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Critical Accounting Estimates
 
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates, judgments and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. We believe that the nature of these estimates and assumptions is material due to the subjectivity and judgment necessary, or the susceptibility of such matters to change, and the impact of these on our financial condition or results of operations.
 
In our management’s opinion, the more significant reporting areas impacted by management’s judgments and estimates are impairments of goodwill and long-lived assets, accounting for derivative instruments and hedging activities, successful efforts method of accounting, contingent liabilities, valuation of deferred tax assets and tax contingencies.
 
Impairments of Goodwill and Long-Lived Assets
 
We have assessed goodwill for impairment annually as of the end of the year and we have performed interim assessments of goodwill if impairment triggering events or circumstances were present. One such triggering event is a significant decline in forward natural gas prices. Early in 2010, we evaluated the impact of declines in forward gas prices across all future production periods and determined that the impact was not significant enough to warrant a full impairment review. Forward natural gas prices through 2025 used in these prior analyses had declined less than 10 percent, on average, from December 31, 2009 through March 31, 2010 and June 30, 2010. During the third quarter of 2010, these forward natural gas prices through 2025 declined an additional 19 percent for a total year-to-date decline of more than 22 percent on average through September 30, 2010. Based on forward prices as of September 30, 2010, we evaluated the impact of this decline across all future production periods and determined that a full impairment review was warranted.
 
As a result, we evaluated our goodwill of approximately $1 billion resulting from a 2001 acquisition related to our domestic natural gas production operations (the “reporting unit”). Our impairment evaluation of goodwill first considered management’s estimate of the fair value of the reporting unit compared to its carrying value, including goodwill. If the carrying value of the reporting unit exceeded its fair value, a computation of the implied fair value of the goodwill was compared with its related carrying value. If the carrying value of the reporting unit goodwill exceeded the implied fair value of that goodwill, an impairment loss was recognized in the amount of the excess. Because quoted market prices were not available for the reporting unit, management applied reasonable judgments (including market supported assumptions when available) in estimating the fair value for the reporting unit. We estimated the fair value of the reporting unit on a stand-alone basis and also considered Williams’ market capitalization and third party estimates in corroborating our estimate of the fair value of the reporting unit.
 
The fair value of the reporting unit was estimated primarily by valuing proved and unproved reserves. We use an income approach (discounted cash flows) for valuing reserves, based on inputs we believed would be utilized by market participants. The significant inputs into the valuation of proved and unproved reserves include reserve quantities, forward natural gas prices, anticipated drilling and operating costs, anticipated production curves, income taxes and appropriate discount rates. To estimate the fair value of the reporting unit and the implied fair value of goodwill under a hypothetical acquisition of the reporting unit, we assumed a tax structure where a buyer would obtain a step-up in the tax basis of the net assets acquired.
 
In our assessment as of September 30, 2010, the carrying value of the reporting unit, including goodwill, exceeded its fair value. We then determined that the implied fair value of the goodwill was zero. As a result, we recognized a full $1 billion impairment charge related to our goodwill. See Notes 6 and 14 of Notes to Combined Financial Statements for additional discussion and significant inputs into the fair value determination.
 
We evaluate our long-lived assets for impairment when we believe events or changes in circumstances indicate that we may not be able to recover the carrying value. Our computations utilize judgments and

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assumptions that include the estimated fair value of the asset, undiscounted future cash flows, discounted future cash flows and the current and future economic environment in which the asset is operated.
 
As a result of significant declines in forward natural gas prices during the third quarter of 2010, we assessed our natural gas producing properties and acquired unproved reserve costs for impairment using estimates of future cash flows. Significant judgments and assumptions in these assessments include estimates of natural gas reserves quantities, estimates of future natural gas prices using a forward NYMEX curve adjusted for locational basis differentials, drilling plans, expected capital costs and our estimate of an applicable discount rate commensurate with the risk of the underlying cash flow estimates. The assessment performed at September 30, 2010 identified certain properties with a carrying value in excess of their calculated fair values. As a result, we recognized a $678 million impairment charge. See Notes 6 and 14 of Notes to Combined Financial Statements for additional discussion and significant inputs into the fair value determination.

In addition to those long-lived assets described above for which impairment charges were recorded, certain others were reviewed for which no impairment was required. These reviews included our other domestic producing properties and acquired unproved reserve costs, and utilized inputs generally consistent with those described above. Judgments and assumptions are inherent in our estimate of future cash flows used to evaluate these assets. The use of alternate judgments and assumptions could result in the recognition of different levels of impairment charges in the combined financial statements. For certain other producing assets reviewed, but for which impairment charges were not recorded, we estimate that approximately 12 percent could be at risk for impairment if forward prices across all future periods decline by approximately 8 to 12 percent, on average, as compared to the forward prices at December 31, 2010. A substantial portion of the remaining carrying value of these other assets (primarily related to our assets in the Piceance Basin) could be at risk for impairment if forward prices across all future periods decline by at least 30 percent, on average, as compared to the prices at December 31, 2010.

 
As of June 30, 2011, the impact of changes in forward prices since December 31, 2010 to our cash flow estimates was not indicative of a potential impairment. However, in the period from June 30, 2011 to August 31, 2011, weighted average declines in these forward prices as they relate to the Powder River Basin production projection have at times been as high as six percent. If these forward prices do not recover, we will have to conduct an impairment review of our proved producing oil and gas properties in the Powder River Basin as of September 30, 2011. The net book value of our proved producing assets in the Powder River Basin was approximately $500 million at June 30, 2011. If the recording of an impairment charge becomes necessary as of September 30, 2011, it is reasonably possible that the amount of such charge could be at least $200 million. Any potential interim impairment assessment would include not only a review of forward pricing assumptions but also consideration of other factors impacting estimated future net cash flows, including but not limited to reserve and production estimates, future operating costs, future development costs and production taxes, all of which could impact the need for an impairment, and, if necessary, the amount of such impairment charge.

Accounting for Derivative Instruments and Hedging Activities
 
We review our energy contracts to determine whether they are, or contain, derivatives. Our energy derivatives portfolio is largely comprised of exchange-traded products or like products and the tenure of our derivatives portfolio is relatively short-term, with more than 99 percent of the value of our derivatives portfolio expiring in the next 24 months. We further assess the appropriate accounting method for any derivatives identified, which could include:

 	•  	qualifying for and electing cash flow hedge accounting, which recognizes changes in the fair value of the derivative in other comprehensive income (to the extent the hedge is effective) until the hedged item is recognized in earnings;	
 		
 	•  	qualifying for and electing accrual accounting under the normal purchases and normal sales exception; or	
 		
 	•  	applying mark-to-market accounting, which recognizes changes in the fair value of the derivative in earnings.	

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If cash flow hedge accounting or accrual accounting is not applied, a derivative is subject to mark-to-market accounting. Determination of the accounting method involves significant judgments and assumptions, which are further described below.
 
The determination of whether a derivative contract qualifies as a cash flow hedge includes an analysis of historical market price information to assess whether the derivative is expected to be highly effective in offsetting the cash flows attributed to the hedged risk. We also assess whether the hedged forecasted transaction is probable of occurring. This assessment requires us to exercise judgment and consider a wide variety of factors in addition to our intent, including internal and external forecasts, historical experience, changing market and business conditions, our financial and operational ability to carry out the forecasted transaction, the length of time until the forecasted transaction is projected to occur and the quantity of the forecasted transaction. In addition, we compare actual cash flows to those that were expected from the underlying risk. If a hedged forecasted transaction is not probable of occurring, or if the derivative contract is not expected to be highly effective, the derivative does not qualify for hedge accounting.
 
For derivatives designated as cash flow hedges, we must periodically assess whether they continue to qualify for hedge accounting. We prospectively discontinue hedge accounting and recognize future changes in fair value directly in earnings if we no longer expect the hedge to be highly effective, or if we believe that the hedged forecasted transaction is no longer probable of occurring. If the forecasted transaction becomes probable of not occurring, we reclassify amounts previously recorded in other comprehensive income into earnings in addition to prospectively discontinuing hedge accounting. If the effectiveness of the derivative improves and is again expected to be highly effective in offsetting the cash flows attributed to the hedged risk, or if the forecasted transaction again becomes probable, we may prospectively re-designate the derivative as a hedge of the underlying risk.
 
Derivatives for which the normal purchases and normal sales exception has been elected are accounted for on an accrual basis. In determining whether a derivative is eligible for this exception, we assess whether the contract provides for the purchase or sale of a commodity that will be physically delivered in quantities expected to be used or sold over a reasonable period in the normal course of business. In making this assessment, we consider numerous factors, including the quantities provided under the contract in relation to our business needs, delivery locations per the contract in relation to our operating locations, duration of time between entering the contract and delivery, past trends and expected future demand and our past practices and customs with regard to such contracts. Additionally, we assess whether it is probable that the contract will result in physical delivery of the commodity and not net financial settlement.
 
Since our energy derivative contracts could be accounted for in three different ways, two of which are elective, our accounting method could be different from that used by another party for a similar transaction. Furthermore, the accounting method may influence the level of volatility in the financial statements associated with changes in the fair value of derivatives, as generally depicted below:

 	 	Combined Statement of Operations	 	Combined Balance Sheet	
Accounting Method	 	Drivers	 	Impact	 	Drivers	 	Impact	
 		
Accrual Accounting	 	Realizations	 	Less Volatility	 	None	 	No Impact	
Cash Flow Hedge
Accounting	 	Realizations &
Ineffectiveness	 	Less Volatility	 	Fair Value Changes	 	More Volatility	
Mark-to-Market Accounting	 	Fair Value Changes	 	More Volatility	 	Fair Value Changes	 	More Volatility	

Our determination of the accounting method does not impact our cash flows related to derivatives.
 
Additional discussion of the accounting for energy contracts at fair value is included in Notes 1 and 14 of Notes to Combined Financial Statements.

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Successful Efforts Method of Accounting for Oil and Gas Exploration and Production Activities
 
We use the successful efforts method of accounting for our oil- and gas-producing activities. Estimated natural gas and oil reserves and forward market prices for oil and gas are a significant part of our financial calculations. Following are examples of how these estimates affect financial results:

 	•  	An increase (decrease) in estimated proved oil and gas reserves can reduce (increase) our unit-of-production depreciation, depletion and amortization rates; and	
 		
 	•  	Changes in oil and gas reserves and forward market prices both impact projected future cash flows from our oil and gas properties. This, in turn, can impact our periodic impairment analyses.	
 
The process of estimating natural gas and oil reserves is very complex, requiring significant judgment in the evaluation of all available geological, geophysical, engineering and economic data. After being estimated internally, approximately 94 percent of our domestic reserve estimates are audited by independent experts. The data may change substantially over time as a result of numerous factors, including additional development cost and activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, material revisions to existing reserve estimates could occur from time to time. Such changes could trigger an impairment of our oil and gas properties and have an impact on our depreciation, depletion and amortization expense prospectively. For example, a change of approximately 10 percent in our total oil and gas reserves could change our annual depreciation, depletion and amortization expense between approximately $76 million and $93 million. The actual impact would depend on the specific basins impacted and whether the change resulted from proved developed, proved undeveloped or a combination of these reserve categories.
 
Forward market prices, which are utilized in our impairment analyses, include estimates of prices for periods that extend beyond those with quoted market prices. This forward market price information is consistent with that generally used in evaluating our drilling decisions and acquisition plans. These market prices for future periods impact the production economics underlying oil and gas reserve estimates. The prices of natural gas and oil are volatile and change from period to period, thus impacting our estimates. Significant unfavorable changes in the forward price curve could result in an impairment of our oil and gas properties.
 
We record the cost of leasehold acquisitions as incurred. Individually significant lease acquisition costs are assessed annually, or as conditions warrant, for impairment considering our future drilling plans, the remaining lease term and recent drilling results. Lease acquisition costs that are not individually significant are aggregated by prospect or geographically, and the portion of such costs estimated to be nonproductive prior to lease expiration is amortized over the average holding period. Changes in our assumptions regarding the estimates of the nonproductive portion of these leasehold acquisitions could result in impairment of these costs. Upon determination that specific acreage will not be developed, the costs associated with that acreage would be impaired.
 
Contingent Liabilities
 
We record liabilities for estimated loss contingencies, including environmental matters, when we assess that a loss is probable and the amount of the loss can be reasonably estimated. Revisions to contingent liabilities are generally reflected in income when new or different facts or information become known or circumstances change that affect the previous assumptions with respect to the likelihood or amount of loss. Liabilities for contingent losses are based upon our assumptions and estimates and upon advice of legal counsel, engineers or other third parties regarding the probable outcomes of the matter. As new developments occur or more information becomes available, our assumptions and estimates of these liabilities may change. Changes in our assumptions and estimates or outcomes different from our current assumptions and estimates could materially affect future results of operations for any particular quarterly or annual period. See Note 11 of Notes to Combined Financial Statements.

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Valuation of Deferred Tax Assets and Liabilities
 
Our domestic operations are included in the consolidated and combined federal and state income tax returns for Williams, except for certain separate state filings. The income tax provision has been calculated on a separate return basis, which requires judgment in computing a stand-alone effective state tax rate as we did not exist as a stand-alone filer during these periods. If the effective state tax rate were to be revised upward by one percent, this would result in an increase to our net deferred income tax liability of approximately $33 million.
 
We have deferred tax assets resulting from certain investments and businesses that have a tax basis in excess of book basis and from certain separate state losses generated in the current and prior years. We must evaluate whether we will ultimately realize these tax benefits and establish a valuation allowance for those that may not be realizable. This evaluation considers tax planning strategies, including assumptions about the availability and character of future taxable income. When assessing the need for a valuation allowance, we consider forecasts of future company performance, the estimated impact of potential asset dispositions, and our ability and intent to execute tax planning strategies to utilize tax carryovers. The ultimate amount of deferred tax assets realized could be materially different from those recorded, as influenced by potential changes in jurisdictional income tax laws and the circumstances surrounding the actual realization of related tax assets. For example, Williams manages its tax position based upon its entire portfolio, which may not be indicative of tax planning strategies available to us if we were operating as an independent company.
 
See Note 10 of Notes to Combined Financial Statements for additional information.
 
Fair Value Measurements
 
A limited amount of our energy derivative assets and liabilities trade in markets with lower availability of pricing information requiring us to use unobservable inputs and are considered Level 3 in the fair value hierarchy. At December 31, 2010, less than 1 percent of our energy derivative assets and liabilities measured at fair value on a recurring basis are included in Level 3. For Level 2 transactions, we do not make significant adjustments to observable prices in measuring fair value as we do not generally trade in inactive markets.
 
The determination of fair value for our energy derivative assets and liabilities also incorporates the time value of money and various credit risk factors which can include the credit standing of the counterparties involved, master netting arrangements, the impact of credit enhancements (such as cash collateral posted and letters of credit) and our nonperformance risk on our energy derivative liabilities. The determination of the fair value of our energy derivative liabilities does not consider noncash collateral credit enhancements. For net derivative assets, we apply a credit spread, based on the credit rating of the counterparty, against the net derivative asset with that counterparty. For net derivative liabilities we apply our own credit rating. We derive the credit spreads by using the corporate industrial credit curves for each rating category and building a curve based on certain points in time for each rating category. The spread comes from the discount factor of the individual corporate curves versus the discount factor of the LIBOR curve. At December 31, 2010, the credit reserve is less than $1 million on both on our net derivative assets and net derivative liabilities. Considering these factors and that we do not have significant risk from our net credit exposure to derivative counterparties, the impact of credit risk is not significant to the overall fair value of our derivatives portfolio.
 
At December 31, 2010, 89 percent of the fair value of our derivatives portfolio expires in the next 12 months and more than 99 percent expires in the next 24 months. Our derivatives portfolio is largely comprised of exchange-traded products or like products where price transparency has not historically been a concern. Due to the nature of the markets in which we transact and the relatively short tenure of our derivatives portfolio, we do not believe it is necessary to make an adjustment for illiquidity. We regularly analyze the liquidity of the markets based on the prevalence of broker pricing and exchange pricing for products in our derivatives portfolio.
 
The instruments included in Level 3 at December 31, 2010, consist of natural gas index transactions that are used to manage the physical requirements of our business. The change in the overall fair value of

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instruments included in Level 3 primarily results from changes in commodity prices during the month of delivery. There are generally no active forward markets or quoted prices for natural gas index transactions.
 
We have an unsecured credit agreement through December 2015 with certain banks that, so long as certain conditions are met, serves to reduce our usage of cash and other credit facilities for margin requirements related to instruments included in the facility. We anticipate this agreement will be dissolved and individual contracts will be executed with the same banks under similar margining requirements. See further discussion in “—Management’s Discussion and Analysis of Financial Condition and Liquidity.”
 
For the years ended December 31, 2010 and 2009, we recognized impairments of certain assets that were measured at fair value on a nonrecurring basis. These impairment measurements are included in Level 3 as they include significant unobservable inputs, such as our estimate of future cash flows and the probabilities of alternative scenarios. See Note 14 of Notes to Combined Financial Statements.

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BUSINESS
 
Overview
 
We are an independent natural gas and oil exploration and production company engaged in the exploitation and development of long-life unconventional properties. We are focused on profitably exploiting our significant natural gas reserve base and related NGLs in the Piceance Basin of the Rocky Mountain region, and on developing and growing our positions in the Bakken Shale oil play in North Dakota and the Marcellus Shale natural gas play in Pennsylvania. Our other areas of domestic operations include the Powder River Basin in Wyoming and the San Juan Basin in the southwestern United States. In addition, we own a 69 percent controlling ownership interest in Apco, which holds oil and gas concessions in Argentina and Colombia and trades on the NASDAQ Capital Market under the symbol “APAGF.” Our international interests make up approximately five percent of our total proved reserves. In consideration of this percentage, unless specifically referenced herein, the information included in this section relates only to our domestic activity.
 
We have built a geographically diverse portfolio of natural gas and oil reserves through organic development and strategic acquisitions. For the five years ended December 31, 2010, we have grown production at a compound annual growth rate of 12 percent. As of December 31, 2010, our proved reserves were 4,473 Bcfe, 59 percent of which were proved developed reserves. Average daily production for the month of July 2011 was 1,294 MMcfe/d. Our Piceance Basin operations form the majority of our proved reserves and current production, providing a low-cost, scalable asset base.
 
The following table provides summary data for each of our primary areas of operation as of December 31, 2010, unless otherwise noted.

 	 	Estimated Net	 	 	July 2011	 	 	 	 	 	2011 Budget Estimate	 	 	 	 	 	 	 	 	 	 	
 	 	Proved Reserves	 	 	Average Daily	 	 	 	 	 	 	 	 	Drilling	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	% Proved	 	 	Net Production	 	 	Net	 	 	Gross	 	 	Capital(2)	 	 	PV-10(3)	 	 	 	 	 	 	 	
Basin/Shale	 	Bcfe	 	 	Developed	 	 	(MMcfe/d)(1)	 	 	Acreage	 	 	Wells	 	 	(Millions)	 	 	(Millions)	 	 	 	 	 	 	 	
 		
Piceance Basin	 	 	2,927	 	 	 	53	%	 	 	745	 	 	 	211,000	 	 	 	376	 	 	$	575	 	 	$	2,707	 	 	 	 	 	 	 	 	 	
Bakken Shale(4)	 	 	136	 	 	 	11	%	 	 	31	 	 	 	89,420	 	 	 	41	 	 	 	260	 	 	 	399	 	 	 	 	 	 	 	 	 	
Marcellus Shale	 	 	28	 	 	 	71	%	 	 	14	 	 	 	99,301	 	 	 	62	 	 	 	170	 	 	 	29	 	 	 	 	 	 	 	 	 	
Powder River Basin	 	 	348	 	 	 	75	%	 	 	235	 	 	 	425,550	 	 	 	411	 	 	 	70	 	 	 	317	 	 	 	 	 	 	 	 	 	
San Juan Basin	 	 	554	 	 	 	79	%	 	 	143	 	 	 	120,998	 	 	 	51	 	 	 	40	 	 	 	477	 	 	 	 	 	 	 	 	 	
Apco(5)	 	 	190	 	 	 	60	%	 	 	49	 	 	 	404,304	 	 	 	37	 	 	 	30	 	 	 	358	 	 	 	 	 	 	 	 	 	
Other(6)	 	 	290	 	 	 	72	%	 	 	77	 	 	 	327,390	 	 	 	94	 	 	 	85	 	 	 	257	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	 	4,473	 	 	 	59	%	 	 	1,294	 	 	 	1,677,963	 	 	 	1,072	 	 	$	1,230	 	 	$	4,544	 	 	 	 	 	 	 	 	 	

 

			
(1)		Represents average daily net production of our continuing operations for the month of July 2011.	
 		
(2)		Based on the midpoint of our estimated capital spending range.	
 		
(3)		PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our oil and natural gas assets. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities. For a definition of PV-10 and a reconciliation of PV-10 to Standardized Measure, see “Prospectus Summary—Summary Combined Historical Operating and Reserve Data—Non-GAAP Financial Measures and Reconciliations.”	
 		
(4)		Our estimated net proved reserves in the Bakken Shale have not been audited by independent reserve engineers.	
 		
(5)		Represents approximately 69 percent of each metric (which corresponds to our ownership interest in Apco) except Percent Proved Developed, Gross Wells and Drilling Capital.	

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(6)		Other includes Barnett Shale, Arkoma and Green River Basins and miscellaneous smaller properties. July 2011 average daily net production excludes Arkoma production of approximately nine MMcfe/d as our Arkoma Basin operations were classified as held for sale and reported as discontinued operations as of June 30, 2011.	
 
2011 Capital Expenditures Budget
 
Our total 2011 capital expenditures budget is expected to be between $1.30 billion and $1.60 billion, and will consist of the following, representing the midpoint of this range:

 	•  	approximately $1.23 billion for development drilling; and	
 		
 	•  	approximately $0.22 billion for facilities, infrastructure, and land/acquisitions.	
 
While we have budgeted between $1.3 billion and $1.6 billion of capital deployment in 2011, the ultimate amount and allocation of capital spent in 2011 could vary. We will evaluate market conditions in each of our operating areas to determine the estimated economic returns on capital employed. If those returns exceed or fall short of our thresholds, our capital expenditures and allocations could change accordingly. In addition, we believe that after completion of this offering we will be well positioned to pursue large scale strategic acquisitions that are not included in our 2011 capital expenditures budget. However, our ability to enter into corporate transactions will be subject to certain restrictions. For example, prior to the spin-off, we may not enter into transactions that would reduce Williams’ ownership to less than 80% of the voting power of all then outstanding shares of our capital stock entitled to vote generally in the election of directors or less than 80% of the then outstanding shares of any class of non-voting stock. Similarly, after the spin-off, we may not enter into transactions that would cause us to undergo either a 50% or greater change in the ownership of our voting stock or a 50% or greater change in the ownership (measured by value) of all classes of our stock taking into account shares issued in this offering in transactions considered related to the spin-off. These restrictions are necessary in order to maintain the tax-free treatment of our separation from Williams. See “Risk Factors—Risks Related to our Relationship with Williams—Our agreements with Williams may limit our ability to obtain additional financing or make acquisitions,” and “Risk Factors—Risks Related to our Relationships with Williams—Our tax sharing agreement with Williams may limit our ability to take certain actions and may require us to indemnify Williams for significant tax liabilities.”
 
Our Business Strategy
 
Our business strategy is to increase shareholder value by finding and developing reserves and producing natural gas, oil and NGLs at costs that generate an attractive rate of return on our investment.

 	•  	Efficiently Allocate Capital for Optimal Portfolio Returns .  We expect to allocate capital to the most profitable opportunities in our portfolio based on commodity price cycles and other market conditions, enabling us to continue to grow our reserves and production in a manner that maximizes our return on investment. In determining which drilling opportunities to pursue, we target a minimum after-tax internal rate of return on each operated well we drill of 15 percent. While we have a significant portfolio of drilling opportunities that we believe meet or exceed our return targets even in challenging commodity price environments, we are disciplined in our approach to capital spending and will adjust our drilling capital expenditures based on our level of expected cash flows, access to capital and overall liquidity position. For example, in 2009 we demonstrated our capital discipline by reducing drilling expenditures in response to prevailing commodity prices and their impact on these factors.	
 		
 	•  	Continue Our Cost-Efficient Development Approach.   We focus on developing properties where we can apply development practices that result in cost-efficiencies. We manage costs by focusing on establishing large scale, contiguous acreage blocks where we can operate a majority of the properties. We believe this strategy allows us to better achieve economies of scale and apply continuous technological improvements in our operations. We intend to replicate these cost-efficient approaches in our recently acquired growth positions in the Bakken Shale and the Marcellus Shale.	
 		
 	•  	Pursue Strategic Acquisitions with Significant Resource Potential .  We have a history of acquiring undeveloped properties that meet our disciplined return requirements and other acquisition criteria to	

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 		expand upon our existing positions as well as acquiring undeveloped acreage in new geographic areas that offer significant resource potential. This is illustrated by our recent acquisitions in the Bakken Shale and the Marcellus Shale. We seek to continue expansion of current acreage positions and opportunistically acquire acreage positions in new areas where we feel we can establish significant scale and replicate our cost-efficient development approach.	

 	•  	Target a More Balanced Commodity Mix in Our Production Profile .  With our Bakken Shale acquisition in December 2010 and our liquids-rich Piceance Basin assets, we have a significant drilling inventory of oil- and liquids-rich opportunities that we intend to develop rapidly in order to achieve a more balanced commodity mix in our production. We refer to the Piceance Basin as “liquids-rich” because our proved reserves in that basin consist of “wet,” as opposed to “dry,” gas and have a significant liquids component. Our current estimated proved reserves of NGLs and condensate in the Piceance Basin are 95 MMbbl and 3 MMbbl, respectively. We will continue to pursue other oil- and liquids-rich organic development and acquisition opportunities that meet our investment returns and strategic criteria.	

 	•  	Maintain Substantial Financial Liquidity and Manage Commodity Price Sensitivity .  We plan to conservatively manage our balance sheet and maintain substantial liquidity through a mix of cash on hand and availability under our Credit Facility. In addition, we have engaged and will continue to engage in commodity hedging activities to maintain a degree of cash flow stability. Typically, we target hedging approximately 50 percent of expected revenue from domestic production during a current calendar year in order to strike an appropriate balance of commodity price upside with cash flow protection, although we may vary from this level based on our perceptions of market risk. At July 31, 2011, our estimated domestic natural gas production revenues were 67 percent hedged for 2011 and 48 percent hedged for 2012. Estimated domestic oil production revenues were 48 percent hedged for 2011 and 49 percent hedged for 2012 as of the same date.	
 
Our Competitive Strengths
 
We have a number of competitive strengths that we believe will help us to successfully execute our business strategies:

 	•  	A Leading Piceance Basin Cost Structure.   We have a large position in the lower cost valley area of the Piceance Basin, which we believe provides us economies associated with lower elevation drilling and large contiguous operations, allowing us to continuously drive down operating costs and increase efficiencies. The existing substantial midstream infrastructure in the Piceance Basin contributes to our cost-efficient structure and provides take-away capacity for our natural gas and NGLs. Because of this cost-efficient structure in the Piceance Basin, we have the ability to generate returns that we believe are in excess of those typically associated with Rockies producers.	
 		
 	•  	Attractive Asset Base Across a Number of High Growth Areas .  In addition to our large scale Piceance Basin properties, our assets include emerging, high growth opportunities such as our Bakken Shale and Marcellus Shale positions. Based on our subsurface geological and engineering analysis of available well data, we believe our Bakken Shale and Marcellus Shale positions are located in core areas of these plays, which have associated historic drilling results that we believe offer highly attractive economic returns.	
 		
 	•  	Extensive Drilling Inventory.   As of December 31, 2010, we have identified approximately 2,900 proved undeveloped drilling locations. We have budgeted drilling approximately 500 gross operated wells during 2011. We have established significant scale in each of our core areas of operation that support multi-year development plans and allow us to optimally leverage our cost-efficient development approach. Our drilling inventory provides opportunities across diverse geographic markets and products including natural gas, oil and NGLs.	
 		
 	•  	Significant Operating Flexibility.   In the Piceance Basin, Bakken Shale and Marcellus Shale, our three primary basins, we operate substantially all of our production. We expect approximately 91 percent of our projected 2011 domestic drilling capital will be spent on projects we operate. We believe acting as operator on our properties allows us to better control costs and capital expenditures,	

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 		manage efficiencies, optimize development pace, ensure safety and environmental stewardship and, ultimately, maximize our return on investment. As operator, we are also able to leverage our experience and expertise across all basins and transfer technology advances between them as applicable. In addition, substantially all of our Piceance Basin properties are held by producing wells, which allows us to adjust our level of drilling activity in response to changing market conditions.	

 	•  	Significant Financial Flexibility.   Our capital structure is intended to provide a high degree of financial flexibility to grow our asset base, both through organic projects and opportunistic acquisitions. Immediately following the completion of this offering, we expect to have $2.0 billion of liquidity, comprised of availability under our $1.5 billion Credit Facility and approximately $500 million of cash on hand. We believe our pro forma level of debt to proved reserves is low relative to a majority of other publicly traded, independent oil and gas producers.	
 		
 	•  	Management Team with Broad Unconventional Resource Experience .  Our management and operating team has significant experience acquiring, operating and developing natural gas and oil reserves from tight-sands and shale formations. Our Chief Executive Officer and his direct reports have in excess of 238 collective years of experience running large scale drilling programs and drilling vertical and horizontal wells requiring complex well design and completion methods. Our team has demonstrated the ability to manage large scale operations and apply current technological successes to new development opportunities. We have deployed members of our successful Piceance Basin, Powder River Basin and Barnett Shale teams to the Bakken Shale and Marcellus Shale teams to help replicate our cost-efficient model and to apply our highly specialized technical expertise in the development of those resources.	
 
Our Recent Acquisition History
 
An important part of our strategy to grow our business and enhance shareholder value is to acquire properties complementary to our existing positions as well as undeveloped acreage with significant resource potential in new geographic areas. Following is a summary of selected recent acquisitions in the Bakken Shale, Marcellus Shale and Piceance Basin.
 
Bakken Shale

 	•  	In December 2010, we acquired Dakota-3 E&P Company LLC, a company that holds approximately 85,800 net acres on the Fort Berthold Indian Reservation in the Williston Basin, with then-current net oil production of 3,300 barrels per day from 24 existing wells, for $949 million.	
 
Marcellus Shale

 	•  	In July 2010, we acquired 42,000 net acres of largely undeveloped properties primarily located in Susquehanna County in northeastern Pennsylvania for $599 million.	
 		
 	•  	During 2010, we also acquired additional unproved leasehold acreage positions in the Marcellus Shale for a total of $164 million.	
 		
 	•  	In June 2009, we initiated our strategy of securing acreage in the Marcellus Shale with our participation and exploration agreement to develop natural gas wells with Rex Energy Corporation. We acquired a 50 percent interest in 44,000 net acres in Pennsylvania’s Westmoreland, Clearfield and Centre Counties for $33 million in a “drill to earn” structure.	
 
Piceance Basin

 	•  	In September 2009, we completed a bolt-on acquisition of 21,800 net acres in the Piceance Basin, east of our existing properties, for $253 million. The asset included then current production of 24 MMcfe/d from 28 wells, related gas and water gathering facilities, 94 approved drilling permits and more than 800 drillable locations at 10-acre spacing. In December 2009, we increased our working interest in these properties through an additional $22 million acquisition.	

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 	•  	In May 2008, we acquired 24,000 net acres in the Piceance Basin for $285 million. The acreage covered by the agreement was contiguous to our existing position in the Ryan Gulch area of the Piceance Basin Highlands in Rio Blanco County. A third party subsequently exercised its contractual option to purchase a 49 percent interest in a portion of the acquired assets for $71 million.	
 
Recent Sales & Dispositions

 	•  	In November 2010, we sold certain of our gathering and processing assets in Colorado’s Piceance Basin to Williams Partners for $702 million in cash and approximately 1.8 million Williams Partners common units, which units were subsequently distributed to Williams. These assets include the Parachute Plant Complex, three other treating facilities with a combined processing capacity of 1.2 Bcf/d, and a gathering system with approximately 150 miles of pipeline. There are more than 3,300 wells connected to the gathering system, which includes pipelines ranging up to 30-inch trunk lines. As part of this sale, we agreed to continue to use this gathering system for our production in this area for the life of our leases. See “Other Related Party Transactions—Agreements Related to the Piceance Disposition.”	

 	•  	In January 2008, we sold a contractual right to a production payment on certain future hydrocarbon production in Peru for $148 million. As a result of the contract termination, we have no further interests associated with this crude oil concession, which we had obtained through our acquisition of Barrett Resources Corporation in 2001.	
 
Significant Properties
 
Our principal areas of operation are the Piceance Basin, Bakken Shale, Marcellus Shale, Powder River Basin, San Juan Basin and, through our ownership of Apco, Colombia and Argentina. A map of our properties within these geographic areas and our other properties can be found on the inside cover of this prospectus.
 
Piceance Basin
 
We entered the Piceance Basin in May 2001 with the acquisition of Barrett Resources and since that time have grown to become the largest natural gas producer in Colorado. Our Piceance Basin properties currently comprise our largest area of concentrated development drilling.
 
For the month of July 2011, we had an average of 745 MMcfe/d of net production from our Piceance Basin properties. Approximately 25 million gallons of NGLs are currently recovered each month from our Piceance Basin properties. A large majority of our natural gas production in this basin currently is gathered through a system owned by Williams Partners and delivered to markets through a number of interstate pipelines. See “Other Related Party Transactions—Gathering, Processing and Treating Contracts.” As of December 31, 2010, our properties in the Piceance Basin included:

 	•  	211,000 total net acres, including 108,165 undeveloped net acres;	
 		
 	•  	2,927 Bcfe of estimated net proved reserves;	
 		
 	•  	3,587 net producing wells; and	
 		
 	•  	1,567 undrilled proved drilling locations.	
 
During 2010, we operated an average of 11 drilling rigs in the basin, including nine in the Piceance Valley and two in the Piceance Highlands. As of July 31, 2011 we were operating 11 rigs and have an average of 11 rigs budgeted for 2011. We have allocated approximately $575 million in capital expenditures to drill 376 gross wells on our Piceance Basin properties in 2011.
 
The Piceance Basin is located in northwestern Colorado. Our operations in the basin are divided into two areas: the Piceance Valley and the Piceance Highlands. Our Piceance Valley area includes operations along the Colorado River valley and is the more developed area where we have produced consistent, repeatable results. The Piceance Highlands, which are those areas at higher elevations above the river valley, contain vast development opportunities that position us well for growth in the future as infrastructure expands and efficiency

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improvements continue. Our development activities in the basin are primarily focused on the Williams Fork section within the Mesaverde formation. The Williams Fork can be over 2,000 feet in thickness and is comprised of several tight, interbedded, lenticular sandstone lenses encountered at depths ranging from 7,000 to 13,000 feet. In order to maximize producing rates and recovery of natural gas reserves we must hydraulically fracture the well using a fluid system comprised of 99 percent water and sand. Advancements in completion technology, including the use of microseismic data have enabled us to more effectively stimulate the reservoir and recover a greater percentage of the natural gas in place. We are currently evaluating deeper horizons such as the Mancos and Niobrara shale formations, which have the potential to provide additional development opportunities.
 
Initial development of the Piceance Basin was limited to conventional drilling and completion techniques. In response to the unique challenges posed by the geology of this area, we collaborated with our drilling contractors to build “fit-for-purpose” type drilling rigs, and beginning in 2005, were the first operator to introduce these types of drilling rigs to the Piceance Basin. Utilizing advancements in drilling technology and several innovative modifications, these special purpose rigs are capable of drilling 22 wells from a single well pad, drilling faster and extending the directional length of our wells, and can accommodate completion and production activities simultaneously. In addition to reducing surface impacts, these rigs are quieter, safer to operate, and have allowed us to significantly reduce cycle times from spud to spud and getting our gas to market. We have pioneered several other innovative practices such as green completions, which essentially eliminate gas flaring and emissions during completion operations, and using a “clustered” plan of development approach taking advantage of centralized facilities, as well as allowing us to fracture stimulate wells from over two miles away from the pumping equipment. In addition, all of our producing wells and associated facilities are fully automated and utilize our state-of-the art telemetry system, which provides our well technicians with real time data to ensure we are optimizing well performance. Our innovative approaches to drilling in the Piceance Basin have earned us positive state and federal recognition.
 
Bakken Shale
 
In December 2010 we acquired approximately 85,800 net acres in the Williston Basin. All of our properties in the Williston Basin are on the Fort Berthold Indian Reservation in North Dakota, where we will be the primary operator. Based on our geologic interpretation of the Bakken formation, the evolution of completion techniques, our own drilling results as well as the publicly available drilling results for other operators in the basin, we believe that a substantial portion of our Williston Basin acreage is prospective in the Bakken formation, the primary target for all of the well locations in our current drilling inventory.
 
For the month of July 2011, we had an average of 5.2 Mboe/d of net production from our Bakken Shale wells. As of December 31, 2010, our properties in the Bakken Shale included:

 	•  	89,420 total net acres, including 75,937 undeveloped net acres;	
 		
 	•  	23 MMboe of estimated net proved reserves; and	
 		
 	•  	13 net producing wells.	
 
As of July 31, 2011 we were operating three rigs and plan to add an additional two rigs during 2011. We have allocated approximately $260 million in capital expenditures to drill 41 gross wells on our Bakken Shale properties in 2011.
 
We plan to develop oil reserves through horizontal drilling from both the Middle Bakken and Upper Three Forks shale oil formations utilizing drilling and completion expertise gained in part through experience in our other basins. Based on our subsurface geological analysis, we believe that our position lies in the area of the basin’s greatest potential recovery for Bakken formation oil. Currently our Bakken Shale development has the highest incremental returns of any of our drilling programs.
 
The Williston Basin is spread across North Dakota, South Dakota, Montana and parts of southern Canada, covering approximately 202,000 square miles, of which 143,000 square miles are in the United States. The basin produces oil and natural gas from numerous producing horizons including the Bakken, Three Forks, Madison and Red River formations. A report issued by the U.S. Geological Survey in April 2008 classified the

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Bakken formation as the largest continuous oil accumulation ever assessed by it in the contiguous United States.
 
The Devonian-age Bakken formation is found within the Williston Basin underlying portions of North Dakota and Montana and is comprised of three lithologic members referred to as the Upper, Middle and Lower Bakken shales. The formation ranges up to 150 feet thick and is a continuous and structurally simple reservoir. The upper and lower shales are highly organic, thermally mature and over pressured and can act as both a source and reservoir for the oil. The Middle Bakken, which varies in composition from a silty dolomite to shaly limestone or sand, serves as the productive formation and is a critical reservoir for commercial production. Generally, the Bakken formation is found at vertical depths of 8,500 to 11,500 feet.
 
The Three Forks formation, generally found immediately under the Bakken formation, has also proven to contain productive reservoir rock that may add incremental reserves to our existing leasehold positions. The Three Forks formation typically consists of interbedded dolomites and shale with local development of a discontinuous sandy member at the top, known as the Sanish sand. The Three Forks formation is an unconventional carbonate play. Similar to the Bakken formation, the Three Forks formation has recently been exploited utilizing the same horizontal drilling and advanced completion techniques as the Bakken development. Drilling in the Three Forks formation began in mid-2008 and a number of operators are currently drilling wells targeting this formation. Based on our geologic interpretation of the Three Forks formation and the evolution of completion techniques, we believe that most of our Williston Basin acreage is prospective in the Three Forks formation. We are in the process of completing a well drilled in the Three Forks formation.
 
Our Middle Bakken development is expected to be comparable to other established operators in the area. For our typical well drilled in the Middle Bakken formation, we expect the initial 30 day production rates to be in the range of 750 Boe/d to 1,100 Boe/d, drilling capital to be in the $8 million to $9 million range and reserve estimates to be from 650 to 850 Mbbls, depending on the area.
 
Our acreage in the Bakken Shale, as well as a portion of our acreage in the Piceance Basin and Powder River Basin, is leased to us by or with the approval of the federal government or its agencies, and is subject to federal authority, NEPA, the Bureau of Indian Affairs or other regulatory regimes that require governmental agencies to evaluate the potential environmental impacts of a proposed project on government owned lands. These regulatory regimes impose obligations on the federal government and governmental agencies that may result in legal challenges and potentially lengthy delays in obtaining project permits or approvals and could result in certain instances in the cancellation of existing leases.
 
Marcellus Shale
 
Our Marcellus Shale acreage is located in four principal areas of the play within Pennsylvania: the northeast portion of the play in and near Susquehanna County; the southwest in and around Westmoreland County; centrally in Clearfield and Centre Counties and the east in Columbia County. We have continued to expand our position since our entry into the Marcellus Shale in 2009, both organically and through third-party acquisitions. We are the primary operator on our acreage for all four areas and plan to develop our acreage using horizontal drilling and completion expertise in part gained through operations in our other basins. Our most established area is in Westmoreland County but in the future we expect our most significant drilling area to be in Susquehanna County. A third party gathering system providing the main trunkline out of the area is expected to go into service in the third quarter of 2011.
 
For the month of July 2011, we had an average of 14 MMcfe/d of net production from our Marcellus Shale properties. As of December 31, 2010, our properties in the Marcellus Shale included:

 	•  	99,301 total net acres, including 98,387 undeveloped net acres;	
 		
 	•  	28 Bcfe of estimated net proved reserves; and	
 		
 	•  	Six net producing wells.	

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As of July 31, 2011 we were operating four rigs and have an average of five rigs budgeted for 2011. We have allocated approximately $170 million in capital expenditures to drill 62 gross wells on our Marcellus Shale properties in 2011.
 
The Marcellus Shale formation is the most expansive shale gas play in the United States, spanning six states in the northeastern United States. The Marcellus Shale is a black, organic rich shale formation located at depths between 4,000 and 8,500 feet, covering approximately 95,000 square miles at an average net thickness of 50 feet to 300 feet.
 
The first commercial well in the Marcellus Shale was drilled and completed in 2005 in Pennsylvania. Since the beginning of 2005, there have been 6,963 wells permitted in Pennsylvania in the Marcellus Shale and 3,030 of the approved wells have been drilled. In 2010, 1,386 wells were drilled in the Marcellus Shale, making it one of the most active and prominent shale gas plays in the United States, and active, widespread drilling in this area is expected to continue. During 2010, there were more than 80 operators active in the play.
 
Powder River Basin
 
We own a large position in coal bed methane reserves in the Powder River Basin and together with our co-developer, Lance Oil & Gas Company Inc., control 950,982 acres, of which our ownership represents 425,550 net acres. We share operations with our co-developer and both companies have extensive experience producing from coal formations in the Powder River Basin dating from its earliest commercial growth in the late 1990s. The natural gas produced is gathered by a system owned by our co-developer.
 
For the month of July 2011, we had an average of 235 MMcfe/d of net production from our Powder River Basin properties. As of December 31, 2010, our properties in the Powder River Basin included:

 	•  	425,550 total net acres, including 175,371 undeveloped net acres;	
 		
 	•  	348 Bcfe of estimated net proved reserves; and	
 		
 	•  	2,884 net producing wells.	
 
We have allocated approximately $70 million in capital expenditures to drill 411 gross wells on our Powder River Basin properties in 2011. We plan to drill 80 operated wells, participate in 253 wells drilled by our joint venture partner and participate in the drilling of 78 wells drilled by others in 2011.
 
Our Powder River Basin properties are located in northeastern Wyoming. Our development operations in this basin are focused on coal bed methane plays in the Big George and Wyodak project areas. Initially, coal bed methane wells typically produce water in a process called dewatering. This process lowers pressure, allowing the natural gas to flow to the wellbore. As the coal seam pressure declines, the wells begin producing methane gas at an increasing rate. As the wells mature, the production peaks, stabilizes and then begins declining. The average life of a coal bed methane well in the Powder River Basin ranges from five to 15 years. While these wells generally produce at much lower rates with fewer reserves attributed to them when compared to conventional natural gas wells in the Rocky Mountains, they also typically have higher drilling success rates and lower capital costs.
 
The coal seams that we target in the Powder River Basin have been extensively mapped as a result of a variety of natural resource development projects that have occurred in the region. Industry data from over 25,000 wellbores drilled through the Ft. Union coal formation allows us to determine critical data such as the aerial extent, thickness, gas saturation, formation pressure and relative permeability of the coal seams we target for development, which we believe significantly reduces our dry hole risk.
 
San Juan Basin
 
We acquired our San Juan Basin properties as part of Williams’ acquisition of Northwest Energy in 1983. These properties represented the first major area of natural gas exploration and development activities for Williams. Our San Juan Basin properties include holdings across the basin producing primarily from the Mesa Verde, Fruitland Coal and Mancos shale gas formations. We operate two units in New Mexico (Rosa and Cox

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Canyon) as well as several non-unit properties, and we operate in three major areas of Colorado (Northwest Cedar Hills, Ignacio and Bondad). We also own properties operated by other operators in New Mexico and Colorado. Approximately 60 percent of our net San Juan Basin production comes from our operated properties.
 
For the month of July 2011, we had an average of 143 MMcfe/d of net production from our San Juan Basin properties. As of December 31, 2010, our properties in the San Juan Basin included:

 	•  	120,998 total net acres, including 1,576 undeveloped net acres;	
 		
 	•  	554 Bcfe of estimated net proved reserves; and	
 		
 	•  	880 net producing wells.	
 
We have allocated approximately $40 million in capital expenditures to drill 51 gross wells on our San Juan Basin properties in 2011. We plan to drill 16 operated wells in 2011 and participate in the drilling of 35 wells operated by our partners in 2011.
 
According to a September 2010 Wood Mackenzie report, the San Juan Basin is one of the oldest and most prolific coal bed methane plays in the world. This report states that production from the San Juan Basin in 2010 was expected to average 3.5 Bcfe/d with approximately 60 percent of net gas production derived from the Fruitland coal bed. The Fruitland coal bed extends to depths of approximately 4,200 ft with net thickness ranging from zero to 100 feet. The Mesa Verde play is the top producing tight gas play in the basin with total thickness ranging from 500 to 2,500 feet. The Mesa Verde is underlain by the upper Mancos Shale and overlain by the Lewis Shale.
 
Apco
 
We hold an approximate 69 percent controlling equity interest in Apco. Apco in turn owns interests in several blocks in Argentina, including concessions in the Neuquén, Austral, Northwest and San Jorge Basins, and in 3 exploration permits in Colombia, with its primary properties consisting of the Neuquén and Austral Basin concessions. Apco’s oil and gas reserves are approximately 57 percent oil, 39 percent natural gas and four percent liquefied petroleum gas. For the month of July 2011, Apco had an average of 12.0 Mboe/d of net production. As of December 31, 2010, Apco’s properties included:

 	•  	586,288 total net acres, including 556,661 undeveloped net acres;	
 		
 	•  	45.9 MMboe of estimated net proved reserves; and	
 		
 	•  	322 net producing wells.	
 
Apco intends to participate in the drilling of 37 wells operated by its partners in 2011 of which Apco has allocated, for its direct ownership interest, approximately $30 million in capital expenditures.
 
The government of Argentina has implemented price control mechanisms over the sale of natural gas and over gasoline prices in the country. As a result of these controls and other actions by the Argentine government, sales price realizations for natural gas and oil sold in Argentina are generally below international market levels and are significantly influenced by Argentine governmental actions.
 
Neuquén Basin.   Apco participates in a joint venture partnership with Petrolera and Petrobras Argentina S.A. for the exploration and development of the Entre Lomas oil and gas concession in the provinces of Río Negro and Neuquén in southwest Argentina. In 2007, the partners created two new joint ventures consisting of the same partners with the same interests in order to expand operations into two areas adjacent to Entre Lomas, the Agua Amarga exploration permit in the province of Río Negro, and the Bajada del Palo concession in the province of Neuquén. In 2009, a portion of the Agua Amarga permit was converted to a 25-year exploitation concession called Charco del Palenque.
 
The Entre Lomas concession covers a surface area of approximately 183,000 acres and produces oil and gas from seven fields, the largest of which is Charco Bayo/Piedras Blancas. The Entre Lomas concession has a primary term of 25 years that expires in the year 2016 with an option to extend for an additional ten-year

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period based on terms to be agreed with the government. The Bajada del Palo concession has a total surface area of approximately 111,000 acres. In 2009, the Bajada del Palo concession term was extended to September 2025.
 
The Agua Amarga exploration area was awarded to Petrolera by the province of Río Negro in 2007. The property has a total surface area of approximately 95,000 acres and is located immediately to the southeast of the Entre Lomas concession. The first exploration period was scheduled to end in May 2010 and was extended for one year until May 2011. The completion of Apco’s work commitments and additional activities executed in the area has enabled Apco to request an additional one-year extension. If granted, the first exploration period would end on May 2012. In 2009, a portion of the Agua Amarga area covering approximately 18,000 acres was converted to an exploitation concession called Charco del Palenque with a 25-year term and a five-year optional extension period.
 
Austral Basin Properties.   Apco holds a 25.78 percent non-operated interest in a joint venture engaged in exploration and production activities in three concessions located on the island of Tierra del Fuego, which we refer to as the “TDF concessions.” The operator of the TDF concessions is ROCH S.A., a privately owned Argentine oil and gas company. The TDF concessions cover a total surface area of approximately 467,000 gross acres, or 120,000 acres net to Apco. Each of the concessions extends three kilometers offshore with their eastern boundaries paralleling the coastline. The most developed of the three concessions is the Las Violetas concession which is the largest onshore concession on the Argentine side of the island of Tierra del Fuego. The concessions have terms of 25 years that expire in 2016 with an option to extend the concessions for an additional ten-year period based on terms to be agreed with the government.
 
Northwest Basin Properties.   Apco holds a 1.5 percent non-operated interest in the Acambuco concession located in the province of Salta in northwest Argentina on the border with Bolivia. The concession covers an area of 294,000 acres, and is one of the largest gas producing concessions in Argentina. Wells drilled to the Huamampampa formation in the Acambuco concession have generally required one year to drill with total costs for drilling and completion ranging from $50 to $70 million.
 
San Jorge Basin Properties.   In the San Jorge Basin, Apco’s areas are more prospective and exploratory in nature. In the Sur Río Deseado Este concession in the province of Santa Cruz, Apco has a 16.94 percent working interest in an exploitation area with limited oil production and an 88 percent working interest in an exploratory area in the northern sector of the concession. Apco sold its interest in the Cañadón Ramirez concession at the end of 2010.
 
Other Properties
 
Our other holdings are comprised of assets in the Barnett Shale located in north central Texas, gas reserves in the Green River Basin of southwest Wyoming, interests in the Arkoma Basin in southeastern Oklahoma and additional international assets in northwest Argentina that are not part of Apco’s holdings.
 
For the month of July 2011, we had an average of 77 MMcfe/d of net production from continuing operations from our other properties. As of December 31, 2010, our other properties included:

 	•  	327,390 total net acres, including 245,497 undeveloped net acres;	
 		
 	•  	290 Bcfe of estimated net proved reserves; and	
 		
 	•  	532 net producing wells.	
 
As of July 31, 2011 we were operating one rig on our other properties. We have allocated approximately $85 million in capital expenditures to drill 94 gross wells on our other properties in 2011.
 
Our Barnett Shale properties produce predominately natural gas from horizontal wells, where we are the primary operator and have drilled more than 200 wells. Our Arkoma Basin properties include 441 gross wells producing gas from coal and shale formations. We have initiated a process to seek offers to sell our Arkoma Basin properties, which include approximately 104,000 net acres, including approximately 48,000 undeveloped net acres. Such properties were classified as held for sale and reported as discontinued operations as of June 30,

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2011, comprised less than one percent of our assets and are not included in our average daily net production amount for the month of June 2011.
 
Reserves and Production Information
 
We have significant oil and gas producing activities primarily in the Rocky Mountain, northeast and Mid-continent areas of the United States. Additionally, we have international oil and gas producing activities, primarily in Argentina. Proved reserves and revenues related to international activities are approximately five percent and three percent, respectively, of our total international and domestic proved reserves and revenues from producing activities. Accordingly, unless specifically stated otherwise, the information in the remainder of this “Business” section relates only to the oil and gas activities in the United States.
 
Oil and Gas Reserves
 
The following table outlines our estimated net proved reserves expressed on a gas equivalent basis for the reporting periods December 31, 2010, 2009 and 2008. We prepare our own reserves estimates and the majority of our reserves are audited by NSAI and M&L. Proved reserves information is reported as gas equivalents, since oil volumes are insignificant in the three years shown below. Reserves for 2010 are approximately 97 percent natural gas. Reserves are more than 99 percent natural gas for 2009 and 2008. Oil reserves increased to approximately three percent of total proved reserves in 2010 as a result of a fourth quarter acquisition of properties in the Bakken Shale.
 
Summary of oil and gas reserves:

 	 	December 31,	 	
 	 	2010	 	 	2009	 	 	2008	 	
 	 	(Bcfe)(1)	 	
 		
Proved developed reserves	 	 	2,498	 	 	 	2,387	 	 	 	2,456	 	
Proved undeveloped reserves	 	 	1,774	 	 	 	1,868	 	 	 	1,883	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total proved reserves	 	 	4,272	 	 	 	4,255	 	 	 	4,339	 	

 

			
(1)		Gas equivalents are calculated using a ratio of six thousand cubic feet of natural gas to one barrel of oil.	

 	 	Estimated Net	 	
 	 	Proved Reserves	 	
Basin / Shale	 	December 31, 2010	 	
 	 	(Bcfe)	 	
 		
Piceance Basin	 	 	2,927	 	
Bakken Shale	 	 	136	 	
Marcellus Shale	 	 	28	 	
Powder River Basin	 	 	348	 	
San Juan Basin	 	 	554	 	
Other(1)	 	 	279	 	
 	 	 	 	 	
Total(2)	 	 	4,272	 	

 

			
(1)		Other includes Barnett Shale, Arkoma and Green River Basins and miscellaneous smaller properties.	
 		
(2)		Of our total 4,272 Bcfe of net proved reserves as of December 31, 2010, three percent are oil.	
 
We have not filed on a recurring basis estimates of our total proved net oil and gas reserves with any U.S. regulatory authority or agency other than with the U.S. Department of Energy and the SEC. The estimates furnished to the Department of Energy have been consistent with those furnished to the SEC.
 
Our 2010 year-end estimated proved reserves were derived using an average price of $4.31 per Mcf, which is the 12-month average, first-of-the-month price for the applicable indices for each basin as adjusted for locational price differentials. During 2010, we added 508 Bcfe of net additions to our proved reserves through drilling 1,162 gross wells at a capital cost of approximately $988 million.

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Reserves estimation process
 
Our reserves are estimated by deterministic methods using an appropriate combination of production performance analysis and volumetric techniques. The proved reserves for economic undrilled locations are estimated by analogy or volumetrically from offset developed locations. Reservoir continuity and lateral persistence of our tight-sands, shale and coal bed methane reservoirs is established by combinations of subsurface analysis and analysis of 2D and 3D seismic data and pressure data. Understanding reservoir quality may be augmented by core samples analysis.
 
The engineering staff of each basin asset team provides the reserves modeling and forecasts for their respective areas. Various departments also participate in the preparation of the year-end reserves estimate by providing supporting information such as pricing, capital costs, expenses, ownership, gas gathering and gas quality. The departments and their roles in the year-end reserves process are coordinated by our reserves analysis department. The reserves analysis department’s responsibilities also include performing an internal review of reserves data for reasonableness and accuracy, working with the third-party consultants and the asset teams to successfully complete the third-party reserves audit, finalizing the year-end reserves report and reporting reserves data to accounting.
 
The preparation of our year-end reserves report is a formal process. Early in the year, we begin with a review of the existing internal processes and controls to identify where improvements can be made from the prior year’s reporting cycle. Later in the year, the reserves staffs from the asset teams submit their preliminary reserves data to the reserves analysis department. After review by the reserves analysis department, the data is submitted to our third party engineering consultants, NSAI and M&L, to begin their audits. After this point, reserves data analysis and further review are conducted and iterated between the asset teams, reserves analysis department and our third party engineering consultants. In early December, reserves are reviewed with senior management. The process concludes when all parties agree upon the reserve estimates and audit tolerance is achieved.
 
The reserves estimates resulting from our process are subjected to both internal and external controls to promote transparency and accuracy of the year-end reserves estimates. Our internal reserves analysis team is independent and does not work within an asset team or report directly to anyone on an asset team. The reserves analysis department provides detailed independent review and extensive documentation of the year-end process. Our internal processes and controls, as they relate to the year-end reserves, are reviewed and updated. The compensation of our reserves analysis team is not linked to reserves additions or revisions.
 
Approximately 93 percent of our total year-end 2010 domestic proved reserves estimates were audited by NSAI. When compared on a well-by-well basis, some of our estimates are greater and some are less than the
NSAI is satisfied with our methods and procedures in preparing the December 31, 2010 reserves estimates and future revenue, and noted nothing of an unusual nature that would cause NSAI to take exception with the estimates, in the aggregate, as prepared by us.
 
In addition, reserves estimates related to properties associated with the former Williams Coal Seam Gas Royalty Trust were audited by M&L. These properties represent approximately one percent of our total domestic proved reserves estimates. The Williams Coal Seam Gas Royalty Trust terminated effective March 1, 2010 and we purchased all the remaining properties from the trust in October 2010.
 
The technical person primarily responsible for overseeing preparation of the reserves estimates and the third party reserves audit is the Director of Reserves and Production Services. The Director’s qualifications include 28 years of reserves evaluation experience, a B.S. in geology from the University of Texas at Austin, an M.S. in Physical Sciences from the University of Houston and membership in the American Association of Petroleum Geologists and The Society of Petroleum Engineers.
 
Proved undeveloped reserves
 
The majority of our reserves is concentrated in unconventional tight-sands, shale and coal bed gas reservoirs. We use available geoscience and engineering data to establish drainage areas and reservoir continuity beyond one direct offset from a producing well, which provides additional proved undeveloped reserves. Inherent in the methodology is a requirement for significant well density of economically producing

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wells to establish reasonable certainty. In fields where producing wells are less concentrated, only direct offsets from proved producing wells were assigned the proved undeveloped reserves classification. No new technologies were used to assign proved undeveloped reserves.
 
At December 31, 2010, our proved undeveloped reserves were 1,774 Bcfe, a decrease of 94 Bcfe over our December 31, 2009 proved undeveloped reserves estimate of 1,868 Bcfe. During 2010, 280 Bcfe of our December 31, 2009 proved undeveloped reserves were converted to proved developed reserves at a cost of $633 million. An additional 129 Bcfe was added due to the development of unproved locations. As of 2010 year-end, we have reclassified a net 253 Bcfe from proved to probable reserves attributable to locations not expected to be developed within five years. These reclassified reserves are predominately in the Piceance Basin where we have a large inventory of drilling locations and have been offset by the addition of 342 Bcfe of new proved undeveloped drilling locations.
 
All proved undeveloped locations are scheduled to be spud within the next five years. Based on current projections, we expect to add additional rigs in 2013 in the Piceance Basin. Our undeveloped estimate contains 91 Bcfe of aging proved undeveloped reserves, or those reserves which are approaching the five-year limit before being reclassified to probable reserves. The majority of these are scheduled to be spud by year-end 2011.
 
Oil and Gas Properties and Production, Production Prices and Production Costs
 
The following table summarizes our net production for the years indicated.

 	 	Year Ended December 31,	 	
 	 	2010	 	 	2009	 	 	2008	 	
 		
Production Data:	 	 	 	 	 	 	 	 	 	 	 	 	
Natural Gas (MMcf)	 	 	 	 	 	 	 	 	 	 	 	 	
U.S.	 	 	 	 	 	 	 	 	 	 	 	 	
Piceance Basin	 	 	241,371	 	 	 	252,387	 	 	 	240,285	 	
Other(1)	 	 	162,571	 	 	 	171,691	 	 	 	156,497	 	
Argentina(2)	 	 	7,304	 	 	 	7,728	 	 	 	6,392	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	 	411,246	 	 	 	431,806	 	 	 	403,174	 	
Oil (MBbls)	 	 	 	 	 	 	 	 	 	 	 	 	
U.S. 	 	 	857	 	 	 	803	 	 	 	731	 	
Argentina(2)	 	 	2,035	 	 	 	1,998	 	 	 	1,991	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	 	2,892	 	 	 	2,801	 	 	 	2,722	 	
Combined Equivalent Volumes (MMcfe)(2)	 	 	428,598	 	 	 	448,612	 	 	 	419,506	 	
Combined Equivalent Volumes (MBoe)	 	 	71,433	 	 	 	74,769	 	 	 	69,918	 	
Average Daily Combined Equivalent Volumes (MMcfe/d)	 	 	 	 	 	 	 	 	 	 	 	 	
U.S.	 	 	 	 	 	 	 	 	 	 	 	 	
Piceance Basin	 	 	674	 	 	 	703	 	 	 	666	 	
Other(1)	 	 	447	 	 	 	472	 	 	 	430	 	
Argentina(2)	 	 	53	 	 	 	54	 	 	 	50	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	 	1,174	 	 	 	1,229	 	 	 	1,146	 	

 
			
(1)		Excludes production from our Arkoma Basin operations which were classified as held for sale and reported as discontinued operations as of June 30, 2011 and comprised less than one percent of our total production.	
 		
(2)		Includes approximately 69 percent of Apco’s production (which corresponds to our ownership interest in Apco) and other minor directly held interests.	

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The following tables summarize our domestic sales price and cost information for the years indicated.

 	 	Year Ended December 31,	 	
 	 	2010	 	 	2009	 	 	2008	 	
 		
Realized average price per unit(1):	 	 	 	 	 	 	 	 	 	 	 	 	
Natural gas, without hedges (per Mcf)(2)	 	$	4.33	 	 	$	3.39	 	 	$	6.84	 	
Impact of hedges (per Mcf)(2)	 	 	0.82	 	 	 	1.45	 	 	 	0.09	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Natural gas, with hedges (per Mcf)(2)	 	$	5.15	 	 	$	4.84	 	 	$	6.93	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Oil, without hedges (per Bbl)	 	$	66.32	 	 	$	47.39	 	 	$	84.63	 	
Impact of hedges (per Bbl)	 	 	—	 	 	 	—	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Oil, with hedges (per Bbl)	 	$	66.32	 	 	$	47.39	 	 	$	84.63	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Price per Boe, without hedges(3)	 	$	26.44	 	 	$	20.63	 	 	$	41.52	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Price per Boe, with hedges(3)	 	$	31.32	 	 	$	29.23	 	 	$	42.03	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Price per Mcfe, without hedges(3)	 	$	4.41	 	 	$	3.44	 	 	$	6.92	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Price per Mcfe, with hedges(3)	 	$	5.22	 	 	$	4.87	 	 	$	7.00	 	

 

			
(1)		Excludes our Arkoma Basin operations, which were classified as held for sale and reported as discontinued operations as of June 30, 2011 and comprised less than one percent of our total revenues.	
 		
(2)		Includes NGLs.	
 		
(3)		Realized average prices reflect realized market prices, net of fuel and shrink.	

 	 	Year Ended December 31,	 	
 	 	2010	 	 	2009	 	 	2008	 	
 		
Expenses per Mcfe(1):	 	 	 	 	 	 	 	 	 	 	 	 	
Operating expenses:	 	 	 	 	 	 	 	 	 	 	 	 	
Lifting costs and workovers	 	$	0.46	 	 	$	0.39	 	 	$	0.45	 	
Facilities operating expense	 	 	0.14	 	 	 	0.14	 	 	 	0.15	 	
Other operating and maintenance	 	 	0.05	 	 	 	0.05	 	 	 	0.04	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total LOE	 	$	0.65	 	 	$	0.58	 	 	$	0.64	 	
Gathering, processing and transportation charges	 	 	0.80	 	 	 	0.64	 	 	 	0.57	 	
Taxes other than income	 	 	0.27	 	 	 	0.19	 	 	 	0.60	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Production cost	 	$	1.72	 	 	$	1.41	 	 	$	1.81	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
General and administrative	 	$	0.60	 	 	$	0.56	 	 	$	0.60	 	
Depreciation, depletion and amortization	 	$	2.10	 	 	$	2.03	 	 	$	1.80	 	

 
			
(1)		Excludes our Arkoma Basin operations, which were classified as held for sale and reported as discontinued operations as of June 30, 2011.	

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Productive Oil and Gas Wells
 
The table below summarizes 2010 productive wells by area.*

 	 	Gas Wells	 	 	Gas Wells	 	 	Oil Wells	 	 	Oil Wells	 	
 	 	(Gross)	 	 	(Net)	 	 	(Gross)	 	 	(Net)	 	
 		
Piceance Basin	 	 	3,923	 	 	 	3,587	 	 	 	—	 	 	 	—	 	
Bakken Shale	 	 	—	 	 	 	—	 	 	 	19	 	 	 	13	 	
Marcellus Shale	 	 	14	 	 	 	6	 	 	 	—	 	 	 	—	 	
Powder River Basin	 	 	6,404	 	 	 	2,884	 	 	 	—	 	 	 	—	 	
San Juan Basin	 	 	3,267	 	 	 	881	 	 	 	—	 	 	 	—	 	
Other(1)	 	 	1,626	 	 	 	532	 	 	 	—	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	 	15,234	 	 	 	7,890	 	 	 	19	 	 	 	13	 	

 

			
* 		We use the term “gross” to refer to all wells or acreage in which we have at least a partial working interest and “net” to refer to our ownership represented by that working interest.	
 		
(1)		Other includes Barnett Shale, Arkoma and Green River Basins and miscellaneous smaller properties. Our Arkoma Basin operations were classified as held for sale and reported as discontinued operations as of June 30, 2011 and comprised less than one percent of our assets.	
 
At December 31, 2010, there were 181 gross and 105 net producing wells with multiple completions.
 
Developed and Undeveloped Acreage
 
The following table summarizes our leased acreage as of December 31, 2010.

 	 	Developed	 	 	Undeveloped	 	 	Total	 	
 	 	Gross Acres	 	 	Net Acres	 	 	Gross Acres	 	 	Net Acres	 	 	Gross Acres	 	 	Net Acres	 	
 		
Piceance Basin	 	 	133,428	 	 	 	102,835	 	 	 	157,017	 	 	 	108,165	 	 	 	290,445	 	 	 	211,000	 	
Bakken Shale	 	 	16,178	 	 	 	13,483	 	 	 	114,245	 	 	 	75,937	 	 	 	130,423	 	 	 	89,420	 	
Marcellus Shale	 	 	1,828	 	 	 	914	 	 	 	108,023	 	 	 	98,387	 	 	 	109,851	 	 	 	99,301	 	
Powder River Basin	 	 	551,113	 	 	 	250,179	 	 	 	399,869	 	 	 	175,371	 	 	 	950,982	 	 	 	425,550	 	
San Juan Basin	 	 	237,587	 	 	 	119,422	 	 	 	2,100	 	 	 	1,576	 	 	 	239,687	 	 	 	120,998	 	
Other(1)	 	 	149,414	 	 	 	81,731	 	 	 	326,778	 	 	 	241,254	 	 	 	476,191	 	 	 	322,986	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	 	1,089,548	 	 	 	568,565	 	 	 	1,108,032	 	 	 	700,690	 	 	 	2,197,580	 	 	 	1,269,255	 	

 

			
(1)		Other includes Barnett Shale, Arkoma and Green River Basins, other Williston Basin acreage and miscellaneous smaller properties. Our Arkoma Basin operations were classified as held for sale and reported as discontinued operations as of June 30, 2011 and comprised less than one percent of our assets.	

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Drilling and Exploratory Activities
 
We focus on lower-risk development drilling. Our development drilling success rate was approximately 99 percent in each of 2010, 2009 and 2008.
 
The following table summarizes domestic drilling activity by number and type of well for the periods indicated.

 	 	2010	 	 	2009	 	 	2008	 	
 		
 	 	 	Gross Wells	 	 	 	Net Wells	 	 	 	Gross Wells	 	 	 	Net Wells	 	 	 	Gross Wells	 	 	 	Net Wells	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Piceance Basin	 	 	398	 	 	 	360	 	 	 	349	 	 	 	303	 	 	 	687	 	 	 	624	 	
Bakken Shale	 	 	0	 	 	 	0	 	 	 	n/a	 	 	 	n/a	 	 	 	n/a	 	 	 	n/a	 	
Marcellus Shale	 	 	8	 	 	 	3	 	 	 	8	 	 	 	4	 	 	 	n/a	 	 	 	n/a	 	
Powder River Basin	 	 	531	 	 	 	242	 	 	 	233	 	 	 	95	 	 	 	702	 	 	 	324	 	
San Juan Basin	 	 	43	 	 	 	15	 	 	 	77	 	 	 	39	 	 	 	95	 	 	 	37	 	
Other	 	 	177	 	 	 	38	 	 	 	208	 	 	 	45	 	 	 	298	 	 	 	65	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Productive, development	 	 	1,157	 	 	 	658	 	 	 	875	 	 	 	486	 	 	 	1,782	 	 	 	1,050	 	
Productive, exploration	 	 	0	 	 	 	0	 	 	 	3	 	 	 	1	 	 	 	4	 	 	 	2	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total Productive	 	 	1,157	 	 	 	658	 	 	 	878	 	 	 	487	 	 	 	1,786	 	 	 	1,052	 	
Dry, development	 	 	5	 	 	 	3	 	 	 	2	 	 	 	0	 	 	 	1	 	 	 	0	 	
Dry, exploration	 	 	0	 	 	 	0	 	 	 	2	 	 	 	1	 	 	 	0	 	 	 	0	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total Drilled	 	 	1,162	 	 	 	661	 	 	 	882	 	 	 	488	 	 	 	1,787	 	 	 	1,052	 	

 

			
(1)		Other includes Barnett Shale, Arkoma and Green River Basins and miscellaneous smaller properties.	
 
In 2010, we drilled five gross nonproductive development wells and three net nonproductive development wells. Total gross operated wells drilled were 656 in 2010, 472 in 2009 and 1,125 in 2008.
 
Present Activities
 
At July 31, 2011, we had 39 gross (23 net) wells in the process of being drilled.
 
Scheduled Lease Expirations
 
Domestic.   The table below sets forth, as of July 31, 2011, the gross and net acres scheduled to expire over the next several years. The acreage will not expire if we are able to establish production by drilling wells on the lease prior to the expiration date. We expect to hold substantially all of the Bakken and Marcellus Shale acreage by drilling prior to its expiration. We are working with the BLM to form a federal unit to prevent a majority of the Piceance acreage shown in the table below in 2011 and 2012 from expiring and believe that we will be successful in these efforts. Approximately 81% of the acreage shown in the table below as “Other” in 2011 through 2013 consists of our Arkoma Basin operations which are currently held for sale.

 	 	2011	 	 	2012	 	 	2013	 	 	2014 +	 	 	Total	 	
 		
Piceance Basin	 	 	21,869	 	 	 	4,236	 	 	 	5,840	 	 	 	3,720	 	 	 	35,665	 	
Bakken Shale	 	 	280	 	 	 	14,055	 	 	 	51,323	 	 	 	7,289	 	 	 	72,947	 	
Marcellus Shale	 	 	331	 	 	 	2,273	 	 	 	44,533	 	 	 	56,771	 	 	 	103,908	 	
Powder River Basin	 	 	2,099	 	 	 	8,432	 	 	 	15,874	 	 	 	1,109	 	 	 	27,514	 	
San Juan Basin	 	 	0	 	 	 	0	 	 	 	0	 	 	 	0	 	 	 	0	 	
Other	 	 	29,294	 	 	 	11,950	 	 	 	8,430	 	 	 	81,131	 	 	 	130,805	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total (Gross Acres)	 	 	53,873	 	 	 	40,946	 	 	 	126,000	 	 	 	150,020	 	 	 	370,839	 	

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 	 	2011	 	 	2012	 	 	2013	 	 	2014 +	 	 	Total	 	
 		
Piceance Basin	 	 	20,488	 	 	 	2,208	 	 	 	2,422	 	 	 	3,491	 	 	 	28,609	 	
Bakken Shale	 	 	191	 	 	 	13,682	 	 	 	49,725	 	 	 	2,629	 	 	 	66,227	 	
Marcellus Shale	 	 	273	 	 	 	1,756	 	 	 	30,701	 	 	 	46,544	 	 	 	79,274	 	
Powder River Basin	 	 	726	 	 	 	2,677	 	 	 	7,720	 	 	 	561	 	 	 	11,684	 	
San Juan Basin	 	 	0	 	 	 	0	 	 	 	0	 	 	 	0	 	 	 	0	 	
Other	 	 	18,276	 	 	 	9,743	 	 	 	7,249	 	 	 	80,822	 	 	 	116,090	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total (Net Acres)	 	 	39,954	 	 	 	30,066	 	 	 	97,817	 	 	 	134,047	 	 	 	301,884	 	

International.   In general, all of our concessions have expiration dates of either 2025 or 2026, except for two concessions that expire beyond 2030 and four that expire in 2015 and 2016. With respect to these four we are negotiating ten year extensions for which we have contractual rights. These four concessions represent approximately 169,000 acres net to Apco or approximately 116,000 acres net to WPX based on our 69% ownership in Apco. Our remaining properties in Argentina and Colombia are all exploration permits or exploration contracts that have much shorter terms and on which we have made exploration investment commitments that must be completed. These areas will expire in 2011 to 2013 unless discoveries are made. There are opportunities to extend exploration terms for a year with good technical justification. We can either declare the portions of these blocks where we have made discoveries commercial and convert that acreage to a concession or exploitation acreage with a specified term for production of 25 to 35 years, or relinquish a portion or the balance of the acreage if we are not willing to make further exploration commitments.
 
Gas Management
 
Our sales and marketing activities to date include the sale of our natural gas and oil production, in addition to third party purchases and subsequent sales to Williams Partners for fuel and shrink gas. Following the completion of the spin-off of our stock to Williams’ stockholders, we do not expect to continue to provide fuel and shrink gas services to Williams Partners’ midstream business on a long-term basis. Our sales and marketing activities also include the management of various natural gas related contracts such as transportation, storage and related hedges. We also sell natural gas purchased from working interest owners in operated wells and other area third party producers. We primarily engage in these activities to enhance the value received from the sale of our natural gas and oil production. Revenues associated with the sale of our production are recorded in oil and gas revenues. The revenues and expenses related to other marketing activities are reported on a gross basis as part of gas management revenues and costs and expenses.
 
Delivery Commitments
 
We hold a long-term obligation to deliver on a firm basis 200,000 MMBtu/d of natural gas to a buyer at the White River Hub (Greasewood-Meeker, Colorado), which is the major market hub exiting the Piceance Basin. The Piceance, being our largest producing basin, generates ample production to fulfill this obligation without risk of nonperformance during periods of normal infrastructure and market operations. While the daily volume of natural gas is large and represents a significant percentage of our daily production, this transaction does not represent a material exposure. This obligation expires in 2014.
 
Purchase Commitments
 
In connection with a gathering agreement entered into by Williams Partners with a third party in December 2010, we concurrently agreed to buy up to 200,000 MMBtu/d of natural gas at Transco Station 515 (Marcellus Shale) priced at market prices from the same third party. Purchases under the 12-year contract are expected to begin in the third quarter of 2011. We expect to sell this natural gas in the open market and may utilize available transportation capacity to facilitate the sales.
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Hedging Activity
 
To manage the commodity price risk and volatility of owning producing natural gas properties, we enter into derivative contracts for a portion of our expected future production. See further discussion in “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
 
Customers
 
Oil and gas production is sold through our sales and marketing activities to a variety of purchasers under various length contracts ranging from one day to multi-year at market based prices. Our third party customers include other producers, utility companies, power generators, banks, marketing and trading companies and midstream service providers. In 2010, natural gas sales to BP Energy Company accounted for approximately 13 percent of our revenues. We believe that the loss of one or more of our current natural gas, oil or NGLs purchasers would not have a material adverse effect on our ability to sell our production, because any individual purchaser could be readily replaced by another purchaser, absent a broad market disruption.
 
Title to Properties
 
Our title to properties is subject to royalty, overriding royalty, carried, net profits, working and other similar interests and contractual arrangements customary in the natural gas and oil industry, to liens for current taxes not yet due and to other encumbrances. In addition, leases on Native American reservations are subject to Bureau of Indian Affairs and other approvals unique to those locations. As is customary in the industry in the case of undeveloped properties, a limited investigation of record title is made at the time of acquisition. Drilling title opinions are usually prepared before commencement of drilling operations. We believe we have satisfactory title to substantially all of our active properties in accordance with standards generally accepted in the natural gas and oil industry. Nevertheless, we are involved in title disputes from time to time which can result in litigation and delay or loss of our ability to realize the benefits of our leases.
 
Seasonality
 
Generally, the demand for natural gas decreases during the spring and fall months and increases during the winter months and in some areas during the summer months. Seasonal anomalies such as mild winters or hot summers can lessen or intensify this fluctuation. Conversely, during extreme weather events such as blizzards, hurricanes, or heat waves, pipeline systems can become temporary constraints to supply meeting demand thus amplifying localized price spikes. In addition, pipelines, utilities, local distribution companies and industrial users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the warmer months. This can lessen seasonal demand fluctuations. World weather and resultant prices for liquefied natural gas can also affect deliveries of competing liquefied natural gas into this country from abroad, affecting the price of domestically produced natural gas. In addition, adverse weather conditions can also affect our production rates or otherwise disrupt our operations.
 
Competition
 
We compete with other oil and gas concerns, including major and independent oil and gas companies in the development, production and marketing of natural gas. We compete in areas such as acquisition of oil and gas properties and obtaining necessary equipment, supplies and services. We also compete in recruiting and retaining skilled employees.
 
In our gas management services business, we compete directly with large independent energy marketers, marketing affiliates of regulated pipelines and utilities and natural gas producers. We also compete with brokerage houses, energy hedge funds and other energy-based companies offering similar services.
 
Environmental Matters and Regulation
 
Our operations are subject to numerous federal, state, local, Native American tribal and foreign laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental

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protection. Applicable U.S. federal environmental laws include, but are not limited to, the Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), the Clean Water Act (“CWA”) and the Clean Air Act (“CAA”). These laws and regulations govern environmental cleanup standards, require permits for air, water, underground injection, solid and hazardous waste disposal and set environmental compliance criteria. In addition, state and local laws and regulations set forth specific standards for drilling wells the maintenance of bonding requirements in order to drill or operate wells, the spacing and location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells, and the prevention and cleanup of pollutants and other matters. We maintain insurance against costs of clean-up operations, but we are not fully insured against all such risks. Additionally, Congress and federal and state agencies frequently revise the environmental laws and regulations, and any changes that result in delay or more stringent and costly permitting, waste handling, disposal and clean-up requirements for the oil and gas industry could have a significant impact on our operating costs. Although future environmental obligations are not expected to have a material impact on the results of our operations or financial condition, there can be no assurance that future developments, such as increasingly stringent environmental laws or enforcement thereof, will not cause us to incur material environmental liabilities or costs.
 
Public and regulatory scrutiny of the energy industry has resulted in increased environmental regulation and enforcement being either proposed or implemented. For example, in March 2010, EPA announced its National Enforcement Initiatives for 2011 to 2013, which includes the addition of “Energy Extraction Activities” to its enforcement priorities list. According to the EPA’s website, “some energy extraction activities, such as new techniques for oil and gas extraction and coal mining, pose a risk of pollution of air, surface waters and ground waters if not properly controlled.” To address these concerns, the EPA is developing an initiative to ensure that energy extraction activities are complying with federal environmental requirements. This initiative will be focused on those areas of the country where energy extraction activities are concentrated, and the focus and nature of the enforcement activities will vary with the type of activity and the related pollution problem presented. This initiative could involve a large scale investigation of our facilities and processes, and could lead to potential enforcement actions, penalties or injunctive relief against us.
 
Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal fines and penalties and the imposition of injunctive relief. Accidental releases or spills may occur in the course of our operations, and we cannot assure you that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons. Although we believe that we are in substantial compliance with applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on us, there can be no assurance that this will continue in the future.
 
The environmental laws and regulations that could have a material impact on the oil and natural gas exploration and production industry and our business are as follows:
 
Hazardous Substances and Wastes.   CERCLA, also known as the “Superfund law,” imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that transported or disposed or arranged for the transport or disposal of the hazardous substances found at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.
 
The Resource Conservation and Recovery Act (“RCRA”) generally does not regulate wastes generated by the exploration and production of natural gas and oil. The RCRA specifically excludes from the definition of hazardous waste “drilling fluids, produced waters and other wastes associated with the exploration, development or production of crude oil, natural gas or geothermal energy.” However, legislation has been proposed in Congress from time to time that would reclassify certain natural gas and oil exploration and production wastes as “hazardous wastes,” which would make the reclassified wastes subject to much more stringent handling, disposal and clean-up

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requirements. If such legislation were to be enacted, it could have a significant impact on our operating costs, as well as the natural gas and oil industry in general. An environmental organization recently petitioned the EPA to reconsider certain RCRA exemptions for exploration and production wastes. Moreover, ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste oils, may be regulated as hazardous waste.
 
We own or lease, and have in the past owned or leased, onshore properties that for many years have been used for or associated with the exploration and production of natural gas and oil. Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us on or under other locations where such wastes have been taken for disposal. In addition, a portion of these properties have been operated by third parties whose treatment and disposal or release of wastes was not under our control. These properties and the wastes disposed thereon may be subject to CERCLA, the CWA, the RCRA and analogous state laws. Under such laws, we could be required to remove or remediate previously disposed wastes (including waste disposed of or released by prior owners or operators) or property contamination (including groundwater contamination by prior owners or operators), or to perform remedial plugging or closure operations to prevent future contamination.
 
Waste Discharges.   The CWA and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or an analogous state agency. The CWA and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. Spill prevention, control and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of navigable waters by a petroleum hydrocarbon tank spill, rupture or leak. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. Federal and state regulatory agencies can impose administrative, civil and criminal penalties as well as other enforcement mechanisms for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations. In 2007, 2008 and 2010, we received three separate information requests from the EPA pursuant to Section 308 of the CWA. The information requests required us to provide the EPA with information about releases at three of our facilities and our compliance with spill prevention, control and countermeasure requirements. We have responded to these information requests and no proceeding or enforcement actions have been initiated. We believe that our operations are in substantial compliance with the CWA.
 
On April 25, 2011, EPA issued for public comment a new draft general permit for stormwater discharges from construction activities involving more than one acre. EPA is developing this draft construction general permit (“CGP”) to implement the new Effluent Limitations Guidelines and New Source Performance Standards for the Construction and Development Industry. Because the existing permit is set to expire on June 30, 2011, EPA also is proposing to extend that permit until January 31, 2012. When EPA finalizes the new CGP, likely in early January 2012, operators of construction activities will be subject to significantly more stringent erosion and sediment control, inspection, and monitoring requirements.
 
Air Emissions.   The CAA and associated state laws and regulations restricts the emission of air pollutants from many sources, including oil and gas operations. New facilities may be required to obtain permits before construction can begin, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. More stringent regulations governing emissions of toxic air pollutants and greenhouse gases (“GHGs”) have been developed by the EPA and may increase the costs of compliance for some facilities.
 
Oil Pollution Act.   The Oil Pollution Act of 1990, as amended (“OPA”) and regulations thereunder impose a variety of requirements on “responsible parties” related to the prevention of oil spills and liability for damages resulting from such spills in United States waters. A “responsible party” includes the owner or operator of an onshore facility, pipeline or vessel, or the lessee or permittee of the area in which an offshore facility is located. OPA assigns liability to each responsible party for oil cleanup costs and a variety of public

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and private damages. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of a federal safety, construction or operating regulation. If the party fails to report a spill or to cooperate fully in the cleanup, liability limits likewise do not apply. Few defenses exist to the liability imposed by OPA. OPA imposes ongoing requirements on a responsible party, including the preparation of oil spill response plans and proof of financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill.
 
National Environmental Policy Act.   Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. The process involves the preparation of either an environmental assessment or environmental impact statement depending on whether the specific circumstances surrounding the proposed federal action will have a significant impact on the human environment. The NEPA process involves public input through comments which can alter the nature of a proposed project either by limiting the scope of the project or requiring resource-specific mitigation. NEPA decisions can be appealed through the court system by process participants. This process may result in delaying the permitting and development of projects, increase the costs of permitting and developing some facilities and could result in certain instances in the cancellation of existing leases.
 
Endangered Species Act.   The Endangered Species Act (“ESA”) restricts activities that may affect endangered or threatened species or their habitats. While some of our operations may be located in areas that are designated as habitats for endangered or threatened species, we believe that we are in substantial compliance with the ESA. However, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected states.
 
Worker Safety.   The Occupational Safety and Health Act (“OSHA”) and comparable state statutes regulate the protection of the health and safety of workers. The OSHA hazard communication standard requires maintenance of information about hazardous materials used or produced in operations and provision of such information to employees. Other OSHA standards regulate specific worker safety aspects of our operations. Failure to comply with OSHA requirements can lead to the imposition of penalties.
 
Safe Drinking Water Act.   The Safe Drinking Water Act (“SDWA”) and comparable state statutes restrict the disposal, treatment or release of water produced or used during oil and gas development. Subsurface emplacement of fluids (including disposal wells or enhanced oil recovery) is governed by federal or state regulatory authorities that, in some cases, includes the state oil and gas regulatory authority or the state’s environmental authority. These regulations may increase the costs of compliance for some facilities.
 
Hydraulic Fracturing.   We use hydraulic fracturing as a means to maximize the productivity of our oil and gas wells in all of the domestic basins in which we operate other than the Arkoma and Powder River Basins. Our net acreage position in the basins in which hydraulic fracturing is utilized total approximately 550,000 acres and represents approximately 94% of our domestic proved undeveloped oil and gas reserves. Although average drilling and completion costs for each basin will vary, as will the cost of each well within a given basin, on average approximately 31% of the drilling and completion costs for each of our wells for which we use hydraulic fracturing is associated with hydraulic fracturing activities. These costs are treated in the same way that all other costs of drilling and completion of our wells are treated and are built into and funded through our normal capital expenditure budget.
 
The protection of groundwater quality is extremely important to us. We follow applicable standard industry practices and legal requirements for groundwater protection in our operations. These measures are subject to close supervision by state and federal regulators (including the BLM with respect to federal acreage), which conduct many inspections during operations that include hydraulic fracturing. Industry standards and legal requirements for groundwater protection focus on five principal areas: (i) pressure testing of well construction and integrity, (ii) lining of pits used to hold water and other fluids used in the drilling process isolated from surface water and groundwater, (iii) casing and cementing practices for wells to ensure separation of the production zone from groundwater, (iv) disclosure of the chemical content of fracturing liquids, and (v) setback requirements as to the location of waste disposal areas. The legal requirements relating

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to the protection of surface water and groundwater vary from state to state and there are also federal regulations and guidance that apply to all domestic drilling. In addition, the American Petroleum Institute publishes industry standards and guidance for hydraulic fracturing and the protection of surface water and groundwater. Our policy and practice is to follow all applicable guidelines and regulations in the areas where we conduct hydraulic fracturing.
 
In addition to the required use of and specifications for casing and cement in well construction, there are additional regulatory requirements and best practices that we follow to ensure wellbore integrity and full isolation of any underground aquifers and protection of surface waters. These include the following:

 	• 	Prior to perforating the production casing and hydraulic fracturing operations, the casing is pressure tested.	
 		
 	• 	Before the fracturing operation commences, all surface equipment is pressure tested, which includes the wellhead and all pressurized lines and connections leading from the pumping equipment to the wellhead. During the pumping phases of the hydraulic fracturing treatment, specialized equipment is utilized to monitor and record surface pressures, pumping rates, volumes and chemical concentrations to ensure the treatment is proceeding as designed and the wellbore integrity is sound. Should any problem be detected during the hydraulic fracturing treatment, the operation is shut down until the problem is evaluated, reported and remediated.	
 		
 	• 	As a means to protect against the negative impacts of any potential surface release of fluids associated with the hydraulic fracturing operation, special precautions are taken to ensure proper containment and storage of fluids. For example, any earthen pits containing non-fresh water must be lined with a synthetic impervious liner. These pits are tested regularly, and in certain sensitive areas have additional leak detection systems in place. At least two feet of freeboard, or available capacity, must be present in the pit at all times. In addition, earthen berms are constructed around any storage tanks, any fluid handling equipment, and in some cases around the perimeter of the location to contain any fluid releases. These berms are considered to be a “secondary” form of containment and serve as an added measure for the protection of groundwater.	
 		
 	• 	We conduct baseline water monitoring in many of the basins in which we use hydraulic fracturing:	

 	• 	In Colorado, baseline water monitoring may be required by the Colorado Oil and Gas Conservation Commission (“COGCC”) or BLM as a condition of approval for the drilling permit, but otherwise it is not a requirement. The industry is currently working with the COGCC in preparing a voluntary baseline water monitoring program by basin. The Company has committed to this program that will likely go into effect later in 2011.	
 		
 	• 	In the Barnett Shale, and with landowner approval, we perform water monitoring of fresh water wells within an agreed upon distance on a voluntary basis, even though not required by state regulation.	
 		
 	• 	In Pennsylvania, we perform baseline water monitoring pursuant to Pennsylvania Department of Environmental Protection requirements.	
 		
 	• 	There are currently no regulatory requirements to conduct baseline water monitoring in the Bakken Shale or the San Juan Basin. We plan to begin voluntarily conducting water monitoring in the Bakken Shale. The majority of our assets in the San Juan Basin are on federal lands, and there are few cases where water wells are within one to two miles of our wells, which is outside the range that we would typically sample.	
 
Once a pipe is set in place, cement is pumped into the well where it hardens and creates a permanent, isolating barrier between the steel casing pipe and surrounding geological formations. This aspect of the well design essentially eliminates a “pathway” for the fracturing fluid to contact any aquifers during the hydraulic fracturing operations. Furthermore, in the basins in which we conduct hydraulic fracturing, the hydrocarbon bearing formations are separated from any usable underground aquifers by thousands of feet of impermeable rock layers. This wide separation serves as a protective barrier, preventing any migration of fracturing fluids or hydrocarbons upwards into any groundwater zones.

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In addition, the vendors we employ to conduct hydraulic fracturing are required to monitor all pump rates and pressures during the fracturing treatments. This monitoring occurs on a real-time basis and data is recorded to ensure protection of groundwater.
 
The cement and steel casing used in well construction can have rare failures. Any failure in isolation is reported to the applicable oil and gas regulatory body. A remediation procedure is written and approved and then completed on the well before any further operations or production is commenced. Possible isolation failures may result from:

 	• 	Improper cementing work . This can create conditions in which hydraulic fracturing fluids and other natural occurring substances can migrate into the surrounding geological formation. Production casing cementing tops and cement bond effectiveness are evaluated using either a temperature log or an acoustical cement bond log prior to any completion operations. If the cement bond or cement top is determined to be inadequate for zone isolation, remedial cementing operations are performed to fill any voids and re-establish integrity. As part of this remedial operation, the casing is again pressure tested before fracturing operations are initiated.	
 		
 	• 	Initial casing integrity failure . The casing is pressure tested prior to commencing completion operations. If the test fails due to a compromise in the casing, the applicable oil and gas regulatory body will be notified and a remediation procedure will be written, approved, and completed before any further operations are conducted. In addition, casing pressures are monitored throughout the fracturing treatment and any indication of failure will result in an immediate shutdown of the operation.	
 		
 	• 	Well failure or casing integrity failure during production . Loss of wellbore integrity can occur over time even if the well was correctly constructed due to downhole operating environments causing corrosion and stress. During production, the bradenhead, casing, and tubing pressures are monitored and a casing failure can be identified and evaluated. Remediation could include placing additional cement behind casing, installing a casing patch, or plugging and abandoning the well, if necessary.	
 		
 	• 	“Fluid leakoff” during the fracturing process . Fluid leakoff can occur during hydraulic fracturing operations whereby some of the hydraulic fracturing fluid flows through the artificially created fractures into the micropore or pore spaces within the formation, existing natural factures in the formation, or small fractures opened into the formation by the pressure in the induced fracture. Fluid leakoff is accounted for in the volume design of nearly every fracturing job and “pump-in” tests are often conducted prior to fracturing jobs to estimate the extent of fluid leakoff. In certain situations, a very fine grain sand is added in the initial part of the treatment to seal-off any small fractures of micropore spaces and mitigate fluid leak-off.	
 
Approximately 99% of hydraulic fracturing fluids are made up of water and sand. We utilize major hydraulic fracturing service companies whose research departments conduct ongoing development of “greener” chemicals that are used in fracturing. We evaluate, test, and where appropriate adopt those products that are more environmentally friendly. We have also chosen to participate in a voluntary fracturing chemical registry that is a public website: www.fracfocus.org at which interested persons can find out information about fracturing fluids. This registry is a joint project of the Ground Water Protection Council and the Interstate Oil and Gas Compact Commission and provides our industry with an avenue to voluntarily disclose chemicals used in the hydraulic fracturing process. The Company registered with the FracFocus Chemical Disclosure Registry in April 2011 and began uploading data when the registry went live on April 11, 2011. To date, we have loaded data on 59 wells. We plan to add all wells fractured since January 1, 2011 to the site. Consistent with other industry participants, we are not planning to add data on wells drilled prior to 2011. The information included on this website is not incorporated by reference in this prospectus.
 
We currently recycle over 90% of the water recovered from our operations in the Piceance Basin and the Marcellus Shale. This recycling greatly lessens the demand on local natural water resources. We recycled more than 30,000 barrels of water per day on average in 2010. Across all areas where we conduct hydraulic fracturing operations, approximately 9.6 million barrels of water (53,000 barrels of water per day) were used during the first six months of 2011 in our hydraulic fracturing activities. We recover approximately 80% of

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this volume during the first one to two months of flowback and production with small additional volumes recovered over longer time frames. Any water from our hydraulic fracturing operations that is not recycled is disposed of in a way that does not impact surface waters.
 
Despite our efforts to minimize impacts on the environment from hydraulic fracturing activities, in light of the volume of our hydraulic fracturing activities, we have occasionally been engaged in litigation and received requests for information, notices of alleged violation, and citations related to the activities of our hydraulic fracturing vendors, none of which has resulted in any material costs or penalties.
 
Recently, there has been a heightened debate over whether the fluids used in hydraulic fracturing may contaminate drinking water supply and proposals have been made to revisit the environmental exemption for hydraulic fracturing under the SDWA or to enact separate federal legislation or legislation at the state and local government levels that would regulate hydraulic fracturing. Both the United States House of Representatives and Senate are considering Fracturing Responsibility and Awareness of Chemicals Act (“FRAC Act”) bills and a number of states, including states in which we have operations, are looking to more closely regulate hydraulic fracturing due to concerns about water supply. A committee of the U.S. House of Representatives is also conducting an investigation of hydraulic fracturing practices. The recent congressional legislative efforts seek to regulate hydraulic fracturing to Underground Injection Control program requirements, which would significantly increase well capital costs. If the exemption for hydraulic fracturing is removed from the SDWA, or if the FRAC Act or other legislation is enacted at the federal, state or local level, any restrictions on the use of hydraulic fracturing contained in any such legislation could have a significant impact on our financial condition and results of operations.
 
Federal agencies are also considering regulation of hydraulic fracturing. The EPA recently asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the SDWA’s Underground Injection Control Program. While the EPA has yet to take any action to enforce or implement this newly asserted regulatory authority, the EPA’s interpretation without formal rule making has been challenged and industry groups have filed suit challenging the EPA’s interpretation. If the EPA prevails in this lawsuit, its interpretation could result in enforcement actions against service providers or companies that used diesel products in the hydraulic fracturing process or could require such providers or companies to conduct additional studies regarding diesel in the groundwater. Furthermore, the State of Colorado, in response to an EPA request, has asked companies operating in Colorado, including us, to report whether diesel products were used in the hydraulic fracturing process from 2004 to 2009. In response to this inquiry we consulted our service providers and reported to the State of Colorado that at least nine wells were subject to hydraulic fracturing utilizing fluids that contained chemical products that contained diesel fuel as a component. The State of Colorado may conduct additional investigations related to this inquiry. Any enforcement actions or requirements of additional studies or investigations by the EPA or the State of Colorado could increase our operating costs and cause delays or interruptions of our operations.
 
The EPA is also collecting information as part of a study into the effects of hydraulic fracturing on drinking water. The results of this study, expected in late 2012, could result in additional regulations, which could lead to operational burdens similar to those described above. In connection with the EPA study, we have received a request for information from the EPA for 52 of our wells located in various basins that have been hydraulically fractured. The requested information covers well design, construction and completion practices, among other things. We understand that similar requests were sent to eight other companies that own or operate wells that utilized hydraulic fracturing.
 
In addition to the EPA study, the Shale Gas Subcommittee of the Secretary of Energy Advisory Board issued a report on hydraulic fracturing in August 2011. The report concludes that the risk of fracturing fluids contaminating drinking water sources through fractures in the shale formations “is remote.” It also states that development of the nation’s shale resources has produced major economic benefits. The report includes recommendations to address concerns related to hydraulic fracturing and shale gas production, including but not limited to conducting additional field studies on possible methane leakage from shale gas wells to water reservoirs and adopting new rules and enforcement practices to protect drinking and surface waters. The Government Accountability Office is also examining the environmental impacts of produced water and the Counsel for Environmental Quality has been petitioned by environmental groups to develop a programmatic environmental impact statement

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under NEPA for hydraulic fracturing. The United States Department of the Interior is also considering whether to impose disclosure requirements or other mandates for hydraulic fracturing on federal land.
 
Several states, including Pennsylvania, Texas, Colorado, North Dakota and New Mexico, have adopted or are considering adopting, regulations that could restrict or impose additional requirements related to hydraulic fracturing. For example, on June 17, 2011, Texas signed into law a mandate for public disclosure of the chemicals that operators use during hydraulic fracturing in Texas. The law goes into effect September 1, 2011. State regulators have until 2013 to complete implementing rules. Pennsylvania also requires that detailed information be disclosed regarding the hydraulic fracturing fluids, including but not limited to, a list of chemical additives, volume of each chemical added, and list of chemicals in the material safety data sheets. Since June 2009, Colorado has required all operators to maintain a chemical inventory by well site for each chemical product used downhole or stored for use downhole during drilling, completion and workover operations, including fracture stimulation in an amount exceeding 500 pounds during any quarterly reporting period. Disclosure of chemicals used in the hydraulic fracturing process could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater.
 
In addition, at least three local governments in Texas have imposed temporary moratoria on drilling permits within city limits so that local ordinances may be reviewed to assess their adequacy to address such activities, while some state and local governments in the Marcellus Shale have considered or imposed temporary moratoria on drilling operations using hydraulic fracturing until further study of the potential environmental and human health impacts by EPA or the relative state agencies are completed. Additionally, publicly operated treatment works facilities in Pennsylvania have ceased taking wastewater from hydraulic fracturing operations, and we are now recycling this wastewater and utilizing it in subsequent hydraulic fracturing operations. At this time, it is not possible to estimate the potential impact on our business of these state and local actions or the enactment of additional federal or state legislation or regulations affecting hydraulic fracturing.
 
Global Warming and Climate Change.   Recent scientific studies have suggested that emissions of GHGs, including carbon dioxide and methane, may be contributing to warming of the earth’s atmosphere. Both houses of Congress have previously considered legislation to reduce emissions of GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. The EPA has begun to regulate GHG emissions. On December 15, 2009, the EPA published its findings that emissions of GHGs present an endangerment to public heath and the environment. These findings allow the EPA to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the CAA. The EPA has adopted two sets of regulations under the CAA. The first limits emissions of GHGs from motor vehicles beginning with the 2012 model year. The EPA has asserted that these final motor vehicle GHG emission standards trigger CAA construction and operating permit requirements for stationary sources, commencing when the motor vehicle standards take effect on January 2, 2011. On June 3, 2010, the EPA published its final rule to address the permitting of GHG emissions from stationary sources under the Prevention of Significant Deterioration and Title V permitting programs. This rule “tailors” these permitting programs to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting. Most recently, on November 30, 2010, the EPA published its final rule expanding the existing GHG monitoring and reporting rule to include onshore and offshore oil and natural gas production facilities and onshore oil and natural gas processing, transmission, storage, and distribution facilities. Reporting of GHG emissions from such facilities will be required on an annual basis, with reporting beginning in 2012 for emissions occurring in 2011. We are required to report our GHG emissions under this rule but are not subject to GHG permitting requirements. Several of the EPA’s GHG rules are being challenged in court proceedings and depending on the outcome of such proceedings, such rules may be modified or rescinded or the EPA could develop new rules.
 
Because regulation of GHG emissions is relatively new, further regulatory, legislative and judicial developments are likely to occur. Such developments may affect how these GHG initiatives will impact our operations. In addition to these regulatory developments, recent judicial decisions have allowed certain tort claims alleging property damage to proceed against GHG emissions sources may increase our litigation risk for such claims. New legislation or regulatory programs that restrict emissions of or require inventory of

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GHGs in areas where we operate have adversely affected or will adversely affect our operations by increasing costs. The cost increases so far have resulted from costs associated with inventorying our GHG emissions, and further costs may result from the potential new requirements to obtain GHG emissions permits, install additional emission control equipment and an increased monitoring and record-keeping burden.
 
Legislation or regulations that may be adopted to address climate change could also affect the markets for our products by making our products more or less desirable than competing sources of energy. To the extent that our products are competing with higher GHG emitting energy sources such as coal, our products would become more desirable in the market with more stringent limitations on GHG emissions. To the extent that our products are competing with lower GHG emitting energy sources such as solar and wind, our products would become less desirable in the market with more stringent limitations on GHG emissions. We cannot predict with any certainty at this time how these possibilities may affect our operations.
 
Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. If any such effects were to occur, they could adversely affect or delay demand for the oil or natural gas or otherwise cause us to incur significant costs in preparing for or responding to those effects.
 
Foreign Operations.   Our exploration and production operations outside the United States are subject to various types of regulations similar to those described above imposed by the governments of the countries in which we operate, and may affect our operations and costs within those countries. For example, the Argentine Department of Energy and the government of the provinces in which Apco’s oil and gas producing concessions are located have environmental control policies and regulations that must be adhered to when conducting oil and gas exploration and exploitation activities. Future environmental regulation of certain aspects of our operations in Argentina and Columbia that are currently unregulated and changes in the laws or regulations could materially affect our financial condition and results of operations.
 
Other Regulation of the Oil and Gas Industry
 
The oil and natural gas industry is extensively regulated by numerous federal, state, local and foreign authorities, including Native American tribes in the United States. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, and Native American tribes are authorized by statute to issue rules and regulations binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for noncompliance. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.
 
The availability, terms and cost of transportation significantly affect sales of oil and natural gas. The interstate transportation and sale for resale of oil and natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the FERC. Federal and state regulations govern the price and terms for access to oil and natural gas pipeline transportation. The FERC’s regulations for interstate oil and natural gas transmission in some circumstances may also affect the intrastate transportation of oil and natural gas.
 
Although oil and natural gas prices are currently unregulated, Congress historically has been active in the area of oil and natural gas regulation. We cannot predict whether new legislation to regulate oil and natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on our operations. Sales of condensate and oil and NGLs are not currently regulated and are made at market prices.
 
Drilling and Production
 
Our operations are subject to various types of regulation at federal, state, local and Native American tribal levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports

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concerning operations. Most states, and some counties, municipalities and Native American tribal areas where we operate also regulate one or more of the following activities:

 	•  	the location of wells;	
 		
 	•  	the method of drilling and casing wells;	
 		
 	•  	the timing of construction or drilling activities including seasonal wildlife closures;	
 		
 	•  	the employment of tribal members or use of tribal owned service businesses;	
 		
 	•  	the rates of production or “allowables;”	
 		
 	•  	the surface use and restoration of properties upon which wells are drilled;	
 		
 	•  	the plugging and abandoning of wells; and	
 		
 	•  	the notice to surface owners and other third parties.	
 
State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of natural gas, oil and NGLs within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but there can be no assurance that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and gas that may be produced from our wells, negatively affect the economics of production from these wells, or to limit the number of locations we can drill.
 
Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production facilities and pipelines, and for site restoration, in areas where we operate. The New Mexico Oil Conservation requires the posting of performance bonds to fulfill financial requirements for owners and operators on state land. The Corps and many other state and local authorities also have regulations for plugging and abandonment, decommissioning and site restoration. Although the Corps does not require bonds or other financial assurances, some state agencies and municipalities do have such requirements.
 
Natural Gas Sales and Transportation
 
Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production. The FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Various federal laws enacted since 1978 have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in first sales, which include all of our sales of our own production. Under the Energy Policy Act of 2005, the FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties.
 
The FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which we may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas and release of our natural gas pipeline capacity. Commencing in 1985, the FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. The FERC’s initiatives have led to the development of a competitive, open access market for natural gas purchases and sales that permits all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, we cannot guarantee that the less

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stringent regulatory approach currently pursued by the FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on our natural gas related activities.
 
Under the FERC’s current regulatory regime, transmission services must be provided on an open-access, nondiscriminatory basis at cost-based rates or at market-based rates if the transportation market at issue is sufficiently competitive. Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Although its policy is still in flux, the FERC has in the past reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our costs of transporting gas to point-of-sale locations.
 
Oil Sales and Transportation
 
Sales of crude oil, condensate and NGLs are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.
 
Our crude oil sales are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate regulation. The FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act and intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is of material difference from those of our competitors.
 
Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors.
 
Operation on Native American Reservations
 
A portion of our leases are, and some of our future leases may be, regulated by Native American tribes. In addition to regulation by various federal, state, local and foreign agencies and authorities, an entirely separate and distinct set of laws and regulations applies to lessees, operators and other parties within the boundaries of Native American reservations in the United States. Various federal agencies within the U.S. Department of the Interior, particularly the Bureau of Indian Affairs, the Office of Natural Resources Revenue and BLM, and the EPA, together with each Native American tribe, promulgate and enforce regulations pertaining to oil and gas operations on Native American reservations. These regulations include lease provisions, royalty matters, drilling and production requirements, environmental standards, Tribal employment contractor preferences and numerous other matters.
 
Native American tribes are subject to various federal statutes and oversight by the Bureau of Indian Affairs and BLM. However, each Native American tribe is a sovereign nation and has the right to enact and enforce certain other laws and regulations entirely independent from federal, state and local statutes and regulations, as long as they do not supersede or conflict with such federal statutes. These tribal laws and regulations include various fees, taxes, requirements to employ Native American tribal members or use tribal owned service businesses and numerous other conditions that apply to lessees, operators and contractors conducting operations within the boundaries of a Native American reservation. Further, lessees and operators within a Native American reservation are subject to the Native American tribal court system, unless there is a specific waiver of sovereign immunity by the Native American tribe allowing resolution of disputes between the Native American tribe and those lessees or operators to occur in federal or state court.
 
Therefore, we are subject to various laws and regulations pertaining to Native American tribal surface ownership, Native American oil and gas leases, fees, taxes and other burdens, obligations and issues unique to oil and gas ownership and operations within Native American reservations. One or more of these requirements, or delays in obtaining necessary approvals or permits pursuant to these regulations, may increase our costs of

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doing business on Native American tribal lands and have an impact on the economic viability of any well or project on those lands.
 
Employees
 
At June 30, 2011, Williams had approximately 1,038 full-time employees dedicated to our business, including personnel who are now employed by certain of the subsidiaries that Williams will transfer to us prior to the completion of this offering. This number does not include employees of Williams who provide services to our business and other of Williams’ businesses. Prior to the completion of this offering, the employees of the subsidiaries that Williams will transfer to us will be transferred to an affiliate services company owned by Williams, and we will reimburse the services company for all direct and indirect expenses it incurs or payments it makes in connection with providing personnel to us. As a result, we will have no employees at the completion of this offering.
 
Offices
 
Our principal executive offices are located at One Williams Center, Tulsa, Oklahoma 74172.
 
Legal Proceedings
 
Royalty litigation
 
In September 2006, royalty interest owners in Garfield County, Colorado, filed a class action suit in District Court, Garfield County Colorado, alleging we improperly calculated oil and gas royalty payments, failed to account for the proceeds that we received from the sale of natural gas and extracted products, improperly charged certain expenses and failed to refund amounts withheld in excess of ad valorem tax obligations. Plaintiffs sought to certify a class of royalty interest owners, recover underpayment of royalties, and obtain corrected payments resulting from calculation errors. We entered into a final partial settlement agreement. The partial settlement agreement defined the class members for class certification, reserved two claims for court resolution, resolved all other class claims relating to past calculation of royalty and overriding royalty payments, and established certain rules to govern future royalty and overriding royalty payments. This settlement resolved all claims relating to past withholding for ad valorem tax payments and established a procedure for refunds of any such excess withholding in the future. The first reserved claim is whether we are entitled to deduct in our calculation of royalty payments a portion of the costs we incur beyond the tailgates of the treating or processing plants for mainline pipeline transportation. We received a favorable ruling on our motion for summary judgment on the first reserved claim. Plaintiffs appealed that ruling and the Colorado Court of Appeals found in our favor in April 2011. In June, 2011, Plaintiffs filed a Petition for Certiorari with the Colorado Supreme Court. We anticipate that the Court will issue a decision on whether to grant further review later in 2011 or early in 2012. The second reserved claim relates to whether we are required to have proportionately increased the value of natural gas by transporting that gas on mainline transmission lines and, if required, whether we did so and are thus entitled to deduct a proportionate share of transportation costs in calculating royalty payments. We anticipate trial on the second reserved claim following resolution of the first reserved claim. We believe our royalty calculations have been properly determined in accordance with the appropriate contractual arrangements and Colorado law. At this time, the plaintiffs have not provided us a sufficient framework to calculate an estimated range of exposure related to their claims. However, it is reasonably possible that the ultimate resolution of this item could result in a future charge that may be material to our results of operations.
 
California energy crisis
 
Our former power business was engaged in power marketing in various geographic areas, including California. Prices charged for power by us and other traders and generators in California and other western states in 2000 and 2001 were challenged in various proceedings, including those before the FERC. We have entered into settlements with the State of California (“State Settlement”), major California utilities (“Utilities Settlement”), and others that substantially resolved each of these issues with these parties.
 
Although the State Settlement and Utilities Settlement resolved a significant portion of the refund issues among the settling parties, we continue to have potential refund exposure to nonsettling parties, including various California end users that did not participate in the Utilities Settlement. We are currently in settlement

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negotiations with certain California utilities aimed at eliminating or substantially reducing this exposure. If successful, and subject to a final “true-up” mechanism, the settlement agreement would also resolve our collection of accrued interest from counterparties as well as our payment of accrued interest on refund amounts. Thus, as currently contemplated by the parties, the settlement agreement would resolve most, if not all, of our legal issues arising from the 2000-2001 California Energy Crisis. With respect to these matters, amounts accrued are not material to our financial position.
 
Certain other issues also remain open at the FERC and for other nonsettling parties.
 
Pursuant to the separation and distribution agreement, Williams will indemnify us for any cash amounts determined to be owed by us, and will be entitled to any cash amounts received by us, in connection with pending proceedings related to these matters.
 
Reporting of natural gas-related information to trade publications
 
Civil suits based on allegations of manipulating published gas price indices have been brought against us and others, in each case seeking an unspecified amount of damages. We are currently a defendant in class action litigation and other litigation originally filed in state court in Colorado, Kansas, Missouri and Wisconsin brought on behalf of direct and indirect purchasers of natural gas in those states. These cases were transferred to the federal court in Nevada. In 2008, the court granted summary judgment in the Colorado case in favor of us and most of the other defendants based on plaintiffs’ lack of standing. On January 8, 2009, the court denied the plaintiffs’ request for reconsideration of the Colorado dismissal and entered judgment in our favor. We expect that the Colorado plaintiffs will appeal now that the court’s order became final on July 18, 2011.
 
In the other cases, on July 18, 2011, the Nevada district court granted our joint motions for summary judgment to preclude the plaintiffs’ state law claims because the federal Natural Gas Act gives the FERC exclusive jurisdiction to resolve those issues. The court also denied the plaintiffs’ class certification motion as moot. On July 22, 2011, the plaintiffs filed their notice of appeal with the Nevada district court. Because of the uncertainty around these current pending unresolved issues, including an insufficient description of the purported classes and other related matters, we cannot reasonably estimate a range of potential exposures at this time. However, it is reasonably possible that the ultimate resolution of these items could result in future charges that may be material to our results of operations.
 
Pursuant to the separation and distribution agreement, Williams will indemnify us for any cash payments (including indirect, punitive or consequential damages) incurred by us in connection with pending proceedings related to these matters. However, such indemnification will not extend to losses incurred by us to the extent those losses arise out of certain legacy natural gas derivative contracts of Williams Gas Marketing Services (See Note 15 of Notes to Combined Financial Statements) detailed in the separation and distribution agreement.
 
EPA Settlement
 
On August 26, 2011, we signed an Administrative Complaint and Consent Agreement with EPA Region 8 to settle allegations of noncompliance with the Clean Air Act Prevention of Significant Deterioration provisions with respect to the absence of emission permits at 76 locations in the Fort Berthold Indian Reservation in North Dakota. We agreed to pay $228,000 in penalties in connection with this settlement, although that amount may be reduced upon further factual investigation.

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MANAGEMENT
 
Directors and Executive Officers

Set forth below is certain information regarding persons who serve as our executive officers and directors or who will become directors prior to the completion of this offering.

 	 	 	 	 	 	 	
Name	 	Age	 	Position	
 		
Alan S. Armstrong	 	 	49	 	 	Chairman of the Board	
Ralph A. Hill	 	 	51	 	 	Chief Executive Officer	
Donald R. Chappel	 	 	59	 	 	Chief Financial Officer(1)	
Ted T. Timmermans	 	 	54	 	 	Chief Accounting Officer(1)	
James J. Bender	 	 	54	 	 	General Counsel and Corporate Secretary(2)	
Robyn L. Ewing	 	 	55	 	 	Chief Administrative Officer(1)	
Rodney J. Sailor	 	 	52	 	 	Treasurer and Deputy Chief Financial Officer(3)	
George A. Lorch	 	 	69	 	 	Prospective Director	
William G. Lowrie	 	 	67	 	 	Prospective Director	
Bryan K. Guderian	 	 	52	 	 	Senior Vice President of Operations(4)	
Neal A. Buck	 	 	55	 	 	Senior Vice President of Business Development and Land(4)	
Marcia M. MacLeod	 	 	58	 	 	Senior Vice President of Human Resources and Administration(4)	
Michael R. Fiser	 	 	47	 	 	Senior Vice President of Marketing(4)	
Steven G. Natali	 	 	57	 	 	Senior Vice President of Exploration(4)	
J. Kevin Vann	 	 	40	 	 	Chief Accounting Officer and Controller(4)	

 

 
			
(1)		Upon the earlier of January 1, 2012 or the time of the spin-off, this individual will no longer serve as one of our officers.	

 
			
(2)		Effective upon the earlier of January 1, 2012 or the time of the spin-off, Mr. Bender’s position will be Senior Vice President, General Counsel and Corporate Secretary.	

 
			
(3)		Effective upon the earlier of January 1, 2012 or the time of the spin-off, Mr. Sailor’s position will be Senior Vice President, Chief Financial Officer and Treasurer.	

 
			
(4)		Position to be effective at the earlier of January 1, 2012 or the time of the spin-off.	

Alan S. Armstrong.   Mr. Armstrong was named Chairman of our Board in April 2011. Mr. Armstrong has been Chief Executive Officer, President and a Director of Williams since January 3, 2011. From February 2002 until January 2011, he was Senior Vice President—Midstream at Williams and acted as President of the Midstream business at Williams. From 1999 to February 2002, Mr. Armstrong was Vice President, Gathering and Processing for Midstream at Williams. From 1998 to 1999 he was Vice President, Commercial Development for Midstream at Williams. As of January 2011, Mr. Armstrong serves as Chairman of the Board and Chief Executive Officer of Williams Partners GP LLC, the general partner of Williams Partners, where he was Senior Vice President—Midstream from February 2010 and Chief Operating Officer and a director from February 2005.
 
We believe that Mr. Armstrong is well qualified to serve as our Chairman of the Board. Mr. Armstrong has many years of experience in our industry, including over 25 years of operating and executive experience with Williams, and we believe this experience will be critical to his ability to identify, understand and address challenges and opportunities that we will face. As the current Chief Executive Officer and President of Williams, we believe Mr. Armstrong is uniquely suited to serve as our Chairman as we become a newly public company. Mr. Armstrong also has knowledge and understanding of corporate governance issues through serving as a public company senior executive and board member. Further, we believe that his executive experience dealing with legislators and regulators will make him an excellent resource for our management and other directors.

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Ralph A. Hill.   Mr. Hill was named Chief Executive Officer in April 2011. Prior to becoming our Chief Executive Officer, Mr. Hill was Senior Vice President—Exploration and Production and acted as President of the Exploration and Production business at Williams since 1998. He was Vice President and General Manager of Exploration and Production business at Williams from 1993 to 1998, as well as Senior Vice President and General Manager of Petroleum Services at Williams from 1998 to 2003. Mr. Hill has served as the Chairman of the Board and Chief Executive Officer of Apco since 2002. Mr. Hill has served as a director of Petrolera Entre Lomas S.A. since 2003. He joined Williams in June 1981 as a member of a management training program and has worked in numerous capacities within the Williams organization.
 
Donald R. Chappel.   Mr. Chappel was named Chief Financial Officer in April 2011. Mr. Chappel has been Senior Vice President and Chief Financial Officer of Williams since April 2003. Prior to joining Williams, Mr. Chappel held various financial, administrative, and operational leadership positions. Mr. Chappel is included in Institutional Investor magazine’s Best CFOs listing for 2011, 2010, 2008, 2007, and 2006. Mr. Chappel also serves as Chief Financial Officer and a director of Williams Partners GP LLC, the general partner of Williams Partners. Mr. Chappel was Chief Financial Officer, from August 2007, and a director, from January 2008, of the general partner of Williams Pipeline Partners L.P., until its merger with Williams Partners in August 2010. Mr. Chappel is also a director of SUPERVALU Inc.
 
Ted T. Timmermans.   Mr. Timmermans was named Chief Accounting Officer in April 2011. Mr. Timmermans has been Vice President, Controller and Chief Accounting Officer of Williams since July 2005, and Vice President, Controller and Chief Accounting Officer of Williams Partners GP LLC, the general partner of Williams Partners since September 2005. Mr. Timmermans served as an Assistant Controller of Williams from April 1998 to July 2005. Mr. Timmermans served as Chief Accounting Officer of the general partner of Williams Pipeline Partners L.P., from 2008 until its merger with Williams Partners in August 2010.
 
James J. Bender.   Mr. Bender was named General Counsel and Corporate Secretary in April 2011. Mr. Bender has been Senior Vice President and General Counsel of Williams since December 2002, and General Counsel of Williams Partners GP LLC, the general partner of Williams Partners, since September 2005. Mr. Bender served as the General Counsel of the general partner of Williams Pipeline Partners L.P., from 2007 until its merger with Williams Partners in August 2010. From June 2000 to June 2002, Mr. Bender was Senior Vice President and General Counsel of NRG Energy, Inc. Mr. Bender was Vice President, General Counsel, and Secretary of NRG Energy from June 1997 to June 2000. NRG Energy, Inc. filed a voluntary bankruptcy petition during 2003 and its plan of reorganization was approved in December 2003.
 
Robyn L. Ewing.   Ms. Ewing was named Chief Administrative Officer in April 2011. Ms. Ewing has been Senior Vice President and Chief Administrative Officer of Williams since April 2008. From 2004 to 2008 Ms. Ewing was Vice President of Human Resources at Williams. Prior to joining Williams, Ms. Ewing worked at MAPCO, which merged with Williams in April 1998. She began her career with Cities Service Company in 1976.
 
Rodney J. Sailor.   Mr. Sailor was named Treasurer and Deputy Chief Financial Officer in April 2011. Mr. Sailor has served as Vice President and Treasurer of Williams since July 2005. He served as Assistant Treasurer of Williams from 2001 to 2005 and was responsible for capital restructuring and capital markets transactions, management of Williams’ liquidity position and oversight of Williams’ balance sheet restructuring program. From 1985 to 2001, Mr. Sailor served in various capacities for Williams. Mr. Sailor was a director of Williams Partners GP LLC, the general partner of Williams Partners, from October 2007 to February 2010. Mr. Sailor has served as a director of Apco since September 2006.
 
George A. Lorch.   Mr. Lorch will be elected as a director prior to the completion of this offering. Mr. Lorch has been a director of Williams since 2001 and currently serves as a member of Williams’ Compensation Committee and its Nominating and Governance Committee. Prior to joining our board, Mr. Lorch will resign from the Williams board of directors. Mr. Lorch is Chairman Emeritus of Armstrong Holdings, Inc., the holding company for Armstrong World Industries, Inc. (a manufacturer and marketer of floors, ceilings, and cabinets). He was the Chief Executive Officer and President of Armstrong World Industries, Inc. from 1993 to 1994 and Chairman of the Board and Chief Executive Officer from 1994 to 2000. From May 2000 to August 2000, he was Chairman of the Board and Chief Executive Officer of

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Armstrong Holdings, Inc. Mr. Lorch has 37 years of sales and marketing experience at Armstrong, including 17 years of experience as a head of operations, with responsibility for profit and loss statements, balance sheets, and stockholder relations. During his 21 years as a director in varied industries, Mr. Lorch has participated in CEO searches, succession planning, strategy development, takeover defense and offense, and director recruitment, and he has served on dozens of board committees. Mr. Lorch has also completed an executive management course at the Kellogg School of Management at Northwestern University. Mr. Lorch is the non-executive Chairman of the Board of Pfizer, Inc. (a research-based pharmaceutical company) and a director of Autoliv, Inc. (a developer, manufacturer, and supplier of automotive safety systems); HSBC Finance Corporation and HSBC North America Holdings Inc., non-public, wholly-owned subsidiaries of HSBC LLC (a banking and financial services provider); and Masonite (a door manufacturer). Mr. Lorch also serves as an advisor to the Carlyle Group (a private equity firm).
 
We believe that Mr. Lorch is well qualified to serve as a member of our board. Mr. Lorch’s executive experience provides valuable financial and management experience, including expertise leading a large organization with multi-national operations, and we believe these experiences will be critical to his ability to identify, understand and address challenges and opportunities that we will face. Mr. Lorch also has knowledge and understanding of the strategy, recruitment, compensation and corporate governance issues that we will face from his extensive experience as a director. Further, we believe Mr. Lorch’s experience as a director of Williams will be advantageous to us as we become a newly public company.
 
William G. Lowrie.   Mr. Lowrie will be elected as a director prior to the completion of this offering. Mr. Lowrie has been a director of Williams since 2003 and currently serves as the Chair of Williams’ Audit Committee and a member of Williams’ Nominating and Governance Committee. In 1999, Mr. Lowrie retired as Deputy Chief Executive Officer and director of BP Amoco PLC (a global energy company), where he spent his entire 33-year career. At Amoco, Mr. Lowrie held various positions of increasing responsibility, developing expertise in drilling, reservoir engineering, financial analysis of projects, and other skills related to the oil and natural gas exploration, production, and processing businesses. At various times in his Amoco tenure, Mr. Lowrie managed natural gas and natural gas liquids pipeline operations, hedging and other hydrocarbon price risk mitigation functions, international contract negotiations, petroleum product refining and marketing operations, environmental health and safety program design, and the development and execution of a process for managing capital investment projects. Mr. Lowrie also worked closely with all financial functions, internal and external auditors, and industry organizations such as the American Petroleum Institute. From 1995 to 1999, Mr. Lowrie served on the board of Bank One Corporation (now JP Morgan Chase), including on that board’s audit committee. He has attended the Executive Program at the University of Virginia. Mr. Lowrie is a director of The Ohio State University Foundation and a trustee of the South Carolina chapter of The Nature Conservancy.
 
We believe that Mr. Lowrie is well qualified to serve as a member of our board. Mr. Lowrie has many years of experience in our industry, including operating, financial and executive experience, and we believe these experiences will be critical to his ability to identify, understand and address challenges and opportunities that we will face. Mr. Lowrie also has extensive risk-management experience from his time at BP Amoco and from his service on Williams’ Audit Committee. Further, we believe Mr. Lowrie’s experience as a director of Williams will be advantageous to us as we become a newly public company.

Bryan K. Guderian.   Mr. Guderian was named Senior Vice President of Operations in August 2011, to be effective at the earlier of January 1, 2012 or the time of the spin-off. Since 1998, Mr. Guderian has served as Vice President of the Exploration & Production unit of Williams with responsibility for the operational and commercial oversight and management of assigned exploration and production assets in the Marcellus Shale, the San Juan Basin and other basins. Mr. Guderian also has responsibility for overseeing Williams’ international operations and has served as a director of Apco since 2002 and a director of Petrolera Entre Lomas S.A. since 2003. Mr. Guderian joined Williams in 1991 as a gas marketing representative.

 
Neal A. Buck.   Mr. Buck was named Senior Vice President of Business Development and Land in August 2011, to be effective at the earlier of January 1, 2012 or the time of the spin-off. Mr. Buck has been Vice President Commercial Operations & Gas Management with Williams Exploration & Production since August

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2001. In that capacity, he is responsible for acquisitions and divestitures, planning, gathering and processing contracts, reserves and production reporting and other services. Mr. Buck joined Williams in 1996, and served as Director of Planning and Analysis from March 1998 to August 2001. Prior to joining Williams, Mr. Buck was with Occidental Petroleum Corporation.

 
Marcia M. MacLeod.   Ms. MacLeod was named Senior Vice President of Human Resources and Administration in August 2011, to be effective at the earlier of January 1, 2012 or the time of the spin-off. Ms. MacLeod has served as Vice President and Chief Information Officer of Williams since July 2008. Since joining Williams in 2000, Ms. MacLeod served as Vice President of Compensation, Benefits and Human Resources Information Services from October 2000 to May 2004 as well as Vice President of Enterprise Business Services from May 2004 to July 2008. Prior to joining Williams, Ms. MacLeod served as Managing Director of Global Compensation and Benefits for Electronic Data Systems. She has held management roles at JC Penney Company and HEB Grocery Company, and has practiced tax and employee benefits law with a firm in Dallas. Ms. MacLeod is also a member of Mott Production LLC, a privately held company holding various oil and gas interests.

 
Michael R. Fiser.   Mr. Fiser was named Senior Vice President of Marketing in August 2011, to be effective at the earlier of January 1, 2012 or the time of the spin-off. Since May 2008, Mr. Fiser has served as Vice President and Director of Williams Gas Marketing, Inc, with responsibilities including the sales, marketing, transportation management, operations, storage management, trading and hedging of Williams’ natural gas portfolio. He served as Director for Williams Energy Marketing and Trading and Williams Power from September 1998 to 2008 and was responsible for commercial trading strategies, hedging and logistics. Prior to joining Williams, Mr. Fiser worked at Koch Industries, Inc. in various marketing and trading roles from June 1987 to September 1998.

 
Steven G. Natali.   Mr. Natali was named Senior Vice President of Exploration in August 2011, to be effective at the earlier of January 1, 2012 or the time of the spin-off. Mr. Natali has served as Williams’ Vice President of Exploration and Geophysics since 2001. Mr. Natali served as Chief Geophysicist and Vice President of Exploration of Barrett Resources from 1995 until Williams’ purchase of that company in 2001. Prior to his employment with Barrett Resources, Mr. Natali worked for 12 years as an exploration geophysicist for Amoco Production Company, participating in many of the emerging plays of the Rocky Mountain basins, Oklahoma Spiro Sandstone play and North Slope of Alaska.

 
J. Kevin Vann.   Mr. Vann was named Chief Accounting Officer and Controller in August 2011, to be effective at the earlier of January 1, 2012 or the time of the spin-off. Since June 2007, Mr. Vann has served as Controller for Williams’ Exploration & Production business unit. He was Controller for Williams Power Company from 2006 to 2007 and Director of Enterprise Risk Management for Williams from 2002 to 2006. In his Controller positions, he was responsible for the development and implementation of internal controls to ensure effective financial and business systems, accurate financial statements and the timely provision of appropriate information and analysis to assist in the strategic management of the company. As Director of Enterprise Risk Management, he was responsible for the aggregation and measurement of commodity and credit risk.

Board Composition
 
Our business and affairs will be managed under the direction of our board of directors. Immediately following the completion of this offering, we expect that at least one member of our board of directors will be “independent” under applicable rules of the NYSE. Within one year following the completion of this offering, the board of directors will include three independent directors under applicable rules of the NYSE. The directors will have discretion to increase or decrease the size of the board of directors.
 
Status as a “Controlled Company”
 
Upon completion of this offering and prior to the anticipated spin-off of our stock to Williams’ stockholders, Williams will control a majority of the voting power for the election of our directors, and we will therefore be a “controlled company” under NYSE corporate governance standards. A controlled company

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need not comply with NYSE corporate governance rules that require its board of directors to have a majority of independent directors and independent compensation and nominating and corporate governance committees. We intend to avail ourselves of the controlled company exception under the NYSE corporate governance standards. Notwithstanding our status as a controlled company, we will remain subject to the NYSE corporate governance standard that requires us to have an audit committee composed entirely of independent directors. As a result, we must have at least one independent director on our audit committee by the date our Class A common stock is listed on the NYSE, or the listing date, at least two independent directors within 90 days of the listing date and at least three independent directors within one year of the listing date.
 
If Williams completes a spin-off of all of the shares of our common stock that it owns to its stockholders or holds less than a majority of the voting power for any other reason, we will no longer be a controlled company within the meaning of the NYSE corporate governance standards. Once we cease to be a controlled company, our board of directors will be required to have a compensation committee and a nominating and governance committee, each with at least one independent director. Within 90 days of ceasing to be a controlled company, we will be required to have each of a compensation committee and a nominating and governance committee with a majority of independent directors, and within one year of ceasing to be a controlled company, a majority of our board of directors must be comprised of independent directors.
 
Board Committees
 
Audit committee
 
Prior to completion of this offering, our board of directors will establish an audit committee, composed of           directors. The audit committee will consist of the number of independent directors as required by the applicable NYSE rules within the applicable time periods following the completion of this offering. The board of directors will determine that all of the audit committee members are financially literate.
 
The audit committee’s functions will include providing assistance to the board of directors in fulfilling its oversight responsibility relating to our financial statements and the financial reporting process, compliance with legal and regulatory requirements, the qualifications and independence of our independent registered public accounting firm, our system of internal controls, the internal audit function, our code of ethical conduct, retaining and, if appropriate, terminating the independent registered public accounting firm, and approving audit and non-audit services to be performed by the independent registered public accounting firm. In addition, as the audit committee will be made up exclusively of independent directors, it will be responsible for the future amendment or establishment of all related party transactions between us and Williams.
 
In compliance with the NYSE listing standards, our audit committee will annually conduct a self-evaluation to determine whether it is functioning effectively. In addition, the audit committee will prepare the report of the committee required by the rules and regulations of the SEC to be included in our annual proxy statement.
 
Our board of directors will adopt a written charter for our audit committee, which will be available on our corporate website prior to or upon completion of this offering.
 
Other Committees
 
Because we will be a “controlled company” within the meaning of the NYSE corporate governance standards, we will not be required to, and will not, have a compensation or nominating and governance committee. While we are a controlled company, Williams’ nominating and corporate governance committee will identify and evaluate potential candidates for nomination as a director and recommend any such candidates to our board of directors.
 
Our board of directors may form a compensation committee and/or a nominating and governance committee after the completion of this offering.

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Compensation Committee Interlocks and Insider Participation
 
Initially, compensation recommendations regarding our executive officers may be made by the Williams compensation committee. Our board of directors may appoint a successor compensation committee after the completion of this offering. None of our executive officers serves, or has served during the last completed fiscal year, on the compensation committee or board of directors of any other company that has one or more executive officers serving on our compensation committee or board of directors.
 
Code of Ethics
 
In connection with this offering, our board of directors will adopt a Code of Ethics for Senior Officers that applies to our Chief Executive Officer, Chief Financial Officer and Controller, or persons performing similar functions. Our code of ethics will be publicly available on our corporate website. Any waiver of our code of ethics with respect to our Chief Executive Officer, Chief Financial Officer and Controller, or persons performing similar functions may only be authorized by our audit committee and will be disclosed as required by applicable law.

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EXECUTIVE COMPENSATION
 
Compensation Discussion and Analysis
 
We have yet to establish a compensation committee of our board of directors. As a result, the compensation information provided herein reflects the compensation program established by the compensation committee of Williams’ board of directors (“Committee”) in place to compensate Williams’ officers on December 31, 2010, except as otherwise indicated.
 
As our compensation program is developed, the Williams board of directors and/or Committee will provide input, analyze and approve WPX Energy’s compensation and benefit plans and policies until our compensation committee is formed. To date, the Committee has approved our pay philosophy and our comparator group of companies. Specific compensation and benefit programs for WPX Energy have yet to be developed.
 
It should be noted that Williams provides generally consistent compensation programs and metrics for all officers across the enterprise. In 2010, an officer working in Williams’ Exploration & Production business unit, the base group for WPX Energy, had the same long-term incentive and annual incentive award metrics and design as an officer working in any other part of Williams. Therefore, the compensation programs described for the named executive officers of WPX Energy (“NEOs”) in this Compensation Discussion and Analysis are consistent in form with the compensation program received by officers in the Exploration & Production business unit.
 
The executive officers who were largely responsible for conducting the business of WPX Energy and for managing the operations of Williams’ Exploration & Production business unit during 2010 are also executive officers of Williams. For the fiscal year ending December 31, 2010, the Williams executive officers who comprised the executive team for WPX Energy and who are referred to as the NEOs were: Steven J. Malcolm, former Chairman, President and Chief Executive Officer (“CEO”) of Williams; Donald R. Chappel, Chief Financial Officer of Williams and our Chief Financial Officer; Ralph A. Hill, Senior Vice President—Exploration & Production of Williams, and our CEO; James J. Bender, Senior Vice President and General Counsel of Williams and our General Counsel and Corporate Secretary; and Robyn L. Ewing, Senior Vice President and Chief Administrative Officer of Williams and our Chief Administrative Officer.
 
Objective of Williams’ Compensation Programs
 
The role of compensation for Williams is to attract and retain the talent needed to drive stockholder value and to help enable each business of Williams to meet or exceed financial and operational performance targets. The objective of Williams’ compensation programs is to reward employees for successfully implementing the strategy to grow the business and create long-term stockholder value. To that end, Williams uses relative and absolute Total Shareholder Return (“TSR”) to measure long-term performance, and Economic Value Added ® (“EVA ® ”) 1 to measure annual performance. Williams believes using both TSR and EVA ® to incent and pay NEOs helps ensure that the business decisions made are aligned with the long-term interests of Williams’ stockholders.
 
Looking forward —While our pay philosophy has been approved by the Committee, the specific design of our long-term incentive, the annual cash incentive, the base pay and benefit plans has yet to be determined.
 
Williams’ 2010 Pay Philosophy
 
Williams’ pay philosophy throughout the entire organization is to pay for performance, be competitive in the marketplace and consider the value a job provides to Williams. The compensation programs reward NEOs and employees not just for accomplishing goals, but also for how those goals are pursued. Williams strives to reward the right results and the right behaviors while fostering a culture of collaboration and teamwork.

 
1      Economic Value Added ® (EVA ® ) is a registered trademark of Stern, Stewart & Co.

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The principles of Williams’ pay philosophy influence the design and administration of its pay programs. Decisions about how to pay NEOs are based on these principles. The Committee uses several different types of pay that are linked to both long-term and short-term performance in the executive compensation programs. Included are long-term incentives, annual cash incentives, base pay and benefits. The chart below illustrates the linkage between the types of pay used and the pay principles.

 	 	Long-term	 	 	Annual Cash	 	 	 	 	 	 	 	
Williams’ Pay Principles	 	Incentives	 	 	Incentives	 	 	Base Pay	 	 	Benefits	 	
 		
Pay should reinforce business objectives and values	 	 	ü	 	 	 	ü	 	 	 	ü	 	 	 	 	 	
A significant portion of an NEO’s total pay should be variable based on performance	 	 	ü	 	 	 	ü	 	 	 	 	 	 	 	 	 	
Incentive pay should balance long-term, intermediate and short-term performance	 	 	ü	 	 	 	ü	 	 	 	 	 	 	 	 	 	
Incentives should align interest of NEOs with stockholders	 	 	ü	 	 	 	ü	 	 	 	 	 	 	 	 	 	
Pay opportunity should be competitive	 	 	ü	 	 	 	ü	 	 	 	ü	 	 	 	ü	 	
A portion of pay should be provided to compensate for the core activities required for performing in the role	 	 	 	 	 	 	 	 	 	 	ü	 	 	 	ü	 	
Pay should foster a culture of collaboration with shared focus and commitment to Williams	 	 	ü	 	 	 	ü	 	 	 	 	 	 	 	 	 	

Looking Forward —Our pay philosophy, which will serve to influence the design and delivery of our pay programs, has been approved by the Committee. Our approved pay philosophy is substantially the same as Williams’ pay philosophy.
 
Williams’ 2010 Compensation Summary
 
In 2010, Williams, including its Exploration and Production business unit, continued to focus on creating stockholder value by delivering solid financial and operational performance. The effects of the economic recession during late 2008 and 2009 eased during 2010. Crude oil and NGL prices returned to attractive levels, but natural gas prices remained low. Williams continued to respond to the changing landscape and completed a number of significant business transactions as detailed on page 106. Williams took several actions, described below, to ensure that its executive pay program remains affordable and competitive in the current market and after market conditions improve.
 
Williams’ 2010 Pay Decisions
 
As indicated above, significant consideration was given to the need to balance Williams’ pay philosophy and practices with affordability and sustainability. Williams continued to grant long-term incentives in the form of performance-based restricted stock units (“RSUs”), stock options and time-based RSUs in 2010 to emphasize its commitment to pay for performance.
 
Consistent with its commitment to provide a meaningful connection between pay and performance, Williams has granted performance-based RSUs to NEOs since 2004. The performance-based RSUs granted in 2008 for the 2008-2010 performance period did not meet threshold targets set at the beginning of the period as a result of the global economic crisis. The challenging performance targets established in 2008 for the three-year performance period included economic assumptions that could not anticipate the significant decline in economic conditions. In accordance with the design of the awards, these awards were cancelled. This is the second consecutive year the performance-based RSUs were not earned. This resulted in each NEO losing a significant portion of pay that was targeted for 2007-2009 and 2008-2010.
 
It is important to note that the Summary Compensation Table displays a value for equity awards on the date of grant. This approach does not reflect the actual realized value associated with equity award grants. While the grant date values make it appear that NEOs’ pay has been fairly consistent in recent years, the value realized by the NEOs has significantly declined in recent years due to Williams’ pay for performance philosophy.

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Historically, Williams sets performance targets for its Annual Incentive Program (“AIP”) during the first quarter. The targets established in 2010 anticipated an improving economic environment and required significantly improved performance over 2009. While EVA ® performance exceeded 2009 levels, the 2010 AIP results paid less than 2009 due to higher 2010 performance targets.
 
With respect to base salary, Mr. Malcolm did not receive a base pay increase in 2009 or 2010. The remaining NEOs did not receive a base pay increase in 2009 and received a two percent base pay increase in 2010, other than Ms. Ewing who received a 3.5% increase in 2010.
 
Williams’ Plan Design Decisions
 
The Committee regularly reviews Williams’ existing pay programs to ensure Williams’ ability to attract and retain the talent needed to deliver the strong financial and operating performance necessary to create stockholder value while ensuring its program effectively links pay to the performance of Williams. As part of this process in 2010, the Committee reached several important decisions. The Committee decided to continue awarding a significant portion of long-term incentive awards in the form of performance-based restricted stock units (“RSUs”). The metric for these awards utilizes absolute and relative TSR. NEOs will earn their targeted performance-based RSUs for the 2010 to 2012 period only if Williams delivers positive absolute TSR and also achieves solid TSR in relation to the Williams’ comparator group of companies. The Committee believes it is important to include both relative and absolute TSR to ensure that results are impacted by the absolute TSR actually delivered to stockholders, as well as the company’s performance relative to comparator companies. Williams’ commitment to these awards combined with the utilization of both relative and absolute TSR metrics demonstrates the emphasis on linking pay to long-term performance and aligning its pay programs with the interest of stockholders.
 
Williams continues to deliver a significant portion of equity in performance-based awards and stock options because these awards have the strongest alignment to stockholders. Shown below is the long-term incentive mix for the NEOs under Williams’ compensation program for 2010.

 	 	Mr. Malcolm	 	 	Other NEOs	 	
 		
Performance-Based RSUs	 	 	50	%	 	 	35	%	
Stock Options	 	 	50	%	 	 	30	%	
Time-Based RSUs	 	 	0	%	 	 	35	%	

As to Williams’ AIP, EVA ® improvement remained the performance metric in 2010. The difficult economic and commodity price environment made establishing a target level of performance very challenging. In anticipation of an improving economic environment, the Committee approved a 2010 EVA ® performance target that was substantially higher than targets established for 2009. The Committee also continued a decision reached in 2009 to require that the AIP performance necessary to move from threshold to target was doubled from 2008 levels. Likewise, the performance required to move from target to stretch was doubled from 2008 levels. This design attempts to keep the AIP as a meaningful performance incentive throughout the year while ensuring a payout significantly above target only occurs if Williams significantly exceeds established performance targets.
 
Mitigating Risk
 
After a thorough review and analysis, it was determined that the risks arising from Williams’ compensation policies and practices are not reasonably likely to have a material adverse effect on Williams.
 
Williams’ Compensation Recommendation and Decision Process
 
Role of Williams’ Management
 
In order to make pay recommendations, management provides the Williams CEO with data from the annual proxy statements of companies in Williams’ comparator group along with pay information compiled from nationally recognized executive and industry related compensation surveys. The survey data is used to confirm that pay practices among companies in the comparator group are aligned with the market as a whole.

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Role of Williams’ CEO
 
Before recommending base pay adjustments and long-term incentive awards to the Committee, Williams’ CEO reviews the competitive market information related to each of Williams other named executive officers while also considering internal equity and individual performance.
 
For the annual cash incentive program, the Williams CEO’s recommendation is based on EVA ® attainment with a potential adjustment for individual performance. Individual performance includes business unit EVA ® results for the business unit leaders, achievement of business goals and demonstrated key leadership competencies (for more on leadership competencies, see the section entitled “Base Pay” in this Compensation Discussion and Analysis). The modifications made are fairly modest. For 2010 the adjustments made to the NEOs’ annual cash incentive awards were in total less than 5%.
 
Role of the Other NEOs
 
The NEOs, and Williams’ other named executive officers, have no role in setting compensation for any of the NEOs.
 
Role of Williams’ Compensation Committee
 
For all NEOs, except the Williams CEO, the Committee reviews the Williams CEO’s recommendations, supporting market data and individual performance assessments. In addition, the Committee’s independent compensation consultant, Frederic W. Cook & Co., Inc., reviews all of the data and advises on the reasonableness of the Williams CEO’s pay recommendations.
 
For the Williams CEO, the Williams board of directors meets in executive session without management present to review the Williams CEO’s performance. In this session, the Williams board of directors reviewed:

 	• 	Evaluations of the Williams CEO completed by the board members and the executive officers (excluding the Williams CEO);	
 		
 	• 	The Williams CEO’s written assessment of his/her own performance compared with the stated goals; and	
 		
 	• 	EVA ® performance of the Company relative to established targets as well as the financial and safety metrics presented as a supplement to EVA ® performance.	
 
The Committee uses these evaluations and competitive market information provided by its independent compensation consultant to determine the Williams CEO’s long-term incentive amounts, annual cash incentive target, base pay and any performance adjustments to be made to the Williams CEO’s annual cash incentive payment.
 
Role of the Independent Compensation Consultant
 
Frederic W. Cook & Co., Inc. assists the Committee in determining or approving the compensation for Williams’ executive officers. Frederick W. Cook & Co., Inc. will serve as the independent compensation consultant to the Committee as the Committee provides input and analyzes and approves our compensation and benefit plans and policies until our compensation committee is formed.
 
To assist the Committee in discussions and decisions about compensation for the NEOs, the Committee’s independent compensation consultant presents competitive market data that includes proxy data from the approved Williams’ comparator group and published compensation data, using the same surveys and methodology used for the other NEOs (described in the “Role of Management” section in this Compensation Discussion and Analysis). The Williams comparator group is developed by the Committee’s independent compensation consultant, with input from management, and is approved by the Committee.

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2010 Williams’ Comparator Group
 
How Williams Uses its Comparator Group
 
Williams refers to publicly available data showing how much Williams’ comparator group pays, as well as how that pay is divided among base pay, annual incentive, equity and other forms of compensation. This allows the Committee to ensure competitiveness and appropriateness of proposed compensation packages. When setting pay, the Committee uses market median information of Williams’ comparator group, as opposed to market averages, to ensure that the impact of any unusual events that may occur at one or two companies during any particular year is diminished from the analysis. If an event is particularly unusual and surrounds unique circumstances, the data is completely removed from the assessment.
 
Composition of the Williams Comparator Group
 
Each year the Committee reviews the prior year’s Williams’ comparator group to ensure that it is still appropriate. Williams last made changes to this group for 2009. Williams’ comparator group focuses on companies that work in the same industry segment and reflect where Williams competes for business and talent. The 2010 Williams’ comparator group for 2010 included 20 companies, which comprise a mix of both direct competitors to Williams and companies whose primary business is similar to at least one of Williams’ business segments. These companies are included in the chart below under the column entitled Williams’ 2010 Comparator Company Group.
 
Characteristics of Williams’ Comparator Group
 
Companies in Williams’ comparator group have a range of revenues, assets and market capitalization. Business consolidation and unique operating models today create some challenges in identifying comparator companies. Accordingly, Williams takes a broader view of comparability to include organizations that are similar to Williams in some, but not all, respects. This results in compensation that is appropriately scaled and reflects comparable complexities in business operations.
 
Composition of Our Comparator Group
 
Our comparator company group approved by the Committee is provided below. This group is anticipated to be used in making our compensation decisions that we currently expect to be applied beginning in 2012.

 	 	Williams’ 2010	 	 	Our	 	
 	 	Comparator	 	 	Comparator	 	
 	 	Company	 	 	Company	 	
Company Name	 	Group	 	 	Group	 	
 		
Anadarko Petroleum Corp. 	 	 	X	 	 	 	 	 	
Apache Corp. 	 	 	X	 	 	 	 	 	
Cabot Oil & Gas Corp. 	 	 	 	 	 	 	X	 	
Centerpoint Energy Inc. 	 	 	X	 	 	 	 	 	
Chesapeake Energy Corp. 	 	 	X	 	 	 	X	 	
Cimarex Energy Corp. 	 	 	 	 	 	 	X	 	
Devon Energy Corp. 	 	 	X	 	 	 	X	 	
Dominion Resources Inc. 	 	 	X	 	 	 	 	 	
El Paso Corp. 	 	 	X	 	 	 	 	 	
EOG Resources Inc. 	 	 	X	 	 	 	X	 	
EQT Corp. 	 	 	X	 	 	 	 	 	
Forest Oil Corp. 	 	 	 	 	 	 	X	 	
Hess Corp. 	 	 	X	 	 	 	 	 	
Murphy Oil Corp. 	 	 	X	 	 	 	 	 	

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 	 	Williams’ 2010	 	 	Our	 	
 	 	Comparator	 	 	Comparator	 	
 	 	Company	 	 	Company	 	
Company Name	 	Group	 	 	Group	 	
 		
Newfield Exploration Co. 	 	 	 	 	 	 	X	 	
NiSource Inc. 	 	 	X	 	 	 	 	 	
Noble Energy Inc. 	 	 	X	 	 	 	X	 	
Oneok Inc. 	 	 	X	 	 	 	 	 	
Petrohawk Energy Corp. 	 	 	 	 	 	 	X	 	
Pioneer Natural Resources Co. 	 	 	 	 	 	 	X	 	
Plains All American Pipeline	 	 	X	 	 	 	 	 	
QEP Resources Inc. 	 	 	 	 	 	 	X	 	
Questar Corp. 	 	 	X	 	 	 	 	 	
Range Resources Corp. 	 	 	 	 	 	 	X	 	
Sandridge Energy Inc. 	 	 	 	 	 	 	X	 	
Sempra Energy	 	 	X	 	 	 	 	 	
SM Energy Co. 	 	 	 	 	 	 	X	 	
Southern Union Co. 	 	 	X	 	 	 	 	 	
Southwestern Energy Co. 	 	 	 	 	 	 	X	 	
Spectra Energy Corp	 	 	X	 	 	 	 	 	
Ultra Petroleum Corp. 	 	 	 	 	 	 	X	 	
XTO Energy Inc. (acquired by ExxonMobil—removed)	 	 	X	 	 	 	 	 	

Characteristics of Our Comparator Group
 
Our comparator group focuses on companies that work in the same industry segment and reflect where we compete for business and talent. Companies in the comparator group have a range of revenues, assets and market capitalization as well as a range of operational measures such as production and reserves. Our comparator group is appropriately scaled and these companies’ primary business is similar to ours and is subject to similar economic circumstances.
 
Williams’ Pay Setting Process
 
Setting pay for our NEOs historically has been an annual process that occurs during the first quarter of the year. The Committee completes a review to ensure that pay is competitive, equitable and encourages and rewards performance.
 
The compensation data of Williams’ comparator group disclosed in proxy statements is the primary market data used when benchmarking the competitive pay of the NEOs. Aggregate market data obtained from recognized third-party executive compensation survey companies (e.g. Towers Watson, Mercer, AonHewitt) is used to supplement and validate Williams’ comparator group market data for these executive officers. Typically, the Committee is presented with a range of annual revenues of the companies whose data is included in the aggregate analysis provided by the third party survey, but does not know the identities of the specific companies included.
 
Although the Committee reviews relevant data as it designs compensation packages, setting pay is not an exact science. Since market data alone does not reflect the strategic competitive value of various roles within Williams, internal pay equity is also considered when making pay decisions. Because Williams applies an enterprise-wide perspective to promote collaboration and ensure overall success, paying the executive officers equitably is important. Other considerations when making pay decisions for the NEOs include historical pay and tally sheets that include annual pay and benefit amounts, wealth accumulated over the past five years and the total aggregate value of the NEOs’ equity awards and holdings.
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When setting pay, Williams determines a target pay mix (distribution of pay among long-term incentives, annual incentives, base pay and other forms of compensation) for the NEOs. Consistent with Williams’ pay-for-performance philosophy, the actual amounts paid, excluding benefits, are determined based on Williams’ and individual performance. The following table provides the 2010 target pay mix by NEO.

 	 	2010 Target Pay Mix by NEO	 	
 	 	Base	 	 	Annual	 	 	Long-Term	 	 	 	 	
 	 	Salary	 	 	Incentive	 	 	Incentive	 	 	Total	 	
 		
Mr. Malcolm	 	 	14	%	 	 	14	%	 	 	72	%	 	 	100	%	
Mr. Chappel	 	 	20	%	 	 	15	%	 	 	65	%	 	 	100	%	
Mr. Hill	 	 	19	%	 	 	13	%	 	 	68	%	 	 	100	%	
Mr. Bender	 	 	23	%	 	 	15	%	 	 	62	%	 	 	100	%	
Mrs. Ewing	 	 	22	%	 	 	14	%	 	 	64	%	 	 	100	%	

Game Plan for Growth
 
Williams’ goal for 2010 was to grow the natural gas-based businesses in order to generate superior value for investors in Williams and Williams Partners. The performance of the NEOs and other employees is measured by progress made towards the Game Plan for Growth goals. Individual adjustments within Williams’ annual cash incentive program are based on each NEO’s contributions to the Game Plan for Growth. The goals defined in the Game Plan for Growth include:
 
Invest in Growth

 	• 	Enhance Williams’ relationships with customers so that Williams continues to grow its competitive advantage and earn recognition for the reliable service and value that is essential to their success.	
 		
 	• 	Invest in Williams’ businesses in ways that grow EVA ® , earnings and cash flows for Williams and Williams Partners; meet Williams’ customers’ needs; and enhance Williams’ competitive position.	
 		
 	• 	Pursue additional investment opportunities in new and emerging basins to capture significant, strategic, long-lived growth.	
 		
 	• 	Expand Williams’ intellectual, operational and leadership capacities so that Williams can successfully grow and develop high-performing employees and businesses.	
 
Support Williams’ Growth

 	• 	Comply with applicable laws and regulations.	
 		
 	• 	Continuously improve Williams’ safety and environmental compliance performance in all of Williams’ operations.	
 		
 	• 	Assess and manage risks effectively; take appropriate, well-considered risks in order to create value. Exercise financial discipline so that Williams’ and Williams Partners’ financial condition is strong and credit ratings are investment-grade.	
 
Deliver the Growth

 	• 	Achieve or exceed Williams’ EVA ® , earnings and cash flow goals. Also achieve attractive growth in value for Williams and Williams Partners investors.	
 		
 	• 	Openly engage with communities, vendors and other stakeholders crucial to Williams’ success so that Williams grows the competitive advantage we enjoy as a preferred partner.	
 		
 	• 	Operate the business in a way that grows Williams’ reputation as a leader in environmental stewardship.	

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During 2010, Williams made significant strides toward achieving Williams’ Game Plan for Growth. The following are some of the most impactful 2010 accomplishments:

 	• 	Completed the transformation of Williams Partners to a large diversified master limited partnership with reliable access to capital markets. This was accomplished through:	

 	• 	Strategic asset drop-downs from Williams to Williams Partners; and	
 		
 	• 	The merger of Williams Partners and Williams Pipeline Partners L.P.	

 	• 	Completed significant asset acquisitions in the Marcellus Shale. All of Williams’ businesses have a strategic presence in the Marcellus Shale allowing Williams to leverage the strengths of each business unit;	
 		
 	• 	Invested $2.8 billion in drilling activity and acquisitions in Williams’ Exploration & Production business. This included $1.7 billion related to acquisitions in the Bakken and Marcellus Shale areas. The Bakken Shale transaction creates more diversification in Williams’ Exploration and Production business by expanding the long-term crude oil portfolio;	
 		
 	• 	Invested $1 billion in capital and investment expenditures in the midstream businesses and invested $473 million in capital expenditures in Williams’ gas pipelines business in 2010;	
 		
 	• 	Expanded ownership of the Overland Pass Pipeline;	
 		
 	• 	Maintained Williams’ investment grade credit rating while achieving an upgrade of Williams Partners to an investment grade credit rating; and	
 		
 	• 	In addition to continuing to expand Williams’ natural gas businesses and drive stockholder value, Williams was recognized for its efforts to make Williams a great place to work for its employees;	

 	• 	The Houston Business Journal recognized Williams as a Best Place to Work in Houston among companies not based in Houston. This was the third year in a row Williams was recognized on the Best Place to Work in Houston list;	
 		
 	• 	Utah Business magazine named Williams as a finalist in its Best Companies to Work for program, where Williams was recognized as one of the four best medium-sized companies in Utah for the second year in a row;	
 		
 	• 	OKCBiz magazine recognized Williams on its Best Places to Work in Oklahoma list for the third year in a row; and	
 		
 	• 	Tulsa Business Journal’s Economic Development Impact Awards recognized Williams as a finalist for the Best Workplace for Young Professionals.	
 
How Williams Determines the Amount for Each Type of Pay
 
Long-term incentives, annual cash incentives, base pay and benefits accomplish different objectives.
 
Long-Term Incentives
 
Williams awards long-term incentives to reward performance and align NEOs with long-term stockholder interests by providing NEOs with an ownership stake in Williams, encouraging sustained long-term performance and providing an important retention element to their compensation program. Long-term incentives are provided in the form of equity and may include performance based RSUs, stock options and time-based RSUs.
 
To determine the value for long-term incentives granted to an NEO each year, Williams considers the following factors:

 	• 	the proportion of long-term incentives relative to base pay;	
 		
 	• 	the NEO’s impact on Williams’ performance and ability to create value;	

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 	• 	long-term business objectives;	
 		
 	• 	awards made to NEOs in similar positions within Williams’ comparator group of companies	
 		
 	• 	the market demand for the NEO’s particular skills and experience;	
 		
 	• 	the amount granted to other NEOs in comparable positions at Williams;	
 		
 	• 	the NEO’s demonstrated performance over the past few years; and	
 		
 	• 	the NEO’s leadership performance.	
 
The allocation of the long-term incentive program for 2010 is shown on page 105. The long-term incentive mix for the NEOs is shown on page 101.
 
The primary objectives for each type of equity awarded are shown below. The size of the circles in the chart indicates how closely each equity type aligns with each objective.

 	 	 	 	 	 	Drives operating	 	 	
 	 	Stockholder	 	 	 	and financial	 	Retention	
Equity type and Performance Drivers	 	alignment	 	Stock ownership	 	performance	 	Incentive	
 		
Performance-Based RSUs
 Absolute and Relative TSR	 	l	 	l	 	l	 	 	
Stock Options
 Stock Price Appreciation	 	l	 	l	 	l	 	 	
Time-Based RSUs
 Stock Price Appreciation	 	l	 	l	 	 	 	l	

2010 Performance-Based RSUs
 
Performance-based RSU awards further strengthen the relationship between pay and performance and over time will more closely link the long-term pay of the NEOs to the experience of Williams’ long-term stockholders.
 
Williams believes it is important to measure TSR on both an absolute and a relative basis. In absolute terms, Williams wants to ensure it is delivering a responsible return to stockholders. Additionally, Williams believes awards should be influenced by how TSR compares to the TSR of companies in Williams’ comparator group. Shown in the chart below are the absolute and relative TSR targets for the performance-based restricted stock unit awards for the 2010 to 2012 performance period and the continuum that will determine the resulting potential payout level:

 
2008 Performance-Based RSUs
 
The performance cycle for Williams’ 2008 performance-based RSUs ended in 2010. As discussed earlier, Williams did not attain threshold performance during the three-year period as a result of the global economic crisis. No performance-based RSU awards that were granted in 2008 were paid out under this plan. This resulted in each NEO losing a significant portion of pay that was targeted for 2008-2010. The performance goals for this award were set during a less volatile time based on market guidance and expectations for

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Williams’ performance at that time. The following is a chart of the threshold, target and stretch goals that were established in early 2008.

EVA ®	 	Payout Level as a % of Target	
(Millions)	 	(Attainment %)	
 		
 	 	Threshold	
$191	 	(where incentives start to be earned)	
$299	 	100%	
$407	 	200%	

Stock Option Awards
 
For recipients, stock options have value only to the extent the price of the common stock is higher on the date the options are exercised than it was on the date the options were granted.
 
Time-Based RSUs
 
Williams uses this type of equity to retain executives and to facilitate stock ownership. The use of time-based RSUs is also consistent with the practices of Williams’ comparator group of companies.
 
Grant Practices
 
Historically, the Committee typically approves the annual equity grant in February or early March of each year shortly after the annual earnings release. The grant date for awards is on or after the date of such approval to ensure the market has time to absorb material information disclosed in the earnings release and reflect that information in the stock price.
 
The grant date for off-cycle grants for individuals who are not Williams’ executive officers, for reasons such as retention or new hires, is the first business day of the month following the approval of the grant. By using this consistent approach, Williams removes grant timing from the influence of the release of material information.
 
Looking Forward —We intend to establish an equity plan prior to completion of this offering. The design of the plan and the form, terms and conditions of future long-term incentive awards available for grant thereunder have not been determined at this time.
 
Annual Cash Incentives
 
Williams provides annual cash incentives to encourage and reward NEOs for making decisions that improve Williams’ performance as measured by EVA ® . EVA ® measures the value created by a company. Simply stated, it is the financial return in a given period less the capital charge for that period. The calculation used is as follows:

EVA ®	 	=	 	Adjusted Net Operating
Profits after Taxes
(NOPAT)	 	Less	 	Adjusted Capital Charge (the amount
of capital invested by Williams
multiplied by the cost of capital)	

Generating profits in excess of both operating and capital costs (debt and equity) creates EVA ® . If EVA ® improves, value has been created. The objectives of the EVA ® -based incentive program are to:

 	• 	Motivate and incent management to choose strategies and investments that maximize long-term stockholder value;	
 		
 	• 	Offer sufficient incentive compensation to motivate management to put forth extra effort, take prudent risks and make tough decisions to maximize stockholder value;	
 		
 	• 	Provide sufficient total compensation to retain management; and	

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 	• 	Limit the cost of compensation to levels that will maximize the wealth of current stockholders without compromising the other objectives.	
 
The EVA ® Calculation
 
EVA ® is first calculated as NOPAT less Capital Charge. Williams’ incentive program allows for the Committee to make adjustments to EVA ® calculations to reflect certain business events. After studying companies that utilize EVA ® as an incentive measure, Williams determined that it is standard practice to make adjustments to EVA ® calculations to create better alignment with stockholders.
 
When determining which adjustments are appropriate, Williams is guided by the principle that incentive payments should not result in unearned windfalls or impose undue penalties. In other words, Williams makes adjustments to ensure NEOs are not rewarded for positive results they did not facilitate nor are they penalized for certain unusual circumstances outside their control. Williams believes the adjustments improve the alignment of incentives with stockholder value creation and ensure EVA ® is an incentive measure that effectively encourages NEOs to take actions to create value for stockholders. The categories of potential adjustments to the EVA ® calculation are:

 	• 	Gains, losses and impairments;	
 		
 	• 	Mark-to-market, commodity price collar and construction work-in-progress; and	
 		
 	• 	Other unusual items that could result in unearned windfalls or undue penalties to NEOs such as certain litigation matters and natural disasters.	
 
Williams’ management regularly reviews with the Committee a supplemental scorecard reflecting Williams’ segment profit, earnings per share, cash flow from operations and safety to provide updates regarding Williams’ performance as well as to ensure alignment between these measures and EVA ® . This scorecard provides the Committee with additional data to assist in determining final AIP awards. There is strong correlation between Williams’ EVA ® performance and other metrics included on the supplemental scorecard.
 
The Committee’s independent compensation consultant annually compares Williams’ relative performance on various measures, including total stockholder return, earnings per share and cash flow, with Williams’ comparator group of companies. The Committee also uses this analysis to validate the reasonableness of the EVA ® results.
 
Annual Cash Incentives—Target
 
The starting point to determine annual cash incentive targets (expressed as a percent of base pay) is competitive market information, which gives Williams an idea of what other companies target to pay in annual cash incentives for similar jobs. Williams also considers the internal value of each job—i.e., how important the job is to executing its strategy compared to other jobs in Williams—before the target is set for the year. The annual cash incentive targets as a percentage of base pay for the NEOs in 2010 were as follows:

Mr. Malcolm	 	 	100	%	
Mr. Chappel	 	 	75	%	
Other NEOs	 	 	65	%	

Annual Cash Incentives—Actual
 
For NEOs, the annual cash incentive program is funded when Williams attains an established level of EVA ® performance. Applying EVA ® measurement to this annual cash incentive process encourages management to make business decisions that help drive long-term stockholder value. To determine the funding of the annual cash incentive, Williams uses the following calculation for each NEO:

Base Pay received in 2010	 	X	 	Incentive Target %	 	X	 	EVA ® Goal Attainment %	

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Actual payments may be adjusted upwards to recognize individual performance that exceeded expectations, such as success toward the Game Plan for Growth and individual goals and successful demonstration of the leadership competencies discussed in the Base Pay section on page 111. Payments may also be adjusted downwards if performance warrants.
 
How Williams Sets the EVA ® Goals
 
Setting the EVA ® goals for the annual cash incentive program begins with internal budgeting and planning. This rigorous process includes an evaluation of the challenges and opportunities for Williams and each of its business units. The key steps are as follows:

 	• 	Business and financial plans are submitted by the business units and consolidated by the corporate planning department.	
 		
 	• 	The business and financial plans are reviewed and analyzed by Williams’ chief executive officer, chief financial officer and other named executive officers.	
 		
 	• 	Using the plan guidance, Williams’ management establishes the EVA ® goal and recommends it to the Committee.	
 		
 	• 	The Committee reviews, discusses and makes adjustments as necessary to management’s recommendations and sets the goal at the beginning of each fiscal year.	
 		
 	• 	Thereafter, progress toward the goal is regularly monitored and reported to the Committee throughout the year.	
 
2010 EVA ® Goal for the Annual Cash Incentive Program
 
The attainment percentage of EVA ® goals results in payment of annual cash incentives along a continuum between threshold and stretch levels, which corresponds to 0% through 250% of the NEO’s annual cash incentive target. The chart below shows the EVA ® improvement goals for the 2010 annual cash incentive and the resulting payout level. It is important to note that setting the EVA ® goal for 2010 was again challenging considering the uncertain economic and commodity price environment. The EVA ® goal established in 2010 was more challenging than the 2009 EVA ® goal, reflecting an anticipated improvement in economic conditions.

EVA ®	 	Payout Level as a % of Target	
(Millions)	 	(Attainment %)	
 		
 	 	Threshold	
($563)	 	(where incentives start to be earned)	
($347)	 	100%	
($131)	 	200%	

As noted, EVA ® considers both financial earnings and a cost of capital in measuring performance. The two main components of EVA ® are NOPAT and a charge for the cost of capital. EVA ® , like other performance metrics, has been impacted by the economic environment. NOPAT improved from 2009, but fell slightly below the 2010 plan while the 2010 charge for the cost of capital was better than 2009 and better than plan. As a result of the NOPAT and capital charge changes, total EVA ® improved significantly from 2009 but was only modestly above the 2010 plan target.
 
Based on EVA ® performance relative to the established goals, the Committee certified performance results of ($337) million in EVA ® and approved payment of the annual cash incentive program at 105% of target.
 
Looking Forward —We intend to establish an annual cash incentive program to reward our executive officers. At this time, the design of the program, including the target opportunity and the performance metric(s), has not been determined.

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Base Pay
 
Base pay compensates NEOs for carrying out the duties of their jobs, and serves as the foundation of Williams’ pay program. Most other major components of pay are set based on a relationship to base pay, including annual and long-term incentives and retirement benefits.
 
Base pay for NEOs is set considering the market median, with potential individual variation from the median due to experience, skills and sustained performance of the individual as part of Williams’ pay-for-performance philosophy. Performance is measured in two ways: through the “Right Results” obtained in the “Right Way.” Right Results considers the NEOs’ success in attaining their annual goals as they relate to the Game Plan for Growth, business unit strategies and personal development plans. Right Way reflects the NEOs’ behavior as exhibited through Williams’ leadership competencies. The following table contains these competencies grouped within Williams’ five leadership areas.

 	 	INSPIRE A	 	 	 	 	 	OPTIMIZE	
MODEL THE	 	SHARED	 	CHAMPION	 	LEVERAGE	 	BUSINESS	
WAY	 	VISION	 	INNOVATION	 	TALENT	 	PERFORMANCE	
 		
Caring About People	 	Enterprise Perspective	 	Change Leadership	 	Building Effective Teams	 	Business Acumen	
Integrity	 	Vision and Strategic Perspective	 	Entrepreneurial Spirit	 	Communication	 	Customer and Market Focus	
Loyalty and Commitment	 	 	 	Promoting Diversity and Creativity	 	Developing People Resources	 	Decision Making	
 	 	 	 	Willingness to Take Risks	 	Empowering Others	 	Drive for Results	
 	 	 	 	 	 	Managerial Courage	 	Functional/Technical Skills	
 	 	 	 	 	 	Motivating and Inspiring Others	 	 	

Looking Forward —Our pay philosophy and comparator company group has been determined. This philosophy along with comparator company pay information will influence the base pay decisions of our executive officers. We currently expect this to be applied beginning in 2012.
 
Benefits
 
Consistent with Williams’ philosophy to emphasize pay for performance, NEOs receive very few perquisites (perks) or supplemental benefits. They are as follows:

 	• 	Retirement Restoration Benefits.   All NEOs participate in Williams’ qualified retirement program on the same terms as other Williams’ employees. Williams offers a retirement restoration plan to NEOs to maintain a proportional level of pension benefits to officers as provided to other employees. The Code limits qualified pension benefits based on an annual compensation limit. For 2010, the limit was $245,000. Any reduction in an NEO’s pension benefit in the tax-qualified pension plan due to this limit is made up for (subject to a cap) in the unfunded restoration retirement plan. Benefits for NEOs are calculated using the same benefit formula as that used to calculate benefits for all employees in the qualified pension plan. The value of pay in the form of stock option or other equity is not used in the formula to calculate benefits under the pension plan or restoration plan for NEOs, which is consistent with the treatment for all employees. Additionally, Williams does not provide a nonqualified benefit related to the qualified 401(k) defined contribution retirement plan.	
 		
 	• 	Financial Planning Allowance.   Williams offers financial planning to the NEOs to provide expertise on current tax laws with personal financial planning and preparations for contingencies such as death and disability. In addition, by working with a financial planner, executive officers gain a better understanding of and appreciation for the programs Williams provides, which helps to maximize the retention and engagement aspects of the dollars Williams spends on these programs.	

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 	• 	Home Security.   Williams paid 2010 home security system and monitoring fees for its former CEO, Mr. Malcolm.	
 		
 	• 	Personal Use of Williams’ Company Aircraft.   Williams provides limited personal use of Williams’ company aircraft at the Williams CEO’s discretion. There was limited personal use of Williams’ company aircraft by the NEOs in 2010 and the details are provided in the footnote to the Summary Compensation Table.	
 		
 	• 	Event Center.   Williams has a suite and club seats at an event center that were purchased for business purposes. If it is not being used for business purposes, Williams makes them available to all employees, including the NEOs, as a form of reward and recognition.	
 		
 	• 	Executive Physicals.   The Committee approved physicals for the NEOs beginning in 2009. Executive officer physicals align with Williams’ wellness initiative as well as assist Williams in mitigating risk. These physicals reduce vacancy succession risk because they help to identify and prevent issues that would leave a role vacated unexpectedly.	
 
Looking Forward —Our pay philosophy has been determined. This information and competitive market information will influence the design of our benefits program. The form of these designed benefit programs will influence the offering of any supplemental benefits. Any perquisites to be offered have not been defined at this time.
 
Additional Components of Williams’ Executive Compensation Program
 
In addition to establishing the pay elements described above, Williams has adopted a number of policies to further the goals of the executive compensation program, particularly with respect to strengthening the alignment of NEOs’ interests with stockholder long-term interests.
 
Recoupment Policy
 
In 2008, the Committee approved a recoupment policy to allow Williams to recover incentive-based compensation from executive officers in the event Williams is required to restate the financial statements due to fraud or intentional misconduct. The policy provides the Board discretion to determine situations where recovery of incentive pay is appropriate.
 
Stock Ownership Guidelines
 
All NEOs must hold an equity interest in Williams.   The chart below shows the NEO stock ownership guidelines, which have been in effect since 2005:

 	 	Holding Requirement as	 	 	 	 	
 	 	a multiple of Base Pay	 	 	Time Frame for	 	
Position	 	2010	 	 	2011	 	 	Compliance	 	
 		
Mr. Malcolm	 	 	5	 	 	 	6	 	 	 	5 Years	 	
Other NEOs	 	 	3	 	 	 	3	 	 	 	5 Years	 	

Annually the Committee reviews the guidelines for competitiveness and alignment with best practice and monitors the NEOs’ progress toward compliance. The Committee increased the Williams CEO’s ownership guideline from five times base pay to six times base pay beginning in 2011. Shares owned outright and unvested performance-based and time-based RSUs count as owned for purposes of the program. Stock options are not included. The Committee maintains discretion to modify the guidelines in special circumstances of financial hardship such as illness of the NEO or a family member.
 
Derivative Transactions
 
Williams’ insider trading policy applies to transactions in positions or interests whose value is based on the performance or price of the common stock. Because of the inherent potential for abuse, Williams prohibits

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officers, directors and certain key employees from entering into short sales or use of equivalent derivative securities.
 
Accounting and Tax Treatment
 
Williams considers the impact of accounting and tax treatment when designing all aspects of pay, but the primary driver of its program design is to support its business objectives. Stock options and performance-based RSUs are intended to satisfy the requirements for performance-based compensation as defined in Section 162(m) of the Code and are therefore considered a tax deductible expense. Time-based RSUs do not qualify as performance-based and may not be fully deductible.
 
Williams’ annual cash incentive program satisfies the requirements for performance-based compensation as defined in Section 162(m) of the Code and is therefore a tax deductible expense. For payments under Williams’ annual cash incentive program to be considered performance-based compensation under Section 162(m), the Committee can only exercise negative discretion relative to actual performance when determining the amount to be paid. In order to ensure compliance with Section 162(m), the Committee has established a target in excess of the maximum individual payout allowed to Williams’ named executive officers under the annual cash incentive program. Reductions are made each year and are not a reflection of the performance of the Williams’ named executive officers but rather ensure flexibility with respect to paying based upon performance.
 
Employment Agreements
 
Williams does not enter into employment agreements with the NEOs and can remove an NEO when it is in the best interest of the Company.
 
Termination and Severance Arrangements
 
The NEOs are not covered under a severance plan. However the Committee may exercise judgment and consider the circumstances surrounding each departure and may decide a severance package is appropriate. In designing a severance package, the Committee takes into consideration the NEO’s term of employment, past accomplishments, reasons for separation from Williams and competitive market practice. The only pay or benefits an employee has a right to receive upon termination of employment are those that have already vested or which vest under the terms in place when an award was granted.
 
Rationale for Change in Control Agreements
 
Williams’ change in control agreements, in conjunction with the NEOs’ RSU agreements, provide separation benefits for the NEOs. Williams’ program includes a double trigger for benefits and equity vesting. This means there must be a change in control of Williams and the NEO’s employment must terminate prior to receiving benefits under the agreement. While a double trigger for equity is not the competitive norm of Williams’ comparator group, this practice creates security for the NEOs but does not provide an incentive for NEOs to leave Williams. The program is designed to encourage the NEOs to focus on the best interests of Williams’ stockholders by alleviating their concerns about a possible detrimental impact to their compensation and benefits under a potential Williams change in control, not to provide compensation advantages to NEOs for executing a transaction.
 
The Committee reviews Williams’ change in control benefits annually to ensure they are consistent with competitive practice and aligned with Williams’ compensation philosophy. As part of the review, calculations are performed to determine the overall program costs to Williams if a change in control event were to occur and all covered NEOs were terminated as a result. An assessment of competitive norms including the reasonableness of the elements of compensation received is used to validate benefit levels for a change in control. In reviewing the change in control program in 2010 and 2011, the Committee concluded that certain changes to the benefits provided are appropriate. The Committee approved eliminating the excise tax gross-up provision from the change in control program. The Committee opted to provide a ‘best net’ provision providing NEOs with the better of their after-tax benefit capped at the safe harbor amount or their benefit paid in full subjecting them to possible excise tax payments. Therefore, in 2011 Williams provided the one year

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notice required by the NEOs’ change in control agreements in order to effect the change in 2012. After this provision is implemented, Williams will no longer provide additional compensation to address excise taxes. The Committee continues to believe that offering a change in control program is appropriate and critical to attracting and retaining executive talent and keeping them aligned with Williams’ stockholder interests in the event of a change in control of Williams.
 
The following chart details the benefits received if an NEO were to be terminated or resigned for a defined good reason following a change in control as well as an analysis of those benefits as it relates to Williams, stockholders and the NEO. Please also see the “Change in Control Agreements” section below for further discussion of Williams’ change in control program.

 	 	What does the	 	 	
 	 	benefit provide to	 	What does the	
Change in Control	 	Williams and	 	benefit provide to	
Benefit	 	stockholders?	 	the NEO?	
 		
Multiple of 3x base pay plus annual cash incentive at target	 	Encourages NEOs to remain engaged and stay focused on successfully closing the transaction.	 	Financial security for the NEO equivalent to three years of continued employment.	
 	 	 	 	 	
Accelerated vesting of stock awards	 	An incentive to stay during and after a change in control. If there is risk of forfeiture, NEOs may be less inclined to stay or to support the transaction.	 	The NEOs are kept whole, if they have a separation from service following a change in control.	
 	 	 	 	 	
Up to 18 months of medical or health coverage through COBRA	 	This is a minimal cost to Williams that creates a competitive benefit.	 	Access to health coverage.	
 	 	 	 	 	
3x the previous year’s retirement restoration allocation	 	This is a minimal cost to Williams that creates a competitive benefit.	 	May allow those NEOs who are nearing retirement to receive a cash payment to make up for lost allocations due to a change in control.	
 	 	 	 	 	
Reimbursement of legal fees to enforce benefit	 	Keeps NEOs focused on Williams and not concerned about whether the acquiring company will honor commitments after a change in control.	 	Security during a non-stable period of time.	
 	 	 	 	 	
Outplacement assistance	 	Keeps NEOs focused on supporting the transaction and less concerned about trying to secure another position.	 	Assists NEOs in finding a comparable executive position.	

Looking Forward —We have yet to determine the extent to which any of these programs may be provided to our executive officers.

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Our Equity Plans Following this Offering
 
After the completion of this offering, we will have an equity incentive plan and an employee stock purchase plan, which are summarized below.
 
2011 Incentive Plan
 
The following is a summary of the material terms of the WPX Energy, Inc. 2011 Incentive Plan, which is referred to as the 2011 Incentive Plan. The 2011 Incentive Plan was adopted on     , 2011 by our board of directors. This description is not complete. For more information, we refer you to the full text of the 2011 Incentive Plan, which we filed as an exhibit to the registration statement of which this prospectus forms a part.
 
The 2011 Incentive Plan authorizes the grant of nonqualified stock options, incentive stock options, stock appreciation rights (SARs), restricted stock, restricted stock units (RSUs), performance shares, performance units and other stock-based awards valued in whole or in part by reference to or otherwise based on the common stock or other securities, and non-equity incentive awards that are not valued by reference to or payable in shares, to our employees, officers and non-employee directors for the purpose of strengthening their commitment to the success of the Company and stimulating their efforts on behalf of the Company, as well as attracting and retained employees, officers and non-employee directors. The number of shares of common stock issuable pursuant to all awards granted under the 2011 Incentive Plan shall not exceed           shares. No awards have been granted under the 2011 Incentive Plan to date. The number of shares issued or reserved pursuant to the 2011 Incentive Plan (or pursuant to outstanding awards) is subject to adjustment as a result of mergers, consolidations, reorganizations, stock splits, stock dividends and other changes in our common stock. If any shares subject to any award under the 2011 Incentive Plan are forfeited or payment is made in a form other than shares or the award otherwise terminates without payment being made, the shares subject to such awards generally may again be available for issuance under the 2011 Incentive Plan. However, shares withheld or surrendered in payment of the exercise price for stock options or withheld for taxes upon the exercise or settlement of an award will not be available for issuance under the 2011 Incentive Plan. Notwithstanding the foregoing, an unlimited number of shares may be issued under the 2011 Incentive Plan upon the assumption of, or in substitution for, outstanding awards previously granted by an entity in connection with a corporate transaction, unless otherwise expressly provided for under the 2011 Incentive Plan.
 
Administration.   The 2011 Incentive Plan will be administered by either the full board of directors or a committee as designated by the board of directors (referred to herein as the “committee”). Except to the extent the board of directors reserves administrative powers to itself or appoints a different committee to administer the 2011 Incentive Plan, the committee will be the board of directors with respect to all non-employee director grantees and the compensation committee of the board of directors with respect to all executive officer grantees. Unless the board of directors or the compensation committee chooses to administer the 2011 Incentive Plan with respect to other non-executive officer grantees, a committee consisting of the CEO will do so, provided the CEO is a member of the board of directors. In addition, to the extent that the board of directors considers it desirable to comply with Rule 16b-3 of the Exchange Act or meet the performance-based exception to tax deductibility limitations under Internal Revenue Code Section 162(m), the committee will consist of two or more members of the board of directors, all of whom qualify both as “outside directors” within the meaning of Internal Revenue Code Section 162(m) and “non-employee directors” within the meaning of Rule 16b-3 of the Exchange Act. Subject to the terms of the 2011 Incentive Plan, the committee has full power and sole discretion to administer the 2011 Incentive Plan, including, among other things, to select when, to whom and in what types and amounts awards will be granted; to determine the terms and conditions of awards, including but not limited to the term, the vesting schedule, restrictions, and performance criteria relating to any award; to determine the settlement, cancellation, forfeiture, exchange or surrender of any award; to make adjustments in the terms and conditions of awards; to construe and interpret the 2011 Incentive Plan and any award agreement; to establish, amend and revoke rules and regulations for the administration of the 2011 Incentive Plan; to make all determinations deemed necessary or advisable for administration of the 2011 Incentive Plan; and to exercise any powers and perform any acts it deems necessary or advisable to administer the 2011 Incentive Plan.

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Eligibility.   Our employees, officers and non-employee directors are eligible to receive awards under the 2011 Incentive Plan, as determined by the committee.
 
Limits on Awards.   The 2011 Incentive Plan contains several limits on the number of shares and the amount of cash that may be issued as awards.

To the extent the committee determines that compliance with the performance-based exception to tax deductibility limitations under Internal Revenue Code Section 162(m) is desirable, the maximum number of shares of common stock that may be subject to one or more awards to any individual pursuant to the 2011 Incentive Plan during any calendar year is 3,500,000 shares of common stock, and the maximum potential value of awards to be settled in cash or property (other than shares) that may be granted with respect to any calendar year shall not exceed $15,000,000 as to each individual.

Stock Options.   The committee is authorized to grant stock options, including incentive stock options and non-qualified stock options. A stock option allows a grantee to purchase a specified number of shares at a predetermined exercise price during a fixed period measured from the date of grant. The exercise price per share of stock subject to a stock option is determined by the committee and cannot be less than 100% of the fair market value of a share on the grant date. Except in the case of a change in our capital structure, extraordinary distribution to stockholders, or other corporate transaction or event that affects our common stock, the committee shall not reprice an option without stockholder approval. The term of each option is fixed by the committee, provided that it may not exceed ten years from the grant date. Such awards may vest and become exercisable in whole or in part at such time or times as determined by the committee. Options may be exercised by payment of the purchase price in cash or stock as provided in the 2011 Incentive Plan, subject to approval of the committee.
 
Stock Appreciation Rights.   The committee may grant stock appreciation rights, which entitle a grantee the right to receive upon exercise of the stock appreciation right an amount equal to the difference between base amount of the stock appreciation right and the fair market value of a share on the exercise date, multiplied by the number of shares with respect to which the stock appreciation right relates. The committee determines the terms and conditions of such awards, including the base amount of the stock appreciation right. Except in the case of a change in our capital structure, an extraordinary distribution to stockholders, or other corporate transaction or event that affects our common stock, the committee shall not reprice a stock appreciation right without stockholder approval.
 
Restricted Stock.   The committee may award restricted stock consisting of shares that may not be transferred or disposed of by grantees until certain restrictions on such shares as established by the committee lapse. A grantee receiving restricted stock will have all of the rights of a stockholder, including the right to vote the shares and the right to receive any dividends on shares once they vest, unless the committee otherwise determines.
 
Restricted Stock Units.   The committee may also make awards of restricted stock units, consisting of a right to receive shares at a future date upon the satisfaction of certain conditions set forth in the award agreement. Awards of restricted stock units are subject to such limitations as the committee may impose, which limitations may lapse at the end of a specified period, in installments or otherwise. Restricted stock unit awards carry no voting or dividend rights or other rights associated with stock ownership.
 
Performance Units.   The committee may grant performance units, which entitle a grantee to cash or shares conditioned upon the fulfillment of certain performance conditions and other restrictions as specified by the committee. A performance unit is valued based upon a value established by the committee. The committee will determine the terms and conditions of such awards, including performance and other restrictions placed on these awards. Performance measures may be selected from among those listed in the 2011 Incentive Plan, as described below, or other specific criteria determined by the committee, in each case, over any period or periods determined by the committee.
 
Performance Shares.   The committee may grant performance shares, which entitle a grantee to a certain number of shares of common stock, conditioned upon the fulfillment of certain performance conditions and other restrictions as specified by the committee. The committee will determine the terms and conditions of

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such awards, including performance and other restrictions placed on these awards. Performance measures may be selected from among those listed in the 2011 Incentive Plan, as described below, or other specific criteria determined by the committee, in each case, over any period or periods determined by the committee.
 
Non-Equity Incentive Awards.   The committee may grant non-equity incentive awards, which awards are under the 2011 Incentive Plan that are not granted, valued by reference to, or payable in shares of common stock, alone or in conjunction with other awards. The committee will determine the terms and conditions of such awards, including performance and other restrictions placed on these awards. Performance measures may be selected from among those listed in the 2011 Incentive Plan, as described below, or other specific criteria determined by the committee, in each case, over any period or periods determined by the committee.
 
Other Stock-Based Awards.   In order to enable us to respond to significant regulatory developments as well as to trends in executive compensation practices, the 2011 Incentive Plan authorizes the committee to grant awards that are valued in whole or in part by reference to or otherwise based on our securities. The committee shall determine the terms and conditions of such awards, including consideration paid for awards granted as share purchase rights and whether awards are paid in shares or cash.
 
Non-Employee Director Annual Grants.   Generally, each member of our board of directors who is not our employee will be granted on each regularly scheduled annual meeting of stockholders or at such other time as the board of directors may, in its sole discretion, determine, restricted stock units, restricted stock or a combination thereof representing and/or shares having a fair market value on the grant date of up to $300,000. A person who first becomes a non- employee director after the conclusion of the annual meeting of stockholders and prior to August 1 of any year shall be granted the full director annual grant for such year as of December 15. A person who first becomes a non-employee director on or after August 1 of any year from and after 2012 and prior to the first annual meeting of stockholders following the date the person becomes a non-employee director shall be granted a prorated director annual grant for such first year as set forth in the 2011 Incentive Plan.
 
Non-employee directors may elect to defer receipt of payment of restricted stock units awarded in lieu of cash or shares, as applicable, with respect to director annual grants or director fees, until a time after the date that they would otherwise vest in accordance with the terms of the 2011 Incentive Plan.
 
Performance-Based Awards.   The committee may require satisfaction of pre-established performance goals, consisting of one or more business criteria and a targeted performance level with respect to such criteria, as a condition of awards being granted or becoming exercisable or payable under the 2011 Incentive Plan, or as a condition to accelerating the timing of the grant or vesting of an award. The performance measure(s) to be used for purposes of any awards intended to satisfy the “performance-based” exception to the limitations of Internal Revenue Code Section 162(m) must be chosen from among the following: (i) earnings (either in the aggregate or on a per-share basis); (ii) net income; (iii) operating income; (iv) operating profit; (v) cash flow; (vi) stockholder returns (including return on assets, investments, equity, or gross sales) (including income applicable to common stockholders or other class of stockholders); (vii) return measures (including return on assets, equity, sales or capital expenditures); (viii) earnings before or after either, or any combination of, interest, taxes, depreciation or amortization (EBITDA); (ix) gross revenues; (x) share price (including growth measures and total stockholder return or attainment by the shares of a specified value for a specified period of time); (xi) reductions in expense levels in each case where applicable determined either in a Company-wide basis or in respect of any one or more business units; (xii) net economic value; (xiii) market share; (xiv) annual net income to common stock; (xv) earnings per share; (xvi) annual cash flow provided by operations; (xvii) changes in annual revenues; (xviii) strategic business criteria, consisting of one or more objectives based on meeting specified revenue, market penetration, geographic business expansion goals, objectively identified project milestones, production volume levels, cost targets, and goals relating to acquisitions or divestitures; (xix) reserve growth (reserve replacement) or reserves per share; (xx) reserve replacement efficiency ratio; (xxi) productions growth or production per share; (xxii) drilling results; (xxiii) development costs; (xxiv) economic value added; (xxv) sales; (xxvi) costs; (xxvii) results of customer satisfaction surveys; (xxviii) aggregate product price and other product price measures; (xxix) safety record; (xxx) service reliability; (xxxi) operating and maintenance cost management; (xxxii) energy production

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availability performance measures; (xxxiii) debt rating; and/or (xxxiv) achievement of objective business or operational goals such as market share and/or business development; provided that clauses (i) through (vii) may be measured on a pre- or post-tax basis; and provided further that the committee may, on the grant date of an award intended to comply with the “performance-based” exception to the limitations of Section 162(m), and in the case of other grants, at any time, provide that the formula for such award may include or exclude items to measure specific objectives, such as losses from discontinued operations, extraordinary gains or losses, the cumulative effect of accounting changes, acquisitions or divestitures, foreign exchange impacts and any unusual, nonrecurring gain or loss. For awards intended to comply with the “performance-based” exception to the limitations of Section 162(m), the committee shall set the performance measures within the time period prescribed by Section 162(m). The levels of performance required with respect to performance measures may be expressed in absolute or relative levels and may be based upon a set increase, set positive result, maintenance of the status quo, set decrease or set negative result, and may be measured annually, cumulatively over a period of years or over such other period determined by the committee. Performance measures may differ for awards to different grantees. The committee shall specify the weighting (which may be the same or different for multiple objectives) to be given to each performance measure for purposes of determining the final amount payable with respect to any such award. Any one or more of the performance measures may apply to the grantee, to a department, unit, division or function within the Company or any one or more of its affiliates, or to the Company and/or any one or more of its affiliates; and may apply either alone or relative to the performance of other businesses or individuals (including industry or general market indices). The committee has the discretion to adjust the determinations of the degree of attainment of the pre-established performance goals; provided, however, that awards which are designed to qualify for the performance-based exception to the limitations of Section 162(m) may not be adjusted upward (the committee retains the discretion to adjust such awards downward) so as to cause the performance based exception to be unavailable. The committee may not delegate any responsibility with respect to awards intended to qualify for the performance-based exception. All determinations by the committee as to the achievement of the performance measure(s) will be in writing prior to payment of the award.
 
Payment and Deferral of Awards.   The committee may require or permit grantees to defer the distribution of all or part of an award in accordance with such terms and conditions as the committee may establish. The 2011 Incentive Plan is intended to constitute an “unfunded” plan for incentive and deferred compensation, provided, that the 2011 Incentive Plan authorizes the committee to place shares or other property in trusts or to make other arrangements to provide for payment of obligations under the 2011 Incentive Plan, which trusts or other arrangements shall be consistent with the “unfunded” status of the 2011 Incentive Plan, unless the committee otherwise determines. We may require as a condition to the payment of an award that the grantee satisfy applicable withholding taxes and may provide that a portion of the stock or other property to be distributed will be withheld to satisfy such tax obligations.
 
Transfer Limitations on Awards.   Awards granted under the 2011 Incentive Plan generally may not be assigned, alienated, pledged, attached, sold or otherwise transferred or encumbered except by will or by the laws of descent and distribution. Each award will be exercisable during the grantee’s lifetime only by the grantee or, if permitted under applicable law, by the grantee’s guardian or legal representative. However, certain transfers of awards for estate incentive planning or wealth transfer incentive planning purposes may be permitted in the discretion of the committee in accordance with the 2011 Incentive Plan.
 
Amendment and Termination.   The 2011 Incentive Plan may be amended, altered, suspended, discontinued, or terminated by the board of directors in whole or in part without further stockholder approval, unless such approval of an amendment or alteration is required by law or regulation or under the rules of the New York Stock Exchange (or any securities exchange or other form of securities market on which the common stock is then listed or quoted). The board of directors, in its discretion, may seek to obtain stockholder approval for amendments or other actions affecting the 2011 Incentive Plan for which stockholder approval is not required in any circumstance that the board of directors determines such approval would be advisable. In addition, except as otherwise specifically permitted in the 2011 Incentive Plan or any award agreement thereunder, no amendment, modification or termination of the 2011 Incentive Plan may adversely affect in any material way any award previously granted under the 2011 Incentive Plan, without the written consent of the

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grantee of such award, other than an amendment to the change in control provisions of the 2011 Incentive Plan prior to the time that a change in control of us may occur).
 
In no event may an award be granted pursuant to the 2011 Incentive Plan on or after the tenth anniversary of the date our board of directors approved the 2011 Incentive Plan.
 
Change in Control.   If, upon or within two years after a “change in control” (as defined in the 2011 Incentive Plan), a grantee has a termination of affiliation with the Company and its affiliates (but not including a termination of service as a director), excluding any transfer to the Company or its affiliates, voluntarily for “good reason” or involuntarily (other than due to “cause,” death, “disability,” or “retirement” (each as defined in the 2011 Incentive Plan): (i) all of the grantee’s outstanding awards will become fully vested, (ii) all performance criteria will be deemed achieved or fulfilled (at their target level, to the extent applicable), and (iii) the any nonqualified options subject to such accelerated vesting will continue to be exercisable after such termination of affiliation for 18 months (or if less, the remaining original option term).
 
Assumption of Certain Williams Equity Incentive Awards.   In connection with and at the time of the spin-off, it is anticipated that we will assume equity-based incentive compensation awards granted by Williams to our employees as follows: (i) we will assume all Williams restricted stock units awards granted to our employees prior to the date of the spin-off (including time-based and performance-based restricted stock units) and convert such awards into restricted stock units with respect to our common stock with substantially the same terms and conditions as in effect prior to the spin-off, (ii) we will assume all outstanding Williams stock options granted to our employees after December 31, 2005 and prior to the date of the spin-off and convert such awards into options to acquire our common stock with substantially the same terms and conditions as in effect prior to the spin-off, (iii) we will assume all outstanding Williams stock options granted to our employees prior to December 31, 2005 and convert such awards into options to acquire a number of shares of our common stock and Williams common stock (in proportions reflecting the number of shares of our common stock issued in the spin-off in respect of each share of Williams common stock then outstanding) with substantially the same terms and conditions as in effect prior to the spin-off, in each case, with such equitable adjustments as reasonably necessary to prevent a dilution or enlargement of the employees’ rights thereunder (including equitable adjustments to the manner in which total stockholder return is calculated for purposes of performance-based restricted stock units).
 
Employee Stock Purchase Plan
 
The following is a summary of the material terms of the WPX Energy, Inc. 2011 Employee Stock Purchase Plan, which is referred to as the ESPP. The ESPP was adopted on          , 2011 by our board of directors. This description is not complete. For more information, we refer you to the full text of the ESPP, which we filed as an exhibit to the registration statement of which this prospectus forms a part.
 
The ESPP provides our employees the opportunity to purchase our common stock through payroll deductions. The maximum number of shares that shall be made available for sale under the ESPP is          shares. This number may be adjusted for stock splits and similar events. If the total number of shares that would otherwise be subject to rights to purchase at the beginning of an offering period exceeds the number of shares then available under the ESPP, the committee will make a pro rata allocation of the shares remaining available under the ESPP. In such event, the committee will give affected participants written notice of the number of shares of common stock allocated and will reduce the rate of payroll deductions as necessary.
 
Administration.   The ESPP will be administered by either the board of directors or a committee as designated by our board of directors (referred to herein as the “committee”). Subject to the provisions of the ESPP, the committee will have full power and authority to promulgate rules and regulations as it deems necessary for the proper administration of the ESPP, to interpret the provisions and supervise the administration of the ESPP and to take all action in connection with or related to the ESPP as it deems necessary or advisable.
 
Eligibility.   Employees are generally eligible to participate in the ESPP if they are (i) customarily employed by us or one of our designated subsidiaries and (ii) employed as of the first day of the offering

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period; but in all cases excluding any such employee who is a highly compensated employee within the meaning of Section 414(q) of the Code and who holds a position that has been classified as an executive position by our executive compensation department. However, such employees will not be eligible to participate in the ESPP if, immediately following the grant, they (or any other person whose stock would be attributed to them pursuant to Section 424(d) of the Code) would possess common stock and/or hold outstanding options to purchase stock, or stock of a subsidiary, representing 5% or more of the total combined voting power or value of all such classes of stock or of any subsidiary.

Offering Period.   The ESPP generally provides for offerings beginning on the first day of the year or the first day of the seventh month of the year (the “offering date”) and concludes on the last day of the sixth month after the offering date (the “purchase date”). The six month period for which an offering is effective is referred to as an “offering period”. However, the first offering period under the ESPP is anticipated to be a shorter offering period beginning on a date following the completion of the spin-off to be designated by the committee and ending on June 30, 2012, or such later date designated by the committee. Eligible employees may elect to participate in an offering period. Such election shall provide the right to purchase shares of common stock on the purchase date of such offering period. The number of shares of common stock shall be determined by dividing each participant’s payroll deductions accumulated during each offering period prior to such purchase date and retained in the participant’s payroll deduction account as of such purchase date by the applicable purchase price. The right to purchase shares of common stock with respect to an offering period will expire on the purchase date.

In general, the maximum payroll deduction for the ESPP, to be applied annually, is $15,000, or such greater amount as designated by the committee. In general, the maximum payroll deductions that a participant may elect for any offering period shall not exceed $7,500.
 
Purchase of Stock; Limitations on Purchase of Stock.   Unless a participant reduces his or her payroll deduction to zero, or otherwise becomes ineligible, the purchase of shares of common stock will be exercised automatically on each purchase date, and, subject to the limitations on the number of shares that may be purchased under the ESPP, the maximum number of shares will be purchased for such participant at the applicable purchase price with the accumulated payroll deductions elected to be withheld under the ESPP. Participants may not purchase shares of common stock under the ESPP to the extent that their rights to purchase shares under the ESPP, when combined with all other rights and options granted to them under all employee stock purchase ESPPs or any subsidiary corporation ESPPs, would permit them to purchase shares of common stock with a fair market value (determined on the first day of the applicable offering period) in excess of $25,000 for any calendar year in which such purchase right is outstanding at any time. In order to comply with this $25,000 limitation, we may decrease the rate of payroll deductions to zero percent at any time during the offering period.
 
Purchase Price.   The purchase price per share of common stock under the ESPP will be the lesser of: (i) 85% of the fair market value of a share of common stock on the offering date and (ii) 85% of the fair market value of a share of common stock on the purchase date.
 
Termination of Employment.   Upon termination of a participant’s employment during the offering period for any reason, including voluntary termination, retirement or death, the payroll deductions credited to the ESPP (that have not been used to purchase shares of common stock) will be returned to him or her or, in the case of his or her death, to the person or persons entitled thereto. The participant’s option will be automatically terminated. Such termination will be deemed a withdrawal from the ESPP.
 
Transferability.   Rights under the ESPP are not transferable by participants, other than by will or the laws of descent and distribution or as otherwise allowed by the ESPP by way of designation of a beneficiary. Any such attempt at assignment, transfer, pledge or other disposition will have no effect, except that we may treat such act as an election to withdraw funds.
 
Amendment; Termination.   The board may at any time and for any reason terminate or amend the ESPP. Except as allowed by the ESPP generally with respect to changes in capitalization or corporate transactions, no such termination of the ESPP may affect options previously granted. Additionally, except as allowed by the

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ESPP generally with respect to changes in capitalization or corporate transactions, no such amendment to the ESPP shall make any change in any option previously granted that adversely affects the rights of any participant. We will obtain stockholder approval of any amendment in such a manner and to such a degree as required to the extent necessary to comply with Section 423 of the Code or any other applicable law, regulation or stock exchange rule.
 
Executive Compensation and Other Information
 
2010 Summary Compensation Table
 
The following table sets forth certain information with respect to the compensation of the NEOs earned during fiscal years 2010, 2009 and 2008.

 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	Change in	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	Pension	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	Value and	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	Nonqualified	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	Non-Equity	 	 	Deferred	 	 	 	 	 	 	 	
Name and Principal	 	 	 	 	 	 	 	 	 	 	Stock	 	 	Option	 	 	Incentive Plan	 	 	Compensation	 	 	All Other	 	 	 	 	
Position(1)	 	Year	 	 	Salary(2)	 	 	Bonus	 	 	Awards(3)	 	 	Awards(4)	 	 	Compensation(5)	 	 	Earnings(6)	 	 	Compensation(7)	 	 	Total	 	

Steven J. Malcolm	 	 	2010	 	 	$	1,100,000	 	 	$	—	 	 	$	2,936,283	 	 	$	1,902,806	 	 	$	1,276,378	 	 	$	744,426	 	 	$	43,805	 	 	$	8,003,698	 	
Former Chairman, President &	 	 	2009	 	 	 	1,142,308	 	 	 	—	 	 	 	2,116,863	 	 	 	2,846,407	 	 	 	1,903,360	 	 	 	1,399,796	 	 	 	71,100	 	 	 	9,479,835	 	
Chief Executive Officer	 	 	2008	 	 	 	1,094,231	 	 	 	—	 	 	 	2,906,309	 	 	 	2,789,127	 	 	 	2,000,000	 	 	 	1,201,514	 	 	 	56,134	 	 	 	10,047,315	 	
of Williams	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	

Donald R. Chappel	 	 	2010	 	 	 	610,154	 	 	 	—	 	 	 	1,436,882	 	 	 	407,743	 	 	 	559,052	 	 	 	225,539	 	 	 	16,320	 	 	 	3,255,690	 	
Chief Financial Officer	 	 	2009	 	 	 	623,077	 	 	 	—	 	 	 	1,242,734	 	 	 	618,783	 	 	 	765,047	 	 	 	383,380	 	 	 	16,320	 	 	 	3,649,341	 	
of Williams	 	 	2008	 	 	 	597,115	 	 	 	—	 	 	 	2,114,349	 	 	 	651,405	 	 	 	780,008	 	 	 	330,531	 	 	 	15,744	 	 	 	4,489,152	 	

Ralph A. Hill	 	 	2010	 	 	 	493,208	 	 	 	—	 	 	 	1,257,287	 	 	 	356,777	 	 	 	384,479	 	 	 	315,626	 	 	 	16,304	 	 	 	2,823,681	 	
Senior Vice President —	 	 	2009	 	 	 	503,654	 	 	 	—	 	 	 	1,056,319	 	 	 	525,969	 	 	 	566,473	 	 	 	427,867	 	 	 	37,786	 	 	 	3,118,068	 	
Exploration & Production of Williams	 	 	2008	 	 	 	480,962	 	 	 	—	 	 	 	1,606,867	 	 	 	495,071	 	 	 	579,633	 	 	 	363,151	 	 	 	30,371	 	 	 	3,556,055	 	

James J. Bender	 	 	2010	 	 	 	477,954	 	 	 	—	 	 	 	933,975	 	 	 	265,033	 	 	 	359,122	 	 	 	188,427	 	 	 	33,900	 	 	 	2,258,411	 	
Senior Vice President and General	 	 	2009	 	 	 	488,077	 	 	 	—	 	 	 	807,773	 	 	 	402,209	 	 	 	522,119	 	 	 	250,679	 	 	 	26,647	 	 	 	2,497,504	 	
Counsel of Williams	 	 	2008	 	 	 	466,538	 	 	 	—	 	 	 	1,271,209	 	 	 	390,840	 	 	 	533,132	 	 	 	216,799	 	 	 	30,323	 	 	 	2,908,842	 	

Robyn L. Ewing	 	 	2010	 	 	 	442,692	 	 	 	—	 	 	 	933,975	 	 	 	265,033	 	 	 	328,364	 	 	 	233,254	 	 	 	35,579	 	 	 	2,238,897	 	
Senior Vice President and Chief	 	 	2009	 	 	 	446,538	 	 	 	—	 	 	 	745,640	 	 	 	371,269	 	 	 	485,362	 	 	 	304,374	 	 	 	31,093	 	 	 	2,384,277	 	
Administrative Officer of	 	 	2008	 	 	 	370,198	 	 	 	—	 	 	 	299,757	 	 	 	118,485	 	 	 	435,072	 	 	 	248,784	 	 	 	30,096	 	 	 	1,502,392	 	
Williams	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	

 
			
(1)		Name and Principal Position. On January 3, 2011 Mr. Malcolm retired as Chairman, President and Chief Executive Officer of Williams.	
 		
(2)		Salary . All NEOs did not receive a salary increase in 2009. The increase in the reported 2009 salary was due to a payroll timing issue resulting in a 27th bi-weekly paycheck being issued in the calendar year.	
 		
(3)		Stock Awards. Awards were granted under the terms of Williams’ 2007 Incentive Plan and include time-based and performance-based RSUs. Amounts shown are the grant date fair value of awards computed in accordance with FASB ASC Topic 718. The assumptions used to value the stock awards can be found in Williams’ Annual Report on Form 10-K for the year-ended December 31, 2010.	
 		
		The potential maximum values of the performance-based RSUs, subject to changes in performance outcomes, are as follows:	

 	 	2010 Performance-Based RSU	 	
 	 	Maximum potential	 	
 		
Steven J. Malcolm	 	$	5,872,566	 	
Donald R. Chappel	 	 	1,468,141	 	
Ralph A. Hill	 	 	1,284,639	 	
James J. Bender	 	 	954,294	 	
Robyn L. Ewing	 	 	954,294	 	

			
(4)		Option Awards. Awards are granted under the terms of Williams’ 2007 Incentive Plan and include non-qualified stock options. Amounts shown are the grant date fair value of awards computed in accordance with FASB ASC Topic 718. The assumptions used to value the option awards can be found in our Annual Report on Form 10-K for the year-ended December 31, 2010.	

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(5)		Non-Equity Incentive Plan . Under Williams’ AIP, the maximum annual incentive pool funding for NEOs is 250% of target. The reserve provision of the AIP was eliminated in 2009 and the outstanding balances for the NEOs remained at risk over a three year performance period in which threshold performance levels must be attained in order for the balances to be paid and will be reduced if threshold is not met in accordance with previous plan provisions. Threshold performance was met in 2009 and 2010 and a portion of the respective reserve balance was paid to each NEO each year.	
 		
		The annual cash incentive and reserve amounts paid in 2011 as it relates to 2010 performance are as follows:	

 	 	 	 	 	 	 	 	Amount of	 	 	Total AIP plus	 	
 	 	Reserve	 	 	AIP	 	 	Reserve	 	 	Reserve	 	
 	 	Balance	 	 	for 2010	 	 	Paid in 2011	 	 	for 2010	 	
 		
Steven J. Malcolm	 	$	242,756	 	 	$	1,155,000	 	 	$	121,378	 	 	$	1,276,378	 	
Donald R. Chappel	 	 	60,103	 	 	 	529,000	 	 	 	30,052	 	 	 	559,052	 	
Ralph A. Hill	 	 	72,958	 	 	 	348,000	 	 	 	36,479	 	 	 	384,479	 	
James J. Bender	 	 	44,244	 	 	 	337,000	 	 	 	22,122	 	 	 	359,122	 	
Robyn L. Ewing	 	 	20,728	 	 	 	318,000	 	 	 	10,364	 	 	 	328,364	 	

			
(6)		Change in Pension Value and Nonqualified Deferred Compensation Earnings. The amount shown is the aggregate change from December 31, 2009 to December 31, 2010 in the actuarial present value of the accrued benefit under the qualified pension and supplemental plan sponsored by Williams. Please refer to the “Pension Benefits” table for further details of the present value of the accrued benefit. The underlying benefit programs have been consistent during the time period displayed. The primary reason for the fluctuation in the change in present value during this time is due to the use of updated discount rates and conversion rates.	
 		
(7)		All Other Compensation. Amounts shown represent payments by Williams made on behalf of the NEOs and includes life insurance premium, a 401(k) matching contribution and perquisites (if applicable). Perquisites include financial planning services, mandated annual physical exam, home security monitoring for the CEO and personal use of Williams’ company aircraft. The incremental cost method was used to calculate the personal use of the Company aircraft. The incremental cost calculation includes such items as fuel, maintenance, weather and airport services, pilot meals, pilot overnight expenses, aircraft telephone and catering. The amounts of perquisites for Mr. Malcolm, Mr. Bender and Ms. Ewing are included because the aggregate amounts exceed $10,000.	

 	 	 	 	 	 	 	 	 	 	 	Company	 	
 	 	 	 	 	Annual	 	 	 	 	 	Aircraft	 	
 	 	Financial	 	 	Physical	 	 	Home	 	 	Personal	 	
 	 	Planning	 	 	Exam	 	 	Security	 	 	Usage	 	
 		
Steven J. Malcolm	 	$	15,000	 	 	$	0	 	 	$	438	 	 	$	12,047	 	
James J. Bender	 	 	15,000	 	 	 	2,646	 	 	 	0	 	 	 	0	 	
Robyn L. Ewing	 	 	15,000	 	 	 	4,437	 	 	 	0	 	 	 	0	 	

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2010 Grants of Williams’ Plan Based Awards
 
The following table sets forth certain information with respect to the grant of stock options to acquire Williams’ stock, RSUs with respect to Williams’ stock and awards payable under Williams’ annual cash incentive program during the fiscal year 2010 to the NEOs.

 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	All Other	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	Stock	 	 	All Other	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	Awards:	 	 	Option	 	 	 	 	 	Grant	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	Number	 	 	Awards	 	 	Exercise	 	 	Date Fair	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	of Shares	 	 	Number of	 	 	or Base	 	 	Value of	 	
 	 	 	 	 	Equity Future Payouts Under	 	 	Estimated Future Payouts Under	 	 	of Stock	 	 	Securities	 	 	Price of	 	 	Stock and	 	
 	 	Grant	 	 	Non-Equity Incentive Plan Awards(1)	 	 	Equity Incentive Plan Awards	 	 	or	 	 	Underlying	 	 	Option	 	 	Option	 	
Name	 	Date	 	 	Threshold	 	 	Target	 	 	Maximum	 	 	Threshold	 	 	Target(2)	 	 	Maximum	 	 	Units(3)	 	 	Options(4)	 	 	Awards	 	 	Awards	 	
 		
Steven J. Malcolm	 	 	2/23/2010	 	 	$	121,378	 	 	$	1,221,378	 	 	$	2,871,378	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	271,055	 	 	$	21.22	 	 	$	1,902,806	 	
 	 	 	2/23/2010	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	—	 	 	 	140,492	 	 	 	280,984	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	2,936,283	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Donald R. Chappel	 	 	2/23/2010	 	 	 	30,052	 	 	 	487,667	 	 	 	1,174,090	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	58,083	 	 	 	21.22	 	 	 	407,743	 	
 	 	 	2/23/2010	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	—	 	 	 	35,123	 	 	 	70,246	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	734,071	 	
 	 	 	2/23/2010	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	35,123	 	 	 	 	 	 	 	 	 	 	 	702,811	 	

Ralph A. Hill	 	 	2/23/2010	 	 	 	36,479	 	 	 	357,064	 	 	 	837,941	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	50,823	 	 	 	21.22	 	 	 	356,777	 	
 	 	 	2/23/2010	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	—	 	 	 	30,733	 	 	 	61,466	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	642,320	 	
 	 	 	2/23/2010	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	30,733	 	 	 	 	 	 	 	 	 	 	 	614,967	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
James J. Bender	 	 	2/23/2010	 	 	 	22,122	 	 	 	332,792	 	 	 	798,797	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	37,754	 	 	 	21.22	 	 	 	265,033	 	
 	 	 	2/23/2010	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	—	 	 	 	22,830	 	 	 	45,660	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	477,147	 	
 	 	 	2/23/2010	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	22,830	 	 	 	 	 	 	 	 	 	 	 	456,828	 	

Robyn L. Ewing	 	 	2/23/2010	 	 	 	10,364	 	 	 	298,114	 	 	 	729,739	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	37,754	 	 	 	21.22	 	 	 	265,033	 	
 	 	 	2/23/2010	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	—	 	 	 	22,830	 	 	 	45,660	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	477,147	 	
 	 	 	2/23/2010	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	22,830	 	 	 	 	 	 	 	 	 	 	 	456,828	 	

 
			
(1)		Non-Equity Incentive Awards. Awards from Williams’ 2010 AIP are shown.	

 	•  	Threshold: Because one-half of the AIP reserve balance from prior years is payable in 2011 upon meeting threshold performance, one-half of the reserve balance is shown.	
 		
 	•  	Target: The amount shown is based upon an EVA ® attainment of 100%, plus one-half of the existing AIP reserve balance.	
 		
 	•  	Maximum: The maximum amount the NEOs can receive is 250% of their AIP target, plus one-half of the AIP reserve balance.	

(2)		Represents performance-based RSUs granted under Williams’ 2007 Incentive Plan. Performance-based RSUs can be earned over a three-year period only if the established performance target is met and the NEO is employed on the certification date, subject to certain exceptions such as the executive’s death or disability. These shares will be distributed no earlier than the third anniversary of the grant other than due to a termination upon a change in control. If performance plan goals are exceeded, the NEO can receive up to 200% of target. If plan goals are not met, the NEO can receive as little as 0% of target.	
 		
(3)		Represents time-based RSUs granted under Williams’ 2007 Incentive Plan. Time-based units vest three years from the grant date of 2/23/2010 on 2/23/2013.	
 		
(4)		Represents stock options granted under Williams’ 2007 Incentive Plan. Stock options granted in 2010 become exercisable in three equal annual installments beginning one year after the grant date. One-third of the options vested on 2/23/2011. Another one-third will vest on 2/23/2012, with the final one-third vesting on 2/23/2013. Once vested, stock options are exercisable for a period of 10 years from the grant date.	

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2010 Outstanding Williams’ Equity Awards
 
The following table sets forth certain information with respect to the outstanding Williams’ equity awards held by the NEOs at the end of fiscal year 2010.

 	 	Option Award	 	Stock Awards	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	Equity	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	Equity	 	Incentive	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	Incentive	 	Plan Award:	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	Plan	 	Market or	 	 	
 	 	 	 	 	 	 	 	Equity	 	 	 	 	 	 	 	 	 	 	 	Awards:	 	Payout	 	 	
 	 	 	 	 	 	 	 	Incentive	 	 	 	 	 	 	 	 	 	 	 	Number of	 	Value of	 	 	
 	 	 	 	 	 	 	 	Plan	 	 	 	 	 	 	 	 	 	Market	 	Unearned	 	Unearned	 	 	
 	 	 	 	 	 	 	 	Awards:	 	 	 	 	 	 	 	Number	 	Value of	 	Shares,	 	Shares,	 	 	
 	 	 	 	Number of	 	Number of	 	Number of	 	 	 	 	 	 	 	of Shares	 	Shares or	 	Units of	 	Units or	 	 	
 	 	 	 	Securities	 	Securities	 	Securities	 	 	 	 	 	 	 	or Units	 	Units of	 	Stock or	 	Other	 	 	
 	 	 	 	Underlying	 	Underlying	 	Underlying	 	 	 	 	 	 	 	of Stock	 	Stock	 	Other	 	Rights	 	 	
 	 	 	 	Unexercised	 	Unexercised	 	Unexercised	 	Option	 	 	 	 	 	That	 	That	 	Rights	 	That Have	 	 	
 	 	Grant	 	Options (#)	 	Options (#)	 	Unearned	 	Exercise	 	Expiration	 	Grant	 	Have Not	 	Have Not	 	That Have	 	Not	 	 	
Name	 	Date(1)	 	Exercisable	 	Unexercisable	 	Options	 	Price	 	Date	 	Date	 	Vested	 	Vested	 	Not Vested	 	Vested(4)	 	 	
 		
Steven J. Malcolm	 	 	2/23/2010	 	 	 	—	 	 	 	271,055	 	 	 	 	 	 	$	21.22	 	 	 	2/23/2020	 	 	 	2/23/2010(3	)	 	 	 	 	 	 	140,492	 	 	$	3,472,962	 	 	 	 	 	 	 	 	 	
 	 	 	2/23/2009	 	 	 	169,429	 	 	 	338,858	 	 	 	 	 	 	 	10.86	 	 	 	2/23/2019	 	 	 	2/23/2009(3	)	 	 	 	 	 	 	288,401	 	 	 	7,129,273	 	 	 	 	 	 	 	 	 	
 	 	 	2/25/2008	 	 	 	144,927	 	 	 	72,464	 	 	 	 	 	 	 	36.50	 	 	 	2/25/2018	 	 	 	2/25/2008(3	)	 	 	 	 	 	 	82,192	 	 	 	2,031,786	 	 	 	 	 	 	 	 	 	
 	 	 	2/26/2007	 	 	 	200,000	 	 	 	—	 	 	 	 	 	 	 	28.30	 	 	 	2/26/2017	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	3/3/2006	 	 	 	250,000	 	 	 	—	 	 	 	 	 	 	 	21.67	 	 	 	3/3/2016	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	2/25/2005	 	 	 	225,000	 	 	 	—	 	 	 	 	 	 	 	19.29	 	 	 	2/25/2015	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	2/5/2004	 	 	 	300,000	 	 	 	—	 	 	 	 	 	 	 	9.93	 	 	 	2/5/2014	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	2/11/2002	 	 	 	200,000	 	 	 	—	 	 	 	 	 	 	 	15.86	 	 	 	2/11/2012	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	9/19/2001	 	 	 	33,333	 	 	 	—	 	 	 	 	 	 	 	26.79	 	 	 	9/19/2011	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	4/2/2001	 	 	 	27,232	 	 	 	—	 	 	 	 	 	 	 	39.98	 	 	 	4/2/2011	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	1/18/2001	 	 	 	114,373	 	 	 	—	 	 	 	 	 	 	 	34.77	 	 	 	1/18/2011	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Donald R. Chappel	 	 	2/23/2010	 	 	 	—	 	 	 	58,083	 	 	 	 	 	 	 	21.22	 	 	 	2/23/2020	 	 	 	2/23/2010(2	)	 	 	 	 	 	 	35,123	 	 	 	868,241	 	 	 	 	 	 	 	 	 	
 	 	 	2/23/2009	 	 	 	36,832	 	 	 	73,665	 	 	 	 	 	 	 	10.86	 	 	 	2/23/2019	 	 	 	2/23/2010(3	)	 	 	 	 	 	 	35,123	 	 	 	868,241	 	 	 	 	 	 	 	 	 	
 	 	 	2/25/2008	 	 	 	33,848	 	 	 	16,924	 	 	 	 	 	 	 	36.50	 	 	 	2/25/2018	 	 	 	2/23/2009(2	)	 	 	 	 	 	 	73,145	 	 	 	1,808,144	 	 	 	 	 	 	 	 	 	
 	 	 	2/26/2007	 	 	 	48,450	 	 	 	—	 	 	 	 	 	 	 	28.30	 	 	 	2/26/2017	 	 	 	2/23/2009(3	)	 	 	 	 	 	 	73,145	 	 	 	1,808,144	 	 	 	 	 	 	 	 	 	
 	 	 	3/3/2006	 	 	 	41,921	 	 	 	—	 	 	 	 	 	 	 	21.67	 	 	 	3/3/2016	 	 	 	2/25/2008(2	)	 	 	 	 	 	 	19,911	 	 	 	492,200	 	 	 	 	 	 	 	 	 	
 	 	 	2/25/2005	 	 	 	55,000	 	 	 	—	 	 	 	 	 	 	 	19.29	 	 	 	2/25/2015	 	 	 	2/25/2008(3	)	 	 	 	 	 	 	39,822	 	 	 	984,400	 	 	 	 	 	 	 	 	 	
 	 	 	2/5/2004	 	 	 	75,000	 	 	 	—	 	 	 	 	 	 	 	9.93	 	 	 	2/5/2014	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	4/16/2003	 	 	 	175,000	 	 	 	—	 	 	 	 	 	 	 	5.10	 	 	 	4/16/2013	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Ralph A. Hill	 	 	2/23/2010	 	 	 	—	 	 	 	50,823	 	 	 	 	 	 	 	21.22	 	 	 	2/23/2020	 	 	 	2/23/2010(2	)	 	 	 	 	 	 	30,733	 	 	 	759,720	 	 	 	 	 	 	 	 	 	
 	 	 	2/23/2009	 	 	 	31,307	 	 	 	62,616	 	 	 	 	 	 	 	10.86	 	 	 	2/23/2019	 	 	 	2/23/2010(3	)	 	 	 	 	 	 	30,733	 	 	 	759,720	 	 	 	 	 	 	 	 	 	
 	 	 	2/25/2008	 	 	 	25,724	 	 	 	12,863	 	 	 	 	 	 	 	36.50	 	 	 	2/25/2018	 	 	 	2/23/2009(2	)	 	 	 	 	 	 	62,173	 	 	 	1,536,917	 	 	 	 	 	 	 	 	 	
 	 	 	2/26/2007	 	 	 	43,605	 	 	 	—	 	 	 	 	 	 	 	28.30	 	 	 	2/26/2017	 	 	 	2/23/2009(3	)	 	 	 	 	 	 	62,173	 	 	 	1,536,917	 	 	 	 	 	 	 	 	 	
 	 	 	3/3/2006	 	 	 	30,488	 	 	 	—	 	 	 	 	 	 	 	21.67	 	 	 	3/3/2016	 	 	 	2/25/2008(2	)	 	 	 	 	 	 	15,132	 	 	 	374,063	 	 	 	 	 	 	 	 	 	
 	 	 	2/25/2005	 	 	 	40,000	 	 	 	—	 	 	 	 	 	 	 	19.29	 	 	 	2/25/2015	 	 	 	2/25/2008(3	)	 	 	 	 	 	 	30,264	 	 	 	748,126	 	 	 	 	 	 	 	 	 	
 	 	 	1/18/2001	 	 	 	22,875	 	 	 	—	 	 	 	 	 	 	 	34.77	 	 	 	1/18/2011	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
James J. Bender	 	 	2/23/2010	 	 	 	—	 	 	 	37,754	 	 	 	 	 	 	 	21.22	 	 	 	2/23/2020	 	 	 	2/23/2010(2	)	 	 	 	 	 	 	22,830	 	 	 	564,358	 	 	 	 	 	 	 	 	 	
 	 	 	2/23/2009	 	 	 	23,941	 	 	 	47,882	 	 	 	 	 	 	 	10.86	 	 	 	2/23/2019	 	 	 	2/23/2010(3	)	 	 	 	 	 	 	22,830	 	 	 	564,358	 	 	 	 	 	 	 	 	 	
 	 	 	2/25/2008	 	 	 	20,308	 	 	 	10,155	 	 	 	 	 	 	 	36.50	 	 	 	2/25/2018	 	 	 	2/23/2009(2	)	 	 	 	 	 	 	47,544	 	 	 	1,175,288	 	 	 	 	 	 	 	 	 	
 	 	 	2/26/2007	 	 	 	29,070	 	 	 	—	 	 	 	 	 	 	 	28.30	 	 	 	2/26/2017	 	 	 	2/23/2009(3	)	 	 	 	 	 	 	47,544	 	 	 	1,175,288	 	 	 	 	 	 	 	 	 	
 	 	 	3/3/2006	 	 	 	24,136	 	 	 	—	 	 	 	 	 	 	 	21.67	 	 	 	3/3/2016	 	 	 	2/25/2008(2	)	 	 	 	 	 	 	11,946	 	 	 	295,305	 	 	 	 	 	 	 	 	 	
 	 	 	2/25/2005	 	 	 	40,000	 	 	 	—	 	 	 	 	 	 	 	19.29	 	 	 	2/25/2015	 	 	 	2/25/2008(3	)	 	 	 	 	 	 	23,893	 	 	 	590,635	 	 	 	 	 	 	 	 	 	
 	 	 	2/5/2004	 	 	 	15,000	 	 	 	—	 	 	 	 	 	 	 	9.93	 	 	 	2/5/2014	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Robyn L. Ewing	 	 	2/23/2010	 	 	 	—	 	 	 	37,754	 	 	 	 	 	 	 	21.22	 	 	 	2/23/2020	 	 	 	2/23/2010(2	)	 	 	 	 	 	 	22,830	 	 	 	564,358	 	 	 	 	 	 	 	 	 	
 	 	 	2/23/2009	 	 	 	22,099	 	 	 	44,199	 	 	 	 	 	 	 	10.86	 	 	 	2/23/2019	 	 	 	2/23/2010(3	)	 	 	 	 	 	 	22,830	 	 	 	564,358	 	 	 	 	 	 	 	 	 	
 	 	 	2/25/2008	 	 	 	6,156	 	 	 	3,079	 	 	 	 	 	 	 	36.50	 	 	 	2/25/2018	 	 	 	2/23/2009(2	)	 	 	 	 	 	 	43,887	 	 	 	1,084,887	 	 	 	 	 	 	 	 	 	
 	 	 	2/26/2007	 	 	 	10,174	 	 	 	—	 	 	 	 	 	 	 	28.30	 	 	 	2/26/2017	 	 	 	2/23/2009(3	)	 	 	 	 	 	 	43,887	 	 	 	1,084,887	 	 	 	 	 	 	 	 	 	
 	 	 	3/3/2006	 	 	 	11,738	 	 	 	—	 	 	 	 	 	 	 	21.67	 	 	 	3/3/2016	 	 	 	2/25/2008(2	)	 	 	 	 	 	 	3,622	 	 	 	89,536	 	 	 	 	 	 	 	 	 	
 	 	 	2/25/2005	 	 	 	23,000	 	 	 	—	 	 	 	 	 	 	 	19.29	 	 	 	2/25/2015	 	 	 	2/25/2008(3	)	 	 	 	 	 	 	4,829	 	 	 	119,373	 	 	 	 	 	 	 	 	 	

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Stock Options

(1)		The following table reflects the vesting schedules for associated stock option grant dates for awards that had not been 100% vested as of December 31, 2010.	

Grant Date	 	Vesting Schedule	 	Vesting Dates	
 		
2/23/2010	 	One-third vests each year for three years	 	 	2/23/2011, 2/23/2012, 2/23/2013	 	
2/23/2009	 	One-third vests each year for three years	 	 	2/23/2010, 2/23/2011, 2/23/2012	 	
2/25/2008	 	One-third vests each year for three years	 	 	2/25/2009, 2/25/2010, 2/25/2011	 	

Stock Awards

(2)		The following table reflects the vesting dates for associated time-based restricted stock unit award grant dates.	

Grant Date	 	Vesting Schedule	 	Vesting Dates	
 		
2/23/2010	 	100% vests in three years	 	 	2/23/2013	 	
2/23/2009	 	100% vests in three years	 	 	2/23/2012	 	
2/25/2008	 	100% vests in three years	 	 	2/25/2011	 	

			
(3)		All performance-based RSUs are subject to attainment of performance targets established by the Committee. These awards will vest no earlier than the end of the performance period and therefore do not have a specific vesting date. The awards included on the table are outstanding as of December 31, 2010.	
 		
(4)		Values are based on a closing stock price for Williams of $24.72 on December 31, 2010.	
 
2010 Williams’ Option Exercises and Stock Vested
 
The following table sets forth certain information with respect to options to acquire the stock of Williams exercised by the NEO and stock that vested during fiscal year 2010.

 	 	Option Awards	 	Stock Awards	
 	 	Number of Shares	 	 	 	Number of Shares	 	 	
 	 	Acquired on	 	Value Realized	 	Acquired on	 	Value Realized	
Name	 	Exercise	 	on Exercise	 	Vesting	 	on Vesting	
 		
Steven J. Malcolm	 	 	475,000	 	 	$	10,096,083	 	 	 	—	 	 	$	—	 	
Donald R. Chappel	 	 	—	 	 	 	—	 	 	 	19,069	 	 	 	410,746	 	
Ralph A. Hill	 	 	—	 	 	 	—	 	 	 	17,162	 	 	 	369,669	 	
James J. Bender	 	 	—	 	 	 	—	 	 	 	11,442	 	 	 	246,461	 	
Robyn L. Ewing	 	 	—	 	 	 	—	 	 	 	4,005	 	 	 	86,268	 	

The Committee determines pay based on a target total compensation amount. While the Committee reviews tally sheets and wealth accumulation information on each NEO, thus far amounts realized from previous equity grants have not been a material factor when the Committee determines pay. How much compensation the NEOs actually receive is significantly impacted by the stock market performance of Williams’ shares.
 
Retirement Plan
 
The retirement plan for Williams’ executives consists of two plans: the pension plan and the retirement restoration plan as described below. Together these plans provide the same level of benefits to our executives as the pension plan provides to all other employees of Williams. The retirement restoration plan was implemented to address the annual compensation limit of the Code.

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Pension Plan
 
Williams’ executives who have completed one year of service participate in Williams’ pension plan on the same terms as other Williams’ employees. The pension plan is a noncontributory, tax qualified defined benefit plan (with a cash balance design) subject to the Employee Retirement Income Security Act of 1974, as amended.
 
Each year, participants earn compensation credits that are posted to their cash balance account. The annual compensation credits are equal to the sum of a percentage of eligible pay (base pay and certain bonuses) and a percentage of eligible pay greater than the social security wage base. The percentage credited is based upon the participant’s age as shown in the following table.

 	 	Percentage of	 	 	 	Percent of Eligible Pay Greater	
Age	 	Eligible Pay	 	 	 	than the Social Security Wage Base	
 		
Less than 30	 	 	4.5	%	 	 	+	 	 	from 1% to 1.2%	
30-39	 	 	6	%	 	 	+	 	 	2%	
40-49	 	 	8	%	 	 	+	 	 	3%	
50 or over	 	 	10	%	 	 	+	 	 	5%	

For participants who were active employees and participants under the plan on March 31, 1998, and April 1, 1998, the percentage of eligible pay is increased by 0.3% multiplied by the participant’s total years of benefit service earned as of March 31, 1998.
 
In addition, interest is credited to account balances quarterly at a rate determined annually in accordance with the terms of the plan.
 
The monthly annuity available to those who take normal retirement is based on the participant’s account balance as of the date of retirement. Normal retirement age is 65. Early retirement eligibility begins at 55. At retirement, participants may choose to receive a single-life annuity (for single participants) or a qualified joint and survivor annuity (for married participants) or they may choose one of several other forms of payment having an actuarial value equal to that of the relevant annuity.
 
Retirement Restoration Plan
 
The Code limits pension benefits based on the annual compensation limit that can be accrued in tax-qualified defined benefit plans, such as Williams’ pension plan. Any reduction in an executive’s pension benefit accrual due to these limits will be compensated, subject to a cap, under an unfunded top hat plan—Williams’ retirement restoration plan.
 
The elements of compensation that are included in applying the payment and benefit formula for the retirement restoration plan are the same elements that are used, except for application of a cap, in the base pension plan for all Williams’ employees. The elements of pay included in that definition are total base pay, including any overtime, base pay-reduction amounts and cash bonus awards, if paid (unless specifically excluded under a written bonus or incentive-pay arrangement). Specifically excluded from the definition are severance pay, cost-of-living pay, housing pay, relocation pay (including mortgage interest differential), taxable and non-taxable fringe benefits and all other extraordinary pay, including any amounts received from equity compensation awards.
 
With respect to bonuses, annual cash incentives are considered in determining eligible pay under the pension plan. Long-term equity compensation incentives are not considered.

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2010 Williams’ Pension Benefits
 
The following table sets forth certain information with respect to the actuarial present value of the accrued benefit as of December 31, 2010 under Williams’ qualified pension plan and retirement restoration plan.

 	 	 	 	Number of	 	 	 	Payments	
 	 	 	 	Years Credited	 	Present Value of	 	During Last	
Name	 	Plan Name	 	Services	 	Accrued Benefit(1)	 	Fiscal Year	
 		
Steven J. Malcolm(2)(3)	 	Pension Plan	 	 	27	 	 	$	829,307	 	 	 	—	 	
 	 	Retirement Restoration Plan	 	 	27	 	 	 	5,497,857	 	 	 	—	 	
Donald R. Chappel(2)	 	Pension Plan	 	 	8	 	 	 	245,359	 	 	 	—	 	
 	 	Retirement Restoration Plan	 	 	8	 	 	 	1,319,741	 	 	 	—	 	
Ralph A. Hill(3)	 	Pension Plan	 	 	27	 	 	 	586,869	 	 	 	—	 	
 	 	Retirement Restoration Plan	 	 	27	 	 	 	1,321,013	 	 	 	—	 	
James J. Bender	 	Pension Plan	 	 	8	 	 	 	216,010	 	 	 	—	 	
 	 	Retirement Restoration Plan	 	 	8	 	 	 	799,037	 	 	 	—	 	
Robyn L. Ewing(2)	 	Pension Plan	 	 	30	 	 	 	598,781	 	 	 	—	 	
 	 	Retirement Restoration Plan	 	 	30	 	 	 	723,095	 	 	 	—	 	

 
			
(1)		The primary actuarial assumptions used to determine the present values include an annual interest credit to normal retirement age equal to 5% and a discount rate equal to 5.29% for the pension plan and discount rate equal to 5.1% for the retirement restoration plan.	
 		
(2)		Mr. Malcolm, Mr. Chappel and Ms. Ewing are the only NEOs eligible to retire as of December 31, 2010.	
 		
(3)		Williams’ pension plan includes a Rule of 55 benefit that is a transition benefit that was provided to all employees meeting the eligibility criteria at the time Williams’ pension plan was converted from a final average pay formula to a cash balance formula. To be eligible for the Rule of 55 enhancement an employee’s age and years of service at the time of the cash balance conversion in 1998 must have totaled 55. Mr. Malcolm and Mr. Hill are the only NEOs that met the eligibility criteria for the Rule of 55 transitional benefit.	
 
Nonqualified Deferred Compensation
 
Williams does not provide nonqualified deferred compensation for any NEOs or other employees.
 
Change in Control Agreements
 
Williams has entered into change in control agreements with certain officers, including each of the NEOs, to facilitate continuity of management if there is a change in control of Williams. These arrangements do not provide for the payment of any benefits in the event of a future change in control of the ownership of WPX Energy. The provisions of such agreements are described below. The definitions of words in quotations are also provided below.
 
If during the term of a change in control agreement, a “change in control” occurs and (i) the employment of any NEO is terminated other than for “cause,” “disability,” death or a “disqualification disaggregation” or (ii) an NEO resigns for “good reason,” such NEO is entitled to the following:

 	•  	Within 10 business days after the termination date:	

 	•  	Accrued but unpaid base salary, accrued earned but unpaid cash incentive, accrued but unpaid paid time off and any other amounts or benefits due but not paid (lump sum payment);	

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 	•  	On the first business day following six months after the termination date:	

 	•  	Prorated annual bonus for the year of separation through the termination date (lump sum payment);	
 		
 	•  	A severance amount equal to three times his/her base salary for the NEO as of the termination date plus an annual bonus amount equal to his/her target percentage multiplied by his/her base salary in effect at the termination date as if performance goals were achieved at 100% (lump sum payment);	
 		
 	•  	An amount equal to three times for the total allocations made by Williams for the NEOs in the preceding calendar year under our retirement restoration plan (lump sum payment);	
 		
 	•  	An amount equal to the sum of the value of the unvested portion of the NEO’s accounts or accrued benefits under Williams’ 401(k) plan that would have otherwise been forfeited (lump sum payment);	

 	•  	Continued participation in Williams’ medical benefit plans for so long as the NEO elects coverage or 18 months from the termination, whichever is less, in the same manner and at the same cost as similarly situated active employees;	
 		
 	•  	All restrictions on stock options held by the NEO will lapse, and the options will vest and become immediately exercisable;	
 		
 	•  	All restricted stock will vest and will be paid out only in accordance with the terms of the respective award agreements;	
 		
 	•  	Continued participation in Williams’ directors’ and officers’ liability insurance for six years or any longer known applicable statute of limitations period;	
 		
 	•  	Indemnification as set forth under Williams’ bylaws; and	
 		
 	•  	Outplacement benefits for six months at a cost not exceeding $25,000.	
 
In addition, each NEO is generally entitled to receive a gross-up payment in an amount sufficient to make him/her whole for any federal excise tax on excess parachute payments imposed under Section 280G and 4999 of the Code or any similar tax under any state, local, foreign or other law (other than Section 409A of the Code). However, in reviewing the change in control agreements in 2010 and 2011, the Committee approved eliminating this excise tax gross-up provision. The Committee opted to provide a ‘best net’ provision providing the NEOs with the better of their after-tax benefit capped at the safe harbor amount or their benefit paid in full subjecting them to possible excise tax payments. Therefore, in 2011 Williams will provide the one year notice required by the NEOs’ change in control agreements in order to effect the change in 2012. After this change is implemented, Williams will no longer provide additional compensation to address excise taxes.
 
If an NEO’s employment is terminated for “cause” during the period beginning upon a change of control and continuing for two years or until the termination of the agreement, whichever happens first, the NEO is entitled to accrued but unpaid base salary, accrued earned but unpaid cash incentive, accrued but unpaid paid time off and any other amounts or benefits due but not paid (lump sum payment).
 
The agreements with our NEOs use the following definitions:
 
“Cause” means an NEO’s

 	•  	conviction of or a plea of nolo contendere to a felony or a crime involving fraud, dishonesty or moral turpitude;	
 		
 	•  	willful or reckless material misconduct in the performance of his/her duties that has an adverse effect on Williams or any of its subsidiaries or affiliates;	
 		
 	•  	willful or reckless violation or disregard of the code of business conduct of Williams or the policies of Williams or its subsidiaries; or	
 		
 	•  	habitual or gross neglect of his/her duties.	

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Cause generally does not include bad judgment or negligence (other than habitual neglect or gross negligence); acts or omissions made in good faith after reasonable investigation by the NEO or acts or omissions with respect to which Williams’ board of directors could determine that the NEO had satisfied the standards of conduct for indemnification or reimbursement under Williams’ bylaws, indemnification agreement or applicable law; or failure (despite good faith efforts) to meet performance goals, objectives or measures for a period beginning upon a change of control and continuing for two years or until the termination of the agreement, whichever happens first. An NEO’s act or failure to act (except as relates to a conviction or plea of nolo contendere described above), when done in good faith and with a reasonable belief after reasonable investigation that such action or non-action was in the best interest of Williams or its affiliate or required by law shall not be Cause if the NEO cures the action or non-action within 10 days of notice. Furthermore, no act or failure to act will be Cause if the NEO acted under the advice of Williams’ counsel or required by the legal process.
 
“Change in control” means:

 	•  	Any person or group (other than an affiliate of Williams or an employee benefit plan sponsored by Williams or its affiliates) becomes a beneficial owner, as such term is defined under the Exchange Act, of 20% or more of the common stock of Williams or 20% or more of the combined voting power of all securities entitled to vote generally in the election of directors of Williams (“Voting Securities”), unless such person owned both more than 75% of common stock and Voting Securities, directly or indirectly, in substantially the same proportion immediately before such acquisition;	
 		
 	•  	Williams’ directors as of a date of the agreement (“Existing Directors”) and directors approved after that date by at least two-thirds of the Existing Directors cease to constitute a majority of the directors of Williams;	
 		
 	•  	Consummation of any merger, reorganization, recapitalization consolidation or similar transaction (“Reorganization Transaction”), other than a Reorganization Transaction that results in the person who was the direct or indirect owner of outstanding common stock and Voting Securities of Williams prior to the transaction becoming, immediately after the transaction, the owner of at least 65% of the then outstanding common stock and Voting Securities representing 65% of the combined voting power of the then outstanding Voting Securities of the surviving corporation in substantially the same respective proportion as that person’s ownership immediately before such Reorganization Transaction; or	
 		
 	•  	approval by the stockholders of Williams of the sale or other disposition of all or substantially all of the consolidated assets of Williams or the complete liquidation of Williams other than a transaction that would result in (i) a related party owning more than 50% of the assets that were owned by Williams immediately prior to the transaction or (ii) the persons who were the direct or indirect owners of outstanding Williams common stock and Voting Securities prior to the transaction continuing to own, directly or indirectly, 50% or more of the assets that were owned by Williams immediately prior to the transaction.	
 
A change in control will not occur if:

 	•  	the NEO agrees in writing prior to an event that such an event will not be a change in control; or	
 		
 	•  	Williams’ board of directors determines that a liquidation, sale or other disposition approved by the stockholders, as described in the fourth bullet above, will not occur, except to the extent termination occurred prior to such determination.	
 
“Disability” means a physical or mental infirmity that impairs the NEO’s ability to substantially perform his/her duties for twelve months or more and for which he/she is receiving income replacement benefits from a Williams’ plan for not less than three months.
 
“Disqualification disaggregation” means:

 	•  	the termination of an NEO’s employment from Williams or an affiliate before a change in control for any reason; or	

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 	•  	the termination of an NEO’s employment by a successor (during the period beginning upon a change of control and continuing for two years or until the termination of the agreement, whichever happens first), if the NEO is employed in substantially the same position and the successor has assumed the Williams’ change in control agreement.	
 
“Good reason” means, generally, a material adverse change in the NEO’s title, position or responsibilities, a reduction in the NEO’s base salary, a reduction in the NEO’s annual bonus, required relocation, a material reduction in the level of aggregate compensation or benefits not applicable to Williams’ peers, a successor company’s failure to honor the agreement or the failure of Williams’ board of directors to provide written notice of the act or omission constituting “cause.”
 
Termination Scenarios
 
The following table sets forth circumstances that provide for payments by Williams to the NEOs following or in connection with a change in control of Williams or an NEO’s termination of employment for cause, upon retirement, upon death and disability or not for cause, all while employed by Williams. NEOs are generally eligible to retire at the earlier of age 55 and completion of 3 years of service or age 65.
 
All values are based on a hypothetical termination date of December 31, 2010 and a closing stock price for Williams’ common stock of $24.72 on such date. The values shown are intended to provide reasonable estimates of the potential benefits the NEOs would receive upon termination. The values are based on various assumptions and may not represent the actual amount an NEO would receive. In addition to the amounts disclosed in the following table, a departing NEO would retain the amounts he/she has earned over the course of his/her employment prior to the termination event, including accrued retirement benefits and previously vested stock options and RSUs.

 	 	 	 	For	 	 	 	 	 	Death &	 	 	Not for	 	 	 	 	
Name	 	Payment	 	Cause(1)	 	 	Retirement(2)	 	 	Disability(3)	 	 	Cause(4)	 	 	CIC(5)	 	
 		
Malcolm, Steven J	 	AIP Reserve	 	 	—	 	 	$	242,756	 	 	$	242,756	 	 	$	242,756	 	 	$	242,756	 	
 	 	Stock options	 	 	—	 	 	 	5,645,264	 	 	 	5,645,264	 	 	 	—	 	 	 	5,645,264	 	
 	 	Stock awards	 	 	—	 	 	 	7,240,399	 	 	 	7,240,399	 	 	 	7,240,399	 	 	 	12,634,022	 	
 	 	Cash Severance	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	6,600,000	 	
 	 	Outplacement	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	25,000	 	
 	 	Health & Welfare	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	18,170	 	
 	 	Retirement Restoration	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Plan	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	2,207,808	 	
 	 	Enhancement	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Tax Gross Up	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	8,649,197	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Total	 	 	—	 	 	$	13,128,419	 	 	$	13,128,419	 	 	$	7,483,155	 	 	$	36,022,217	 	

Chappel, Donald R	 	AIP Reserve	 	 	—	 	 	$	60,103	 	 	$	60,103	 	 	$	60,103	 	 	$	60,103	 	
 	 	Stock options	 	 	—	 	 	 	1,224,287	 	 	 	1,224,287	 	 	 	—	 	 	 	1,224,287	 	
 	 	Stock awards	 	 	—	 	 	 	4,086,877	 	 	 	5,444,451	 	 	 	5,444,451	 	 	 	6,829,365	 	
 	 	Cash Severance	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	3,213,000	 	
 	 	Outplacement	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	25,000	 	
 	 	Health & Welfare	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	26,699	 	
 	 	Retirement Restoration Plan	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	 	 	
 	 	Enhancement	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	646,557	 	
 	 	Tax Gross Up	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	2,966,960	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Total	 	 	—	 	 	$	5,371,267	 	 	$	6,728,841	 	 	$	5,504,554	 	 	$	14,991,971	 	

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 	 	 	 	For	 	 	 	 	 	Death &	 	 	Not for	 	 	 	 	
Name	 	Payment	 	Cause(1)	 	 	Retirement(2)	 	 	Disability(3)	 	 	Cause(4)	 	 	CIC(5)	 	
 		
Hill, Ralph A	 	AIP Reserve	 	 	—	 	 	$	72,958	 	 	$	72,958	 	 	$	72,958	 	 	$	72,958	 	
 	 	Stock options	 	 	—	 	 	 	1,045,738	 	 	 	1,045,738	 	 	 	—	 	 	 	1,045,738	 	
 	 	Stock awards	 	 	—	 	 	 	3,360,366	 	 	 	4,527,523	 	 	 	4,527,523	 	 	 	5,715,453	 	
 	 	Cash Severance	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	2,448,765	 	
 	 	Outplacement	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	25,000	 	
 	 	Health & Welfare	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	26,346	 	
 	 	Retirement Restoration Plan	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	 	 	
 	 	Enhancement	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	636,018	 	
 	 	Tax Gross Up	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Total	 	 	—	 	 	$	4,479,062	 	 	$	5,646,219	 	 	$	4,600,481	 	 	$	9,970,278	 	

Bender, James J	 	AIP Reserve	 	 	—	 	 	$	44,244	 	 	$	44,244	 	 	$	44,244	 	 	$	44,244	 	
 	 	Stock options	 	 	—	 	 	 	795,784	 	 	 	795,784	 	 	 	—	 	 	 	795,784	 	
 	 	Stock awards	 	 	—	 	 	 	2,586,716	 	 	 	3,467,769	 	 	 	3,467,769	 	 	 	4,365,230	 	
 	 	Cash Severance	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	2,373,030	 	
 	 	Outplacement	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	25,000	 	
 	 	Health & Welfare	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	26,346	 	
 	 	Retirement Restoration Plan	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	 	 	
 	 	Enhancement	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	423,896	 	
 	 	Tax Gross Up	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	2,217,566	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Total	 	 	—	 	 	$	3,426,744	 	 	$	4,307,797	 	 	$	3,512,013	 	 	$	10,271,096	 	

Ewing, Robyn L	 	AIP Reserve	 	 	—	 	 	$	20,728	 	 	$	20,728	 	 	$	20,728	 	 	$	20,728	 	
 	 	Stock options	 	 	—	 	 	 	744,737	 	 	 	744,737	 	 	 	—	 	 	 	744,737	 	
 	 	Stock awards	 	 	—	 	 	 	1,836,807	 	 	 	2,671,273	 	 	 	2,671,273	 	 	 	3,507,393	 	
 	 	Cash Severance	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	2,202,750	 	
 	 	Outplacement	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	25,000	 	
 	 	Health & Welfare	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	26,346	 	
 	 	Retirement Restoration Plan	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	 	 	
 	 	Enhancement	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	437,948	 	
 	 	Tax Gross Up	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	1,861,484	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Total	 	 	—	 	 	$	2,602,272	 	 	$	3,436,738	 	 	$	2,692,001	 	 	$	8,826,386	 	

 

			
(1)		If an NEO is terminated for cause or leaves Williams voluntarily, no additional benefits will be received.	
 		
(2)		If an NEO retires from Williams, then all unvested stock options will fully accelerate. A pro-rated portion of the unvested time based RSUs will accelerate and a pro-rated portion of any performance-based RSUs will vest on the original vesting date if the Committee certifies that the performance measures were met.	
 		
(3)		If an NEO dies or becomes disabled, then all unvested stock options will fully accelerate. All unvested time-based RSUs will fully accelerate, and a pro-rated portion of any performance-based RSUs will vest if the Committee certifies that the performance measures were met.	
 		
(4)		For an NEO who is involuntarily terminated who receives severance or for an NEO whose job is outsourced with no comparable internal offer, all unvested time-based RSUs will fully accelerate and a pro-rated portion of any performance-based RSUs will vest if the Committee certifies that the performance measures were met. However all unvested stock options cancel.	
 		
(5)		See “Change In Control Agreements” above.	
 
Please note that we make no assumptions as to the achievement of performance goals as it relates to the performance based RSUs. If an award is covered by Section 409A of the Code, lump sum payments and distributions occurring from these events will occur six months after the triggering event as required by the Code and our award agreements.
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PRINCIPAL STOCKHOLDER
 
All outstanding shares of our common stock are owned beneficially and of record by Williams. The following table sets forth information with respect to the beneficial ownership of our common stock immediately after the completion of this offering by:

 	• 	each person who is an executive officer;	
 		
 	• 	each person who is a director or is expected to serve as a director upon completion of this offering;	
 		
 	• 	all directors or persons expected to serve as directors and all executive officers as a group; and	
 		
 	• 	Williams, who, after completion of this offering will own 100% of the outstanding shares of our Class B common stock, which will represent (1)     % of all classes of our outstanding common stock (     % if the underwriters exercise their option to purchase additional Class A common shares in full) and (2)     % of the combined voting power of all classes of our outstanding common stock on all matters (     % if the underwriters exercise their option to purchase additional Class A common shares in full).	
 
Beneficial ownership has been determined in accordance with the rules of the SEC and includes the power to vote or direct the voting of securities, or to dispose or direct the disposition thereof, or the right to acquire such powers within 60 days. Except as otherwise indicated, the persons or entities listed below have sole voting and investment power with respect to all shares of our common stock beneficially owned by them. The address for Williams is One Williams Center, Tulsa, Oklahoma 74172-0172. Unless otherwise indicated, the address for each director and executive officer listed is: c/o WPX Energy, Inc., One Williams Center, Tulsa, Oklahoma 74172-0172.

 	 	Number of Class A	 	 	 	Number of Class B	 	 	
 	 	Shares Beneficially	 	Percentage	 	Shares Beneficially	 	Percentage	
Name of Beneficial Owner	 	Owned	 	of Class	 	Owned	 	of Class	
 		
The Williams Companies, Inc.(1)	 	 	—	 	 	 	—	 	 	 	 	 	 	 	100	%	
Alan S. Armstrong	 	 	*	 	 	 	*	 	 	 	—	 	 	 	—	 	
Ralph A. Hill	 	 	*	 	 	 	*	 	 	 	—	 	 	 	—	 	
Donald R. Chappel	 	 	*	 	 	 	*	 	 	 	—	 	 	 	—	 	
Ted T. Timmermans	 	 	*	 	 	 	*	 	 	 	—	 	 	 	—	 	
James J. Bender	 	 	*	 	 	 	*	 	 	 	—	 	 	 	—	 	
Robyn L. Ewing	 	 	*	 	 	 	*	 	 	 	—	 	 	 	—	 	
Rodney J. Sailor	 	 	*	 	 	 	*	 	 	 	—	 	 	 	—	 	
George A. Lorch	 	 	*	 	 	 	*	 	 	 	—	 	 	 	—	 	
William G. Lowrie	 	 	*	 	 	 	*	 	 	 	—	 	 	 	—	 	
All executive officers and directors as a group (nine persons)	 	 	*	 	 	 	*	 	 	 	—	 	 	 	—	 	

 
			
* 		Represents less than 1%.	
 		
(1)		Assumes the underwriters do not exercise their option to purchase additional Class A common shares.	

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ARRANGEMENTS BETWEEN WILLIAMS AND OUR COMPANY
 
This section provides a summary description of agreements between Williams and us relating to our restructuring transactions, this offering and our relationship with Williams after this offering. When used in this section, “distribution date” refers to the date, if any, following the offering on which Williams will distribute, or spin-off, its shares of our common stock to its stockholders.
 
This description of the agreements between Williams and us is a summary and, with respect to each such agreement, is qualified by reference to the terms of the agreement, each of which will be filed as an exhibit to the registration statement of which this prospectus is a part. We encourage you to read the full text of these agreements. We will enter into these agreements with Williams prior to the completion of this offering; accordingly, we will enter into these agreements with Williams in the context of our relationship as a wholly-owned subsidiary of Williams. The terms of these agreements may be more or less favorable to us than if they had been negotiated with unaffiliated third parties.
 
Separation and Distribution Agreement
 
We will enter into a separation and distribution agreement with Williams that will set forth our agreements with Williams regarding the principal corporate transactions required to effect our restructuring transactions, this offering and the distribution of our shares to Williams common stockholders. It will also set forth the other agreements governing our relationship with Williams that we describe in this section.
 
Transfer of Assets and Assumption of Liabilities.   The separation and distribution agreement will identify the assets to be contributed and transferred, and liabilities to be assumed, in connection with our separation from Williams so that each of Williams and us ultimately retains the assets of, and the liabilities associated with, our respective businesses.
 
In connection with the separation, all agreements, arrangements, commitments and understandings, including all intercompany loans and accounts payable and receivable, between us and our subsidiaries and other affiliates, on the one hand, and Williams and its other subsidiaries and other affiliates, on the other hand, will terminate, except certain agreements and arrangements which are expressly identified as intended to survive the separation.
 
This Offering.   The separation and distribution agreement will require us to use commercially reasonable efforts to consummate this offering.
 
The Distribution.   The separation and distribution agreement will govern the rights and obligations of Williams and us regarding the proposed distribution by Williams to its common stockholders of the shares of our common stock held by Williams. We will be required to cooperate with Williams to accomplish the distribution and, at Williams’ discretion, promptly take any and all actions necessary or desirable to effect the distribution.
 
In the separation and distribution agreement, Williams will represent its intention to complete the distribution during 2012. However, the completion of the distribution will be subject to various conditions that must be satisfied or waived by Williams in its sole discretion. In addition, Williams will have the right not to complete the distribution if, at any time, Williams’ board of directors determines, in its sole discretion, that the distribution is not in the best interest of Williams or its stockholders. As a result, we cannot assure you as to when or whether the distribution will occur.
 
Representations and Warranties.   Except as expressly set forth in the separation and distribution agreement or in any other ancillary agreement, neither we nor Williams will make any representation or warranty in connection with our separation from Williams, this offering or the distribution.

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Contractual Restrictions.   For so long as Williams owns at least 50% of the total voting power of our outstanding stock generally entitled to elect our directors, we will not (without Williams’ prior written consent):

 	•  	take any action that would limit the ability of Williams to transfer its shares of our common stock or limit the rights of any transferee of Williams as a holder of our common stock;	
 		
 	•  	issue any shares of our capital stock, or any rights, warrants or options to acquire our capital stock, if the issuance would cause Williams to own less than 50% of the total value of all classes of our outstanding capital stock, 80% of the total voting power of all classes of our outstanding capital stock generally entitled to elect our directors or 80% of any class of outstanding capital stock not entitled to vote; or	
 		
 	•  	take any action, or fail to take any action, to the extent such action or failure could reasonably result in Williams being in breach or default under a contract of which Williams has notified us.	
 
We will agree in the separation and distribution agreement that we will not (without Williams’ prior written consent) take any of the following actions prior to the spin-off:

 	•  	acquire any businesses or assets with an aggregate value of more than $50 million for all such acquisitions;	
 		
 	•  	dispose of any assets with an aggregate value of more than $50 million for all such dispositions; and	
 		
 	•  	acquire any equity or debt securities of any other person with an aggregate value of more than $50 million for all such acquisitions.	
 
In addition, for so long as Williams is required to consolidate our results of operations and financial position, we will agree not to incur any additional indebtedness (excluding the Credit Facility and the Notes) without the consent of Williams.
 
During the term of the administrative services agreement and the transition services agreement, and for one year thereafter, neither we nor Williams will be permitted to solicit each other’s employees for employment without the other’s consent.
 
Financial Reporting.   We will agree, for so long as Williams is required to consolidate our results of operations and financial position, to:

 	•  	comply with all requirements under applicable law regarding disclosure controls and procedures and internal control over financial reporting;	
 		
 	•  	maintain internal systems and procedures that will provide Williams with reasonable assurance that our financial statements and other publicly reported information is reliable and timely prepared in accordance with GAAP and any other applicable law;	
 		
 	•  	provide Williams with financial reports, including consolidated financial statements (and notes thereto) and discussion and analysis by management of our financial condition and liquidity, in the form, and in accordance with the dates, specified by Williams;	
 		
 	•  	unless required by law, use the auditors (and lead audit partners) directed by Williams; and	
 		
 	•  	unless required by law, to the extent requested by Williams, keep our accounting practices and principles consistent with those of Williams.	
 
Releases.   Except as otherwise provided in the separation and distribution agreement, each of Williams and us will release and discharge the other and their respective subsidiaries and other affiliates from all liabilities existing or arising from any acts or events occurring or failing to occur or alleged to have occurred or to have failed to occur or any conditions existing or alleged to have existed on or before the separation from Williams. The releases will not extend to obligations or liabilities under any agreements between Williams and us that remain in effect following the separation, which agreements include, but are not limited

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to, the separation and distribution agreement, the administrative services agreement, the transition services agreement, the registration rights agreement and the tax sharing agreement.
 
Confidentiality.   Each party will agree to treat as confidential and not disclose confidential information of the other party except in specific circumstances identified in the separation and distribution agreement.
 
Further Assurances.   Each party will agree to use its reasonable best efforts to take or cause to be taken all actions, and to do or cause be done all things reasonably necessary, proper or advisable under applicable law, regulations and agreements to consummate and make effective the transactions contemplated by the separation and distribution agreement and the ancillary agreements.
 
Indemnification.   The separation and distribution agreement will provide that we will indemnify, defend and hold harmless Williams, its subsidiaries, and each of their respective current, former and future directors, officers and employees, and each of the heirs, executors, successors and assigns of any of the foregoing for any losses arising out of or resulting from:

 	•  	the liabilities being assumed by us pursuant to the separation and distribution agreement;	
 		
 	•  	the operation of our business;	
 		
 	•  	any breach by us of the separation and distribution agreement or the ancillary agreements; and	
 		
 	•  	any untrue statement or alleged untrue statement of a material fact or omission or alleged omission to state a material fact required to be stated therein or necessary to make the statements therein not misleading, with respect to all information (i) contained in the registration statement of which this prospectus is a part or in this prospectus, (ii) contained in any public filings made by us with the SEC following the separation; and (iii) provided by us to Williams specifically for inclusion in Williams’ annual or quarterly reports following the separation.	
 
Williams will indemnify, defend and hold harmless us, our subsidiaries, and each of our and their respective current, former and future directors, officers and employees, and each of the heirs, executors, successors and assigns of any of the foregoing for any losses arising out of or resulting from:

 	•  	the liabilities being retained by Williams pursuant to the separation and distribution agreement;	
 		
 	•  	the operation of Williams’ business;	
 		
 	•  	any breach by Williams of the separation and distribution agreement or the ancillary agreements; and	
 		
 	•  	certain pending or threatened litigation related to the 2000-2001 California Energy Crisis and the reporting of certain natural gas-related information to trade publications.	
 
The separation and distribution agreement will also specify procedures with respect to claims subject to indemnification and related matters.
 
Termination.   The separation and distribution agreement will be terminable before the separation in the sole discretion of Williams. In the event of such a termination, no party will have any liability or further obligation with respect to the separation and distribution agreement.
 
Dispute Resolution.   In the event of a dispute relating to the separation and distribution agreement between us and our subsidiaries and other affiliates, on the one hand, and Williams and its other subsidiaries and other affiliates, on the other hand, the separation and distribution agreement will provide for the following procedures:

 	•  	first, the parties will use commercially reasonable efforts to resolve the dispute through negotiations between our representatives and Williams’ representatives;	
 		
 	•  	if negotiations fail, then the parties will attempt to resolve the dispute through non-binding mediation; and	
 		
 	•  	if mediation fails, then the parties may seek relief in any court of competent jurisdiction.	

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Expenses.   Except as expressly set forth in the separation and distribution agreement or in any other ancillary agreement, all fees and expenses incurred in connection with our separation from Williams will be paid by the party incurring such fees or expenses.
 
Administrative Services and Transition Services Agreements
 
We will enter into an administrative services agreement and a transition services agreement with Williams under which Williams will provide to us, on an interim basis, various corporate support services. These services will consist generally of the services that have been provided to WPX on an intercompany basis prior to this offering. These services relate to:

 	•  	cash management and treasury administration;	
 		
 	•  	finance and accounting;	
 		
 	•  	tax;	
 		
 	•  	internal audit;	
 		
 	•  	investor relations;	
 		
 	•  	payroll and human resource administration;	
 		
 	•  	information technology;	
 		
 	•  	legal and government affairs;	
 		
 	•  	insurance and claims administration;	
 		
 	•  	records management;	
 		
 	•  	real estate and facilities management;	
 		
 	•  	sourcing and procurement; and	
 		
 	•  	mail, print and other office services.	
 
Pursuant to the administrative services agreement, Williams will provide these services to us for the period beginning on the date this offering is completed and ending on the earlier of (i) the date immediately prior to the distribution date or (ii) sixty days’ notice by Williams if it determines that the provision of such services involves certain conflicts of interest between Williams and us or would cause Williams to violate applicable law. Williams will provide the services and we will pay Williams’ costs, including Williams’ direct and indirect administrative and overhead charges allocated in accordance with Williams’ regular and consistent accounting practices. Pursuant to the transition services agreement, Williams will provide certain services for up to one year after the distribution date. The transition services agreement may be terminated by either us or Williams upon 60 days notice after the distribution date. In addition, Williams may immediately terminate any of the services it provides under the transition services agreement if it determines that the provision of such services involves certain conflicts of interest between Williams and us or would cause Williams to violate applicable law.
 
Williams may decline to provide certain services under these agreements if the provision of such services causes Williams to violate applicable law, creates a conflict of interest, requires Williams to retain additional employees or other resources or the provision of such services become impracticable due to reasons outside the control of Williams. Williams will charge us for its full salary and benefits costs associated with individuals providing the services as well as any out-of-pocket expenses incurred by Williams in the provision of the services, plus, during the term of the transition services agreement, an administrative fee.
 
In both cases, Williams will provide these services with the same general degree of care, at the same general volumes and at the same general degree of accuracy and responsiveness, as when the services were performed prior to the separation.

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In addition, in the event that Williams determines that it will require any services from us after the distribution date, the transition services agreement will permit Williams to request such services from us prior to the distribution date. If Williams makes such a request, we will use commercially reasonable efforts to provide such services on the same terms and conditions as those governing the services Williams is providing to us under the transition services agreement.
 
Registration Rights Agreement
 
The registration rights agreement provides Williams with rights relating to the shares of our common stock held by Williams. Under the registration rights agreement, Williams has the right, subject to the terms of its lock-up agreement with the underwriters, to require us to register for offer and sale all or a portion of the shares of our common stock covered by the agreement.
 
Shares Covered.   The registration rights agreement covers those shares of our common stock that are held by Williams or a transferee of Williams.
 
Demand Registration.   Williams may request registration under the Securities Act of all or any portion of our shares covered by the registration rights agreement, and we will be obligated, subject to limited exceptions, to register such shares as requested by Williams. The maximum number of registrations Williams may require us to effect is five. Williams has the right to designate the terms of each offering it requests.
 
We are not required to undertake any demand registration requested by Williams within 90 days after completion of a previously-requested demand registration other than pursuant to a shelf registration statement. In addition, we have the right, which may be exercised once in any 12-month period, to postpone the filing or effectiveness of any demand registration if we determine in the good faith judgment of our general counsel, confirmed by our board of directors, that such registration would reasonably be expected to require the disclosure of material information that we have a business purpose to keep confidential and the disclosure of which would have a material adverse effect on any then-active proposals to engage in certain material transactions until the earlier of (i) 15 business days after the date of disclosure of such material information, or (ii) 75 days after we make such determination.
 
Piggy-Back Registration.   If we at any time intend to file on our behalf or on behalf of any of our other security holders a registration statement in connection with a public offering of any of our securities on a form and in a manner that would permit the registration for offer and sale of the shares of our common stock, Williams has the right to have those shares included in that offering.
 
Registration Expenses.   We are responsible for all registration expenses incurred in connection with the performance of our obligations under the registration rights agreement. Williams is responsible for all of the fees and expenses of counsel to Williams, any applicable underwriting discounts or commissions, and any registration or filing fees incurred with respect to shares of our common stock being sold under the registration rights agreement.
 
Indemnification.   The registration rights agreement contains indemnification and contribution provisions by us for the benefit of Williams and its affiliates and representatives and, in limited situations, by Williams for the benefit of us and any underwriters with respect to information included in any registration statement, prospectus or related documents.
 
Transfer.   Williams may transfer shares covered by the registration rights agreement and the holders of such transferred shares will be entitled to the benefits of the registration rights agreement, provided that each such transferee agrees to be bound by the terms of the registration rights agreement.
 
Duration.   The registration rights under the registration rights agreement will remain in effect with respect to any shares of common stock covered by the agreement until:

 	•  	such shares have been sold pursuant to an effective registration statement under the Securities Act;	
 		
 	•  	such shares have been sold to the public pursuant to Rule 144 under the Securities Act;	

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 	•  	such shares have been otherwise transferred and new certificates evidencing such shares have been delivered and do not bear a legend restricting further transfer of such shares, provided that subsequent public distribution of such shares does not require registration or qualification of them under the Securities Act or any similar state law;	
 		
 	•  	such shares have ceased to be outstanding; or	
 		
 	•  	the distribution date.	
 
Tax Sharing Agreement
 
In connection with this offering, we will enter into a tax sharing agreement with Williams. The tax sharing agreement will govern the respective rights, responsibilities, and obligations of Williams and us with respect to the payment of taxes, filing of tax returns, reimbursements of taxes, control of audits and other tax proceedings, liability for taxes that may be triggered as a result of the spin-off of our stock to Williams’ stockholders and other matters regarding taxes. The tax sharing agreement will remain in effect until the parties agree in writing to its termination.
 
Tax Returns and Taxes.   Williams will be responsible for the preparation and filing of all consolidated, combined, or unitary income tax returns in which we (or our subsidiaries) are included, and the payment of all taxes that relate to such returns. Williams will be entitled to make all decisions regarding the preparation of such tax returns, including the making of any tax elections, and we will be bound by such decisions. We will be responsible for the preparation, filing, and payment of all returns other than those described above that are required to be filed with respect to us or any of our subsidiaries; however, Williams may, in its discretion, assist us in preparing any such returns.
 
Pro Forma Returns and Reimbursements.   For each tax period in which we or any of our subsidiaries are consolidated or combined with Williams for purposes of any tax return, Williams will prepare a pro forma tax return for us as if we filed our own consolidated, combined, or unitary return. Such pro forma returns will take into account all elections and methods of accounting reflected on the true returns; will only include current income, deductions, credits and losses from us (with certain exceptions); will not include any carryovers or carrybacks of any items from us for prior or subsequent periods; and will not take into account the federal Alternative Minimum Tax. For any periods shorter than a full taxable year, the pro forma return computations will be made based on a hypothetical closing of the books for us and our subsidiaries. We will reimburse Williams for any taxes shown on the pro forma tax returns, and Williams will reimburse us for any current losses or credits we recognize based on the pro forma tax returns.
 
Redeterminations.   In the case of any tax audit adjustments, all pro forma returns and associated tax reimbursement obligations will be recomputed to give effect to such adjustments, but only for adjustments that originate from a federal audit.
 
Spin-off.   Williams and we expect that the spin-off of our stock to Williams’ stockholders and any related restructuring transaction, taken together, will qualify for U.S. federal income tax purposes as a tax-free transaction under section 355 and section 368(a)(1)(D) of the Code. Williams is seeking a private letter ruling from the IRS and an opinion from its outside tax advisor to such effect. In connection with the private letter ruling and the opinion, we have made certain factual statements and representations regarding our company and our business, and Williams has made certain representations regarding itself and its business. In the tax sharing agreement, we and Williams will each represent and warrant that any factual statements and representations relating to our respective companies and businesses made in connection with the private letter ruling and tax opinion are true, correct, and complete, and that we have no plan or intention of taking any actions nor know of any circumstances that could cause such factual statements or representations (or any factual statements or representations in the tax sharing agreement or separation and distribution agreement) to be untrue. We and Williams will each also represent and warrant that, for a period leading up to the IPO, there was no agreement or arrangement by any of our officers or directors (or by any person with permission of our officers or directors) regarding an acquisition of more than 50% of the stock of WPX, Williams, or Apco, and that we have no current plan or intention to enter into any such agreements. In addition, we and Williams will each covenant not to take

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any actions that would (i) be inconsistent with any factual statement or representation made in the tax sharing agreement, the separation and distribution agreement, or in connection with the private letter ruling or tax opinion, (ii) create a material risk that the spin-off or any related restructuring transaction would fail to qualify as tax-free, or (iii) create a material risk that section 355(d) or section 355(e) of the Code would apply to the spin-off. Further, we and Williams will each agree not to take any position on a tax return that is inconsistent with the tax free treatment of the spin-off. We and Williams will also agree to notify each other if we or they become aware of a transaction that could affect the status of the spin-off or any related restructuring transaction under section 355 or section 368(a)(1)(D) of the Code, and to take reasonable action or reasonably refrain from taking action to ensure the qualification of the spin-off as tax free, unless the IRS has issued a private letter ruling or other guidance conclusively establishing that such matter or transaction does not adversely affect the tax-free nature of the spin-off. If we and Williams cannot agree on a course of action in this respect, we will be required to take the course of action consistent with applicable law that Williams reasonably determines in good faith, taking into account both our interests and Williams’ interests. Last, we will agree that our officers and directors will not discuss any acquisitions of our stock or the stock of any of our subsidiaries during the two-year period beginning after the spin-off without permission from Williams, such permission not to be unreasonably withheld.
 
Indemnities.   If Williams (or any of its subsidiaries) becomes liable for any taxes because of a failure of the spin-off or any related restructuring transaction to be wholly-tax free under section 355 or section 368(a)(1)(D) of the Code, we will indemnify Williams for such taxes to the extent caused by our breach of any representations or covenants made in the tax sharing agreement, the separation and distribution agreement, or made in connection with the private letter ruling or tax opinion. Williams will indemnify us for all taxes arising from the failure of the spin-off or any related restructuring transaction to be tax-free except for those caused by us as described above.
 
Proceedings and Cooperation.   Williams will have the right to control any tax proceedings or disputes and to make any decisions regarding taxes, payments and settlements relating to consolidated, combined, or unitary returns that include us or our subsidiaries. If a proceeding or dispute could require us to pay taxes arising from the spin-off, Williams will agree to consult with us and give us an opportunity to comment and participate in the proceeding. However, Williams retains sole discretion over all the positions taken in such proceedings, except that we will have consent rights, which have to be exercised reasonably, to approve any settlement. We and Williams will cooperate with each other in good faith regarding all provisions of the tax sharing agreement, and will retain books and records relating to the filing of returns in the agreement for 10 years.
 
Information Technology Transition Costs
 
In conjunction with the completion of this offering, Williams will provide us with approximately $20 million in cash to assist in the funding of certain information technology transition costs and expenses we expect to incur following the completion of this offering. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Management’s Discussion and Analysis of Financial Condition and Liquidity—Liquidity.”

Office Lease

 
On August 25, 2011, we entered into a 10.5 year lease for our present headquarters office with Williams Headquarters Building Company, a direct subsidiary of Williams. We estimate the annual rent payable by us under the lease to be approximately $4.6 million per year.

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OTHER RELATED PARTY TRANSACTIONS
 
In addition to the related party transactions described in “Arrangements Between Williams and Our Company” above, this section discusses other transactions and relationships with related persons during the past three fiscal years.
 
Reimbursement of Expenses of Williams

Williams charges us for the payroll and benefit costs associated with operations employees (referred to as direct employees) and carries the obligations for many employee-related benefits in its financial statements, including the liabilities related to employee retirement and medical plans. Our share of those costs is charged to us through affiliate billings and reflected in lease and facility operating and general and administrative within costs and expenses in the accompanying Combined Statement of Operations. These costs totaled $125 million, $123 million and $111 million for the years ended December 31, 2010, 2009 and 2008, respectively.

In addition, Williams charges us for certain employees of Williams who provide general and administrative services on our behalf (referred to as indirect employees). These charges are either directly identifiable or allocated to our operations. Direct charges include goods and services provided by Williams at our request. Allocated general corporate costs are based on our relative use of the service or on a three-factor formula, which considers revenues; properties and equipment; and payroll. Our share of direct general and administrative expenses and our share of allocated general corporate expenses is reflected in general and administrative expense in the Combined Statement of Operations. These costs totaled $134 million, $136 million and $128 million for the years ended December 31, 2010, 2009 and 2008, respectively. In our management’s estimation, the allocation methodologies used are reasonable and result in a reasonable allocation to us of their costs of doing business incurred by Williams.
 
Commodity Sales Contracts
 
We procure and sell natural gas for shrink replacement and fuel to Williams Partners and other Williams affiliates. We sell substantially all of the NGLs related to our production to Williams Partners. We conduct these transactions at market prices at the time of purchase. Revenues from these sales totaled $786 million, $547 million and $1,078 million for the years ended December 31, 2010, 2009 and 2008, respectively. Effective as of August 1, 2011, we agreed to sell Williams Partners all NGLs produced from our processing plants connected to the Overland Pass Pipeline for an approximate 12 year term in exchange for a price resulting from arm’s length negotiations between us and Williams Partners and approved by the conflicts committee of the board of directors of the general partner of Williams Partners. We retain the option to request redelivery of products at the Mont Belvieu, Texas NGL hub for physical marketing.
 
In addition, through an agency agreement, we manage the jurisdictional merchant gas sales for Transcontinental Gas Pipe Line Company LLC (“Transco”), an indirect, wholly owned subsidiary of Williams Partners. We are authorized to make gas sales on Transco’s behalf in order to manage its gas purchase obligations. Although there is no exchange of payments between us and Transco for these transactions, we receive all margins associated with jurisdictional merchant gas sales business and, as Transco’s agent, assume all market and credit risk associated with such sales.
 
Gathering, Processing and Treating Contracts
 
We purchase gathering, processing and treating services from Williams Partners, primarily in the San Juan and Piceance Basins, under several contracts. We paid $163 million, $72 million and $44 million under these contracts for the years ended December 31, 2010, 2009 and 2008, respectively. The rates Williams Partners charges us to provide these services are comparable to those that Williams Partners charges to similarly-situated nonaffiliated customers.
 
In July 2011, we negotiated amendments to our existing gathering, processing and treating service contracts with Williams Partners in the San Juan and Piceance Basins, primarily to extend terms with

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corresponding adjustments in pricing resulting from arm’s length negotiations between us and Williams Partners and approved by the conflicts committee of the board of directors of the general partner of Williams Partners. The amended and restated gas gathering, processing, dehydrating and treating agreement related to our Piceance Basin production was filed as an exhibit to the registration statement of which this prospectus forms a part. That amended agreement adds life-of-lease high-recovery cryogenic processing for nearly all of the gas we produce in the Piceance Basin to the original agreement’s suite of basic midstream services. It reflects an adjustment in fees corresponding to the change in service and term and provides for future service expansions at market-clearing rates. We also entered into a new gathering contract with Williams Partners in the Marcellus Basin for fees resulting from arm’s length negotiations between us and Williams Partners and approved by the conflicts committee of the board of directors of the general partner of Williams Partners.
 
Transportation Contracts
 
We purchase natural gas transportation services from Williams Partners. Costs for these purchases were $25 million, $28 million and $34 million for the years ended December 31, 2010, 2009 and 2008, respectively. The rates Williams Partners charges us to provide these services are comparable to those that Williams Partners charges to similarly-situated nonaffiliated customers.
 
We have executed a capacity commitment of 135,000 MMBtu/d on Williams Partners’ Transco Northeast Supply Link, which is scheduled to be in-service in the fourth quarter of 2013. Construction of the Northeast Supply Link remains subject to regulatory approvals. The transportation rate for this firm capacity commitment is $0.59/MMbtu and represents a demand payment obligation of $436MM over the 15 year life of the project. The receipt point is Transco Station 517 and the delivery point is the New York City market area.
 
We manage a transportation capacity contract for Williams Partners. To the extent the transportation is not fully utilized or does not recover full-rate demand expense, Williams Partners reimburses us for these transportation costs. These reimbursements to us totaled approximately $9.8 million, $9.1 million and $10.9 million for the years ended December 31, 2010, 2009 and 2008, respectively.
 
Derivative Contracts
 
We periodically enter into derivative contracts with Williams Partners to hedge Williams Partners’ forecasted NGL sales and natural gas purchases. The revenues for these contracts were $14 million and $6 million for the years ended December 31, 2010 and 2009, respectively, and an expense of $3 million for the year ended December 31, 2008. We enter into offsetting derivative contracts with third parties at equivalent pricing and volumes.
 
Agreements Related to the Piceance Disposition
 
We entered into a contribution agreement and certain other agreements with Williams Partners that effected our sale to Williams Partners of certain gathering and processing assets in Colorado’s Piceance Basin (the “Piceance Disposition”). These agreements were the result of arm’s-length negotiations between Williams and the Conflicts Committee of the board of directors of the general partner Williams Partners, which is composed solely of independent directors unaffiliated with Williams.
 
Contribution Agreement.   On November 19, 2010, we closed the Piceance Disposition as contemplated by the contribution agreement. The Piceance Disposition was made in exchange for consideration of $702 million in cash and 1,849,138 Williams Partners common units. In March 2011, the Williams Partners common units we received in this transaction were distributed to Williams in a dividend.
 
Conveyance, Contribution, and Assumption Agreement.   In connection with the closing of the Piceance Disposition, the parties to the contribution agreement entered into a conveyance, contribution, and assumption agreement. This conveyance, contribution, and assumption agreement effected the contribution of the contributed interests from us to Williams Partners.
 
Piceance Omnibus Agreement.   Under an omnibus agreement entered into in connection with the Piceance Disposition, we are obligated to reimburse Williams Partners for (i) amounts incurred by Williams

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Partners for any costs required to complete the pipeline and compression projects known collectively as the Ryan Gulch Expansion Project, (ii) amounts incurred by Williams Partners prior to January 31, 2011 related to the development of a cryogenic processing arrangement with a subsidiary of ours, up to $20 million, and (iii) amounts incurred by Williams Partners for notice of violation or enforcement actions related to compression station land use permits or other losses, costs and expenses related certain surface lease use agreements. As of December 31, 2010, we paid obligations of Williams Partners related to the Ryan Gulch Expansion Project of $2.9 million. Williams Partners is obligated to reimburse us for any costs related to the pipeline and compression projects known collectively as the Kokopelli Expansion irrespective of whether those costs were incurred prior to the effective date of the Piceance Disposition. We received $432,000 in reimbursements for the Kokopelli Expansion for the year ended December 31, 2010.
 
Transition Services Agreement.   We provide transition services to Williams Partners related to the Piceance Disposition. As of December 31, 2010, we incurred expenses of $3 million for which we were reimbursed by Williams Partners pursuant to this agreement.
 
Meter Agency Agreements.   We have agreed to provide for the operation, calibration and maintenance of certain meters for the benefit of Williams Partners. It is anticipated that payments under these agreements will be approximately $275,000 in 2011.
 
Procedures for Review and Approval of Related Party Transactions
 
Our board of directors will adopt written procedures for approving related party transactions prior to the completion of this offering. Pursuant to these procedures, the members of our board of directors who are determined by the board to be both independent under applicable rules of the NYSE and independent from Williams (the “unaffiliated directors”) shall be responsible for reviewing and approving entry into any transaction with Williams or its affiliates. Our Audit Committee will be responsible for reviewing and approving entry into any other transactions with related persons (as defined in the regulations of the SEC), provided, however, that if such transaction involves a member of the board, it must be reviewed and approved by the full board. If it is impractical to convene an Audit Committee meeting before a related party transaction that is subject to Audit Committee approval occurs, the chair of the Audit Committee has the authority to review and approve the transaction. No director may participate in any review, consideration or approval of any related party transaction with respect to which such director or any of his or her immediate family members is the related person.
 
In considering related party transactions under their authority, the Audit Committee, the Audit Committee chair, the full board, or the unaffiliated directors, as the case may be (each such group being referred to herein as an “approving entity”), in good faith, may approve only those related person transactions that are in, or not inconsistent with, our best interests and the best interests of our stockholders. In conducting a review of whether a transaction is in, or is not inconsistent with, our best interests and those of our stockholders, the approving entity will consider the benefits of the transaction to us, the availability of other sources for comparable products or services, the terms of the transaction, the terms available to unrelated third parties and to employees generally, and the nature of the relationship between us and the related party, among other things. All related party transactions required to be disclosed in our filings with the SEC will be so disclosed in accordance with applicable laws, rules and regulations. The agreements with Williams described under the heading “Arrangements Between Williams and our Company” were approved by our board of directors in advance of this offering, prior to the adoption of these procedures.

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DESCRIPTION OF OUR CONCURRENT FINANCING TRANSACTIONS
 
Concurrent with or shortly following this offering, we expect that we will issue up to $1.5 billion in aggregate principal amount of senior unsecured notes and our senior unsecured credit facility will become effective. The following summary is a description of the principal terms of the Notes and the Credit Facility. This offering of our Class A common stock is not contingent upon the effectiveness of the Credit Facility or the completion of the Notes Offering.
 
Notes
 
We expect to offer and sell the Notes only to qualified institutional buyers in reliance on Rule 144A under the Securities Act and to certain non-U.S. persons in transactions outside the United States in reliance on Regulation S under the Securities Act. We do not expect to register the offer and sale of the Notes under the Securities Act and, as a result, the Notes may not be offered and sold in the United States absent registration or an applicable exemption from registration requirements. This prospectus shall not be deemed to be an offer to sell or a solicitation of an offer to buy the Notes.
 
We expect the Notes will bear interest at a fixed rate agreed to by us and the initial purchasers in the Notes Offering. In connection with the Notes Offering, we expect to enter into a registration rights agreement that will obligate us to file an exchange offer registration statement for the exchange of the Notes for a new issue of substantially identical debt securities, the issuance of which has been registered under the Securities Act, as evidence of the same underlying obligation of indebtedness.
 
Credit Facility
 
On June 3, 2011 we entered into a $1.5 billion, five-year senior unsecured revolving credit facility agreement. The Credit Facility may, under certain conditions, be increased by an additional $300 million. Funds may be borrowed under two methods of calculating interest: a fluctuating base rate equal to the lender’s base rate plus an applicable margin, or a periodic base rate equal to LIBOR plus an applicable margin. The applicable margin and the commitment fee are based on our senior unsecured long-term debt ratings. The Credit Facility contains various covenants consistent with like companies’ unsecured credit facilities, with similar credit ratings in the industry. These covenants limit, among other things, our and our subsidiaries’ ability to incur indebtedness, grant certain liens supporting indebtedness, merge or consolidate, sell all or substantially all of our assets, enter into certain affiliate transactions and allow any material change in the nature of our or our subsidiaries’ businesses. Significant financial covenants under the Credit Facility include:

 	•  	a ratio of Debt to Capitalization (as such terms will be defined in the Credit Facility) no greater than 60% for us and our consolidated subsidiaries as calculated at the end of each fiscal quarter; and	
 		
 	•  	if our senior unsecured debt rating at the time of this offering is below investment grade with a stable outlook, an additional covenant will require a minimum ratio of Net Present Value of Projected Future Cash Flows from Proved Reserves to Debt (as defined in the Credit Facility) for us and our consolidated subsidiaries as calculated at the end of each fiscal quarter. This covenant would fall away if and when an investment grade rating with a stable outlook is received.	
 
The Credit Facility includes customary events of default. If an event of default occurs under the Credit Facility, the lenders will be able to terminate the commitments and accelerate the maturity of any loans under the Credit Facility and exercise other rights and remedies.

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DESCRIPTION OF CAPITAL STOCK
 
The following is a description of the material terms of our capital stock as to be provided in our amended and restated certificate of incorporation and amended and restated bylaws, as each is anticipated to be in effect upon the completion of this offering. We also refer you to our amended and restated certificate of incorporation and amended and restated bylaws, copies of which are filed as exhibits to the registration statement of which this prospectus forms a part.
 
Authorized Capitalization

Following completion of this offering, our authorized capital stock will consist of (i) 1,875,000,000 shares of Class A common stock, par value $1.00 per share, (ii) 500,000,000 shares of Class B common stock, par value $1.00 per share and (iii) 100,000,000 shares of preferred stock, par value $1.00 per share.

Authorized but unissued shares of our capital stock may be used for a variety of corporate purposes, including future public offerings, to raise additional capital or to facilitate acquisitions. The Delaware General Corporation Law does not require stockholder approval for any issuance of authorized shares. However, the listing requirements of the NYSE, which would apply so long as our Class A common stock is listed on the NYSE, require stockholder approval of certain issuances equal to or exceeding 20% of the then outstanding voting power or then outstanding number of shares of Class A common stock.
 
Common Stock
 
Voting Rights
 
The holders of Class A common stock and Class B common stock generally have identical rights, except that holders of Class A common stock are entitled to one vote per share while holders of Class B common stock are entitled to ten votes per share on all matters to be voted on by stockholders. Holders of shares of Class A common stock and Class B common stock are not entitled to cumulate their votes in the election of directors. Generally, except as discussed in “—Anti-Takeover Effects of Certificate of Incorporation and Bylaws Provisions,” all matters to be voted on by stockholders must be approved by a majority of the total voting power of the Class A common stock and Class B common stock present in person or represented by proxy, voting together as a single class, at a meeting at which a quorum exists, subject to any voting rights granted to holders of any preferred stock. Except as otherwise provided by law or in the amended and restated certificate of incorporation (as further discussed in “—Anti-Takeover Effects of Certificate of Incorporation and Bylaws Provisions”), and subject to any voting rights granted to holders of any outstanding preferred stock, amendments to the amended and restated certificate of incorporation must be approved by a majority of the votes entitled to be cast by the holders of Class A common stock and Class B common stock, voting together as a single class. Any provision for the voluntary, mandatory and other conversion or exchange of the Class B common stock into or for Class A common stock on a one-for-one basis, whether by amendment to the amended and restated certificate of incorporation, will be deemed not to affect adversely the rights of the Class A common stock.
 
Dividends
 
Holders of Class A common stock and Class B common stock will share equally on a per share basis in any dividend declared by our board of directors, subject to any preferential rights of any outstanding shares of preferred stock. Dividends payable in shares of common stock may be paid only as follows:

 	•  	shares of Class A common stock may be paid only to holders of Class A common stock, and	
 		
 	•  	shares of Class B common stock may be paid only to holders of Class B common stock.	
 
The number of shares so paid will be equal on a per share basis with respect to each outstanding share of Class A common stock and Class B common stock.
 
We may not reclassify, subdivide or combine shares of either class of common stock without at the same time proportionally reclassifying, subdividing or combining shares of the other class.

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Conversion
 
Each share of Class B common stock is convertible at the option of the holder thereof into one share of Class A common stock. Williams has indicated that it intends to convert its Class B common shares to Class A common shares immediately prior to a spin-off of our common stock to Williams’ stockholders, assuming such conversion would not jeopardize the ability to consummate the tax-free spin-off or the tax-free treatment of any related restructuring transaction undertaken by Williams. In the event that Williams does not convert its Class B common shares to Class A common shares prior to such spin-off, then following any distribution of Class B common stock to Williams common stockholders in a transaction (including any distribution in exchange for Williams shares or securities) intended to qualify as a tax-free distribution under section 355 of the Code, or any corresponding provision of any successor statute (a “Tax-Free Spin-Off”), shares of Class B common stock will no longer be convertible into shares of Class A common stock.
 
Any shares of Class B common stock transferred to a person other than Williams or any of its affiliates will be converted automatically into shares of Class A common stock upon such transfer. To the extent that Williams does not convert its Class B common shares to Class A common shares prior to a Tax-Free Spin-Off, shares of Class B common stock transferred to stockholders of Williams in such Tax-Free Spin-Off will not be converted into shares of Class A common stock and, following a Tax-Free Spin-Off, shares of Class B common stock will be transferable as Class B common stock, subject to applicable laws.
 
All shares of Class B common stock will be converted automatically into Class A common stock if the number of outstanding shares of Class B common stock beneficially owned by Williams and its affiliates falls below 50% of the aggregate number of outstanding shares of our common stock. This automatic conversion of Class B common stock into Class A common stock will prevent Williams from decreasing its economic interest in our company to less than 50% while still retaining control of more than 80% of our voting power. All conversions will be effected on a one-for-one basis.
 
Other Rights
 
Unless approved by a majority of the votes entitled to be cast by the holders of each class of our common stock, voting separately as a class, in the event of any reorganization or consolidation of WPX with one or more corporations or a merger of WPX with another corporation in which shares of common stock are converted into or exchangeable for shares of stock, other securities or property (including cash), all holders of our common stock, regardless of class, will be entitled to receive the same kind and amount of shares of stock and other securities and property (including cash).
 
On liquidation, dissolution or winding up of WPX, after payment in full of the amounts required to be paid to holders of preferred stock, if any, all holders of common stock, regardless of class, are entitled to receive the same amount per share with respect to any distribution of assets to holders of shares of common stock.
 
No shares of either class of common stock are subject to redemption or have preemptive rights to purchase additional shares of our common stock or other securities.
 
Upon completion of this offering, all the outstanding shares of Class A common stock and Class B common stock will be validly issued, fully paid and nonassessable.
 
Preferred Stock
 
Our amended and restated certificate of incorporation authorizes our board of directors to establish one or more series of preferred stock. Unless required by law or by any stock exchange on which our common stock is listed, the authorized shares of preferred stock will be available for issuance without further action by you. Our board of directors is able to determine, with respect to any series of preferred stock, the terms and rights of that series, including the following:

 	•  	the designation of the series;	

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 	•  	the number of shares of the series, which our board may, except where otherwise provided in the preferred stock designation, increase or decrease, but not below the number of shares then outstanding;	
 		
 	•  	whether dividends, if any, will be cumulative or non-cumulative and the dividend rate of the series;	
 		
 	•  	the dates at which dividends, if any, will be payable;	
 		
 	•  	the redemption rights and price or prices, if any, for shares of the series;	
 		
 	•  	the terms and amounts of any sinking fund provided for the purchase or redemption of shares of the series;	
 		
 	•  	the amounts payable on shares of the series in the event of any voluntary or involuntary liquidation, dissolution or winding-up of the affairs of our company;	
 		
 	•  	whether the shares of the series will have conversion privileges and if so, the terms and conditions of such privileges, including provision for adjustment of the conversion rate, if any;	
 		
 	•  	restrictions on the issuance of shares of the same series or of any other class or series; and	
 		
 	•  	the voting rights, if any, of the holders of the series.	
 
Provisions of Amended and Restated Certificate of Incorporation Governing Corporate Opportunities
 
After the completion of this offering, Williams will remain a substantial stockholder of ours until it completes the spin-off of our stock to Williams’ stockholders or otherwise disposes of our common stock that it owns. We and Williams are engaged in similar activities or lines of business and have an interest in the same areas of corporate opportunities. Williams will not have a duty to refrain from engaging directly or indirectly in the same or similar business activities or lines of business as us, and to the fullest extent permitted by law, neither Williams nor any of its directors or officers will be liable to us or our stockholders for breach of any fiduciary duty, by reason of any such activities. Additionally, if Williams acquires knowledge of a potential transaction or matter that may be a corporate opportunity for Williams and us, to the fullest extent permitted by law, Williams will have no duty to communicate or offer such corporate opportunity to us and will not be liable to us or our stockholders for breach of any duty (fiduciary or otherwise) if Williams pursues or acquires such corporate opportunity for itself or directs such corporate opportunity to its affiliates. If any director or officer of Williams who is also one of our officers or directors becomes aware of a potential business opportunity, transaction or other matter (other than one expressly offered to that director or officer in writing solely in his or her capacity as our director or officer), that director or officer will have no duty to communicate or offer that opportunity to us, and will be permitted to communicate or offer that opportunity to Williams (or its affiliates) and that director or officer will not to the fullest extent permitted by law, be deemed to have (1) breached or acted in a manner inconsistent with or opposed to his or her fiduciary or other duties to us regarding the opportunity or (2) acted in bad faith or in a manner inconsistent with the best interests of our company or our stockholders. See “Risk Factors—Risks Related to Our Relationship with Williams—Pursuant to the terms of our amended and restated certificate of incorporation, Williams is not required to offer corporate opportunities to us, and certain of our directors and officers are permitted to offer certain corporate opportunities to Williams before us.”
 
The provisions in our amended and restated certificate of incorporation governing corporate opportunities between Williams and us will automatically terminate, expire and have no further force and effect once (1) Williams and its subsidiaries (excluding us and our subsidiaries) cease to beneficially own shares of capital stock representing 50% or more of the voting power of all then outstanding shares of our capital stock entitled to vote generally in the election of directors and (2) no person who is a director or officer of Williams is also a director or officer of ours. At that point, any such activities will be governed by Delaware law generally.

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Anti-Takeover Effects of Certificate of Incorporation and Bylaws Provisions
 
Some provisions of our amended and restated certificate of incorporation and amended and restated bylaws could make the following more difficult, although they have little significance while we are controlled by Williams:

 	•  	acquisition of us by means of a tender offer or merger;	
 		
 	•  	acquisition of us by means of a proxy contest or otherwise; or	
 		
 	•  	removal of our incumbent officers and directors.	
 
These provisions, summarized below, are expected to discourage coercive takeover practices and inadequate takeover bids. These provisions also are designed to encourage persons seeking to acquire control of us to first negotiate with our board of directors. We believe that the benefits of the potential ability to negotiate with the proponent of an unfriendly or unsolicited proposal to acquire or restructure our company outweigh the disadvantages of discouraging those proposals because negotiation of them could result in an improvement of their terms.
 
Classified Board
 
Our amended and restated certificate of incorporation provides that our board of directors is divided into three classes. The term of the first class of directors expires at our 2012 annual meeting of stockholders, the term of the second class of directors expires at our 2013 annual meeting of stockholders and the term of the third class of directors expires at our 2014 annual meeting of stockholders. At each of our annual meetings of stockholders, the successors of the class of directors whose term expires at that meeting of stockholders will be elected for a three-year term, one class being elected each year by our stockholders. This system of electing and removing directors may discourage a third party from making a tender offer or otherwise attempting to obtain control of us if Williams no longer controls us because it generally makes it more difficult for stockholders to replace a majority of our directors.
 
Election and Removal of Directors
 
A director nominee shall be elected to our board of directors if the votes cast for such nominee’s election exceed the votes cast against such nominee’s election.
 
Directors may be removed, with or without cause, by the affirmative vote of shares representing a majority of the votes entitled to be cast by the outstanding capital stock in the election of our board of directors as long as Williams owns shares representing at least a majority of the votes entitled to be cast by the outstanding capital stock in the election of our board of directors. Once Williams ceases to own shares representing at least a majority of the votes entitled to be cast by the outstanding capital stock in the election of our board of directors, our amended and restated certificate of incorporation requires that directors may only be removed for cause and only by the affirmative vote of not less than 75% of votes entitled to be cast by the outstanding capital stock in the election of our board of directors.
 
Size of Board and Vacancies
 
Our amended and restated certificate of incorporation provides that the number of directors on our board of directors will be fixed exclusively by our board of directors. Newly created directorships resulting from any increase in our authorized number of directors will be filled solely by the vote of our remaining directors in office. Any vacancies in our board of directors resulting from death, resignation, retirement, disqualification, removal from office or other cause will be filled solely by the vote of our remaining directors in office; provided, however, that as long as Williams continues to beneficially own shares representing at least a majority of the votes entitled to be cast by the outstanding capital stock in the election of our board of directors and such vacancy was caused by the action of stockholders, then such vacancy also may be filled by the affirmative vote of shares representing at least a majority of the votes entitled to be cast by the outstanding capital stock in the election of our board of directors.

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Stockholder Action by Written Consent
 
Our amended and restated certificate of incorporation permits our stockholders to act by written consent without a meeting as long as Williams continues to beneficially own shares representing at least a majority of the votes entitled to be cast by the outstanding capital stock in the election of our board of directors. Once Williams ceases to beneficially own at least a majority of the votes entitled to be cast by the outstanding capital stock in the election of our board of directors, our amended and restated certificate of incorporation eliminates the right of our stockholders to act by written consent.
 
Stockholder Meetings
 
Our amended and restated certificate of incorporation and amended and restated bylaws provide that a special meeting of our stockholders may be called only by (i) Williams, so long as it beneficially owns at least a majority of the votes entitled to be cast by the outstanding capital stock in the election of our board of directors, (ii) our board of directors, or (iii) the chairman of our board of directors with the concurrence of a majority of our board of directors.
 
Amendments to Certain Provisions of our Bylaws
 
Our amended and restated certificate of incorporation and amended and restated bylaws provide that the provisions of our bylaws relating to the calling of meetings of stockholders, notice of meetings of stockholders, stockholder action by written consent, advance notice of stockholder business or director nominations, the authorized number of directors, the classified board structure, the filling of director vacancies or the removal of directors (and any provision relating to the amendment of any of these provisions) may only be amended by the vote of a majority of our entire board of directors or, as long as Williams owns shares representing at least a majority of the votes entitled to be cast by the outstanding capital stock in the election of our board of directors, by the vote of holders of a majority of the votes entitled to be cast by outstanding capital stock in the election of our board of directors. Once Williams ceases to own shares representing at least a majority of the votes entitled to be cast by the outstanding capital stock in the election of our board of directors, our amended and restated certificate of incorporation and amended and restated bylaws provide that these provisions may only be amended by the vote of a majority of our entire board of directors or by the vote of holders of at least 75% of the votes entitled to be cast by the outstanding capital stock in the election of our board of directors.
 
Amendment of Certain Provisions of our Certificate of Incorporation
 
The amendment of any of the above provisions in our amended and restated certificate of incorporation requires approval by holders of shares representing at least a majority of the votes entitled to be cast by the outstanding capital stock in the election of our board of directors, as long as Williams owns shares representing at least a majority of the votes entitled to be cast by the outstanding capital stock in the election of our board of directors. Once Williams ceases to own shares representing at least a majority of the votes entitled to be cast by the outstanding capital stock in the election of our board of directors, our amended and restated certificate of incorporation and amended and restated bylaws provide that these provisions may only be amended by the vote of a majority of our entire board of directors followed by the vote of holders of at least 75% of the votes entitled to be cast by the outstanding capital stock in the election of our board of directors.
 
Requirements for Advance Notification of Stockholder Nominations and Proposals
 
Our amended and restated bylaws establish advance notice procedures with respect to stockholder proposals and nomination of candidates for election as directors other than nominations made by or at the direction of our board of directors or a committee of our board of directors.

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No Cumulative Voting
 
Our amended and restated certificate of incorporation and amended and restated bylaws do not provide for cumulative voting in the election of directors.
 
Undesignated Preferred Stock
 
The authorization of our undesignated preferred stock makes it possible for our board of directors to issue our preferred stock with voting or other rights or preferences that could impede the success of any attempt to change control of us. These and other provisions may have the effect of deferring hostile takeovers or delaying changes of control of our management.
 
Delaware Anti-Takeover Statute
 
For so long as Williams beneficially owns shares representing at least 15% of the votes entitled to be cast by the outstanding capital stock in the election of our board of directors, Section 203 of the Delaware General Corporation Law, which relates to business combinations with interested stockholders, shall not apply to us. Once Williams ceases to beneficially own shares representing at least 15% of the votes entitled to be cast by the outstanding capital stock in the election of our board of directors, Section 203 of the Delaware General Corporation Law will apply to us. Subject to specific exceptions, Section 203 prohibits a publicly held Delaware corporation from engaging in a “business combination” with an “interested stockholder” for a period of three years after the date of the transaction in which the person became an interested stockholder, unless:

 	•  	the “business combination,” or the transaction in which the stockholder became an “interested stockholder” is approved by the board of directors prior to the date the “interested stockholder” attained that status;	
 		
 	•  	upon completion of the transaction that resulted in the stockholder becoming an “interested stockholder,” the “interested stockholder” owned at least 85% of the voting stock of the corporation outstanding at the time the transaction commenced (excluding for purposes of determining the voting stock outstanding and not outstanding, voting stock owned by the interested stockholder, those shares owned by persons who are directors and also officers, and employee stock plans in which employee participants do not have the right to determine confidentiality whether shares held subject to the plan will be tendered in a tender or exchange offer); or	
 		
 	•  	on or subsequent to the date a person became an “interested stockholder,” the “business combination” is approved by the board of directors and authorized at an annual or special meeting of stockholders by the affirmative vote of at least two-thirds of the outstanding voting stock that is not owned by the “interested stockholder.”	
 
“Business combinations” include mergers, asset sales and other transactions resulting in a financial benefit to the “interested stockholder.” Subject to various exceptions, an “interested stockholder” is a person who, together with his or her affiliates and associates, owns, or within the previous three years did own, 15% or more of the corporation’s outstanding voting stock. These restrictions could prohibit or delay the accomplishment of mergers or other takeover or change in control attempts with respect to us and, therefore, may discourage attempts to acquire us.
 
Limitations on Liability and Indemnification of Officers and Directors
 
The Delaware General Corporation Law authorizes corporations to limit or eliminate the personal liability of directors to corporations and their stockholders for monetary damages for breaches of directors’ fiduciary duties. Under our amended and restated certificate of incorporation, subject to limitations imposed by the Delaware General Corporation Law, no director shall be personally liable to us or our stockholders for monetary damages for breach of fiduciary duty as a director, except for liability:

 	•  	for any breach of the director’s duty of loyalty to the corporation or its stockholders;	

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 	•  	for acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of law;	
 		
 	•  	pursuant to Section 174 of the Delaware General Corporation Law (providing for liability of directors for unlawful payment of dividends or unlawful stock purchases or redemptions); or	
 		
 	•  	for any transaction from which a director derived an improper personal benefit.	
 
Our amended and restated bylaws provide that we must indemnify our directors and officers to the fullest extent authorized by the Delaware General Corporation Law. We are also expressly authorized to advance certain expenses (including attorneys’ fees and disbursements and court costs) and carry directors’ and officers’ insurance providing indemnification for our directors, officers and certain employees for some liabilities. We believe that these indemnification provisions and insurance are useful to attract and retain qualified directors and executive officers. There is currently no pending material litigation or proceeding involving any of our directors, officers or employees for which indemnification is sought.
 
Transfer Agent and Registrar
 
Computershare Trust Company, N.A. will be the transfer agent and registrar for our Class A and Class B common stock.
 
Listing

Our Class A common stock has been approved for listing on the NYSE under the symbol “WPX.”

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SHARES ELIGIBLE FOR FUTURE SALE
 
Prior to this offering, there has not been any public market for our Class A common stock, and a significant public market for our Class A common stock may not develop or be sustained after this offering. We cannot predict what effect, if any, sales of shares of our Class A common stock or the availability of shares of our Class A common stock for sale will have on the prevailing market price of our Class A common stock from time to time. The number of shares of our Class A common stock available for future sale into the public markets is subject to legal and contractual restrictions, some of which are described below. The expiration of these restrictions will permit sales of substantial amounts of our Class A common stock in the public market or could create the perception that these sales could occur, which could adversely affect the market price for our Class A common stock and could make it more difficult for us to raise capital through the sale of our equity or equity-related securities at a time and price that we deem acceptable.
 
Upon the completion of this offering, we expect to have a total of           shares of our Class A common stock outstanding (           if the underwriters exercise their option to purchase additional Class A common shares in full). All of the shares of our Class A common stock sold in this offering will be freely tradable without restriction or further registration under the Securities Act, except for “restricted” shares held by persons who may be deemed our “affiliates,” as that term is defined under Rule 144 of the Securities Act. An “affiliate” is a person that directly, or indirectly through one or more intermediaries, controls or is controlled by us or is under common control with us.
 
Rule 144
 
In general, pursuant to Rule 144 under the Securities Act in effect on the date of this prospectus, once we have been subject to public company reporting requirements for at least 90 days, a person who is not one of our affiliates at any time during the 90 days preceding a sale and who has beneficially owned the shares of our Class A common stock to be sold for at least six months, including the holding period of any prior owner other than our affiliates, would be entitled to sell those shares without complying with the manner of sale, volume limitation or notice provisions of Rule 144, subject to compliance with the public information requirements of Rule 144. In addition, under Rule 144, a person who is not one of our affiliates at any time during the 90 days preceding a sale, and who has beneficially owned the shares of our Class A common stock to be sold for at least one year, including the holding period of any prior owner other than our affiliates, would be entitled to sell those shares without regard to the requirements of Rule 144. Our affiliates or persons selling on behalf of our affiliates are entitled to sell, upon expiration of the lock-up agreements described below, within any three-month period beginning 90 days after the date of this prospectus, a number of shares that does not exceed the greater of:

 	•  	1.0% of the number of shares of Class A common stock then outstanding, which is approximately           (           if the underwriters exercise their option to purchase additional Class A common shares in full) shares of Class A common stock upon the completion of this offering; and	
 		
 	•  	the average weekly trading volume of our Class A common stock on the NYSE during the four calendar weeks preceding each such sale, subject to certain restrictions.	
 
Sales under Rule 144 by our affiliates or persons selling on behalf of our affiliates are also subject to manner of sale provisions and notice requirements and to the availability of current public information about us. Rule 144 also provides that affiliates relying on Rule 144 to sell shares of our Class A common stock that are not restricted shares must nonetheless comply with the same restrictions applicable to restricted shares, other than the holding period requirement.
 
Lock-up Agreements
 
We, our directors, certain of our officers and Williams have agreed with the underwriters not to sell or otherwise transfer or dispose of any shares of our common stock, subject to specified exceptions, during the period from the date of this prospectus continuing through the date that is 180 days after the date of this prospectus, subject to an extension in certain circumstances, except with the prior written consent of Barclays

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Capital Inc. and except that 120 days after the date of this prospectus, Williams will be permitted to spin-off all of our shares of common stock that it owns to its stockholders as described below under “—Spin-off.” See “Underwriting” for a description of these provisions.
 
Shares Issued Under Employee Plans
 
We intend to file a registration statement on Form S-8 under the Securities Act to register Class A common stock issuable under our employee plans. This registration statement is expected to be filed following the effective date of the registration statement of which this prospectus is a part and will be effective upon filing. Accordingly, shares registered under such registration statement will be available for sale in the public market following the effective date, unless such shares are subject to vesting restrictions with us, Rule 144 restrictions applicable to our affiliates, or the lock-up agreements described above.
 
Registration Rights
 
After the completion of this offering, Williams will be entitled to certain rights with respect to the registration under the Securities Act of our common stock that it owns, under the terms of a registration rights agreement between us and Williams. See “Arrangements Between Williams and Our Company—Registration Rights Agreement.”
 
Spin-off
 
Williams has advised us that, following the completion of this offering, it intends to distribute all of the shares of our common stock that it owns through a tax-free distribution, or spin-off, to Williams’ stockholders. The determination of whether, and if so, when, to proceed with the spin-off is entirely within the discretion of Williams, although Williams has indicated its intention to complete the spin-off in 2012 and to convert its Class B common shares to Class A common shares immediately prior to such spin-off, assuming such conversion would not jeopardize the ability to consummate the tax-free distribution or the tax-free treatment of any related restructuring transaction undertaken by Williams. Williams has the sole discretion to determine the form, the structure and all other terms of any transactions to effect the spin-off. Williams will not effect the spin-off unless Williams has obtained a private letter ruling from the IRS and an opinion of its outside tax advisor, in either case reasonably acceptable to the Williams board of directors, to the effect that the distribution by Williams of the shares of our common stock held by Williams after the offering will qualify for U.S. federal income tax purposes as a tax-free transaction under section 355 and section 368(a)(1)(D) of the Code. Williams may decide not to complete the spin-off if, at any time, Williams’ board of directors determines, in its sole discretion, that the spin-off is not in the best interests of Williams or its stockholders. Common stock distributed to Williams’ stockholders in the spin-off transaction generally would be freely transferable, except for common stock received by persons who may be deemed to be our affiliates or otherwise subject to the lock-up agreements described above and under “Underwriting.”

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CERTAIN U.S. FEDERAL INCOME TAX CONSIDERATIONS
 
The following is a summary of the material U.S. federal income tax considerations relating to the purchase, ownership and disposition of the shares of our Class A common stock, as of the date hereof. This summary deals only with shares of our Class A common stock purchased in this offering for cash and held as capital assets. Additionally, this summary does not deal with special situations. For example, this summary does not address:

 	•  	tax consequences to holders who may be subject to special tax treatment, such as dealers in securities or currencies, financial institutions, regulated investment companies, real estate investment trusts, expatriates, tax-exempt entities, traders in securities that elect to use a mark-to-market method of accounting for their securities or insurance companies;	
 		
 	•  	tax consequences to persons holding shares of our Class A common stock as part of a hedging, integrated, or conversion transaction or a straddle or persons deemed to sell shares of our Class A common stock under the constructive sale provisions of the Code;	
 		
 	•  	tax consequences to persons who at any time hold more than 5% of the total fair market value of any class of our stock;	
 		
 	•  	tax consequences to U.S. holders of shares of our Class A common stock whose “functional currency” is not the U.S. dollar;	
 		
 	•  	tax consequences to partnerships or other pass-through entities and investors in such entities; or	
 		
 	•  	alternative minimum tax consequences, if any.	
 
Finally, this summary does not address U.S. federal tax consequences other than income taxes (such as estate and gift tax consequences) or any state, local or foreign tax consequences.
 
The discussion below is based upon the provisions of the Code, and U.S. Treasury regulations, rulings and judicial decisions as of the date hereof. Those authorities may be changed, perhaps retroactively, so as to result in U.S. federal income tax consequences different from those discussed below. This summary does not address all aspects of U.S. federal income taxation and does not deal with all tax consequences that may be relevant to holders in light of their personal circumstances.
 
If a partnership holds shares of our Class A common stock, the tax treatment of a partner in the partnership will generally depend upon the status of the partner and the activities of the partnership. If you are a partner of a partnership holding shares of our Class A common stock, you should consult your tax advisor.
 
If you are considering the purchase of shares of our Class A common stock, you should consult your own tax advisors concerning the U.S. federal income tax consequences to you in light of your particular facts and circumstances and any consequences arising under the laws of any state, local, foreign or other taxing jurisdiction.
 
Consequences to U.S. Holders
 
The following is a summary of the U.S. federal income tax consequences that will apply to a U.S. holder of shares of our Class A common stock. “U.S. holder” means a beneficial owner of common stock for U.S. federal income tax purposes that is:

 	•  	an individual citizen or resident of the United States;	
 		
 	•  	a corporation (or any other entity treated as a corporation for U.S. federal income tax purposes) created or organized in or under the laws of the United States, any state thereof or the District of Columbia;	
 		
 	•  	an estate the income of which is subject to U.S. federal income taxation regardless of its source; or	

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 	•  	a trust if (1) it is subject to the primary supervision of a court within the United States and one or more U.S. persons have the authority to control all substantial decisions of the trust, or (2) it has a valid election in effect under applicable U.S. Treasury regulations to be treated as a U.S. person.	
 
Distributions
 
A distribution in respect of shares of our Class A common stock generally will be treated as a dividend to the extent it is paid from current or accumulated earnings and profits. If the distribution exceeds current and accumulated earnings and profits, the excess will be treated as a nontaxable return of capital reducing the U.S. holder’s tax basis in the Class A common stock to the extent of the U.S. holder’s tax basis in that stock. Any remaining excess will be treated as capital gain. Subject to certain holding period requirements and exceptions, dividends received by individual holders generally will be subject to a reduced maximum tax rate of 15% for qualified dividend income through December 31, 2012, after which the rate applicable to dividends is scheduled to return to the tax rate generally applicable to ordinary income. If a U.S. holder is a U.S. corporation, it may be eligible to claim the deduction allowed to U.S. corporations in respect of dividends received from other U.S. corporations equal to a portion of any dividends received, subject to generally applicable limitations on that deduction.
 
U.S. holders should consult their tax advisors regarding the holding period and other requirements that must be satisfied in order to qualify for the dividends-received deduction and the reduced maximum tax rate for qualified dividend income.
 
Sale, Exchange, Redemption or Certain Other Taxable Dispositions of our Class A Common Stock
 
A U.S. holder will generally recognize capital gain or loss on a sale, exchange, redemption (provided the redemption is treated as a sale or exchange) or certain other taxable dispositions of our Class A common stock. The U.S. holder’s gain or loss will equal the difference between the amount realized by the U.S. holder and the U.S. holder’s tax basis in the stock. The amount realized by the U.S. holder will include the amount of any cash and the fair market value of any other property received for the stock. Gain or loss recognized by a U.S. holder on a sale or exchange of stock will be long-term capital gain or loss if the holder held the stock for more than one year. Long-term capital gains of non-corporate taxpayers are generally taxed at lower rates than those applicable to ordinary income. The deductibility of capital losses is subject to certain limitations.
 
Information Reporting and Backup Withholding
 
When required, we or our paying agent will report to the holders of our Class A common stock and to the IRS amounts paid on or with respect to the Class A common stock during each calendar year and the amount of tax, if any, withheld from such payments. A U.S. holder will be subject to backup withholding on any dividends paid on our Class A common stock and proceeds from the sale of our Class A common stock at the applicable rate if the U.S. holder (a) fails to provide us or our paying agent with a correct taxpayer identification number or certification of exempt status, (b) has been notified by the IRS that it is subject to backup withholding as a result of the failure to properly report payments of interest or dividends, or (c) in certain circumstances, has failed to certify under penalty of perjury that it is not subject to backup withholding. A U.S. holder may be eligible for an exemption from backup withholding by providing a properly completed IRS Form W-9 to us or our paying agent. Any amounts withheld under the backup withholding rules will generally be allowed as a refund or a credit against a U.S. holder’s U.S. federal income tax liability provided the required information is properly furnished to the IRS by the U.S. holder on a timely basis.
 
Consequences to Non-U.S. Holders
 
The following is a summary of the U.S. federal income tax consequences that will apply to you if you are a non-U.S. holder of shares of our Class A common stock. The term “non-U.S. holder” means a beneficial owner of shares of common stock that is, for U.S. federal income tax purposes, an individual, corporation, trust or estate that is not a U.S. holder. Special rules may apply to certain non-U.S. holders such as “controlled

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foreign corporations” or “passive foreign investment companies.” Such entities should consult their own tax advisors to determine the U.S. federal, state, local and other tax consequences that may be relevant to them.
 
Distributions
 
Any dividends paid to a non-U.S. holder with respect to the shares of our Class A common stock will be subject to withholding tax at a 30% rate or such lower rate as specified by an applicable income tax treaty. However, dividends that are effectively connected with the conduct of a trade or business within the United States and, where an applicable tax treaty so provides, are attributable to a U.S. permanent establishment, are not subject to the withholding tax, but instead are subject to U.S. federal income tax on a net income basis at applicable graduated individual or corporate rates. Certain certification and disclosure requirements must be complied with in order for effectively connected income to be exempt from withholding. Any such effectively connected dividends received by a foreign corporation may, under certain circumstances, be subject to an additional branch profits tax at a 30% rate or such lower rate as specified by an applicable income tax treaty.
 
A non-U.S. holder of shares of our Class A common stock who wishes to claim the benefit of an applicable treaty rate is required to satisfy applicable certification and other requirements. If a non-U.S. holder is eligible for a reduced rate of U.S. withholding tax pursuant to an income tax treaty, the holder may obtain a refund of any excess amounts withheld by timely filing an appropriate claim for refund with the IRS.
 
Sale, Exchange, Redemption or Other Taxable Disposition of our Class A Common Stock
 
Any gain realized by a non-U.S. holder upon the sale, exchange, redemption (provided the redemption is treated as a sale or exchange) or other taxable disposition of shares of our Class A common stock will not be subject to U.S. federal income tax with respect to such gain unless:

 	•  	that gain is effectively connected with the conduct of a trade or business in the United States (and, if required by an applicable income tax treaty, is attributable to a U.S. permanent establishment);	
 		
 	•  	the non-U.S. holder is an individual who is present in the United States for 183 days or more in the taxable year of that disposition, and certain other conditions are met; or	
 		
 	•  	our Class A common stock constitutes a U.S. real property interest by reason of our status as a “U.S. real property holding corporation” (a “USRPHC”) for U.S. federal income tax purposes at any time within the shorter of the five-year period preceding the disposition or the period that the non-U.S. holder held our Class A common stock.	
 
A non-U.S. holder described in the first bullet point above will be subject to U.S. federal income tax on the net gain derived from the sale in the same manner as a U.S. holder. If a non-U.S. holder is eligible for the benefits of a tax treaty between the United States and its country of residence, any such gain will be subject to U.S. federal income tax in the manner specified by the treaty. To claim the benefit of a treaty, a non-U.S. holder must properly submit an IRS Form W-8BEN (or suitable successor or substitute form). A non-U.S. holder that is a foreign corporation and is described in the first bullet point above will be subject to tax on gain under regular graduated U.S. federal income tax rates and, in addition, may be subject to a branch profits tax at a 30% rate or a lower rate if so specified by an applicable income tax treaty. An individual non-U.S. holder described in the second bullet point above will be subject to a flat 30% U.S. federal income tax on the gain derived from the sale, which may be offset by U.S. source capital losses.
 
With regard to the third bullet point above, generally, a corporation is a USRPHC if the fair market value of its United States real property interests equals or exceeds 50% of the sum of the fair market value of its worldwide real property interests and its other assets used or held for use in a trade or business. We expect to be a USRPHC for U.S. federal income tax purposes. However, even if we are or become a USRPHC, our Class A common stock will be treated as a U.S. real property interest only if the non-U.S. holder actually or constructively holds more than 5% of our Class A common stock at any time during the holding period described above, provided that our Class A common stock does not cease to be regularly traded on an established securities market prior to the year in which the sale occurs. Any taxable gain generally would be taxed in the same manner as gain that is effectively connected with the conduct of a trade or business in the

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United States, except that the branch profits tax will not apply. Non-U.S. holders should consult their own advisors about the consequences that could result if we are, or become, a USRPHC.
 
Information Reporting and Backup Withholding
 
Generally, we must report to the IRS and to non-U.S. holders the amount of dividends paid to the holder and the amount of tax, if any, withheld with respect to those payments. Copies of the information returns reporting such dividend payments and any withholding may also be made available to the tax authorities in the country in which the holder resides under the provisions of an applicable income tax treaty.
 
In general, a non-U.S. holder will not be subject to backup withholding with respect to payments of dividends that we make to the holder if the non-U.S. holder certifies under penalty of perjury that it is a non-U.S. holder or otherwise establishes an exemption. A non-U.S. holder will be subject to information reporting and, depending on the circumstances, backup withholding with respect to the proceeds of the sale or other disposition of shares of our Class A common stock within the United States or conducted through certain U.S.-related payors, unless the payor of the proceeds receives the statement described above or the holder otherwise establishes an exemption.
 
Any amounts withheld under the backup withholding rules will be allowed as a refund or a credit against a holder’s U.S. federal income tax liability provided the required information is furnished to the IRS.
 
New Legislation Relating to Foreign Accounts
 
Newly enacted legislation may impose withholding taxes on certain types of payments made to “foreign financial institutions” and certain other non-U.S. entities after December 31, 2012. The legislation imposes a 30% withholding tax on dividends on, or gross proceeds from the sale or other disposition of, common stock paid to a foreign financial institution unless the foreign financial institution enters into an agreement with the U.S. Treasury to, among other things, undertake to identify accounts held by certain U.S. persons or U.S.-owned foreign entities, annually report certain information about such accounts, and withhold 30% on payments to account holders whose actions prevent it from complying with these reporting and other requirements. In addition, the legislation imposes a 30% withholding tax on the same types of payments to a foreign non-financial entity unless the entity certifies that it does not have any substantial U.S. owners or furnishes identifying information regarding each substantial U.S. owner. Prospective investors should consult their tax advisors regarding the effect of this legislation, if any, on their ownership and disposition of the shares of our Class A common stock.
 
Health Care Education and Reconciliation Act of 2010
 
On March 30, 2010, President Obama signed into law the Health Care Education and Reconciliation Act of 2010, which requires certain United States persons who are individuals, estates or trusts to pay a 3.8% tax on, among other things, dividends and capital gains from the sale, exchange, redemption or other taxable disposition of equity investments, including common stock, for taxable years beginning after December 31, 2012. Prospective investors should consult their tax advisors regarding the effect, if any, of this legislation on their ownership and disposition of the shares of our Class A common stock.

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UNDERWRITING
 
Barclays Capital Inc., Citigroup Global Markets Inc., J.P. Morgan Securities LLC and Merrill Lynch, Pierce, Fenner & Smith Incorporated are acting as representatives of the underwriters and joint book-running managers of this offering. Under the terms of an underwriting agreement, which will be filed as an exhibit to the registration statement, each of the underwriters named below has severally agreed to purchase from us the respective number of Class A common stock shown opposite its name below:

 	 	Number of	 	
Underwriters	 	Shares	 	
 		
Barclays Capital Inc. 	 	 	 	 	
Citigroup Global Markets Inc. 	 	 	 	 	
J.P. Morgan Securities LLC	 	 	       	 	
Merrill Lynch, Pierce, Fenner & Smith
Incorporated	 	 	 	 	
Deutsche Bank Securities Inc. 	 	 	 	 	
Goldman, Sachs & Co. 	 	 	 	 	
Morgan Stanley & Co. LLC.	 	 	 	 	
Wells Fargo Securities, LLC	 	 	 	 	
Credit Suisse Securities (USA) LLC	 	 	 	 	
RBC Capital Markets, LLC	 	 	 	 	
Scotia Capital (USA) Inc. 	 	 	 	 	
UBS Securities LLC	 	 	 	 	
Howard Weil Incorporated	 	 	 	 	
 	 	 	 	 	
Total	 	 	 	 	

 
The underwriting agreement provides that the underwriters’ obligation to purchase shares of Class A common stock depends on the satisfaction of the conditions contained in the underwriting agreement including:

 	•  	the obligation to purchase all of the shares of Class A common stock offered hereby (other than those shares of Class A common stock covered by their option to purchase additional shares as described below), if any of the shares are purchased;	
 		
 	•  	the representations and warranties made by us to the underwriters are true;	
 		
 	•  	there is no material change in our business or the financial markets; and	
 		
 	•  	we deliver customary closing documents to the underwriters.	
 
Commissions and Expenses
 
The following table summarizes the underwriting discounts and commissions we will pay to the underwriters. These amounts are shown assuming both no exercise and full exercise of the underwriters’ option to purchase additional shares. The underwriting fee is the difference between the initial price to the public and the amount the underwriters pay to us for the shares.

 	 	No Exercise	 	 	Full Exercise	 	
 		
Per share	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	
Total	 	 	       	 	 	 	       	 	

 
The representatives of the underwriters have advised us that the underwriters propose to offer the shares of Class A common stock directly to the public at the public offering price on the cover of this prospectus and to selected dealers, which may include the underwriters, at such offering price less a selling concession not in

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excess of $      per share. After the offering, the representatives may change the offering price and other selling terms. Sales of shares made outside of the United States may be made by affiliates of the underwriters.

The expenses of the offering that are payable by us are estimated to be approximately $4.7 million (excluding underwriting discounts and commissions). The offering of the shares by the underwriters is subject to receipt and acceptance and subject to the underwriters’ right to reject any order in whole or in part.

Option to Purchase Additional Shares
 
We have granted the underwriters an option exercisable for 30 days after the date of the underwriting agreement, to purchase, from time to time, in whole or in part, up to an aggregate of           shares at the public offering price less underwriting discounts and commissions. This option may be exercised if the underwriters sell more than           shares in connection with this offering. To the extent that this option is exercised, each underwriter will be obligated, subject to certain conditions, to purchase its pro rata portion of these additional shares based on the underwriter’s underwriting commitment in the offering as indicated in the table at the beginning of this Underwriting section. Any shares of Class A common stock issued pursuant to this option will not increase the total number of shares of common stock outstanding after this offering, but rather the number of shares of Class B common stock owned by Williams will be reduced share for share by the number of shares of Class A common stock issued pursuant to such option, thus reducing Williams’ ownership interest in us. We will distribute the net proceeds from the sale of shares of Class A common stock pursuant to this option to Williams as part of our restructuring transactions. Williams is deemed to be an underwriter with respect to any shares of Class A common stock issued pursuant to this option.
 
Lock-Up Agreements
 
We, our directors, certain of our officers and Williams have agreed that, subject to certain exceptions, without the prior written consent of Barclays Capital Inc., we and they will not directly or indirectly, (1) offer for sale, sell, pledge, or otherwise dispose of (or enter into any transaction or device that is designed to, or could be expected to, result in the disposition by any person at any time in the future of) any shares of Class A common stock (including, without limitation, shares of Class A common stock that may be deemed to be beneficially owned by us or them in accordance with the rules and regulations of the SEC and shares of Class A common stock that may be issued upon exercise of any options or warrants) or securities convertible into or exercisable or exchangeable for Class A common stock, (2) enter into any swap or other derivatives transaction that transfers to another, in whole or in part, any of the economic consequences of ownership of the Class A common stock, (3) make any demand for or exercise any right or file or cause to be filed a registration statement, including any amendments thereto, with respect to the registration of any shares of Class A common stock or securities convertible, exercisable or exchangeable into Class A common stock or any of our other securities, or (4) publicly disclose the intention to do any of the foregoing for a period of 180 days after the date of this prospectus, except that 120 days after the date of this prospectus, Williams will be permitted to spin-off all of our shares of common stock that it owns to its stockholders.
 
The 180-day restricted period described in the preceding paragraph will be extended if:

 	•  	during the last 17 days of the 180-day restricted period we issue an earnings release or material news or a material event relating to us occurs; or	
 		
 	•  	prior to the expiration of the 180-day restricted period, we announce that we will release earnings results during the 16-day period beginning on the last day of the 180-day period,	
 
in which case the restrictions described in the preceding paragraph will continue to apply until the expiration of the 18-day period beginning on the issuance of the earnings release or the announcement of the material news or occurrence of a material event, unless such extension is waived in writing by Barclays Capital Inc.
 
Barclays Capital Inc., in its sole discretion, may release the Class A common stock and other securities subject to the lock-up agreements described above in whole or in part at any time with or without notice. When determining whether or not to release Class A common stock and other securities from lock-up agreements, Barclays Capital Inc. will consider, among other factors, the holder’s reasons for requesting the

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release, the number of shares of Class A common stock and other securities for which the release is being requested and market conditions at the time.
 
Directed Share Program
 
At our request, the underwriters have reserved for sale at the initial public offering price up to     shares of our Class A common stock offered hereby for officers, directors, employees and certain other persons associated with us. The number of Class A shares available for sale to the general public will be reduced to the extent such persons purchase such reserved shares. Any reserved shares not so purchased will be offered by the underwriters to the general public on the same basis as the other shares of our Class A common stock offered hereby. Any participants in this program shall be prohibited from selling, pledging or assigning any shares sold to them pursuant to this program for a period of 180 days after the date of this prospectus. This 180-day lock up period shall be extended with respect to our issuance of an earnings release or if a material news or a material event relating to us occurs, in the same manner as described above under “— Lock-Up Agreements.”
 
Offering Price Determination
 
Prior to this offering, there has been no public market for our Class A common stock. The initial public offering price will be negotiated between the representatives and us. In determining the initial public offering price of our Class A common stock, the representatives will consider:

 	•  	the history and prospects for the industry in which we compete;	
 		
 	•  	our financial information;	
 		
 	•  	the ability of our management and our business potential and earning prospects;	
 		
 	•  	the prevailing securities markets at the time of this offering; and	
 		
 	•  	the recent market prices of, and the demand for, publicly traded shares of generally comparable companies.	
 
Indemnification
 
We have agreed to indemnify the several underwriters against certain liabilities, including liabilities under the Securities Act, and to contribute to payments that the underwriters may be required to make for these liabilities.
 
Stabilization, Short Positions and Penalty Bids
 
The representatives may engage in stabilizing transactions, short sales and purchases to cover positions created by short sales, and penalty bids or purchases for the purpose of pegging, fixing or maintaining the price of the Class A common stock, in accordance with Regulation M under the Exchange Act:

 	•  	Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum.	

			
 	•  	A short position involves a sale by the underwriters of shares in excess of the number of shares the underwriters are obligated to purchase in the offering, which creates the syndicate short position. This short position may be either a covered short position or a naked short position. In a covered short position, the number of shares involved in the sales made by the underwriters in excess of the number of shares they are obligated to purchase is not greater than the number of shares that they may purchase by exercising their option to purchase additional shares. In a naked short position, the number of shares involved is greater than the number of shares in their option to purchase additional shares. The underwriters may close out any short position by either exercising their option to purchase additional shares and/or purchasing shares in the open market. In determining the source of shares to close out the short position, the underwriters will consider, among other things, the price of shares available for purchase in the open market as compared to the price at which they may purchase shares through their option to purchase additional shares. A naked short position is more likely to be created	

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 		if the underwriters are concerned that there could be downward pressure on the price of the shares in the open market after pricing that could adversely affect investors who purchase in the offering.	

			
 	•  	Syndicate covering transactions involve purchases of the Class A common stock in the open market after the distribution has been completed in order to cover syndicate short positions.	
 		
 	•  	Penalty bids permit the representatives to reclaim a selling concession from a syndicate member when the Class A common stock originally sold by the syndicate member is purchased in a stabilizing or syndicate covering transaction to cover syndicate short positions.	
 
These stabilizing transactions, syndicate covering transactions and penalty bids may have the effect of raising or maintaining the market price of our Class A common stock or preventing or retarding a decline in the market price of the Class A common stock. As a result, the price of the Class A common stock may be higher than the price that might otherwise exist in the open market. These transactions may be effected on the NYSE or otherwise and, if commenced, may be discontinued at any time.
 
Neither we nor any of the underwriters make any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of the Class A common stock. In addition, neither we nor any of the underwriters make representation that the representatives will engage in these stabilizing transactions or that any transaction, once commenced, will not be discontinued without notice.
 
Electronic Distribution
 
A prospectus in electronic format may be made available on the Internet sites or through other online services maintained by one or more of the underwriters and/or selling group members participating in this offering, or by their affiliates. In those cases, prospective investors may view offering terms online and, depending upon the particular underwriter or selling group member, prospective investors may be allowed to place orders online. The underwriters may agree with us to allocate a specific number of shares for sale to online brokerage account holders. Any such allocation for online distributions will be made by the representatives on the same basis as other allocations.
 
Other than the prospectus in electronic format, the information on any underwriter’s or selling group member’s web site and any information contained in any other web site maintained by an underwriter or selling group member is not part of the prospectus or the registration statement of which this prospectus forms a part, has not been approved and/or endorsed by us or any underwriter or selling group member in its capacity as underwriter or selling group member and should not be relied upon by investors.
 
New York Stock Exchange

We have been approved to list our shares of Class A common stock on the NYSE under the symbol “WPX.” In connection with that listing, the underwriters will undertake to sell the minimum number of Class A common shares to the minimum number of beneficial owners necessary to meet the NYSE listing requirements.

Discretionary Sales
 
The underwriters have informed us that they do not intend to confirm sales to discretionary accounts that exceed 5% of the total number of shares offered by them.
 
Stamp Taxes
 
If you purchase shares of Class A common stock offered in this prospectus, you may be required to pay stamp taxes and other charges under the laws and practices of the country of purchase, in addition to the offering price listed on the cover page of this prospectus.

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Relationships

The underwriters and their respective affiliates are full service financial institutions engaged in various activities, which may include securities trading, commercial and investment banking, financial advisory, investment management, investment research, principal investment, hedging, financing and brokerage activities. Certain of the underwriters and their respective affiliates have, from time to time, performed, are currently performing, and may in the future perform, various financial advisory and investment banking services for us or for Williams, for which they may receive customary fees and expenses. For instance, affiliates of the underwriters are lenders, and in some cases agents or managers for the lenders, under our Credit Facility. An affiliate of Citigroup Global Markets Inc. is the administrative agent, Barclays Capital Inc., Citigroup Global Markets Inc., J.P. Morgan Securities LLC and Merrill Lynch, Pierce, Fenner & Smith Incorporated are the joint lead arrangers and joint bookrunners, and Barclays Capital Inc., J.P. Morgan Securities LLC and an affiliate of Merrill Lynch, Pierce, Fenner & Smith Incorporated are the co-syndication agents under our Credit Facility.

In the ordinary course of business, the underwriters and their respective affiliates may make or hold a broad array of investments, including serving as counterparties to certain derivative and hedging arrangements, and actively trade debt and equity securities (or related derivative securities) and financial instruments (including bank loans) for their own account and for the accounts of their customers, and such investment and securities activities may involve securities and/or instruments of us or Williams. The underwriters and their respective affiliates may also make investment recommendations and/or publish or express independent research views in respect of such securities or instruments and may at any time hold, or recommend to clients that they acquire, long and/or short positions in such securities and instruments.

FINRA

 
Prior to this offering, Williams entered into certain separate engagements with Barclays Capital Inc. and Citigroup Global Markets Inc. under which Barclays Capital Inc. and Citigroup Global Markets Inc. agreed to provide financial advisory services in connection with certain strategic transactions and Williams granted a “right of first refusal” pursuant to which it agreed to offer to Barclays Capital Inc. and Citigroup Global Markets Inc. the right to participate in certain future financings related to such engagements. This “right of first refusal” is considered to be an item of value in connection with this offering pursuant to FINRA Rule 5110 and has a deemed compensation value of one percent of the offering proceeds of this offering.

Selling Restrictions
 
European Economic Area
 
In relation to each member state of the European Economic Area which has implemented the Prospectus Directive (each, a “Relevant Member State”), including each Relevant Member State that has implemented the 2010 PD Amending Directive with regard to persons to whom an offer of securities is addressed and the denomination per unit of the offer of securities (each, an “Early Implementing Member State”), with effect from and including the date on which the Prospectus Directive is implemented in that Relevant Member State (the “Relevant Implementation Date”), no offer of shares will be made to the public in that Relevant Member State (other than offers (the “Permitted Public Offers”) where a prospectus will be published in relation to the shares that has been approved by the competent authority in a Relevant Member State or, where appropriate, approved in another Relevant Member State and notified to the competent authority in that Relevant Member State, all in accordance with the Prospectus Directive), except that with effect from and including that Relevant Implementation Date, offers of shares may be made to the public in that Relevant Member State at any time:

 	(a)  	to “qualified investors” as defined in the Prospectus Directive, including:	

 	(i)  	(in the case of Relevant Member States other than Early Implementing Member States), legal entities which are authorized or regulated to operate in the financial markets or, if not so authorized or regulated, whose corporate purpose is solely to invest in securities, or any legal entity which has two or more of (i) an average of at least 250 employees during the last financial year; (ii) a total balance sheet of more than €43.0 million and (iii) an annual turnover of more than €50.0 million as shown in its last annual or consolidated accounts; or	

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 	(ii)  	(in the case of Early Implementing Member States), persons or entities that are described in points (1) to (4) of Section I of Annex II to Directive 2004/39/EC, and those who are treated on request as professional clients in accordance with Annex II to Directive 2004/39/EC, or recognized as eligible counterparties in accordance with Article 24 of Directive 2004/39/EC unless they have requested that they be treated as non-professional clients;	

 	(b)  	to fewer than 100 (or, in the case of Early Implementing Member States, 150) natural or legal persons (other than “qualified investors” as defined in the Prospectus Directive), as permitted in the Prospectus Directive, subject to obtaining the prior consent of the representatives for any such offer; or	

 	(c)  	in any other circumstances falling within Article 3(2) of the Prospectus Directive,	
 
provided that no such offer of shares shall result in a requirement for the publication of a prospectus pursuant to Article 3 of the Prospectus Directive or of a supplement to a prospectus pursuant to Article 16 of the Prospectus Directive.
 
Each person in a Relevant Member State (other than a Relevant Member State where there is a Permitted Public Offer) who initially acquires any shares or to whom any offer is made will be deemed to have represented, acknowledged and agreed that (A) it is a “qualified investor”, and (B) in the case of any shares acquired by it as a financial intermediary, as that term is used in Article 3(2) of the Prospectus Directive, (x) the shares acquired by it in the offering have not been acquired on behalf of, nor have they been acquired with a view to their offer or resale to, persons in any Relevant Member State other than “qualified investors” as defined in the Prospectus Directive, or in circumstances in which the prior consent of the Subscribers has been given to the offer or resale, or (y) where shares have been acquired by it on behalf of persons in any Relevant Member State other than “qualified investors” as defined in the Prospectus Directive, the offer of those shares to it is not treated under the Prospectus Directive as having been made to such persons.
 
For the purpose of the above provisions, the expression “an offer to the public” in relation to any shares in any Relevant Member State means the communication in any form and by any means of sufficient information on the terms of the offer of any shares to be offered so as to enable an investor to decide to purchase any shares, as the same may be varied in the Relevant Member State by any measure implementing the Prospectus Directive in the Relevant Member State and the expression “Prospectus Directive” means Directive 2003/71 EC (including the 2010 PD Amending Directive, in the case of Early Implementing Member States) and includes any relevant implementing measure in each Relevant Member State and the expression “2010 PD Amending Directive” means Directive 2010/73/EU.
 
United Kingdom
 
This prospectus is only being distributed to, and is only directed at, persons in the United Kingdom that are qualified investors within the meaning of Article 2(1)(e) of the Prospectus Directive (“Qualified Investors”) that are also (i) investment professionals falling within Article 19(5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005 (the “Order”) or (ii) high net worth entities, and other persons to whom it may lawfully be communicated, falling within Article 49(2)(a) to (d) of the Order (all such persons together being referred to as “relevant persons”). This prospectus and its contents are confidential and should not be distributed, published or reproduced (in whole or in part) or disclosed by recipients to any other persons in the United Kingdom. Any person in the United Kingdom that is not a relevant persons should not act or rely on this document or any of its contents.
 
Switzerland
 
The shares may not be publicly offered in Switzerland and will not be listed on the SIX Swiss Exchange (“SIX”) or on any other stock exchange or regulated trading facility in Switzerland. This document has been prepared without regard to the disclosure standards for issuance prospectuses under art. 652a or art. 1156 of the Swiss Code of Obligations or the disclosure standards for listing prospectuses under art. 27 ff. of the SIX Listing Rules or the listing rules of any other stock exchange or regulated trading facility in Switzerland. Neither this document nor any other offering or marketing material relating to the shares or the offering may be publicly distributed or otherwise made publicly available in Switzerland.

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Neither this document nor any other offering or marketing material relating to the offering, the Company, the shares have been or will be filed with or approved by any Swiss regulatory authority. In particular, this document will not be filed with, and the offer of shares will not be supervised by, the Swiss Financial Market Supervisory Authority FINMA, and the offer of shares has not been and will not be authorized under the Swiss Federal Act on Collective Investment Schemes (“CISA”). The investor protection afforded to acquirers of interests in collective investment schemes under the CISA does not extend to acquirers of shares.
 
Dubai International Financial Centre
 
This prospectus relates to an Exempt Offer in accordance with the Offered Securities Rules of the Dubai Financial Services Authority (“DFSA”). This prospectus is intended for distribution only to persons of a type specified in the Offered Securities Rules of the DFSA. It must not be delivered to, or relied on by, any other person. The DFSA has no responsibility for reviewing or verifying any documents in connection with Exempt Offers. The DFSA has not approved this prospectus nor taken steps to verify the information set forth herein and has no responsibility for the prospectus. The shares to which this prospectus relates may be illiquid and/or subject to restrictions on their resale. Prospective purchasers of the shares offered should conduct their own due diligence on the shares. If you do not understand the contents of this prospectus you should consult an authorized financial advisor.
 
Australia
 
No prospectus or other disclosure document (as defined in the Corporations Act 2001 (Cth) of Australia (“Corporations Act”)) in relation to the shares has been or will be lodged with the Australian Securities & Investments Commission (“ASIC”). This document has not been lodged with ASIC and is only directed to certain categories of exempt persons. Accordingly, if you receive this document in Australia:

 	(a)  	you confirm and warrant that you are either:	

 	(i)     	a “sophisticated investor” under section 708(8)(a) or (b) of the Corporations Act;	

 	(ii)    	a “sophisticated investor” under section 708(8)(c) or (d) of the Corporations Act and that you have provided an accountant’s certificate to us which complies with the requirements of section 708(8)(c)(i) or (ii) of the Corporations Act and related regulations before the offer has been made;	
 		
 	(iii)   	a person associated with the Company under section 708(12) of the Corporations Act; or	

 	(iv)   	a “professional investor” within the meaning of section 708(11)(a) or (b) of the Corporations Act,	
 
and to the extent that you are unable to confirm or warrant that you are an exempt sophisticated investor, associated person or professional investor under the Corporations Act any offer made to you under this document is void and incapable of acceptance; and

 	(b)  	you warrant and agree that you will not offer any of the shares for resale in Australia within 12 months of those shares being issued unless any such resale offer is exempt from the requirement to issue a disclosure document under section 708 of the Corporations Act.	
 
Hong Kong
 
The shares may not be offered or sold in Hong Kong, by means of any document, other than (a) to “professional investors” as defined in the Securities and Futures Ordinance (Cap. 571, Laws of Hong Kong) and any rules made under that Ordinance or (b) in other circumstances which do not result in the document being a “prospectus” as defined in the Companies Ordinance (Cap. 32, Laws of Hong Kong) or which do not constitute an offer to the public within the meaning of that Ordinance. No advertisement, invitation or document relating to the shares may be issued or may be in the possession of any person for the purpose of the issue, whether in Hong Kong or elsewhere, which is directed at, or the contents of which are likely to be read by, the public in Hong Kong (except if permitted to do so under the laws of Hong Kong) other than with respect to the shares which are intended to be disposed of only to persons outside Hong Kong or only to “professional investors” as defined in the Securities and Futures Ordinance (Cap. 571, Laws of Hong Kong) or any rules made under that Ordinance.

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India
 
This prospectus has not been and will not be registered as a prospectus with the Registrar of Companies in India or with the Securities and Exchange Board of India. This prospectus or any other material relating to these securities is for information purposes only and may not be circulated or distributed, directly or indirectly, to the public or any members of the public in India and in any event to not more than 50 persons in India. Further, persons into whose possession this prospectus comes are required to inform themselves about and to observe any such restrictions. Each prospective investor is advised to consult its advisors about the particular consequences to it of an investment in these securities. Each prospective investor is also advised that any investment in these securities by it is subject to the regulations prescribed by the Reserve Bank of India and the Foreign Exchange Management Act and any regulations framed thereunder.
 
Japan
 
No securities registration statement (“SRS”) has been filed under Article 4, Paragraph 1 of the Financial Instruments and Exchange Law of Japan (Law No. 25 of 1948, as amended) (“FIEL”) in relation to the shares. The shares are being offered in a private placement to “qualified institutional investors” (tekikaku-kikan-toshika) under Article 10 of the Cabinet Office Ordinance concerning Definitions provided in Article 2 of the FIEL (the Ministry of Finance Ordinance No. 14, as amended) (“QIIs”), under Article 2, Paragraph 3, Item 2 i of the FIEL. Any QII acquiring the shares in this offer may not transfer or resell those shares except to other QIIs.
 
Korea
 
The shares may not be offered, sold and delivered directly or indirectly, or offered or sold to any person for reoffering or resale, directly or indirectly, in Korea or to any resident of Korea except pursuant to the applicable laws and regulations of Korea, including the Korea Securities and Exchange Act and the Foreign Exchange Transaction Law and the decrees and regulations thereunder. The shares have not been registered with the Financial Services Commission of Korea for public offering in Korea. Furthermore, the shares may not be resold to Korean residents unless the purchaser of the shares complies with all applicable regulatory requirements (including but not limited to government approval requirements under the Foreign Exchange Transaction Law and its subordinate decrees and regulations) in connection with the purchase of the shares.
 
Singapore
 
This prospectus has not been registered as a prospectus with the Monetary Authority of Singapore. Accordingly, this prospectus and any other document or material in connection with the offer or sale, or invitation for subscription or purchase, of the shares may not be circulated or distributed, nor may the shares be offered or sold, or be made the subject of an invitation for subscription or purchase, whether directly or indirectly, to persons in Singapore other than (i) to an institutional investor under Section 274 of the Securities and Future Act, Chapter 289 of Singapore (the “SFA”), (ii) to a “relevant person” as defined in Section 275(2) of the SFA, or any person pursuant to Section 275 (1A), and in accordance with the conditions, specified in Section 275 of the SFA or (iii) otherwise pursuant to, and in accordance with the conditions of, any other applicable provision of the SFA.
 
Where the shares are subscribed and purchased under Section 275 of the SFA by a relevant person which is:

 	(a)  	a corporation (which is not an accredited investor (as defined in Section 4A of the SFA)) the sole business of which is to hold investments and the entire share capital of which is owned by one or more individuals, each of whom is an accredited investor; or	

 	(b)  	a trust (where the trustee is not an accredited investor (as defined in Section 4A of the SFA)) whose sole whole purpose is to hold investments and each beneficiary is an accredited investor, shares, debentures and units of shares and debentures of that corporation or the beneficiaries’ rights and interest (howsoever described) in that trust shall not be transferable within six months after that corporation or that trust has acquired the shares under Section 275 of the SFA except:	

 	(i)     	to an institutional investor under Section 274 of the SFA or to a relevant person (as defined in Section 275(2) of the SFA) and in accordance with the conditions, specified in Section 275 of the SFA;	

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 	(ii)    	(in the case of a corporation) where the transfer arises from an offer referred to in Section 275(1A) of the SFA, or (in the case of a trust) where the transfer arises from an offer that is made on terms that such rights or interests are acquired at a consideration of not less than S$200,000 (or its equivalent in a foreign currency) for each transaction, whether such amount is to be paid for in cash or by exchange of securities or other assets;	
 		
 	(iii)   	where no consideration is or will be given for the transfer; or	

 	(iv)   	where the transfer is by operation of law.	
 
By accepting this prospectus, the recipient hereof represents and warrants that he is entitled to receive it in accordance with the restrictions set forth above and agrees to be bound by limitations contained herein. Any failure to comply with these limitations may constitute a violation of law.
 
LEGAL MATTERS
 
The validity of the Class A common stock offered hereby will be passed upon for us by Gibson, Dunn & Crutcher LLP. Certain legal matters in connection with the Class A common stock offered hereby will be passed upon for the underwriters by Latham & Watkins LLP, Houston, Texas.
 
EXPERTS
 
Ernst & Young LLP, independent registered public accounting firm, has audited the combined financial statements and schedule at December 31, 2010 and 2009, and for each of the three years in the period ended December 31, 2010, as set forth in their report included in this prospectus. We have included the combined financial statements and schedule in this prospectus and elsewhere in the registration statement in reliance on Ernst & Young LLP’s report, given on their authority as experts in accounting and auditing.
 
Approximately 94 percent of our year-end 2010 U.S. proved reserves estimates included in this prospectus were either audited by Netherland, Sewell & Associates, Inc., or, in the case of reserves estimates related to properties underlying the former Williams Coal Seam Gas Royalty Trust, were audited by Miller and Lents, Ltd.
 
Approximately 94 percent of our year-end 2010 proved reserves estimates for international properties were reviewed and certified by Ralph E. Davis Associates, Inc.
 
WHERE YOU CAN FIND MORE INFORMATION
 
We have filed with the SEC a registration statement on Form S-1 under the Securities Act with respect to the common stock we propose to sell in this offering. This prospectus, which constitutes part of the registration statement, does not contain all of the information set forth in the registration statement. For further information about us and the common stock that we propose to sell in this offering, we refer you to the registration statement and the exhibits and schedules filed as a part of the registration statement. Statements contained in this prospectus as to the contents of any contract or other document filed as an exhibit to the registration statement are not necessarily complete. If a contract or document has been filed as an exhibit to the registration statement, we refer you to the copy of the contract or document that has been filed as an exhibit to the registration statement. When we complete this offering, we will also be required to file annual, quarterly and special reports, proxy statements and other information with the SEC.
 
You can read our SEC filings, including the registration statement, over the Internet at the SEC’s website at www.sec.gov. You may also read and copy any document we filed with the SEC at its public reference facility at 100 F Street, N.E., Washington, D.C. 20549. You may also obtain copies of the documents at prescribed rates by writing to the Public Reference Section of the SEC at 100 F Street, N.E., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the operation of the public reference facilities.

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INDEX TO FINANCIAL STATEMENTS

 	 	Page	
 		
Unaudited pro forma combined financial statements	 	 	 	 	
Introduction	 	 	F-2	 	
Pro Forma Combined Balance Sheet as of June 30, 2011 (unaudited)	 	 	F-3	 	
Pro Forma Combined Statement of Operations for the six months ended June 30, 2011 and the year ended December 31, 2010 (unaudited)	 	 	F-4	 	
Notes to Pro Forma Combined Financial Statements (unaudited)	 	 	F-5	 	
Interim unaudited condensed combined financial statements	 	 	 	 	
Condensed Combined Statement of Operations for the six months ended June 30, 2011 and 2010 (unaudited)	 	 	F-8	 	
Condensed Combined Balance Sheet as of June 30, 2011 and December 31, 2010 (unaudited)	 	 	F-9	 	
Condensed Combined Statement of Equity for the six months ended June 30, 2011 and 2010 (unaudited)	 	 	F-10	 	
Condensed Combined Statement of Cash Flows for the six months ended June 30, 2011 and 2010 (unaudited)	 	 	F-11	 	
Notes to Condensed Combined Financial Statements (unaudited)	 	 	F-12	 	
Annual audited combined financial statements	 	 	 	 	
Report of Independent Registered Public Accounting Firm	 	 	F-30	 	
Combined Statement of Operations for the years ended December 31, 2010, 2009 and 2008	 	 	F-31	 	
Combined Balance Sheet as of December 31, 2010 and 2009	 	 	F-32	 	
Combined Statement of Equity for the years ended December 31, 2010, 2009 and 2008	 	 	F-33	 	
Combined Statement of Cash Flows for the years ended December 31, 2010, 2009 and 2008	 	 	F-34	 	
Notes to Combined Financial Statements	 	 	F-35	 	

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WPX Energy
 
Unaudited Pro Forma Combined Financial Statements
 
Introduction
 
The unaudited pro forma combined financial statements are based upon the historical combined financial position and results of operations of WPX Energy (the “Company”), a wholly owned subsidiary of The Williams Companies, Inc. (“Williams”). In July 2011, Williams contributed to the Company its investment in certain subsidiaries related to its domestic exploration and production business. Additionally, prior to the completion of the offering, Williams will contribute to the Company its investment in certain subsidiaries related to its international exploration and production business. These contributions will be recorded at historical cost as they are considered to be a reorganization of entities under common control. Additionally, in June 2011, Williams contributed to capital all notes payable to Williams owed by the combined entities and, as a result, the Company has received and will receive its investment in these certain subsidiaries without debt to Williams. The unaudited pro forma combined financial statements have been derived from the Company’s historical combined financial statements set forth elsewhere in this prospectus and are qualified in their entirety by reference to such historical combined financial statements and notes thereto. The unaudited pro forma combined financial statements should be read in conjunction with the notes accompanying such unaudited pro forma combined financial statements, as well as in conjunction with our historical combined financial statements and related notes thereto, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Use of Proceeds,” each of which is included elsewhere in this prospectus.
 
The unaudited pro forma combined financial statements as of June 30, 2011 and for the six months ended June 30, 2011 and year ended December 31, 2010 were derived by adjusting the Company’s historical combined financial statements. The pro forma adjustments are based upon currently available information and certain estimates and assumptions; therefore, actual adjustments will differ from the pro forma adjustments. However, management believes the adjustments provide a reasonable basis for presenting the significant effects of the transactions as contemplated and that the pro forma adjustments give appropriate effect to those assumptions and are properly applied in the pro forma combined financial statements. Williams has advised us that, following the completion of this offering, it intends to distribute all of the shares of our common stock it owns through a tax-free distribution, or spin-off, to Williams’ stockholders. The determination of whether, and if so, when, to proceed with the spin-off is entirely within the discretion of Williams, although Williams has indicated its intention to complete the spin-off in 2012. Due to the uncertainty of the spin-off, the unaudited pro forma combined financial statements do not include any adjustments related to such a spin-off of Williams’ ownership in the Company.
 
The unaudited pro forma combined statement of operations may not be indicative of the actual results that would have been achieved had the transactions been consummated on the dates indicated. Also, the unaudited pro forma combined financial statements should not be viewed as indicative of our financial condition or results of operations as of any future dates or for any future period.

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WPX Energy
Unaudited Pro Forma Combined Balance Sheet
 June 30, 2011

 	 	 	 	 	Pro Forma Adjustments	 	 	 	 	
 	 	Combined	 	 	Restructuring	 	 	Concurrent Financing	 	 	Offering	 	 	Combined	 	
 	 	Historical (a)	 	 	Transactions	 	 	Transactions	 	 	Transactions	 	 	Pro Forma	 	
 	 	(millions)	 	
 		
Assets	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Current assets:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash and cash equivalents	 	$	36	 	 	$	—	 	 	$	1,479	(c)	 	$	707	(f)	 	$	538	 	
 	 	 	 	 	 	 	 	 	 	 	(1,684	)(d)	 	 	 	 	 	 	 	 	
Accounts receivable:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Trade, net of allowance for doubtful accounts	 	 	379	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	379	 	
Affiliate	 	 	57	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	57	 	
Derivative assets	 	 	269	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	269	 	
Inventories	 	 	70	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	70	 	
Other	 	 	70	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	70	 	

Total current assets	 	 	881	 	 	 	—	 	 	 	(205	)	 	 	707	 	 	 	1,383	 	
Investments	 	 	114	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	114	 	
Properties and equipment, net	 	 	8,654	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	8,654	 	
Derivative assets	 	 	138	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	138	 	
Other noncurrent assets	 	 	108	 	 	 	—	 	 	 	21	(c)	 	 	(3	)(f)	 	 	126	 	

Total assets	 	$	9,895	 	 	$	—	 	 	$	(184	)	 	$	704	 	 	$	10,415	 	

Liabilities and Equity	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Current liabilities:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Accounts payable:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Trade	 	$	499	 	 	$	—	 	 	$	—	 	 	$	—	 	 	$	499	 	
Affiliates	 	 	63	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	63	 	
Accrued and other current liabilities	 	 	155	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	155	 	
Deferred income taxes	 	 	50	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	50	 	
Derivative liabilities	 	 	108	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	108	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total current liabilities	 	 	875	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	875	 	
Deferred income taxes	 	 	1,639	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	1,639	 	
Long-term debt	 	 	—	 	 	 	—	 	 	 	1,500	(c)	 	 	—	 	 	 	1,500	 	
Derivative liabilities	 	 	112	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	112	 	
Asset retirement obligations	 	 	306	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	306	 	
Other noncurrent liabilities	 	 	94	 	 	 	46	(a)	 	 	—	 	 	 	—	 	 	 	140	 	
Equity:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Owner’s net investment	 	 	6,678	 	 	 	(46	)(a)	 	 	(1,684	)(d)	 	 	—	 	 	 	—	 	
 	 	 	 	 	 	 	(4,948	)(b)	 	 	 	 	 	 	 	 	 	 	 	 	
Accumulated other comprehensive income	 	 	115	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	115	 	
Class A common stock	 	 	—	 	 	 	—	 	 	 	—	 	 	 	704	(f)	 	 	704	 	
Class B common stock	 	 	—	 	 	 	4,948	(b)	 	 	—	 	 	 	—	 	 	 	4,948	 	
Noncontrolling interests	 	 	76	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	76	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total equity	 	 	6,869	 	 	 	(46	)	 	 	(1,684	)	 	 	704	 	 	 	5,843	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total liabilities and equity	 	$	9,895	 	 	$	—	 	 	$	(184	)	 	$	704	 	 	$	10,415	 	

 
See accompanying notes to pro forma financial statements

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WPX Energy
 
 Unaudited Pro Forma Combined Statement of Operations 

 	 	Six Months Ended June 30, 2011	 	 	Year Ended December 31, 2010	 	
 	 	Combined	 	 	Pro Forma	 	 	Combined	 	 	Combined	 	 	Pro Forma	 	 	Combined	 	
 	 	Historical	 	 	Adjustments	 	 	Pro Forma	 	 	Historical	 	 	Adjustments	 	 	Pro Forma	 	
 	 	(Millions - except per share amounts)	 	
 		
Revenues	 	$	1,974	 	 	$	 	 	 	$	1,974	 	 	$	4,034	 	 	$	 	 	 	$	4,034	 	
Costs and expenses:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Lease and facility operating expense, including affiliate	 	 	140	 	 	 	 	 	 	 	140	 	 	 	286	 	 	 	 	 	 	 	286	 	
Gathering, processing and transportation, including affiliate	 	 	240	 	 	 	 	 	 	 	240	 	 	 	326	 	 	 	 	 	 	 	326	 	
Taxes other than income	 	 	76	 	 	 	 	 	 	 	76	 	 	 	125	 	 	 	 	 	 	 	125	 	
Gas management (including charges for unutilized pipeline capacity)	 	 	762	 	 	 	 	 	 	 	762	 	 	 	1,771	 	 	 	 	 	 	 	1,771	 	
Exploration	 	 	33	 	 	 	 	 	 	 	33	 	 	 	73	 	 	 	 	 	 	 	73	 	
Depreciation, depletion and amortization	 	 	452	 	 	 	 	 	 	 	452	 	 	 	875	 	 	 	 	 	 	 	875	 	
Impairment of producing properties and costs of acquired unproved reserves	 	 	—	 	 	 	 	 	 	 	—	 	 	 	678	 	 	 	 	 	 	 	678	 	
Goodwill impairment	 	 	—	 	 	 	 	 	 	 	—	 	 	 	1,003	 	 	 	 	 	 	 	1,003	 	
General and administrative, including affiliate	 	 	135	 	 	 	 	 	 	 	135	 	 	 	253	 	 	 	 	 	 	 	253	 	
Other — net	 	 	5	 	 	 	 	 	 	 	5	 	 	 	(19	)	 	 	 	 	 	 	(19	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total costs and expenses	 	 	1,843	 	 	 	—	 	 	 	1,843	 	 	 	5,371	 	 	 	—	 	 	 	5,371	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating income (loss)	 	 	131	 	 	 	 	 	 	 	131	 	 	 	(1,337	)	 	 	 	 	 	 	(1,337	)	
Interest expense, including affiliate	 	 	(97	)	 	 	94	(a)	 	 	(52	)	 	 	(124	)	 	 	119	(a)	 	 	(103	)	
 	 	 	 	 	 	 	(49	)(e)	 	 	 	 	 	 	 	 	 	 	(98	)(e)	 	 	 	 	
Interest capitalized	 	 	8	 	 	 	 	 	 	 	8	 	 	 	16	 	 	 	 	 	 	 	16	 	
Investment income and other	 	 	12	 	 	 	 	 	 	 	12	 	 	 	21	 	 	 	 	 	 	 	21	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income (loss) from continuing operations before income taxes	 	 	54	 	 	 	45	 	 	 	99	 	 	 	(1,424	)	 	 	21	 	 	 	(1,403	)	
Provision (benefit) for income taxes	 	 	19	 	 	 	16	(g)	 	 	35	 	 	 	(150	)	 	 	8	(g)	 	 	(142	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income (loss) from continuing operations	 	 	35	 	 	 	29	 	 	 	64	 	 	 	(1,274	)	 	 	13	 	 	 	(1,261	)	
Loss from discontinued operations	 	 	(8	)	 	 	 	 	 	 	(8	)	 	 	(8	)	 	 	 	 	 	 	(8	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income (loss)	 	$	27	 	 	$	29	 	 	$	56	 	 	$	(1,282	)	 	$	13	 	 	$	(1,269	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Pro forma income (loss) from continuing operations per share (Note 3):	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Basic	 	$	 	 	 	 	 	 	 	$	 	 	 	 	 	 	 	 	 	 	 	$	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Diluted	 	$	 	 	 	 	 	 	 	$	 	 	 	 	 	 	 	 	 	 	 	$	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Weighted average shares outstanding:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Basic	 	 	 	 	 	 		(f)	 	 	 	 	 	 	 	 	 	 		(f)	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Diluted	 	 	 	 	 	 		(f)	 	 	 	 	 	 	 	 	 	 		(f)	 	 	 	 	

 
See accompanying notes to pro forma financial statements

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Table of Contents

WPX Energy
 
Notes to Pro Forma Combined Financial Statements
(Unaudited)

Note 1.  	Basis of Presentation	
 
The historical financial information is derived from the historical combined financial statements of WPX Energy set forth elsewhere in this Prospectus and is qualified in its entirety by reference to such historical combined financial statements and notes thereto. The pro forma adjustments have been prepared as if the transactions to be effected prior to or at the completion of this offering had taken place on June 30, 2011, in the case of the unaudited pro forma combined balance sheet or as of January 1, 2010, in the case of the unaudited pro forma combined statement of operations for the year ended December 31, 2010, and the six months ended June 30, 2011.
 
Upon completion of this offering, we anticipate incurring incremental general and administrative expense as a result of being a public company. No pro forma adjustment has been made for these additional expenses, as an estimate of these expenses is not objectively determinable. Additionally, we currently depend on Williams for a number of administrative functions. Prior to the completion of this offering, we will enter into an administrative services agreement under which Williams will provide to us, on an interim basis, various corporate support services. These services will consist generally of the services that have been provided to us on an intercompany basis prior to this offering and we will pay Williams’ costs, including Williams’ direct and indirect administrative and overhead charges allocated in accordance with Williams’ regular and consistent accounting practices. For more information regarding this agreement, see “Arrangements Between Williams and Our Company.”
 
In conjunction with the completion of this offering, Williams will provide us with approximately $20 million in cash to assist in the funding of certain information technology transition costs and expenses we expect to incur following the completion of this offering. The entire amount we receive from Williams will be recorded as a capital contribution from Williams upon receipt and any future amounts we spend on such information technology transition costs and expenses will be recorded as increases in our assets or expenses depending on the specific nature of the costs. No pro forma adjustment has been made for this capital contribution or the related information technology transition costs and expenses as an estimate of these costs and expenses is not objectively determinable.
 
Upon completion of this offering, we will enter into a tax sharing agreement with Williams. The tax sharing agreement will govern the respective rights, responsibilities and obligations of Williams and us with respect to various matters regarding taxes. The Company’s domestic operations are included in the consolidated federal and state income tax returns for Williams, except for certain separate state filings. The income tax provision presented in the Company’s historical combined financial statements has been calculated on a separate return basis, except for certain state and federal tax attributes (primarily minimum tax credit carry-forwards) for which the actual allocation (if any) cannot be determined until the consolidated tax returns are complete for the year in which an income tax deconsolidation event occurs. For more information regarding this agreement and the presentation of income taxes in the historical financial statements, see “Arrangements Between Williams and Our Company” and Note 10 of Notes to Combined Financial Statements.

Note 2.  	Pro Forma Adjustments	
 
Restructuring Transactions
 
(a) In July 2011, in accordance with the terms of our separation and distribution agreement with Williams, Williams contributed its investment in certain subsidiaries related to its domestic exploration and production business to us. Additionally, prior to the completion of this offering, Williams will contribute its investment in certain subsidiaries related to its international exploration and production business to us. Our separation and distribution agreement with Williams also provides certain indemnifications to us related to these contributions. These contributions have or will be recorded at historical cost as they are considered to be

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Table of Contents

WPX Energy
 
Notes to Pro Forma Combined Financial Statements — (Continued)
 
a reorganization of entities under common control. Adjustments included in the pro forma combined financial statements related to our separation and distribution agreement are as follows:

 	•  	In June 2011, Williams contributed to our capital all notes payable to Williams owed by the combined entities and, as a result, as of July 1, 2011, we have and will receive our investment in these certain subsidiaries without any debt to Williams. The unaudited pro forma combined statement of operations reflects the elimination of $94 million and $119 million of affiliate interest expense associated with these notes for the six months ended June 30, 2011 and the year ended December 31, 2010, respectively, that is replaced by the interest incurred on the new senior unsecured notes.	
 		
 	•  	The indemnifications included in the separation and distribution agreement result in the addition of a $46 million non-current liability as of June 30, 2011, which represents the net asset (net of related liabilities) we have recorded related to Williams’ former power business matters. We will be required to pay Williams for any net cash received upon ultimate resolution of these matters. For additional information regarding these indemnifications and the Williams’ former power business matters, see “Arrangements Between Williams and Our Company” and Note 11 of Notes to Combined Financial Statements, respectively.	
 
(b) Reflects the conversion of the outstanding shares of our common stock, all of which are owned by Williams, into           shares of Class B common stock in exchange for all of the assets (net of the liabilities assumed and the cash we distribute to Williams) contributed to us by Williams.
 
Concurrent Financing Transactions
 
(c) Reflects the receipt of approximately $1.5 billion from our expected offering of the senior unsecured notes, after deducting the discounts of the initial purchasers of these notes and other issuance costs totaling approximately $21 million. These costs will be amortized to interest expense over the respective terms of the notes.
 
(d) Reflects the distribution of approximately $1,684 million to Williams from the combined net proceeds from this offering in excess of $500 million, or approximately $204 million and approximately $1.5 billion from the expected offering of the notes discussed in adjustment (c).
 
(e) Reflects total interest expense for our $1.5 billion expected offering of the notes discussed in adjustment (c) at an assumed average interest rate of     % and our new $1.5 billion senior unsecured revolving credit facility. The amount is comprised of:

 	• 	interest expense on the notes;	
 		
 	• 	amortized debt issuance costs related to our debt; and	
 		
 	• 	commitment fees and amortized costs related to our new credit facility.	
 
No borrowings under the revolving credit facility are assumed for any period presented. Actual interest expense we incur in future periods may be higher or lower depending on the final terms of the senior unsecured notes and our actual utilization of the revolving credit facility. An increase in the average interest rate applicable to the senior unsecured notes of one-eighth of one percent (0.125%) would result in additional interest expense of approximately $      million and $      million for the year ended December 31, 2010 and the six months ended June 30, 2011, respectively.
 
We have certain contractual obligations, primarily interstate transportation agreements, which contain collateral support requirements based on our credit ratings. Because Williams has an investment grade credit rating and guaranteed these contracts, we have not historically been required to provide collateral support. After the completion of this offering, Williams has informed us that it expects it will obtain releases of the guarantees. Depending on our credit rating, we anticipate issuing letters of credit under our Credit Facility of

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Table of Contents

WPX Energy
 
Notes to Pro Forma Combined Financial Statements — (Continued)
 
$295 million to satisfy the provisions of these contracts but the amount could be up to $500 million. No pro forma adjustment has been made for additional interest expense associated with our anticipated issuance of these letters of credit as an estimate of such expense is not objectively determinable until our initial credit rating has been established.
 
Offering Transactions
 
(f) Reflects the receipt of approximately $707 million from the sale of           shares of Class A common stock offered by us at an assumed initial public offering price of $      per share, net of $46 million of estimated underwriter discounts and commissions and offering expenses. Additionally, this adjustment reflects the reclassification of approximately $3 million of deferred costs related to this offering to Class A common stock. The $3 million of deferred costs represents the amount of such costs that had been funded by Williams as of June 30, 2011.
 
Other Adjustments
 
(g) Reflects the adjustment of the provision (benefit) for income taxes for the adjustments made to income (loss) before income taxes at an estimated statutory rate of approximately 36%.

Note 3.  	Earnings per Share	
 
Pro forma basic and diluted income (loss) from continuing operations per share was calculated by dividing the pro forma income (loss) from continuing operations by the assumed issuance of           Class A common shares and           Class B common shares, each as previously discussed. All shares were assumed to have been outstanding since January 1, 2010. Basic and diluted pro forma income (loss) from continuing operations per share are equivalent as there are no dilutive shares or potentially dilutive items at the closing of the initial public offering. Holders of Class A common stock and Class B common stock will share equally on a per share basis in any dividend declared and are entitled to receive the same amount per share with respect to any distribution of assets to holders of shares of common stock upon liquidation, dissolution or winding up of WPX.

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Table of Contents

WPX Energy
(Note 1)

Condensed Combined Statement of Operations
 (Unaudited)

 	 	Six Months Ended June 30,	 	
 	 	2011	 	 	2010	 	
 	 	(Dollars in millions)	 	
 		
Revenues:	 	 	 	 	 	 	 	 	
Oil and gas sales, including affiliate	 	$	1,216	 	 	$	1,114	 	
Gas management, including affiliate	 	 	745	 	 	 	922	 	
Hedge ineffectiveness and mark to market gains and losses	 	 	8	 	 	 	9	 	
Other	 	 	5	 	 	 	23	 	
 	 	 	 	 	 	 	 	 	
Total revenues	 	 	1,974	 	 	 	2,068	 	
Costs and expenses:	 	 	 	 	 	 	 	 	
Lease and facility operating, including affiliate	 	 	140	 	 	 	132	 	
Gathering, processing and transportation, including affiliate	 	 	240	 	 	 	145	 	
Taxes other than income	 	 	76	 	 	 	73	 	
Gas management (including charges for unutilized pipeline capacity)	 	 	762	 	 	 	934	 	
Exploration	 	 	33	 	 	 	18	 	
Depreciation, depletion and amortization	 	 	452	 	 	 	433	 	
General and administrative, including affiliate	 	 	135	 	 	 	122	 	
Other — net	 	 	5	 	 	 	3	 	
 	 	 	 	 	 	 	 	 	
Total costs and expenses	 	 	1,843	 	 	 	1,860	 	
 	 	 	 	 	 	 	 	 	
Operating income	 	 	131	 	 	 	208	 	
Interest expense, including affiliate	 	 	(97	)	 	 	(50	)	
Interest capitalized	 	 	8	 	 	 	8	 	
Investment income and other	 	 	12	 	 	 	11	 	
 	 	 	 	 	 	 	 	 	
Income from continuing operations before income taxes	 	 	54	 	 	 	177	 	
Provision for income taxes	 	 	19	 	 	 	62	 	
 	 	 	 	 	 	 	 	 	
Income from continuing operations	 	 	35	 	 	 	115	 	
Loss from discontinued operations	 	 	(8	)	 	 	(1	)	
 	 	 	 	 	 	 	 	 	
Net income	 	 	27	 	 	 	114	 	
Less: Net income attributable to noncontrolling interests	 	 	5	 	 	 	4	 	
 	 	 	 	 	 	 	 	 	
Net income attributable to WPX Energy	 	$	22	 	 	$	110	 	
 	 	 	 	 	 	 	 	 	
Supplemental pro forma combined basic loss per common share (Note 2)	 	$	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	
Supplemental pro forma combined diluted loss per common share (Note 2)	 	$	 	 	 	 	 	 	

 
See accompanying notes.

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Table of Contents

WPX Energy
(Note 1)

Condensed Combined Balance Sheet
 (Unaudited)

 	 	Supplemental	 	 	 	 	 	 	 	
 	 	Pro Forma	 	 	 	 	 	 	 	
 	 	June 30,	 	 	June 30,	 	 	December 31,	 	
 	 	2011 (Note 2)	 	 	2011	 	 	2010	 	
 	 	(Dollars in millions)	 	
 		
Assets	 	 	 	 	 	 	 	 	 	 	 	 	
Current assets:	 	 	 	 	 	 	 	 	 	 	 	 	
Cash and cash equivalents	 	$	36	 	 	$	36	 	 	$	37	 	
Accounts receivable:	 	 	 	 	 	 	 	 	 	 	 	 	
Trade, net of allowance for doubtful accounts of $17 at June 30, 2011 and $16 at December 31, 2010	 	 	379	 	 	 	379	 	 	 	362	 	
Affiliate	 	 	57	 	 	 	57	 	 	 	60	 	
Derivative assets	 	 	269	 	 	 	269	 	 	 	400	 	
Inventories	 	 	70	 	 	 	70	 	 	 	77	 	
Other	 	 	70	 	 	 	70	 	 	 	22	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total current assets	 	 	881	 	 	 	881	 	 	 	958	 	
Investments	 	 	114	 	 	 	114	 	 	 	105	 	
Properties and equipment (successful efforts method of accounting)	 	 	13,190	 	 	 	13,190	 	 	 	12,564	 	
Less — accumulated depreciation, depletion and amortization	 	 	(4,536	)	 	 	(4,536	)	 	 	(4,115	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Properties and equipment, net	 	 	8,654	 	 	 	8,654	 	 	 	8,449	 	
Derivative assets	 	 	138	 	 	 	138	 	 	 	173	 	
Other noncurrent assets	 	 	108	 	 	 	108	 	 	 	161	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total assets	 	$	9,895	 	 	$	9,895	 	 	$	9,846	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Liabilities and Equity	 	 	 	 	 	 	 	 	 	 	 	 	
Current liabilities:	 	 	 	 	 	 	 	 	 	 	 	 	
Accounts payable:	 	 	 	 	 	 	 	 	 	 	 	 	
Trade	 	$	499	 	 	$	499	 	 	$	451	 	
Affiliates	 	 	63	 	 	 	63	 	 	 	64	 	
Accrued and other current liabilities	 	 	155	 	 	 	155	 	 	 	158	 	
Deferred income taxes	 	 	50	 	 	 	50	 	 	 	87	 	
Notes payable to Williams	 	 	—	 	 	 	—	 	 	 	2,261	 	
Accrued distribution to Williams	 	 	1,684	 	 	 	—	 	 	 	—	 	
Derivative liabilities	 	 	108	 	 	 	108	 	 	 	146	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total current liabilities	 	 	2,559	 	 	 	875	 	 	 	3,167	 	
Deferred income taxes	 	 	1,639	 	 	 	1,639	 	 	 	1,629	 	
Derivative liabilities	 	 	112	 	 	 	112	 	 	 	143	 	
Asset retirement obligations	 	 	306	 	 	 	306	 	 	 	282	 	
Other noncurrent liabilities	 	 	94	 	 	 	94	 	 	 	125	 	
Contingent liabilities and commitments (Note 8) 	 	 	 	 	 	 	 	 	 	 	 	 	
Equity:	 	 	 	 	 	 	 	 	 	 	 	 	
Owner’s net equity:	 	 	 	 	 	 	 	 	 	 	 	 	
Owner’s net investment	 	 	6,678	 	 	 	6,678	 	 	 	4,260	 	
Accrued distribution to Williams	 	 	(1,684	)	 	 	—	 	 	 	—	 	
Accumulated other comprehensive income	 	 	115	 	 	 	115	 	 	 	168	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total owner’s net equity	 	 	5,109	 	 	 	6,793	 	 	 	4,428	 	
Noncontrolling interests in combined subsidiaries	 	 	76	 	 	 	76	 	 	 	72	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total equity	 	 	5,185	 	 	 	6,869	 	 	 	4,500	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total liabilities and equity	 	$	9,895	 	 	$	9,895	 	 	$	9,846	 	

 
See accompanying notes.

F-9

Table of Contents

WPX Energy
(Note 1)
 
Condensed Combined Statement of Equity
 (Unaudited)

 	 	Six Months Ended June 30,	 	
 	 	2011	 	 	2010	 	
 	 	Owner’s Net	 	 	Noncontrolling	 	 	 	 	 	Owner’s Net	 	 	Noncontrolling	 	 	 	 	
 	 	Equity	 	 	Interests*	 	 	Total	 	 	Equity	 	 	Interests*	 	 	Total	 	
 	 	(Millions)	 	
 		
Beginning balance	 	$	4,428	 	 	$	72	 	 	$	4,500	 	 	$	5,341	 	 	$	64	 	 	$	5,405	 	
Comprehensive income (loss):	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income	 	 	22	 	 	 	5	 	 	 	27	 	 	 	110	 	 	 	4	 	 	 	114	 	
Other comprehensive income (loss), net of tax:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net change in cash flow hedges	 	 	(53	)	 	 	—	 	 	 	(53	)	 	 	105	 	 	 	—	 	 	 	105	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total comprehensive income (loss)	 	 	(31	)	 	 	5	 	 	 	(26	)	 	 	215	 	 	 	4	 	 	 	219	 	
Contribution of notes payable from Williams	 	 	2,420	 	 	 	—	 	 	 	2,420	 	 	 	—	 	 	 	—	 	 	 	—	 	
Dividends to noncontrolling interests	 	 	—	 	 	 	(1	)	 	 	(1	)	 	 	—	 	 	 	—	 	 	 	—	 	
Net transfers with Williams	 	 	(24	)	 	 	—	 	 	 	(24	)	 	 	38	 	 	 	—	 	 	 	38	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Ending balance	 	$	6,793	 	 	$	76	 	 	$	6,869	 	 	$	5,594	 	 	$	68	 	 	$	5,662	 	

 

			
* 		Represents the 31 percent interest in Apco Oil and Gas International Inc. owned by others.	
 
See accompanying notes.

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Table of Contents

WPX Energy
(Note 1)
 
Condensed Combined Statement of Cash Flows
 (Unaudited)

 	 	Six Months Ended June 30,	 	
 	 	2011	 	 	2010	 	
 	 	(Dollars in millions)	 	
 		
Operating Activities:	 	 	 	 	 	 	 	 	
Net income	 	$	27	 	 	$	114	 	
Adjustments to reconcile net income to net cash provided by operating activities:	 	 	 	 	 	 	 	 	
Depreciation, depletion, and amortization	 	 	454	 	 	 	437	 	
Deferred income taxes provision (benefit)	 	 	(17	)	 	 	12	 	
Provision for impairment of properties and equipment (including certain exploration expenses)	 	 	42	 	 	 	10	 	
Cash provided (used) by operating assets and liabilities:	 	 	 	 	 	 	 	 	
Accounts receivable and payable — affiliate	 	 	2	 	 	 	18	 	
Accounts receivable — trade	 	 	(23	)	 	 	77	 	
Inventories	 	 	7	 	 	 	(25	)	
Margin deposits and customer margin deposits payable	 	 	(30	)	 	 	5	 	
Other current assets	 	 	(7	)	 	 	7	 	
Accounts payable — trade	 	 	63	 	 	 	(65	)	
Accrued and other current liabilities	 	 	15	 	 	 	(51	)	
Changes in current and noncurrent derivative assets and liabilities	 	 	13	 	 	 	(18	)	
Other, including changes in noncurrent assets and liabilities	 	 	(23	)	 	 	5	 	
 	 	 	 	 	 	 	 	 	
Net cash provided by operating activities	 	 	523	 	 	 	526	 	
 	 	 	 	 	 	 	 	 	
Investing Activities:	 	 	 	 	 	 	 	 	
Capital expenditures*	 	 	(683	)	 	 	(551	)	
Purchases of investments	 	 	(6	)	 	 	(4	)	
Other — net	 	 	22	 	 	 	1	 	
 	 	 	 	 	 	 	 	 	
Net cash used by investing activities	 	 	(667	)	 	 	(554	)	
 	 	 	 	 	 	 	 	 	
Financing Activities:	 	 	 	 	 	 	 	 	
Net changes in notes payable to parent	 	 	159	 	 	 	(10	)	
Net changes in owner’s investment	 	 	(3	)	 	 	39	 	
Revolving debt facility costs	 	 	(8	)	 	 	—	 	
Other	 	 	(5	)	 	 	(1	)	
 	 	 	 	 	 	 	 	 	
Net cash provided (used) by financing activities	 	 	143	 	 	 	28	 	
 	 	 	 	 	 	 	 	 	
Increase in cash and cash equivalents	 	 	(1	)	 	 	—	 	
Cash and cash equivalents at beginning of period	 	 	37	 	 	 	34	 	
 	 	 	 	 	 	 	 	 	
Cash and cash equivalents at end of period	 	$	36	 	 	$	34	 	

* Increases to property, plant, and equipment	 	$	(667	)	 	$	(550	)	
Changes in related accounts payable and accrued liabilities	 	 	(16	)	 	 	(1	)	
 	 	 	 	 	 	 	 	 	
Capital expenditures	 	$	(683	)	 	$	(551	)	

 
See accompanying notes.

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Table of Contents

WPX Energy
 
Notes to Condensed Combined Financial Statements
(Unaudited)

Note 1.  	General	
 
The combined businesses represented herein as WPX Energy (also referred to as the “Company”) comprise substantially all of the exploration and production operating segment of The Williams Companies, Inc. (“Williams”). In these notes, WPX Energy is referred to in the first person as “we”, “us” or “our”.
 
On February 16, 2011, Williams announced that its Board of Directors approved pursuing a plan to separate Williams’ businesses into two stand-alone, publicly traded companies. The plan first calls for Williams to separate its exploration and production business via an initial public offering (the “Offering”) of up to 20 percent of its interest. As a result, WPX Energy, Inc. was formed in April 2011 to effect the separation. In July 2011, Williams contributed to the Company its investment in certain subsidiaries related to its domestic exploration and production business, including its wholly-owned subsidiaries Williams Production Holdings, LLC and Williams Production Company, LLC, as well as all ongoing operations of Williams Gas Marketing Services, Inc. Additionally, prior to the close of the Offering, Williams will contribute and transfer to the Company its investment in certain subsidiaries related to its international exploration and production business, including its 69 percent ownership interest in Apco Oil and Gas International (“Apco”, NASDAQ listed: APAGF). We refer to the collective contributions described herein as the “Contribution”.
 
WPX Energy includes natural gas development, production and gas management activities located in the Rocky Mountain (primarily Colorado, New Mexico, and Wyoming), Mid-Continent (Texas), and Appalachian regions of the United States. We specialize in natural gas production from tight-sands and shale formations and coal bed methane reserves in the Piceance, San Juan, Powder River, Green River, Fort Worth, and Appalachian Basins. During 2010, we acquired a company with a significant acreage position in the Williston Basin (Bakken Shale) in North Dakota, which is primarily comprised of crude oil reserves. We also have international oil and gas interests which represented approximately two percent of combined revenues and approximately six percent of proved reserves for the year ended December 31, 2010. These international interests primarily consist of our ownership in Apco, an oil and gas exploration and production company with operations in South America.

Note 2.  	Basis of Presentation	
 
Our accompanying interim condensed combined financial statements are unaudited and do not include all disclosures required in annual financial statements and therefore should be read in conjunction with the combined financial statements and notes thereto of the Company as of December 31, 2010 and 2009 and for each of the three years in the period ended December 31, 2010, included elsewhere in this registration statement. The accompanying unaudited condensed combined financial statements include all normal recurring adjustments that, in the opinion of our management, are necessary to present fairly our financial position at June 30, 2011 and our results of operations, changes in equity, and cash flows for the six months ended June 30, 2011 and 2010.
 
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the condensed combined financial statements and accompanying notes. Actual results could differ from those estimates.
 
Discontinued operations
 
The accompanying condensed combined financial statements and notes reflect the results of operations and financial position of our Arkoma Basin operations as discontinued operations for all periods (See Note 3).
 
Unless indicated otherwise, the information in the Notes to Condensed Combined Financial Statements relates to our continuing operations.

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Table of Contents

WPX Energy
 
Notes to Condensed Combined Financial Statements—(Continued)
 
Accounting Standards Issued But Not Yet Adopted
 
In May 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update No. 2011-4, “Fair Value Measurement (Topic 820) Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS” (ASU 2011-4). ASU 2011-4 primarily eliminates the differences in fair value measurement principles between the FASB and International Accounting Standards Board. It clarifies existing guidance, changes certain fair value measurements and requires expanded disclosure primarily related to Level 3 measurements and transfers between Level 1 and Level 2 of the fair value hierarchy. ASU 2011-4 is effective on a prospective basis for interim and annual periods beginning after December 15, 2011. We are assessing the application of this Update to our combined financial statements.
 
In June 2011, the FASB issued Accounting Standards Update No. 2011-5, “Comprehensive Income (Topic 220) Presentation of Comprehensive Income” (ASU 2011-5). ASU 2011-5 requires presentation of net income and other comprehensive income either in a single continuous statement or in two separate, but consecutive, statements. The Update requires separate presentation in both net income and other comprehensive income of reclassification adjustments for items that are reclassified from other comprehensive income to net income. The new guidance does not change the items reported in other comprehensive income, nor affect how earnings per share is calculated and presented. We currently report net income in the combined statement of operations and report other comprehensive income in the combined statement of equity. The standard is effective beginning the first quarter of 2012, with a retrospective application to prior periods. We plan to apply the new presentation beginning in 2012.
 
Unaudited Supplemental pro forma balance sheet and pro forma combined loss per share
 
Inasmuch as our planned separation from Williams requires us to make a distribution from the Offering proceeds, which is not reflected in the historical June 30, 2011 balance sheet, and since the distribution is in excess of our combined estimated Offering proceeds and last twelve months’ earnings, we have presented a supplemental unaudited pro forma balance sheet as of June 30, 2011, and also given effect to this via supplemental pro forma combined earnings/loss per share. For pro forma purposes, this distribution is considered a dividend to Williams.
 
Basic and diluted pro forma combined loss per share for the six months ended June 30, 2011 were calculated using the assumed issuance of           Class A common shares from the Offering, and the assumed issuance of           Class B common shares to Williams in exchange for all of the net assets contributed to us by Williams. Additionally, for purposes of calculating basic and diluted pro forma combined loss per share, our historical net income was decreased by $45 million to reflect incremental interest expense (net of tax) related to the portion of the $1,684 million distribution that exceeds the proceeds from the Offering and our earnings for the previous twelve months.

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Table of Contents

WPX Energy
 
Notes to Condensed Combined Financial Statements—(Continued)

Note 3.  	Discontinued Operations	
 
Summarized Results of Discontinued Operations

 	 	Six Months Ended June 30,	 	
 	 	2011	 	 	2010	 	
 	 	(Millions)	 	
 		
Revenues	 	$	7	 	 	$	9	 	
 	 	 	 	 	 	 	 	 	
Loss from discontinued operations before impairment and income taxes	 	$	(2	)	 	$	(2	)	
Impairment of producing properties	 	 	(11	)	 	 	—	 	
Benefit for income taxes	 	 	5	 	 	 	1	 	
 	 	 	 	 	 	 	 	 	
Loss from discontinued operations	 	$	(8	)	 	$	(1	)	

 
Impairment in 2011 reflects a write-down to an estimate of fair value less costs to sell the assets of our Arkoma Basin operations that were classified as held for sale as of June 30, 2011. This nonrecurring fair value measurement, which falls within Level 3 of the fair value hierarchy, was based on a probability-weighted discounted cash flow analysis that included offers we have received on the assets.
 
The assets of our discontinued operations comprise significantly less than one percent of our total combined assets as of June 30, 2011, and December 31, 2010, and are reported within other current assets and other noncurrent assets, respectively, on our Condensed Combined Balance Sheet. Liabilities of our discontinued operations are insignificant for these periods.

4.  	Related Party Transactions	
 
Transactions with Williams and Other Affiliated Entities
 
Below is a summary of the related party transactions for the three months ended June 30, 2011 and 2010:

 	 	Six Months	 	
 	 	Ended	 	
 	 	June 30,	 	
 	 	2011	 	 	2010	 	
 	 	(Millions)	 	
 		
Oil and gas sales revenues — sales of NGLs to WPZ	 	$	178	 	 	$	127	 	
Gas management revenues — sales of natural gas for fuel and shrink to WPZ and another Williams subsidiary	 	 	254	 	 	 	277	 	
Lease and facility operating expenses from Williams-direct employee salary and benefit costs	 	 	10	 	 	 	12	 	
Gathering, processing and transportation expense from WPZ:	 	 	 	 	 	 	 	 	
Gathering and processing	 	 	158	 	 	 	67	 	
Transportation	 	 	20	 	 	 	11	 	
General and administrative from Williams:	 	 	 	 	 	 	 	 	
Direct employee salary and benefit costs	 	 	54	 	 	 	49	 	
Charges for general and administrative services	 	 	30	 	 	 	28	 	
Allocated general corporate costs	 	 	30	 	 	 	32	 	
Other	 	 	7	 	 	 	6	 	
Interest expense on notes payable to Williams	 	 	94	 	 	 	49	 	

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Table of Contents

WPX Energy
 
Notes to Condensed Combined Financial Statements—(Continued)
 
Daily cash activity from our domestic operations was transferred to or from Williams on a regular basis and was recorded as increases or decreases in the balance due under unsecured promissory notes we had in place with Williams through June 30, 2011, at which time the notes were cancelled by Williams. The amount due to Williams at the time of cancellation was $2.4 billion and is reflected as an increase in owner’s net investment.
 
As previously discussed, our domestic operations were contributed to WPX Energy, Inc. on July 1, 2011. As of June 30, 2011, certain entities that were contributed to us on July 1, 2011 withdrew from Williams’ benefit plans and terminated their personnel services agreements with Williams’ payroll companies. Simultaneously, two new administrative services entities owned and controlled by Williams executed new personnel services agreements with the payroll companies and joined the Williams plans as participants. The effect of these transactions is that none of the companies contributed to WPX Energy has any employees as of June 30, 2011. The services entities employ all personnel that provide services to WPX Energy and remain owned and controlled 100% by Williams.
 
In addition, the current amount due to or from affiliates consists of normal course receivables and payables resulting from the sale of products to and cost of gathering services provided by WPZ. Below is a summary of these payables and receivables which are settled monthly:

 	 	June 30,	 	 	December 31,	 	
 	 	2011	 	 	2010	 	
 	 	(Millions)	 	
 		
Current:	 	 	 	 	 	 	 	 	
Accounts receivable:	 	 	 	 	 	 	 	 	
Due from WPZ and another Williams subsidiary	 	$	57	 	 	$	60	 	
 	 	 	 	 	 	 	 	 	
Accounts payable:	 	 	 	 	 	 	 	 	
Due to WPZ	 	$	16	 	 	$	12	 	
Due to Williams for cash overdraft	 	 	37	 	 	 	38	 	
Due to Williams for accrued payroll and benefits	 	 	10	 	 	 	14	 	
 	 	 	 	 	 	 	 	 	
 	 	$	63	 	 	$	64	 	
 	 	 	 	 	 	 	 	 	
Current derivative asset with WPZ	 	$	5	 	 	$	—	 	
 	 	 	 	 	 	 	 	 	
Current derivative liability with WPZ	 	$	5	 	 	$	—	 	

 
		
Note 5.  	Exploration Expenses	
 
The following presents a summary of exploration expenses:

 	 	Six Months	 	
 	 	Ended	 	
 	 	June 30,	 	
 	 	2011	 	 	2010	 	
 	 	(Millions)	 	
 		
Geologic and geophysical costs	 	$	3	 	 	$	10	 	
Dry hole costs	 	 	1	 	 	 	—	 	
Unproved leasehold property impairment, amortization and expiration	 	 	29	 	 	 	8	 	
 	 	 	 	 	 	 	 	 	
Total exploration expense	 	$	33	 	 	$	18	 	

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Table of Contents

WPX Energy
 
Notes to Condensed Combined Financial Statements—(Continued)

Note 6.  	Inventories	

 	 	June 30,	 	 	December 31,	 	
 	 	2011	 	 	2010	 	
 	 	(Millions)	 	
 		
Natural gas in underground storage	 	$	31	 	 	$	31	 	
Materials, supplies and other	 	 	39	 	 	 	46	 	
 	 	 	 	 	 	 	 	 	
Total inventories	 	$	70	 	 	$	77	 	

 
		
Note 7.  	Provision for Income Taxes	
 
The provision for income taxes includes:

 	 	Six Months	 	
 	 	Ended	 	
 	 	June 30,	 	
 	 	2011	 	 	2010	 	
 	 	(Millions)	 	
 		
Current:	 	 	 	 	 	 	 	 	
Federal	 	$	24	 	 	$	49	 	
State	 	 	2	 	 	 	(4	)	
Foreign	 	 	5	 	 	 	5	 	
 	 	 	 	 	 	 	 	 	
 	 	 	31	 	 	 	50	 	
Deferred:	 	 	 	 	 	 	 	 	
Federal	 	 	(11	)	 	 	7	 	
State	 	 	(1	)	 	 	5	 	
Foreign	 	 	—	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	
 	 	 	(12	)	 	 	12	 	
 	 	 	 	 	 	 	 	 	
Total provision	 	$	19	 	 	$	62	 	

 
The effective income tax rate on the total provision for the six months ended June 30, 2011 is less than the federal statutory rate due primarily to taxes on foreign operations offset with the effect of state income taxes.
 
The effective income tax rate on the total provision for the six months ended June 30, 2010, is greater than the federal statutory rate due primarily to the effect of state income taxes and taxes on foreign operations.
 
During the next twelve months, we do not expect ultimate resolution of any uncertain tax position will result in a significant increase or decrease of our unrecognized tax benefit.

Note 8.  	Contingent Liabilities and Commitments	
 
Royalty litigation
 
In September 2006, royalty interest owners in Garfield County, Colorado, filed a class action suit in District Court, Garfield County Colorado, alleging we improperly calculated oil and gas royalty payments, failed to account for the proceeds that we received from the sale of natural gas and extracted products, improperly charged certain expenses and failed to refund amounts withheld in excess of ad valorem tax obligations. Plaintiffs sought to certify as a class of royalty interest owners, recover underpayment of royalties and obtain corrected payments resulting from calculation errors. We entered into a final partial settlement agreement. The partial settlement agreement defined the class members for class certification, reserved two claims for court resolution, resolved all other class claims relating to past calculation of royalty and overriding royalty payments, and established certain rules to govern future royalty and overriding royalty payments. This

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Table of Contents

WPX Energy
 
Notes to Condensed Combined Financial Statements—(Continued)
 
settlement resolved all claims relating to past withholding for ad valorem tax payments and established a procedure for refunds of any such excess withholding in the future. The first reserved claim is whether we are entitled to deduct in our calculation of royalty payments a portion of the costs we incur beyond the tailgates of the treating or processing plants for mainline pipeline transportation. We received a favorable ruling on our motion for summary judgment on the first reserved claim. Plaintiffs appealed that ruling and the Colorado Court of Appeals found in our favor in April 2011. In June 2011, Plaintiffs filed a Petition for Certiorari with the Colorado Supreme Court. We anticipate that Court will issue a decision on whether to grant further review later in 2011 or early in 2012. The second reserved claim relates to whether we are required to have proportionately increased the value of natural gas by transporting that gas on mainline transmission lines and, if required, whether we did so and are thus entitled to deduct a proportionate share of transportation costs in calculating royalty payments. We anticipate trial on the second reserved claim following resolution of the first reserved claim. We believe our royalty calculations have been properly determined in accordance with the appropriate contractual arrangements and Colorado law. At this time, the plaintiffs have not provided us a sufficient framework to calculate an estimated range of exposure related to their claims. However, it is reasonably possible that the ultimate resolution of this item could result in a future charge that may be material to our results of operations.
 
Other producers have been in litigation or discussions with a federal regulatory agency and a state agency in New Mexico regarding certain deductions, comprised primarily of processing, treating and transportation costs, used in the calculation of royalties. Although we are not a party to these matters, we have monitored them to evaluate whether their resolution might have the potential for unfavorable impact on our results of operations. One of these matters involving federal litigation was decided on October 5, 2009. The resolution of this specific matter is not material to us. However, other related issues in these matters that could be material to us remain outstanding. We received notice from the U.S. Department of Interior Office of Natural Resources Revenue (ONRR) in the fourth quarter of 2010, intending to clarify the guidelines for calculating federal royalties on conventional gas production applicable to our federal leases in New Mexico. The ONRR’s guidance provides its view as to how much of a producer’s bundled fees for transportation and processing can be deducted from the royalty payment. We believe using these guidelines would not result in a material difference in determining our historical federal royalty payments for our leases in New Mexico. No similar specific guidance has been issued by ONRR for leases in other states, but such guidelines are expected in the future. However, the timing of receipt of the necessary guidelines is uncertain. In addition, these interpretive guidelines on the applicability of certain deductions in the calculation of federal royalties are extremely complex and will vary based upon the ONRR’s assessment of the configuration of processing, treating and transportation operations supporting each federal lease. From January 2004 through December 2010, our deductions used in the calculation of the royalty payments in states other than New Mexico associated with conventional gas production total approximately $55 million. Correspondence in 2009 with the ONRR’s predecessor did not take issue with our calculation regarding the Piceance Basin assumptions which we believe have been consistent with the requirements. The issuance of similar guidelines in Colorado and other states could affect our previous royalty payments and the effect could be material to our results of operations.
 
Environmental matters
 
The EPA and various state regulatory agencies routinely promulgate and propose new rules, and issue updated guidance to existing rules. These new rules and rulemakings include, but are not limited to, rules for reciprocating internal combustion engine maximum achievable control technology, new air quality standards for ground level ozone, and one hour nitrogen dioxide emission limits. We are unable to estimate the costs of asset additions or modifications necessary to comply with these new regulations due to uncertainty created by the various legal challenges to these regulations and the need for further specific regulatory guidance.

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Table of Contents

WPX Energy
 
Notes to Condensed Combined Financial Statements—(Continued)
 
Matters related to Williams’ former power business
 
California energy crisis
 
Our former power business was engaged in power marketing in various geographic areas, including California. Prices charged for power by us and other traders and generators in California and other western states in 2000 and 2001 were challenged in various proceedings, including those before the FERC. We have entered into settlements with the State of California (State Settlement), major California utilities (Utilities Settlement), and others that substantially resolved each of these issues with these parties.
 
Although the State Settlement and Utilities Settlement resolved a significant portion of the refund issues among the settling parties, we continue to have potential refund exposure to nonsettling parties, including various California end users that did not participate in the Utilities Settlement. We are currently in settlement negotiations with certain California utilities aimed at eliminating or substantially reducing this exposure. If successful, and subject to a final “true-up” mechanism, the settlement agreement would also resolve our collection of accrued interest from counterparties as well as our payment of accrued interest on refund amounts. Thus, as currently contemplated by the parties, the settlement agreement would resolve most, if not all, of our legal issues arising from the 2000-2001 California Energy Crisis. With respect to these matters, amounts accrued are not material to our financial position.
 
Certain other issues also remain open at the FERC and for other nonsettling parties.
 
Reporting of natural gas-related information to trade publications
 
Civil suits based on allegations of manipulating published gas price indices have been brought against us and others, in each case seeking an unspecified amount of damages. We are currently a defendant in class action litigation and other litigation originally filed in state court in Colorado, Kansas, Missouri and Wisconsin brought on behalf of direct and indirect purchasers of natural gas in those states. These cases were transferred to the federal court in Nevada. In 2008, the court granted summary judgment in the Colorado case in favor of us and most of the other defendants based on plaintiffs’ lack of standing. On January 8, 2009, the court denied the plaintiffs’ request for reconsideration of the Colorado dismissal and entered judgment in our favor. We expect that the Colorado plaintiffs will appeal now that the court’s order became final on July 18, 2011.
 
In the other cases, on July 18, 2011, the Nevada district court granted our joint motions for summary judgment to preclude the plaintiffs’ state law claims because the federal Natural Gas Act gives the FERC exclusive jurisdiction to resolve those issues. The court also denied the plaintiffs’ class certification motion as moot. On July 22, 2011, the plaintiffs filed their notice of appeal with the Nevada district court. Because of the uncertainty around these current pending unresolved issues, including an insufficient description of the purported classes and other related matters, we cannot reasonably estimate a range of potential exposures at this time. However, it is reasonably possible that the ultimate resolution of these items could result in future charges that may be material to our results of operations.
 
Other Divestiture Indemnifications
 
Pursuant to various purchase and sale agreements relating to divested businesses and assets, we have indemnified certain purchasers against liabilities that they may incur with respect to the businesses and assets acquired from us. The indemnities provided to the purchasers are customary in sale transactions and are contingent upon the purchasers incurring liabilities that are not otherwise recoverable from third parties. The indemnities generally relate to breach of warranties, tax, historic litigation, personal injury, environmental matters, right of way and other representations that we have provided.
 
At June 30, 2011, we do not expect any of the indemnities provided pursuant to the sales agreements to have a material impact on our future financial position. However, if a claim for indemnity is brought against

F-18

Table of Contents

WPX Energy
 
Notes to Condensed Combined Financial Statements—(Continued)
 
us in the future, it may have a material adverse effect on our results of operations in the period in which the claim is made.
 
In addition to the foregoing, various other proceedings are pending against us which are incidental to our operations.
 
Summary
 
Litigation, arbitration, regulatory matters, and environmental matters are subject to inherent uncertainties. Were an unfavorable ruling to occur, there exists the possibility of a material adverse impact on the results of operations in the period in which the ruling occurs. As of June 30, 2011 and December 31, 2010, the Company had accrued approximately $23 million and $21 million, respectively, for loss contingencies associated with royalty litigation, reporting of natural gas information to trade publications and other contingencies. Management, including internal counsel, currently believes that the ultimate resolution of the foregoing matters, taken as a whole and after consideration of amounts accrued, insurance coverage, recovery from customers or other indemnification arrangements, is not expected to have a materially adverse effect upon our future liquidity or financial position; however, it could be material to our results of operations in any given year.
 
Commitments
 
As part of managing our commodity price risk, we utilize contracted pipeline capacity (including capacity on affiliates’ systems, resulting in a total of $420 million for all years) primarily to move our natural gas production to other locations in an attempt to obtain more favorable pricing differentials. Our commitments under these contracts as of June 30, 2011 are as follows:

 	 	(Millions)	 	
 		
Remainder of 2011	 	$	102	 	
2012	 	 	216	 	
2013	 	 	207	 	
2014	 	 	177	 	
2015	 	 	166	 	
Thereafter	 	 	633	 	
 	 	 	 	 	
Total	 	$	1,501	 	

 
We also have certain commitments to an equity investee and others, primarily for natural gas gathering and treating services and well completion services, which total $803 million over approximately seven years.
 
We hold a long-term obligation to deliver on a firm basis 200,000 MMBtu per day of natural gas to a buyer at the White River Hub (Greasewood-Meeker, Colorado), which is the major market hub exiting the Piceance Basin. This obligation expires in 2014.
 
In connection with a gathering agreement entered into by WPZ with a third party in December 2010, we concurrently agreed to buy up to 200,000 MMBtu per day of natural gas at Transco Station 515 (Marcellus Basin) at market prices from the same third party. Purchases under the 12-year contract are expected to begin in the third quarter of 2011. We expect to sell this natural gas in the open market and may utilize available transportation capacity to facilitate the sales.

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Table of Contents

WPX Energy
 
Notes to Condensed Combined Financial Statements—(Continued)
 
Future minimum annual rentals under noncancelable operating leases as of June 30, 2011, are payable as follows:

 	 	(Millions)	 	
 		
Remainder of 2011	 	$	20	 	
2012	 	 	62	 	
2013	 	 	57	 	
2014	 	 	48	 	
2015	 	 	24	 	
Thereafter	 	 	15	 	
 	 	 	 	 	
Total	 	$	226	 	

 
		
Note 9.  	Fair Value Measurements	
 
The following table presents, by level within the fair value hierarchy, our assets and liabilities that are measured at fair value on a recurring basis.

 	 	June 30, 2011	 	December 31, 2010	
 	 	Level 1	 	Level 2	 	Level 3	 	Total	 	Level 1	 	Level 2	 	Level 3	 	Total	
 	 	 	 	(Millions)	 	 	 	 	 	(Millions)	 	 	
 		
Energy derivative assets	 	$	46	 	 	$	358	 	 	$	3	 	 	$	407	 	 	$	97	 	 	$	474	 	 	$	2	 	 	$	573	 	
Energy derivative liabilities	 	$	41	 	 	$	177	 	 	$	2	 	 	$	220	 	 	$	78	 	 	$	210	 	 	$	1	 	 	$	289	 	

Energy derivatives include commodity based exchange-traded contracts and over the counter (OTC) contracts. Exchange-traded contracts include futures, swaps, and options. OTC contracts include forwards, swaps and options.
 
Many contracts have bid and ask prices that can be observed in the market. Our policy is to use a mid-market pricing (the mid-point price between bid and ask prices) convention to value individual positions and then adjust on a portfolio level to a point within the bid and ask range that represents our best estimate of fair value. For offsetting positions by location, the mid-market price is used to measure both the long and short positions.
 
The determination of fair value for our assets and liabilities also incorporates the time value of money and various credit risk factors which can include the credit standing of the counterparties involved, master netting arrangements, the impact of credit enhancements (such as cash collateral posted and letters of credit) and our nonperformance risk on our liabilities. The determination of the fair value of our liabilities does not consider noncash collateral credit enhancements.
 
Exchange-traded contracts include New York Mercantile Exchange and Intercontinental Exchange contracts and are valued based on quoted prices in these active markets and are classified within Level 1.
 
Forward, swap, and option contracts included in Level 2 are valued using an income approach including present value techniques and option pricing models. Option contracts, which hedge future sales of our production, are structured as costless collars and are financially settled. They are valued using an industry standard Black-Scholes option pricing model. Significant inputs into our Level 2 valuations include commodity prices, implied volatility by location, and interest rates, as well as considering executed transactions or broker quotes corroborated by other market data. These broker quotes are based on observable market prices at which transactions could currently be executed. In certain instances where these inputs are not observable for all periods, relationships of observable market data and historical observations are used as a means to estimate fair value. Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2.

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WPX Energy
 
Notes to Condensed Combined Financial Statements—(Continued)
 
Our energy derivatives portfolio is largely comprised of exchange-traded products or like products and the tenure of our derivatives portfolio is relatively short with more than 99 percent of the net fair value of our derivatives portfolio expiring in the next 18 months. Due to the nature of the products and tenure, we are consistently able to obtain market pricing. All pricing is reviewed on a daily basis and is formally validated with broker quotes and documented on a monthly basis.
 
Certain instruments trade with lower availability of pricing information. These instruments are valued with a present value technique using inputs that may not be readily observable or corroborated by other market data. These instruments are classified within Level 3 when these inputs have a significant impact on the measurement of fair value. The instruments included in Level 3 at June 30, 2011, consist primarily of natural gas index transactions that are used to manage our physical requirements.
 
Reclassifications of fair value between Level 1, Level 2, and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. No significant transfers between Level 1 and Level 2 occurred during the period ended June 30, 2011 or 2010. During the period ended June 30, 2011, certain NGL swaps that originated during the first quarter of 2011 were transferred from Level 3 to Level 2. Prior to March 31, 2011, these swaps were considered Level 3 due to a lack of observable third-party market quotes. Due to an increase in exchange traded transactions and greater visibility from OTC trading, we transferred these instruments to Level 2.
 
The following table presents a reconciliation of changes in the fair value of our net energy derivatives classified as Level 3 in the fair value hierarchy.
 
Level 3 Fair Value Measurements Using Significant Unobservable Inputs

 	 	Six Months Ended June 30,	 	
 	 	2011	 	 	2010	 	
 	 	(Millions)	 	
 		
Beginning balance	 	$	1	 	 	$	1	 	
Realized and unrealized gains included in income from continuing operations	 	 	8	 	 	 	1	 	
Settlements	 	 	(5	)	 	 	(1	)	
Transfers into Level 3	 	 	—	 	 	 	—	 	
Transfers out of Level 3	 	 	(3	)	 	 	—	 	
 	 	 	 	 	 	 	 	 	
Ending balance	 	$	1	 	 	$	1	 	
 	 	 	 	 	 	 	 	 	
Unrealized gains included in income from continuing operations relating to instruments still held at June 30	 	$	—	 	 	$	—	 	

 
Realized and unrealized gains included in income from continuing operations for the above periods are reported in revenues in our Condensed Combined Statement of Operations.

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WPX Energy
 
Notes to Condensed Combined Financial Statements—(Continued)

Note 10.  	Financial Instruments, Derivatives, Guarantees, and Concentration of Credit Risk	
 
Financial Instruments
 
Fair-value methods
 
We use the following methods and assumptions in estimating our fair-value disclosures for financial instruments:
 
Cash and cash equivalents and restricted cash :  The carrying amounts reported in the Condensed Combined Balance Sheet approximate fair value due to the nature of the instrument and/or the short-term maturity of these instruments.
 
Other :  Includes margin deposits and customer margin deposits payable for which the amounts reported in the Condensed Combined Balance Sheet approximate fair value.
 
Energy derivatives :  Energy derivatives include futures, forwards, swaps, and options. These are carried at fair value in the Condensed Combined Balance Sheet. See Note 9 for a discussion of the valuation of our energy derivatives.
 
Carrying amounts and fair values of our financial instruments were as follows:

 	 	June 30, 2011	 	 	December 31, 2010	 	
 	 	Carrying	 	 	Fair	 	 	Carrying	 	 	Fair	 	
Asset (Liability)	 	Amount	 	 	Value	 	 	Amount	 	 	Value	 	
 	 	 	 	 	(Millions)	 	 	 	 	
 		
Cash and cash equivalents	 	$	36	 	 	$	36	 	 	$	37	 	 	$	37	 	
Restricted cash	 	$	29	 	 	$	29	 	 	$	24	 	 	$	24	 	
Other	 	$	5	 	 	$	5	 	 	$	(25	)	 	$	(25	)	
Net energy derivatives:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Energy commodity cash flow hedges	 	$	182	 	 	$	182	 	 	$	266	 	 	$	266	 	
Other energy derivatives	 	$	5	 	 	$	5	 	 	$	18	 	 	$	18	 	

Energy Commodity Derivatives
 
Risk management activities
 
We are exposed to market risk from changes in energy commodity prices within our operations. We utilize derivatives to manage exposure to the variability in expected future cash flows from forecasted sales of natural gas and crude oil attributable to commodity price risk. Certain of these derivatives utilized for risk management purposes have been designated as cash flow hedges, while other derivatives have not been designated as cash flow hedges or do not qualify for hedge accounting despite hedging our future cash flows on an economic basis.
 
We produce, buy, and sell natural gas and crude oil at different locations throughout the United States. To reduce exposure to a decrease in revenues from fluctuations in natural gas and crude oil market prices, we enter into natural gas and crude oil futures contracts, swap agreements, and financial option contracts to mitigate the price risk on forecasted sales of natural gas and crude oil. We have also entered into basis swap agreements to reduce the locational price risk associated with our producing basins. Those agreements and contracts designated as cash flow hedges are expected to be highly effective in offsetting cash flows attributable to the hedged risk during the term of the hedge. However, ineffectiveness may be recognized primarily as a result of locational differences between the hedging derivative and the hedged item. Our financial option contracts are either purchased options or a combination of options that comprise a net purchased option or a zero-cost collar.

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WPX Energy
 
Notes to Condensed Combined Financial Statements—(Continued)
 
The following table sets forth the derivative volumes designated as hedges of production volumes as of June 30, 2011:

 	 	 	 	 	 	 	 	 	 	 	 	Weighted Average	
 	 	 	 	 	 	 	 	 	Notional	 	 	Price	
Commodity	 	Period	 	 	Contract Type	 	Location	 	Volume (BBtu)	 	 	($/MMBtu)	
 		
Natural Gas	 	 	Jul-Dec 2011	 	 	Costless Collar	 	Rockies	 	 	8,280	 	 	$5.30 - $7.10	
Natural Gas	 	 	Jul-Dec 2011	 	 	Costless Collar	 	San Juan	 	 	16,560	 	 	$5.27 - $7.06	
Natural Gas	 	 	Jul-Dec 2011	 	 	Costless Collar	 	MidCon	 	 	14,720	 	 	$5.10 - $7.00	
Natural Gas	 	 	Jul-Dec 2011	 	 	Costless Collar	 	SoCal	 	 	5,520	 	 	$5.83 - $7.56	
Natural Gas	 	 	Jul-Dec 2011	 	 	Costless Collar	 	Northeast	 	 	5,520	 	 	$6.50 - $8.14	
Natural Gas	 	 	Jul-Dec 2011	 	 	Location Swaps	 	Rockies	 	 	17,480	 	 	$5.31	
Natural Gas	 	 	Jul-Dec 2011	 	 	Location Swaps	 	San Juan	 	 	20,240	 	 	$5.10	
Natural Gas	 	 	Jul-Dec 2011	 	 	Location Swaps	 	MidCon	 	 	4,600	 	 	$5.05	
Natural Gas	 	 	Jul-Dec 2011	 	 	Location Swaps	 	SoCal	 	 	7,360	 	 	$4.95	
Natural Gas	 	 	Jul-Dec 2011	 	 	Location Swaps	 	Northeast	 	 	21,150	 	 	$5.40	
Natural Gas	 	 	2012	 	 	Location Swaps	 	Rockies	 	 	49,410	 	 	$4.76	
Natural Gas	 	 	2012	 	 	Location Swaps	 	San Juan	 	 	40,260	 	 	$4.94	
Natural Gas	 	 	2012	 	 	Location Swaps	 	MidCon	 	 	32,025	 	 	$4.76	
Natural Gas	 	 	2012	 	 	Location Swaps	 	SoCal	 	 	11,895	 	 	$5.14	
Natural Gas	 	 	2012	 	 	Location Swaps	 	Northeast	 	 	52,460	 	 	$5.58	
Natural Gas	 	 	2013	 	 	Location Swaps	 	Northeast	 	 	1,800	 	 	$6.48	
 	 	 	 	 	 	 	 	 	Notional	 	 	Weighted Average	

Commodity	 	Period	 	 	Contract Type	 	Location	 	Volume (Mbbls)	 	 	Price ($/Bbl)	
 		
Crude Oil	 	 	Jul-Dec 2011	 	 	Business Day Avg Swaps	 	WTI	 	 	782	 	 	$96.31	
Crude Oil	 	 	2012	 	 	Business Day Avg Swaps	 	WTI	 	 	2,624	 	 	$97.32	

We also enter into forward contracts to buy and sell natural gas to maximize the economic value of transportation agreements and storage capacity agreements. To reduce exposure to a decrease in margins from fluctuations in natural gas market prices, we may enter into futures contracts, swap agreements, and financial option contracts to mitigate the price risk associated with these contracts. Hedges for transportation contracts are designated as cash flow hedges and are expected to be highly effective in offsetting cash flows attributable to the hedged risk during the term of the hedge. However, ineffectiveness may be recognized primarily as a result of locational differences between the hedging derivative and the hedged item. Hedges for storage contracts have not been designated as hedging instruments, despite economically hedging the expected cash flows generated by those agreements.
 
We also enter into energy commodity derivatives for other than risk management purposes, including managing certain remaining legacy natural gas contracts and positions from our former power business and providing services to third parties and affiliated entities. These legacy natural gas contracts include substantially offsetting positions and have an insignificant net impact on earnings.
 
The following table depicts the notional amounts of the net long (short) positions which we did not designate as hedges of our production in our commodity derivatives portfolio as of June 30, 2011. Natural gas is presented in millions of British Thermal Units (MMBtu). All of the Central hub risk realizes by March 31, 2012 and 100% of the basis risk realizes by 2013. The net index position includes contracts for the future sale of physical natural gas related to our production. Offsetting these sales are contracts for the future production

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WPX Energy
 
Notes to Condensed Combined Financial Statements—(Continued)
 
of physical natural gas related to WPZ’s natural gas shrink requirements. These contracts result in minimal commodity price risk exposure and have a value of less than $1 million at June 30, 2011.

 	 	Unit of	 	Central Hub	 	Basis	 	Index	
Derivative Notional Volumes	 	Measure	 	Risk(a)(d)	 	Risk(b)	 	Risk(c)	
 		
Not Designated as Hedging Instruments	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Risk Management	 	 	MMBtu	 	 	 	(12,940,000	)	 	 	(15,965,000	)	 	 	(46,487,263	)	
Other	 	 	MMBtu	 	 	 	—	 	 	 	(8,007,500	)	 	 	 	 	

 
			
(a)		includes physical and financial derivative transactions that settle against the Henry Hub price;	
 		
(b)		includes financial derivative transactions priced off the difference in value between the Central Hub and another specific delivery point;	
 		
(c)		includes physical derivative transactions at an unknown future price, including purchases of 113,089,081 MMBtu primarily on behalf of WPZ and sales of 159,576,344 MMBtu.	
 		
(d)		includes financial derivatives entered into with WPZ to reduce its exposure to decreases in its revenues from fluctuations in NGL market prices or increases in costs and operating expenses from fluctuations in natural gas market prices. These contracts are offset by 3rd party agreements.	
 
Fair values and gains (losses)
 
The following table presents the fair value of energy commodity derivatives. Our derivatives are presented as separate line items in our Condensed Combined Balance Sheet as current and noncurrent derivative assets and liabilities. Derivatives are classified as current or noncurrent based on the contractual timing of expected future net cash flows of individual contracts. The expected future net cash flows for derivatives classified as current are expected to occur within the next 12 months. The fair value amounts are presented on a gross basis and do not reflect the netting of asset and liability positions permitted under the terms of our master netting arrangements. Further, the amounts below do not include cash held on deposit in margin accounts that we have received or remitted to collateralize certain derivative positions.

 	 	June 30, 2011	 	 	December 31, 2010	 	
 	 	Assets	 	 	Liabilities	 	 	Assets	 	 	Liabilities	 	
 	 	 	 	 	(Millions)	 	 	 	 	
 		
Designated as hedging instruments	 	$	207	 	 	$	25	 	 	$	288	 	 	$	22	 	
Not designated as hedging instruments:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Legacy natural gas contracts from former power business	 	 	174	 	 	 	173	 	 	 	186	 	 	 	187	 	
All other	 	 	26	 	 	 	22	 	 	 	99	 	 	 	80	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total derivatives not designated as hedging instruments	 	 	200	 	 	 	195	 	 	 	285	 	 	 	267	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total derivatives	 	$	407	 	 	$	220	 	 	$	573	 	 	$	289	 	

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WPX Energy
 
Notes to Condensed Combined Financial Statements—(Continued)
 
The following table presents pre-tax gains and losses for our energy commodity derivatives designated as cash flow hedges, as recognized in accumulated other comprehensive income (AOCI) or revenues.

 	 	Six Months Ended	 	 	 	 	
 	 	June 30,	 	 	 	 	
 	 	2011	 	 	2010	 	 	Classification	 	
 	 	(Millions)	 	 	 	 	
 		
Net gain recognized in other comprehensive income (loss) (effective portion)	 	$	58	 	 	$	294	 	 	 	AOCI	 	
Net gain reclassified from AOCI into income (effective portion)	 	$	142	 	 	$	130	 	 	 	Revenues	 	
Gain recognized in income (ineffective portion)	 	$	—	 	 	$	3	 	 	 	Revenues	 	

There were no gains or losses recognized in income as a result of excluding amounts from the assessment of hedge effectiveness.
 
The following table presents pre-tax gains and losses for our energy commodity derivatives not designated as hedging instruments.

 	 	Six Months Ended June 30,	 	
 	 	2011	 	 	2010	 	
 	 	(Millions)	 	
 		
Gas management revenues	 	$	7	 	 	$	14	 	
Gas management expenses	 	 	—	 	 	 	7	 	
 	 	 	 	 	 	 	 	 	
Net gain	 	$	7	 	 	$	7	 	

 
The cash flow impact of our derivative activities is presented in the Condensed Combined Statement of Cash Flows as changes in current and noncurrent derivative assets and liabilities .
 
Credit-risk-related features
 
Certain of our derivative contracts contain credit-risk-related provisions that would require us, in certain circumstances, to post additional collateral in support of our net derivative liability positions. These credit-risk-related provisions require us to post collateral in the form of cash or letters of credit when our net liability positions exceed an established credit threshold. The credit thresholds are typically based on our senior unsecured debt ratings from Standard and Poor’s and/or Moody’s Investors Service. Under these contracts, a credit ratings decline would lower our credit thresholds, thus requiring us to post additional collateral. We also have contracts that contain adequate assurance provisions giving the counterparty the right to request collateral in an amount that corresponds to the outstanding net liability. Additionally, we have an unsecured credit agreement with certain banks related to hedging activities. We are not required to provide collateral support for net derivative liability positions under the credit agreement as long as the value of our domestic natural gas reserves, as determined under the provisions of the agreement, exceeds by a specified amount certain of its obligations including any outstanding debt and the aggregate out-of-the-money position on hedges entered into under the credit agreement.
 
As of June 30, 2011, we did not have any collateral posted to derivative counterparties to support the aggregate fair value of our net $21 million derivative liability position (reflecting master netting arrangements in place with certain counterparties), which includes a reduction of significantly less than $1 million to our liability balance for our own nonperformance risk. At December 31, 2010, we had collateral totaling $8 million posted to derivative counterparties, all of which was in the form of letters of credit, to support the aggregate fair value of our net derivative liability position (reflecting master netting arrangements in place with certain counterparties) of $36 million, which included a reduction of less than $1 million to our liability balance for

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WPX Energy
 
Notes to Condensed Combined Financial Statements—(Continued)
 
our own nonperformance risk. The additional collateral that we would have been required to post, assuming our credit thresholds were eliminated and a call for adequate assurance under the credit risk provisions in our derivative contracts was triggered, was $21 million and $29 million at June 30, 2011 and December 31, 2010, respectively.
 
Cash flow hedges
 
Changes in the fair value of our cash flow hedges, to the extent effective, are deferred in AOCI and reclassified into earnings in the same period or periods in which the hedged forecasted purchases or sales affect earnings, or when it is probable that the hedged forecasted transaction will not occur by the end of the originally specified time period. As of June 30, 2011, we have hedged portions of future cash flows associated with anticipated energy commodity purchases and sales for up to two years. Based on recorded values at June 30, 2011, $98 million of net gains (net of income tax provision of $59 million) will be reclassified into earnings within the next year. These recorded values are based on market prices of the commodities as of June 30, 2011. Due to the volatile nature of commodity prices and changes in the creditworthiness of counterparties, actual gains or losses realized within the next year will likely differ from these values. These gains or losses are expected to substantially offset net losses or gains that will be realized in earnings from previous unfavorable or favorable market movements associated with underlying hedged transactions.
 
Concentration of Credit Risk
 
Derivative assets and liabilities
 
We have a risk of loss from counterparties not performing pursuant to the terms of their contractual obligations. Counterparty performance can be influenced by changes in the economy and regulatory issues, among other factors. Risk of loss is impacted by several factors, including credit considerations and the regulatory environment in which a counterparty transacts. We attempt to minimize credit-risk exposure to derivative counterparties and brokers through formal credit policies, consideration of credit ratings from public ratings agencies, monitoring procedures, master netting agreements and collateral support under certain circumstances. Collateral support could include letters of credit, payment under margin agreements, and guarantees of payment by credit worthy parties. The gross credit exposure from our derivative contracts as of June 30, 2011, is summarized as follows:

 	 	Investment	 	 	 	 	
Counterparty Type	 	Grade(a)	 	 	Total	 	
 	 	(Millions)	 	
 		
Gas and electric utilities and integrated oil and gas companies	 	$	9	 	 	$	9	 	
Energy marketers and traders	 	 	—	 	 	 	112	 	
Financial institutions	 	 	286	 	 	 	286	 	
 	 	 	 	 	 	 	 	 	
 	 	$	295	 	 	 	407	 	
 	 	 	 	 	 	 	 	 	
Credit reserves	 	 	 	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	
Gross credit exposure from derivatives	 	 	 	 	 	$	407	 	

 
We assess our credit exposure on a net basis to reflect master netting agreements in place with certain counterparties. We offset our credit exposure to each counterparty with amounts we owe the counterparty

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WPX Energy
 
Notes to Condensed Combined Financial Statements—(Continued)
 
under derivative contracts. The net credit exposure from our derivatives as of June 30, 2011, excluding collateral support discussed below, is summarized as follows:

 	 	Investment	 	 	 	 	
Counterparty Type	 	Grade(a)	 	 	Total	 	
 	 	(Millions)	 	
 		
Gas and electric utilities and integrated oil and gas companies	 	$	3	 	 	$	3	 	
Energy marketers and traders	 	 	—	 	 	 	1	 	
Financial institutions	 	 	204	 	 	 	204	 	
 	 	 	 	 	 	 	 	 	
 	 	$	207	 	 	 	208	 	
 	 	 	 	 	 	 	 	 	
Credit reserves	 	 	 	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	
Net credit exposure from derivatives	 	 	 	 	 	$	208	 	

 

			
(a)		We determine investment grade primarily using publicly available credit ratings. We include counterparties with a minimum Standard & Poor’s rating of BBB- or Moody’s Investors Service rating of Baa3 in investment grade.	
 
Our seven largest net counterparty positions represent approximately 92 percent of our net credit exposure from derivatives and are all with investment grade counterparties. Included within this group are counterparty positions, representing 83 percent of our net credit exposure from derivatives, associated our hedging facility. Under certain conditions, the terms of this credit agreement may require the participating financial institutions to deliver collateral support to a designated collateral agent (which is another participating financial institution in the agreement). The level of collateral support required is dependent on whether the net position of the counterparty financial institution exceeds specified thresholds. The thresholds may be subject to prescribed reductions based on changes in the credit rating of the counterparty financial institution.
 
At June 30, 2011, the designated collateral agent is not required to hold any collateral support on our behalf under our hedging facility. We hold collateral support, which may include cash or letters of credit, of $4 million related to our other derivative positions.

Note 11.  	Revolving Credit Agreement	
 
On June 3, 2011, WPX Energy, Inc., as borrower, entered into a new $1.5 billion five-year senior unsecured revolving credit facility agreement (the “Credit Facility Agreement”), together with the lenders named therein, and Citibank N.A. (“Citi”), as administrative agent and swingline lender. Under the terms of the Credit Facility Agreement and subject to certain requirements, WPX Energy, Inc. may request an increase in the commitments of up to an additional $300 million by either commitments from new lenders or increased commitments from existing lenders. Borrowings under the Credit Facility Agreement may be used for working capital, acquisitions, capital expenditures and other general corporate purposes.
 
Under the Credit Facility Agreement, WPX Energy, Inc. may also obtain same day funds by requesting a swingline loan of up to an amount of $125 million from the swingline lender. Interest on swingline loans will be payable at a fluctuating base rate equal to Citi’s adjusted base rate plus the applicable margin.
 
The Credit Facility Agreement will not be effective until the date on which certain conditions listed in the agreement (including, among others, the completion of the initial public offering of WPX Energy, Inc.) have been met or waived; provided that the effective date must be on or before November 30, 2011 or such later date as may be agreed to by WPX Energy, Inc. and the lenders. If the effective date has not occurred by November 30, 2011, the Credit Facility Agreement will automatically terminate unless otherwise extended by WPX Energy, Inc. and the lenders. Costs totalling $8 million associated with the establishment of this facility have been deferred in other assets and will be amortized over the life of the agreement.

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WPX Energy
 
Notes to Condensed Combined Financial Statements—(Continued)
 
Interest on borrowings under the Credit Facility Agreement will be payable at rates per annum equal to, at the option of WPX Energy, Inc.: (1) a fluctuating base rate equal to Citi’s adjusted base rate plus the applicable margin, or (2) a periodic fixed rate equal to LIBOR plus the applicable margin. The adjusted base rate will be the highest of (i) the federal funds rate plus 0.5 percent, (ii) Citi’s publicly announced base rate, and (iii) one-month LIBOR plus 1.0 percent. WPX Energy, Inc. will be required to pay a commitment fee based on the unused portion of the commitments under the Credit Facility Agreement. The applicable margin and the commitment fee will be determined by reference to a pricing schedule based on WPX Energy, Inc.’s senior unsecured debt ratings.
 
Under the Credit Facility Agreement, prior to the occurrence of the Investment Grade Date (as defined below), WPX Energy, Inc. will be required to maintain a ratio of PV to debt (each as defined in the Credit Facility Agreement) of at least 1.50 to 1.00. PV is determined as of the end of each fiscal year and reflects the present value, discounted at 9 percent, of projected future cash flows of domestic proved oil and gas reserves (with a limitation of no more than 35% of proved undeveloped reserves), based on lender projected commodity price assumptions and after giving effect to hedge arrangements. Also, for WPX Energy, Inc. and its consolidated subsidiaries, the ratio of debt to capitalization (defined as net worth plus debt) will not be permitted to be greater than 60%. Each of the above ratios will be tested beginning June 30, 2011 at the end of each fiscal quarter. Investment Grade Date means the first date on which WPX Energy, Inc.’s long-term senior unsecured debt ratings are BBB- or better by S&P or Baa3 or better by Moody’s (without negative outlook or negative watch), provided that the other of the two ratings is at least BB+ by S&P or Ba1 by Moody’s.
 
The Credit Facility Agreement contains customary representations and warranties and affirmative, negative and financial covenants which were made only for the purposes of the Credit Facility Agreement and as of the specific date (or dates) set forth therein, and may be subject to certain limitations as agreed upon by the contracting parties. The covenants limit, among other things, the ability of WPX Energy, Inc.’s subsidiaries to incur indebtedness, WPX Energy, Inc. and its material subsidiaries from granting certain liens supporting indebtedness, making investments, loans or advances and entering into certain hedging agreements, WPX Energy, Inc.’s ability to merge or consolidate with any person or sell all or substantially all of its assets to any person, enter into certain affiliate transactions, make certain distributions during the continuation of an event of default and allow material changes in the nature of its business. In addition, the representations, warranties and covenants contained in the Credit Facility Agreement may be subject to standards of materiality applicable to the contracting parties that differ from those applicable to investors. Investors are not third-party beneficiaries of the Credit Facility Agreement and should not rely on the representations, warranties and covenants contained therein, or any descriptions thereof, as characterizations of the actual state of facts or conditions of WPX Energy, Inc.
 
The Credit Facility Agreement includes customary events of default, including events of default relating to non-payment of principal, interest or fees, inaccuracy of representations and warranties in any material respect when made or when deemed made, violation of covenants, cross payment-defaults, cross acceleration, bankruptcy and insolvency events, certain unsatisfied judgments and a change of control. If an event of default with respect to a borrower occurs under the Credit Facility Agreement, the lenders will be able to terminate the commitments and accelerate the maturity of the loans of the defaulting borrower under the Credit Facility Agreement and exercise other rights and remedies.

Note 12.  	Subsequent Event	
 
In our assessment for impairment of producing oil and gas properties at December 31, 2010, we noted that approximately 12 percent of our producing assets, primarily located in the Powder River Basin, could be at risk for impairment if the weighted average forward price across all periods used in our cash flow estimates were to decline by approximately 8 to 12 percent, on average, absent changes in other factors impacting

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Table of Contents

WPX Energy
 
Notes to Condensed Combined Financial Statements—(Continued)

estimated future net cash flows. As of June 30, 2011, the impact of changes in forward prices since December 31, 2010 to our cash flow estimates was not indicative of a potential impairment. However, in the period from June 30, 2011 to August 31, 2011, weighted average declines in these forward prices as they relate to the Powder River Basin production projection have at times been as high as six percent. If these forward prices do not recover, we will have to conduct an impairment review of our proved producing oil and gas properties in the Powder River Basin as of September 30, 2011. The net book value of our proved producing assets in the Powder River Basin was approximately $500 million at June 30, 2011. If the recording of an impairment charge becomes necessary as of September 30, 2011, it is reasonably possible that the amount of such charge could be at least $200 million. Any potential interim impairment assessment would include not only a review of forward pricing assumptions but also consideration of other factors impacting estimated future net cash flows, including but not limited to reserve and production estimates, future operating costs, future development costs and production taxes, all of which could impact the need for an impairment, and, if necessary, the amount of such impairment charge.

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Table of Contents
 
Report of Independent Registered Public Accounting Firm
 
The Board of Directors
WPX Energy, Inc.
 
We have audited the accompanying combined balance sheet of WPX Energy (see Note 1) as of December 31, 2010 and 2009, and the related combined statements of operations, equity, and cash flows for each of the three years in the period ended December 31, 2010. Our audits also included the financial statement schedule listed at Item 16(b). These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.
 
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
 
In our opinion, the financial statements referred to above present fairly, in all material respects, the combined financial position of WPX Energy at December 31, 2010 and 2009, and the combined results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
 
As discussed in Note 5 to the combined financial statements, beginning in 2009, the Company changed its reserve estimates and related disclosures as a result of adopting new oil and gas reserve estimation and disclosure requirements.
 
/s/   Ernst & Young LLP
 
Tulsa, Oklahoma
April 29, 2011, except as it relates to the matter discussed
in the first paragraph of Basis of Presentation—Discontinued
Operations as set forth in Note 1, and the matter
discussed in Note 2, as to which the date is
June 21, 2011, and except as it relates to the matter
discussed in the second paragraph of Description of
Business as set forth in Note 1, as to which the date is
July 18, 2011

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Table of Contents

WPX Energy
(Note 1)

 Combined Statement of Operations 

 	 	Years Ended December 31,	 	
 	 	2010	 	 	2009	 	 	2008	 	
 	 	(Dollars in millions)	 	
 		
Revenues:	 	 	 	 	 	 	 	 	 	 	 	 	
Oil and gas sales, including affiliate	 	$	2,225	 	 	$	2,168	 	 	$	2,882	 	
Gas management, including affiliate	 	 	1,742	 	 	 	1,456	 	 	 	3,241	 	
Hedge ineffectiveness and mark to market gains and losses	 	 	27	 	 	 	18	 	 	 	29	 	
Other	 	 	40	 	 	 	39	 	 	 	32	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total revenues	 	 	4,034	 	 	 	3,681	 	 	 	6,184	 	
Costs and expenses:	 	 	 	 	 	 	 	 	 	 	 	 	
Lease and facility operating, including affiliate	 	 	286	 	 	 	263	 	 	 	272	 	
Gathering, processing and transportation, including affiliate	 	 	326	 	 	 	273	 	 	 	229	 	
Taxes other than income	 	 	125	 	 	 	93	 	 	 	254	 	
Gas management (including charges for unutilized pipeline capacity)	 	 	1,771	 	 	 	1,495	 	 	 	3,248	 	
Exploration	 	 	73	 	 	 	54	 	 	 	37	 	
Depreciation, depletion and amortization	 	 	875	 	 	 	887	 	 	 	738	 	
Impairment of producing properties and costs of acquired unproved reserves	 	 	678	 	 	 	15	 	 	 	—	 	
Goodwill impairment	 	 	1,003	 	 	 	—	 	 	 	—	 	
General and administrative, including affiliate	 	 	253	 	 	 	251	 	 	 	247	 	
Gain on sale of contractual right to international production payment	 	 	—	 	 	 	—	 	 	 	(148	)	
Other — net	 	 	(19	)	 	 	33	 	 	 	6	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total costs and expenses	 	 	5,371	 	 	 	3,364	 	 	 	4,883	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating income (loss)	 	 	(1,337	)	 	 	317	 	 	 	1,301	 	
Interest expense, including affiliate	 	 	(124	)	 	 	(100	)	 	 	(74	)	
Interest capitalized	 	 	16	 	 	 	18	 	 	 	20	 	
Investment income and other	 	 	21	 	 	 	8	 	 	 	22	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Income (loss) from continuing operations before income taxes	 	 	(1,424	)	 	 	243	 	 	 	1,269	 	
Provision (benefit) for income taxes	 	 	(150	)	 	 	94	 	 	 	452	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Income (loss) from continuing operations	 	 	(1,274	)	 	 	149	 	 	 	817	 	
Loss from discontinued operations	 	 	(8	)	 	 	(7	)	 	 	(87	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income (loss)	 	 	(1,282	)	 	 	142	 	 	 	730	 	
Less: Net income attributable to noncontrolling interests	 	 	8	 	 	 	6	 	 	 	8	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income (loss) attributable to WPX Energy	 	$	(1,290	)	 	$	136	 	 	$	722	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Unaudited Supplemental pro forma combined basic loss per common share (Note 1)	 	$	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Unaudited Supplemental pro forma combined diluted loss per common share (Note 1)	 	$	 	 	 	 	 	 	 	 	 	 	

 
See accompanying notes.

F-31

Table of Contents

WPX Energy
(Note 1)

 Combined Balance Sheet 

 	 	December 31,	 	
 	 	2010	 	 	2009	 	
 	 	(Dollars in millions)	 	
 		
Assets	 	 	 	 	 	 	 	 	
Current assets:	 	 	 	 	 	 	 	 	
Cash and cash equivalents	 	$	37	 	 	$	34	 	
Accounts receivable:	 	 	 	 	 	 	 	 	
Trade, net of allowance for doubtful accounts of $16 and $19 as of December 31, 2010 and 2009, respectively	 	 	362	 	 	 	359	 	
Affiliate	 	 	60	 	 	 	54	 	
Derivative assets	 	 	400	 	 	 	650	 	
Inventories	 	 	77	 	 	 	61	 	
Other	 	 	22	 	 	 	41	 	
 	 	 	 	 	 	 	 	 	
Total current assets	 	 	958	 	 	 	1,199	 	
Investments	 	 	105	 	 	 	95	 	
Properties and equipment, net (successful efforts method of accounting)	 	 	8,449	 	 	 	7,662	 	
Derivative assets	 	 	173	 	 	 	444	 	
Goodwill, net	 	 	—	 	 	 	1,003	 	
Other noncurrent assets	 	 	161	 	 	 	150	 	
 	 	 	 	 	 	 	 	 	
Total assets	 	$	9,846	 	 	$	10,553	 	
 	 	 	 	 	 	 	 	 	
Liabilities and Equity	 	 	 	 	 	 	 	 	
Current liabilities:	 	 	 	 	 	 	 	 	
Accounts payable:	 	 	 	 	 	 	 	 	
Trade	 	$	451	 	 	$	462	 	
Affiliates	 	 	64	 	 	 	37	 	
Accrued and other current liabilities	 	 	158	 	 	 	231	 	
Deferred income taxes	 	 	87	 	 	 	28	 	
Notes payable to Williams	 	 	2,261	 	 	 	1,216	 	
Derivative liabilities	 	 	146	 	 	 	578	 	
 	 	 	 	 	 	 	 	 	
Total current liabilities	 	 	3,167	 	 	 	2,552	 	
Deferred income taxes	 	 	1,629	 	 	 	1,841	 	
Derivative liabilities	 	 	143	 	 	 	428	 	
Asset retirement obligations	 	 	282	 	 	 	235	 	
Other noncurrent liabilities	 	 	125	 	 	 	92	 	
Contingent liabilities and commitments (Note 11)	 	 	 	 	 	 	 	 	
Equity:	 	 	 	 	 	 	 	 	
Owner’s net equity:	 	 	 	 	 	 	 	 	
Owner’s net investment	 	 	4,260	 	 	 	5,269	 	
Accumulated other comprehensive income	 	 	168	 	 	 	72	 	
 	 	 	 	 	 	 	 	 	
Total owner’s net equity	 	 	4,428	 	 	 	5,341	 	
Noncontrolling interests in combined subsidiaries	 	 	72	 	 	 	64	 	
 	 	 	 	 	 	 	 	 	
Total equity	 	 	4,500	 	 	 	5,405	 	
 	 	 	 	 	 	 	 	 	
Total liabilities and equity	 	$	9,846	 	 	$	10,553	 	

 
See accompanying notes.

F-32

Table of Contents

WPX Energy
(Note 1)

 Combined Statement of Equity 

 	 	 	 	 	Accumulated Other	 	 	 	 	 	 	 	 	 	 	
 	 	Owner’s Net	 	 	Comprehensive	 	 	Total Owner’s Net	 	 	Noncontrolling	 	 	 	 	
 	 	Investment	 	 	Income (Loss)*	 	 	Equity	 	 	Interest**	 	 	Total	 	
 	 	(Dollars in millions)	 	
 		
Balance at December 31, 2007	 	$	4,462	 	 	$	(161	)	 	$	4,301	 	 	$	55	 	 	$	4,356	 	
Comprehensive income:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income	 	 	722	 	 	 	—	 	 	 	722	 	 	 	8	 	 	 	730	 	
Other comprehensive income:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Change in fair value of cash flow hedges (net of $260 of income tax)	 	 	—	 	 	 	454	 	 	 	454	 	 	 	—	 	 	 	454	 	
Net reclassifications into earnings of net cash flow hedge losses (net of $3 income tax benefit)	 	 	—	 	 	 	5	 	 	 	5	 	 	 	—	 	 	 	5	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total other comprehensive income	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	459	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total comprehensive income	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	1,189	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net transfers with Williams	 	 	(35	)	 	 	—	 	 	 	(35	)	 	 	—	 	 	 	(35	)	
Dividends to noncontrolling interests	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(4	)	 	 	(4	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance at December 31, 2008	 	 	5,149	 	 	 	298	 	 	 	5,447	 	 	 	59	 	 	 	5,506	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Comprehensive income:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income	 	 	136	 	 	 	—	 	 	 	136	 	 	 	6	 	 	 	142	 	
Other comprehensive income:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Change in fair value of net cash flow hedges (net of $97 of income tax)	 	 	—	 	 	 	169	 	 	 	169	 	 	 	—	 	 	 	169	 	
Net reclassifications into earnings of cash flow hedge gain (net of $226 income tax provision)	 	 	—	 	 	 	(395	)	 	 	(395	)	 	 	—	 	 	 	(395	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total other comprehensive loss	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	(226	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total comprehensive loss	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	(84	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net transfers with Williams	 	 	(16	)	 	 	—	 	 	 	(16	)	 	 	—	 	 	 	(16	)	
Dividends to noncontrolling interests	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(1	)	 	 	(1	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance at December 31, 2009	 	 	5,269	 	 	 	72	 	 	 	5,341	 	 	 	64	 	 	 	5,405	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Comprehensive income:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net loss	 	 	(1,290	)	 	 	—	 	 	 	(1,290	)	 	 	8	 	 	 	(1,282	)	
Other comprehensive income:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Change in fair value of net cash flow hedges (net of $184 of income tax)	 	 	—	 	 	 	321	 	 	 	321	 	 	 	—	 	 	 	321	 	
Net reclassifications into earnings of cash flow hedge gains (net of $129 income tax provision)	 	 	—	 	 	 	(225	)	 	 	(225	)	 	 	—	 	 	 	(225	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total other comprehensive income	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	96	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total comprehensive loss	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	(1,186	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash proceeds in excess of historical book value related to assets sold to an affiliate	 	 	244	 	 	 	—	 	 	 	244	 	 	 	—	 	 	 	244	 	
Net transfers with Williams	 	 	37	 	 	 	—	 	 	 	37	 	 	 	—	 	 	 	37	 	
Dividends to noncontrolling interests	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance at December 31, 2010	 	$	4,260	 	 	$	168	 	 	$	4,428	 	 	$	72	 	 	$	4,500	 	

 

			
* 		Accumulated other Comprehensive income (loss) is comprised primarily of unrealized gains relating to natural gas hedges totaling $169 million (net of $97 million for income taxes), $74 million (net of $42 million for income taxes) and $299 million (net of $172 million for income taxes) as of December 31, 2010, 2009 and 2008, respectively.	
 		
**		Represents the 31 percent interest in Apco Oil and Gas International Inc. owned by others.	
 
See accompanying notes.

F-33

Table of Contents

WPX Energy
(Note 1)

 Combined Statement of Cash Flows 

 	 	Years Ended December 31,	 	
 	 	2010	 	 	2009	 	 	2008	 	
 	 	(Dollars in millions)	 	
 		
Operating Activities	 	 	 	 	 	 	 	 	 	 	 	 	
Net income (loss)	 	$	(1,282	)	 	$	142	 	 	$	730	 	
Adjustments to reconcile net income (loss) to net cash provided by operating activities:	 	 	 	 	 	 	 	 	 	 	 	 	
Depreciation, depletion and amortization	 	 	882	 	 	 	894	 	 	 	758	 	
Deferred income tax provision (benefit)	 	 	(167	)	 	 	106	 	 	 	456	 	
Provision for impairment of goodwill and properties and equipment (including certain exploration expenses)	 	 	1,734	 	 	 	38	 	 	 	173	 	
Provision for loss on cost-based investment	 	 	—	 	 	 	11	 	 	 	—	 	
Gain on sale of contractual right to international production payment	 	 	—	 	 	 	—	 	 	 	(148	)	
(Gain) loss on sales of other assets	 	 	(22	)	 	 	1	 	 	 	1	 	
Cash provided (used) by operating assets and liabilities:	 	 	 	 	 	 	 	 	 	 	 	 	
Accounts receivable and payable — affiliate	 	 	21	 	 	 	(72	)	 	 	20	 	
Accounts receivable — trade	 	 	7	 	 	 	103	 	 	 	127	 	
Other current assets	 	 	19	 	 	 	(17	)	 	 	(11	)	
Inventories	 	 	(16	)	 	 	24	 	 	 	(32	)	
Margin deposits and customer margin deposit payable	 	 	(1	)	 	 	4	 	 	 	87	 	
Accounts payable — trade	 	 	(54	)	 	 	(17	)	 	 	(91	)	
Accrued and other current liabilities	 	 	(62	)	 	 	(109	)	 	 	27	 	
Changes in current and noncurrent derivative assets and liabilities	 	 	(45	)	 	 	38	 	 	 	(119	)	
Other, including changes in other noncurrent assets and liabilities	 	 	42	 	 	 	35	 	 	 	31	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Net cash provided by operating activities	 	 	1,056	 	 	 	1,181	 	 	 	2,009	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Investing Activities	 	 	 	 	 	 	 	 	 	 	 	 	
Capital expenditures*	 	 	(1,856	)	 	 	(1,434	)	 	 	(2,467	)	
Purchase of business	 	 	(949	)	 	 	—	 	 	 	—	 	
Proceeds from sale of contractual right to international production payment	 	 	—	 	 	 	—	 	 	 	148	 	
Proceeds from sales of assets	 	 	493	 	 	 	—	 	 	 	72	 	
Purchases of investments	 	 	(7	)	 	 	(1	)	 	 	(5	)	
Other	 	 	(18	)	 	 	—	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Net cash used in investing activities	 	 	(2,337	)	 	 	(1,435	)	 	 	(2,252	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Financing Activities	 	 	 	 	 	 	 	 	 	 	 	 	
Net changes in notes payable to parent	 	 	1,045	 	 	 	270	 	 	 	269	 	
Net changes in owner’s net investment	 	 	241	 	 	 	(16	)	 	 	(38	)	
Other	 	 	(2	)	 	 	2	 	 	 	(6	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Net cash provided by financing activities	 	 	1,284	 	 	 	256	 	 	 	225	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Net change in cash and cash equivalents	 	 	3	 	 	 	2	 	 	 	(18	)	
Cash and cash equivalents at beginning of period	 	 	34	 	 	 	32	 	 	 	50	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash and cash equivalents at end of period	 	$	37	 	 	$	34	 	 	$	32	 	

* Increase to properties and equipment	 	$	(1,891	)	 	$	(1,291	)	 	$	(2,520	)	
Changes in related accounts payable	 	 	35	 	 	 	(143	)	 	 	53	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Capital expenditures	 	$	(1,856	)	 	$	(1,434	)	 	$	(2,467	)	

 
See accompanying notes.

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Table of Contents

WPX Energy
 
Notes to Combined Financial Statements

1.  	Description of Business, Basis of Presentation and Summary of Significant Accounting Policies	
 
Description of Business
 
The combined businesses represented herein as WPX Energy (also referred to herein as the “Company”) comprise substantially all of the exploration and production operating segment of The Williams Companies, Inc. (“Williams”). In these notes, WPX Energy is at times referred to in the first person as “we”, “us” or “our”.
 
On February 16, 2011, Williams announced that its Board of Directors approved pursuing a plan to separate Williams’ businesses into two stand-alone, publicly traded companies. The plan first calls for Williams to separate its exploration and production business via an initial public offering (the “Offering”) of up to 20 percent of its interest. As a result, WPX Energy, Inc. has been formed to effect the separation. In July 2011, Williams contributed to the Company its investment in certain subsidiaries related to its domestic exploration and production business, including its wholly-owned subsidiaries Williams Production Holdings, LLC and Williams Production Company, LLC, as well as all ongoing operations of Williams Gas Marketing Services, Inc. Additionally, prior to the close of the Offering, Williams will contribute and transfer to the Company its investment in certain subsidiaries related to its international exploration and production business, including its 69 percent ownership interest in Apco Oil and Gas International (“Apco”, NASDAQ listed: APAGF). We refer to the collective contributions described herein as the “Contribution”.
 
WPX Energy includes natural gas development, production and gas management activities located in the Rocky Mountain (primarily Colorado, New Mexico, and Wyoming), Mid-Continent (Texas), and Appalachian regions of the United States. We specialize in natural gas production from tight-sands and shale formations and coal bed methane reserves in the Piceance, San Juan, Powder River, Green River, Fort Worth, and Appalachian Basins. During 2010, we acquired a company with a significant acreage position in the Williston Basin (Bakken Shale) in North Dakota, which is primarily comprised of crude oil reserves. We also have international oil and gas interests which represented approximately two percent of combined revenues and approximately six percent of proved reserves for the year ended December 31, 2010. These international interests primarily consist of our ownership in Apco, an oil and gas exploration and production company with operations in South America.
 
Basis of Presentation
 
These financial statements are prepared on a combined, rather than a consolidated basis. The combined financial statements have been derived from the financial statements and accounting records of Williams using the historical results of operations and historical basis of the assets and liabilities of the Contribution to WPX Energy.
 
Management believes the assumptions underlying the financial statements are reasonable. However, the financial statements included herein may not necessarily reflect the Company’s results of operations, financial position and cash flows in the future or what its results of operations, financial position and cash flows would have been had the Company been a stand-alone company during the periods presented. Because a direct ownership relationship did not exist among the various entities that will comprise the Company, Williams’ net investment in the Company, excluding notes payable to Williams, is shown as owner’s net investment in lieu of stockholder’s equity in the combined financial statements. Transactions between the Company and Williams which are not part of the notes payable have been identified in the Combined Statements of Equity as net transfers with Williams (see Note 4). Transactions with Williams’ other operating businesses, which generally settle monthly, are shown as accounts receivable-affiliate or accounts payable-affiliate (see Note 4). The accompanying combined financial statements do not reflect any changes that have occurred or will occur upon the Contribution and recapitalization of the Company, or may occur in the capitalization and operations of the Company as a result of, or after, any spin-off of the Company.
 
During fourth quarter 2010, the Company sold certain gathering and processing assets in Colorado’s Piceance Basin (the “Piceance Sale”) with a net book value of $458 million to Williams Partners L.P.

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Table of Contents

WPX Energy
 
Notes to Combined Financial Statements—(Continued)
 
(“WPZ”), an entity under the common control of Williams, in exchange for $702 million in cash and 1.8 million WPZ limited partner units. As the Company and WPZ are under common control, no gain was recognized on this transaction in the Combined Statement of Operations. Accordingly, the $244 million difference between the cash consideration received and the historical net book value of the assets has been reflected in the Combined Statement of Equity for the year ended December 31, 2010. Since the WPZ units received in this transaction by the Company were intended to be (and now have been, as described below) distributed through a dividend to Williams, these units (as well as the tax effects associated with these units of $42 million) have been presented net within equity and are included in net transfers with Williams in 2010. Further, as a result of the limitations on the Company’s ability to sell these units and the subsequent dividend to Williams, no gains on the value of the common units during the holding period have been recognized in the Combined Statement of Operations. In conjunction with the Piceance Sale, we entered into long-term contracts with WPZ for gathering and processing of our natural gas production in the area. Due to the continuation of significant direct cash flows related to these assets, historical operating results of these assets continue to be presented in the Combined Statement of Operations as continuing operations for all periods presented. In March, 2011, the 1.8 million WPZ units and related tax basis were distributed via dividend to Williams.
 
Discontinued operations
 
During the first quarter 2011, we initiated a formal process to pursue the divestiture of our holdings in the Arkoma Basin. As these assets are currently held for sale, will be eliminated from our ongoing operations, and we will not have any significant continuing involvement, we have reported the results of operations and financial position of the Arkoma operations as discontinued operations.
 
Additionally, the accompanying combined financial statements and notes include the results of operations of Williams’ former power business most of which was disposed in 2007 as discontinued operations. The discontinued operations have been included in these combined financial statements because contingent obligations related to this former business directly relate to Williams Gas Marketing Services, resulting in the potential of charges or benefits to the Company in periods subsequent to the exit from this business. See Note 11 for a discussion of contingencies related to this discontinued power business.
 
Unless indicated otherwise, the information in the Notes to Combined Financial Statements relates to continuing operations.
 
Summary of Significant Accounting Policies
 
Basis of combination
 
The combined financial statements include the accounts of the combined entities as set forth in Description of Business and Basis of Presentation above. Companies in which WPX Energy entities own 20 percent to 50 percent of the voting common stock, or otherwise exercise significant influence over operating and financial policies of the company, are accounted for under the equity method. All material intercompany transactions have been eliminated.
 
Use of estimates
 
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the combined financial statements and accompanying notes. Actual results could differ from those estimates.
 
Significant estimates and assumptions which impact these financials include:

 	•  	Impairment assessments of long-lived assets and goodwill;	
 		
 	•  	Assessments of litigation-related contingencies;	

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WPX Energy
 
Notes to Combined Financial Statements—(Continued)

			
 	•  	Valuations of derivatives;	
 		
 	•  	Hedge accounting correlations and probability;	
 		
 	•  	Estimation of oil and natural gas reserves.	
 
These estimates are discussed further throughout these notes.
 
Cash and cash equivalents
 
Our cash and cash equivalents relate primarily to our international operations. We consider all investments with a maturity of three months or less when acquired to be cash equivalents.
 
Additionally, our domestic businesses currently participate in the Williams’ cash management program (see Note 4) rather than maintaining cash and cash equivalent balances.
 
Restricted cash
 
Restricted cash primarily consists of approximately $19 million in both 2010 and 2009 related to escrow accounts established as part of the settlement agreement with certain California utilities (see Note 11) and is included in noncurrent other assets.
 
Accounts receivable
 
Accounts receivable are carried on a gross basis, with no discounting, less the allowance for doubtful accounts. We estimate the allowance for doubtful accounts based on existing economic conditions, the financial conditions of the customers and the amount and age of past due accounts. Receivables are considered past due if full payment is not received by the contractual due date. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted. A portion of our receivables are from joint interest owners of properties we operate. Thus, we may have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings.
 
Inventories
 
All inventories are stated at the lower of cost or market. Our inventories consist primarily of tubular goods and production equipment for future transfer to wells of $46 million in 2010 and $34 million in 2009. Additionally, we have natural gas in storage of $31 million in 2010 and $27 million in 2009 primarily related to our gas management activities. Inventory is recorded and relieved using the weighted average cost method except for production equipment which is on the specific identification method. We recorded lower of cost or market writedowns on natural gas in storage of $2 million in 2010, $7 million in 2009 and $35 million in 2008.
 
Properties and equipment
 
Oil and gas exploration and production activities are accounted for under the successful efforts method. Costs incurred in connection with the drilling and equipping of exploratory wells are capitalized as incurred. If proved reserves are not found, such costs are charged to exploration expense. Other exploration costs, including geological and geophysical costs and lease rentals are charged to expense as incurred. All costs related to development wells, including related production equipment and lease acquisition costs, are capitalized when incurred whether productive or nonproductive.
 
Unproved properties include lease acquisition costs and costs of acquired unproved reserves. Individually significant lease acquisition costs are assessed annually, or as conditions warrant, for impairment considering our future drilling plans, the remaining lease term and recent drilling results. Lease acquisition costs that are not individually significant are aggregated by prospect or geographically, and the portion of such costs estimated to

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WPX Energy
 
Notes to Combined Financial Statements—(Continued)
 
be nonproductive prior to lease expiration is amortized over the average holding period. The estimate of what could be nonproductive is based on our historical experience or other information, including current drilling plans and existing geological data. Impairment and amortization of lease acquisition costs are included in exploration expense in the Combined Statement of Operations. A majority of the costs of acquired unproved reserves are associated with areas to which we or other producers have identified significant proved developed producing reserves. Generally, economic recovery of unproved reserves in such areas is not yet supported by actual production or conclusive formation tests, but may be confirmed by our continuing development program. Ultimate recovery of unproved reserves in areas with established production generally has greater probability than in areas with limited or no prior drilling activity. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and gas properties. We refer to unproved lease acquisition costs and costs of acquired unproved reserves as unproved properties.
 
Other capitalized costs
 
Costs related to the construction or acquisition of field gathering, processing and certain other facilities are recorded at cost. Ordinary maintenance and repair costs are expensed as incurred.
 
Depreciation, depletion and amortization
 
Capitalized exploratory and developmental drilling costs, including lease and well equipment and intangible development costs are depreciated and amortized using the units-of-production method based on estimated proved developed oil and gas reserves on a field basis or concession for our international properties. International concession reserve estimates are limited to production quantities estimated through the life of the concession. Depletion of producing leasehold costs is based on the units-of-production method using estimated proved oil and gas reserves on a field basis. In arriving at rates under the units-of-production methodology, the quantities of proved oil and gas reserves are established based on estimates made by our geologists and engineers.
 
Costs related to gathering, processing and certain other facilities are depreciated on the straight-line method over the estimated useful lives.
 
Gains or losses from the ordinary sale or retirement of properties and equipment are recorded in other—net included in operating income (loss).
 
Impairment of long-lived assets
 
We evaluate our long-lived assets for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such assets may not be recoverable. When an indicator of impairment has occurred, we compare our management’s estimate of undiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether an impairment has occurred. If an impairment of the carrying value has occurred, we determine the amount of the impairment recognized in the financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value.
 
Proved properties, including developed and undeveloped, are assessed for impairment using estimated future undiscounted cash flows on a field basis. If the undiscounted cash flows are less than the book value of the assets, then a subsequent analysis is performed using discounted cash flows.
 
Costs of acquired unproved reserves are assessed for impairment using estimated fair value determined through the use of future discounted cash flows on a field basis and considering market participants’ future drilling plans.

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WPX Energy
 
Notes to Combined Financial Statements—(Continued)
 
Judgments and assumptions are inherent in our management’s estimate of undiscounted future cash flows and an asset’s fair value. Additionally, judgment is used to determine the probability of sale with respect to assets considered for disposal. These judgments and assumptions include such matters as the estimation of oil and gas reserve quantities, risks associated with the different categories of oil and gas reserves, the timing of development and production, expected future commodity prices, capital expenditures, production costs and appropriate discount rates.
 
Asset retirement obligations
 
We record an asset and a liability upon incurrence equal to the present value of each expected future asset retirement obligation (“ARO”). These estimates include, as a component of future expected costs, an estimate of the price that a third party would demand, and could expect to receive, for bearing the uncertainties inherent in the obligations, sometimes referred to as a market risk premium. The ARO asset is depreciated in a manner consistent with the depreciation of the underlying physical asset. We measure changes in the liability due to passage of time by applying an interest method of allocation. This amount is recognized as an increase in the carrying amount of the liability and as a corresponding accretion expense in lease and facility operating expense included in costs and expenses.
 
Goodwill
 
Goodwill represents the excess of cost over fair value of the assets of businesses acquired. It is evaluated at least annually (in the fourth quarter) for impairment by first comparing our management’s estimate of the fair value of a reporting unit with its carrying value, including goodwill. If the carrying value of the reporting unit exceeds its fair value, a computation of the implied fair value of the goodwill is compared with its related carrying value. If the carrying value of the reporting unit’s goodwill exceeds the implied fair value of that goodwill, an impairment loss is recognized in the amount of the excess.
 
As a result of significant declines in forward natural gas prices during third quarter of 2010, we performed an interim impairment assessment of our goodwill related to our domestic production reporting unit. As a result of that assessment, we recorded an impairment of goodwill of approximately $1 billion (see Note 6).
 
Judgments and assumptions are inherent in our management’s estimate of future cash flows used to determine the estimate of the reporting unit’s fair value.
 
Derivative instruments and hedging activities
 
We utilize derivatives to manage our commodity price risk. These instruments consist primarily of futures contracts, swap agreements, option contracts, and forward contracts involving short- and long-term purchases and sales of a physical energy commodity.
 
We report the fair value of derivatives, except for those for which the normal purchases and normal sales exception has been elected, on the Combined Balance Sheet in derivative assets and derivative liabilities as either current or noncurrent. We determine the current and noncurrent classification based on the timing of expected future cash flows of individual trades. We report these amounts on a gross basis. Additionally, we report cash collateral receivables and payables with our counterparties on a gross basis.
 
The accounting for the changes in fair value of a commodity derivative can be summarized as follows:

Derivative Treatment	 	Accounting Method	
 		
Normal purchases and normal sales exception	 	Accrual accounting	
Designated in a qualifying hedging relationship	 	Hedge accounting	
All other derivatives	 	Mark-to-market accounting	

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WPX Energy
 
Notes to Combined Financial Statements—(Continued)
 
We may elect the normal purchases and normal sales exception for certain short- and long-term purchases and sales of a physical energy commodity. Under accrual accounting, any change in the fair value of these derivatives is not reflected on the balance sheet after the initial election of the exception.
 
We have also designated a hedging relationship for certain commodity derivatives. For a derivative to qualify for designation in a hedging relationship, it must meet specific criteria and we must maintain appropriate documentation. We establish hedging relationships pursuant to our risk management policies. We evaluate the hedging relationships at the inception of the hedge and on an ongoing basis to determine whether the hedging relationship is, and is expected to remain, highly effective in achieving offsetting changes in fair value or cash flows attributable to the underlying risk being hedged. We also regularly assess whether the hedged forecasted transaction is probable of occurring. If a derivative ceases to be or is no longer expected to be highly effective, or if we believe the likelihood of occurrence of the hedged forecasted transaction is no longer probable, hedge accounting is discontinued prospectively, and future changes in the fair value of the derivative are recognized currently in revenues or costs and operating expenses dependent upon the underlying hedge transaction.
 
For commodity derivatives designated as a cash flow hedge, the effective portion of the change in fair value of the derivative is reported in accumulated other comprehensive income (loss) (“AOCI”) and reclassified into earnings in the period in which the hedged item affects earnings. Any ineffective portion of the derivative’s change in fair value is recognized currently in revenues. Gains or losses deferred in AOCI associated with terminated derivatives, derivatives that cease to be highly effective hedges, derivatives for which the forecasted transaction is reasonably possible but no longer probable of occurring, and cash flow hedges that have been otherwise discontinued remain in AOCI until the hedged item affects earnings. If it becomes probable that the forecasted transaction designated as the hedged item in a cash flow hedge will not occur, any gain or loss deferred in AOCI is recognized in revenues at that time. The change in likelihood is a judgmental decision that includes qualitative assessments made by management.
 
For commodity derivatives that are not designated in a hedging relationship, and for which we have not elected the normal purchases and normal sales exception, we report changes in fair value currently in revenues dependent upon the underlying of the hedged transaction.
 
Certain gains and losses on derivative instruments included in the Combined Statement of Operations are netted together to a single net gain or loss, while other gains and losses are reported on a gross basis. Gains and losses recorded on a net basis include:

 	•  	Unrealized gains and losses on all derivatives that are not designated as hedges and for which we have not elected the normal purchases and normal sales exception;	
 		
 	•  	The ineffective portion of unrealized gains and losses on derivatives that are designated as cash flow hedges;	
 		
 	•  	Realized gains and losses on all derivatives that settle financially;	
 		
 	•  	Realized gains and losses on derivatives held for trading purposes; and	
 		
 	•  	Realized gains and losses on derivatives entered into as a pre-contemplated buy/sell arrangement.	
 
Realized gains and losses on derivatives that require physical delivery, as well as natural gas derivatives which are not held for trading purposes nor were entered into as a pre-contemplated buy/sell arrangement, are recorded on a gross basis. In reaching our conclusions on this presentation, we considered whether we act as principal in the transaction; whether we have the risks and rewards of ownership, including credit risk; and whether we have latitude in establishing prices.

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WPX Energy
 
Notes to Combined Financial Statements—(Continued)
 
Business segment information
 
The Company has a single operating segment that consists of all continuing operations, including gas management and oil and gas production activities. An operating segment is a component of an entity that engages in activities from which it may earn revenues and incur expenses, and for which discrete financial information is available and regularly reviewed by the chief operating decision maker for the purposes of assessing performance and allocating resources. We are controlled by Williams and we have determined that our chief operating decision maker is Williams’ Chief Executive Officer (who also serves as the Chairman of our Board of Directors). Performance evaluation and resource allocation decisions are made by our chief operating decision maker based on financial information presented for WPX Energy as a single operating segment.
 
Oil and gas sales revenues
 
Revenues for sales of natural gas, oil and condensate and natural gas liquids are recognized when the product is sold and delivered. Revenues from the production of natural gas in properties for which we have an interest with other producers are recognized based on the actual volumes sold during the period. Any differences between volumes sold and entitlement volumes, based on our net working interest, that are determined to be nonrecoverable through remaining production are recognized as accounts receivable or accounts payable, as appropriate. Our cumulative net natural gas imbalance position based on market prices as of December 31, 2010 and 2009 was insignificant. Additionally, oil and gas sales revenues include hedge gains realized on production sold of $333 million in 2010, $615 million in 2009 and $34 million in 2008.
 
Gas management revenues and expenses
 
Revenues for sales related to gas management activities are recognized when the product is sold and physically delivered. Our gas management activities to date include purchases and subsequent sales to WPZ for fuel and shrink gas (see Note 4). Additionally, gas management activities include the managing of various natural gas related contracts such as transportation, storage and related hedges. The Company also sells natural gas purchased from working interest owners in operated wells and other area third party producers. The revenues and expenses related to these marketing activities are reported on a gross basis as part of gas management revenues and costs and expenses.
 
Charges for unutilized transportation capacity included in gas management expenses were $48 million in 2010, $21 million in 2009 and $8 million in 2008.
 
Capitalization of interest
 
We capitalize interest during construction on projects with construction periods of at least three months or a total estimated project cost in excess of $1 million. The interest rate used is the rate charged to us by Williams, based on Williams’ average quarterly interest rate on its debt.
 
Income taxes
 
The Company’s domestic operations are included in the consolidated federal and state income tax returns for Williams, except for certain separate state filings. The income tax provision for the Company has been calculated on a separate return basis, except for certain state and federal tax attributes (primarily minimum tax credit carry-forwards) for which the actual allocation (if any) cannot be determined until the consolidated tax returns are complete for the year in which an income tax deconsolidation event occurs. This allocation methodology results in the recognition of deferred assets and liabilities for the differences between the financial statement carrying amounts and their respective tax basis, except to the extent of deferred taxes on income considered to be permanently reinvested in foreign jurisdictions. Deferred tax assets and liabilities are measured using enacted tax rates for the years in which those temporary differences are expected to be

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WPX Energy
 
Notes to Combined Financial Statements—(Continued)
 
recovered or settled. In addition, Williams manages its tax position based upon its entire portfolio which may not be indicative of tax planning strategies available to us if we were operating as an independent company.
 
Employee stock-based compensation
 
Certain employees providing direct service to the Company participate in Williams’ common-stock-based awards plans. The plans provide for Williams common-stock-based awards to both employees and Williams’ non-management directors. The plans permit the granting of various types of awards including, but not limited to, stock options and restricted stock units. Awards may be granted for no consideration other than prior and future services or based on certain financial performance targets.
 
Williams charges us for compensation expense related to stock-based compensation awards granted to our direct employees. Stock based compensation is also a component of allocated amounts charged to us by Williams for general and administrative personnel providing services on our behalf.
 
Foreign exchange
 
Translation gains and losses that arise from exchange rate fluctuations applicable to transactions denominated in a currency other than the United States dollar are included in the results of operations as incurred.
 
Earnings (loss) per share
 
Historical earnings per share are not presented since the Company’s common stock was not part of the capital structure of Williams for the periods presented.
 
Unaudited Supplemental Pro forma combined loss per share
 
Basic and diluted pro forma combined loss per share for the year ended December 31, 2010 were calculated using the assumed issuance of           Class A common shares from the Offering, and the assumed issuance of           Class B common shares to Williams in exchange for all of the net assets contributed to us by Williams. Additionally, for purposes of calculating basic and diluted pro forma combined loss per share, our historical net loss was further increased by $88 million to reflect incremental interest expense (net of tax) related to the portion of the $1,684 million distribution that exceeds the proceeds from the Offering and our earnings for the previous twelve months.

2.  	Restatement of Prior Periods	
 
In the first quarter of 2011, we determined that for the years ended December 31, 2010, 2009 and 2008, we had failed to properly accrue estimates of the minimum annual volumetric throughput requirements associated with certain of our compression services agreements. As a result of this error, our costs and expenses were understated by $3 million, $5 million and $6 million for the years ended December 31, 2010, 2009 and 2008, respectively. Based on guidance set forth in Staff Accounting Bulletin No. 99, “Materiality” and in Staff Accounting Bulletin No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements,” (“SAB 108”), we have determined that these amounts are immaterial to each of the periods affected and, therefore, we are not required to amend our previously filed reports. However, if these adjustments were recorded in 2011, we believe the impact could be material to this reporting period. As a result, we have adjusted, in the tables below, our previously reported results for the years ended December 31, 2010, 2009 and 2008 for these amounts as required by SAB 108. In addition to recording the obligations associated with the minimum annual volumetric throughput requirements previously discussed, we have made five other immaterial adjustments to prior year amounts as follows: (1) oil and gas sales revenue decrease of $3 million and $2 million for additional royalties expected to be paid for the years ended December 31, 2010 and 2009, respectively; (2) gas management revenue decrease of $3 million

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WPX Energy
 
Notes to Combined Financial Statements—(Continued)
 
for natural gas measurement adjustments related to the year ended December 31, 2008; (3) gas management expense decrease of $3 million and $1 million for adjustments made under gas purchase agreements for the years ended December 31, 2010 and 2009, respectively; (4) depreciation, depletion and amortization expense increase of $1 million related to the year ended December 31, 2010; and (5) bad debt expense increase of $1 million related the year ended December 31, 2010.

 	 	Year Ended	 	 	Year Ended	 	 	Year Ended	 	
 	 	December 31, 2010	 	 	December 31, 2009	 	 	December 31, 2008	 	
 	 	Previously	 	 	 	 	 	As	 	 	Previously	 	 	 	 	 	As	 	 	Previously	 	 	 	 	 	As	 	
 	 	Reported(1)	 	 	Adjustments	 	 	Adjusted	 	 	Reported(1)	 	 	Adjustments	 	 	Adjusted	 	 	Reported(1)	 	 	Adjustments	 	 	Adjusted	 	
 		
Revenues:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Oil and gas sales, including affiliate	 	$	2,228	 	 	$	(3	)	 	$	2,225	 	 	$	2,170	 	 	$	(2	)	 	$	2,168	 	 	$	2,882	 	 	$	—	 	 	$	2,882	 	
Gas management, including affiliate	 	 	1,742	 	 	 	—	 	 	 	1,742	 	 	 	1,456	 	 	 	—	 	 	 	1,456	 	 	 	3,244	 	 	 	(3	)	 	 	3,241	 	
Hedge ineffectiveness and mark to market gains and losses	 	 	27	 	 	 	—	 	 	 	27	 	 	 	18	 	 	 	—	 	 	 	18	 	 	 	29	 	 	 	—	 	 	 	29	 	
Other	 	 	40	 	 	 	—	 	 	 	40	 	 	 	39	 	 	 	—	 	 	 	39	 	 	 	32	 	 	 	—	 	 	 	32	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total revenues	 	 	4,037	 	 	 	(3	)	 	 	4,034	 	 	 	3,683	 	 	 	(2	)	 	 	3,681	 	 	 	6,187	 	 	 	(3	)	 	 	6,184	 	
Costs and expenses:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Lease and facility operating, including affiliate	 	 	286	 	 	 	—	 	 	 	286	 	 	 	263	 	 	 	—	 	 	 	263	 	 	 	272	 	 	 	—	 	 	 	272	 	
Gathering, processing and transportation, including affiliate	 	 	323	 	 	 	3	 	 	 	326	 	 	 	268	 	 	 	5	 	 	 	273	 	 	 	223	 	 	 	6	 	 	 	229	 	
Taxes other than income	 	 	125	 	 	 	—	 	 	 	125	 	 	 	93	 	 	 	—	 	 	 	93	 	 	 	254	 	 	 	—	 	 	 	254	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Gas management (including charges for unutilized pipeline capacity)	 	 	1,774	 	 	 	(3	)	 	 	1,771	 	 	 	1,496	 	 	 	(1	)	 	 	1,495	 	 	 	3,248	 	 	 	—	 	 	 	3,248	 	
Exploration	 	 	73	 	 	 	—	 	 	 	73	 	 	 	54	 	 	 	—	 	 	 	54	 	 	 	37	 	 	 	—	 	 	 	37	 	
Depreciation, depletion and amortization	 	 	874	 	 	 	1	 	 	 	875	 	 	 	887	 	 	 	—	 	 	 	887	 	 	 	738	 	 	 	—	 	 	 	738	 	
Impairment of producing properties and costs of acquired unproved reserves	 	 	678	 	 	 	—	 	 	 	678	 	 	 	15	 	 	 	—	 	 	 	15	 	 	 	—	 	 	 	—	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Goodwill impairment	 	 	1,003	 	 	 	—	 	 	 	1,003	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
General and administrative, including affiliate	 	 	252	 	 	 	1	 	 	 	253	 	 	 	251	 	 	 	—	 	 	 	251	 	 	 	247	 	 	 	—	 	 	 	247	 	
Gain on sale of contractual right to international production payment	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(148	)	 	 	—	 	 	 	(148	)	
Other—net	 	 	(19	)	 	 	—	 	 	 	(19	)	 	 	33	 	 	 	—	 	 	 	33	 	 	 	6	 	 	 	—	 	 	 	6	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total costs and expenses	 	 	5,369	 	 	 	2	 	 	 	5,371	 	 	 	3,360	 	 	 	4	 	 	 	3,364	 	 	 	4,877	 	 	 	6	 	 	 	4,883	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating income (loss)	 	 	(1,332	)	 	 	(5	)	 	 	(1,337	)	 	 	323	 	 	 	(6	)	 	 	317	 	 	 	1,310	 	 	 	(9	)	 	 	1,301	 	
Interest expense, including affiliate	 	 	(124	)	 	 	—	 	 	 	(124	)	 	 	(100	)	 	 	—	 	 	 	(100	)	 	 	(74	)	 	 	—	 	 	 	(74	)	
Interest capitalized	 	 	16	 	 	 	—	 	 	 	16	 	 	 	18	 	 	 	—	 	 	 	18	 	 	 	20	 	 	 	—	 	 	 	20	 	
Investment income and other	 	 	21	 	 	 	—	 	 	 	21	 	 	 	8	 	 	 	—	 	 	 	8	 	 	 	22	 	 	 	—	 	 	 	22	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income (loss) before income taxes	 	 	(1,419	)	 	 	(5	)	 	 	(1,424	)	 	 	249	 	 	 	(6	)	 	 	243	 	 	 	1,278	 	 	 	(9	)	 	 	1,269	 	
Provision (benefit) for income taxes	 	 	(148	)	 	 	(2	)	 	 	(150	)	 	 	96	 	 	 	(2	)	 	 	94	 	 	 	455	 	 	 	(3	)	 	 	452	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income (loss) from continuing operations	 	 	(1,271	)	 	 	(3	)	 	 	(1,274	)	 	 	153	 	 	 	(4	)	 	 	149	 	 	 	823	 	 	 	(6	)	 	 	817	 	
Loss from discontinued operations	 	 	(8	)	 	 	—	 	 	 	(8	)	 	 	(7	)	 	 	—	 	 	 	(7	)	 	 	(87	)	 	 	—	 	 	 	(87	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income (loss)	 	 	(1,279	)	 	 	(3	)	 	 	(1,282	)	 	 	146	 	 	 	(4	)	 	 	142	 	 	 	736	 	 	 	(6	)	 	 	730	 	
Less: Net income attributable to noncontrolling interests	 	 	8	 	 	 	—	 	 	 	8	 	 	 	6	 	 	 	—	 	 	 	6	 	 	 	8	 	 	 	—	 	 	 	8	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income (loss) attributable to WPX Energy	 	$	(1,287	)	 	$	(3	)	 	$	(1,290	)	 	$	140	 	 	$	(4	)	 	$	136	 	 	$	728	 	 	$	(6	)	 	$	722	 	

 

			
(1)		Includes reclassifications made to report the results of operations of our Arkoma properties as discontinued operations (See Note 1).	

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WPX Energy
 
Notes to Combined Financial Statements—(Continued)

 	 	December 31, 2010	 	 	December 31, 2009	 	
 	 	Previously	 	 	 	 	 	As	 	 	Previously	 	 	 	 	 	As	 	
 	 	Reported(1)	 	 	Adjustments	 	 	Adjusted	 	 	Reported(1)	 	 	Adjustments	 	 	Adjusted	 	
 		
Assets	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Current assets:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash and cash equivalents	 	$	37	 	 	$	—	 	 	$	37	 	 	$	34	 	 	$	—	 	 	$	34	 	
Accounts receivable:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Trade, net of allowance for doubtful accounts of $15 and $19 as of December 31, 2010 and 2009, respectively	 	 	362	 	 	 	—	 	 	 	362	 	 	 	361	 	 	 	(2	)	 	 	359	 	
Affiliate	 	 	60	 	 	 	—	 	 	 	60	 	 	 	54	 	 	 	—	 	 	 	54	 	
Derivative assets	 	 	400	 	 	 	—	 	 	 	400	 	 	 	650	 	 	 	—	 	 	 	650	 	
Inventories	 	 	77	 	 	 	—	 	 	 	77	 	 	 	61	 	 	 	—	 	 	 	61	 	
Other	 	 	22	 	 	 	—	 	 	 	22	 	 	 	41	 	 	 	—	 	 	 	41	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total current assets	 	 	958	 	 	 	—	 	 	 	958	 	 	 	1,201	 	 	 	(2	)	 	 	1,199	 	
Investments	 	 	105	 	 	 	—	 	 	 	105	 	 	 	95	 	 	 	—	 	 	 	95	 	
Properties and equipment, net (successful efforts method of accounting)	 	 	8,450	 	 	 	(1	)	 	 	8,449	 	 	 	7,662	 	 	 	—	 	 	 	7,662	 	
Derivative assets	 	 	173	 	 	 	—	 	 	 	173	 	 	 	444	 	 	 	—	 	 	 	444	 	
Goodwill, net	 	 	—	 	 	 	—	 	 	 	—	 	 	 	1,003	 	 	 	—	 	 	 	1,003	 	
Other noncurrent assets	 	 	161	 	 	 	—	 	 	 	161	 	 	 	150	 	 	 	—	 	 	 	150	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total assets	 	$	9,847	 	 	$	(1	)	 	$	9,846	 	 	$	10,555	 	 	$	(2	)	 	$	10,553	 	

Liabilities and Equity	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Current liabilities:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Accounts payable:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Trade	 	$	446	 	 	$	5	 	 	$	451	 	 	$	460	 	 	$	2	 	 	$	462	 	
Affiliate	 	 	64	 	 	 	—	 	 	 	64	 	 	 	37	 	 	 	—	 	 	 	37	 	
Accrued and other current liabilities	 	 	144	 	 	 	14	 	 	 	158	 	 	 	220	 	 	 	11	 	 	 	231	 	
Deferred income taxes	 	 	87	 	 	 	—	 	 	 	87	 	 	 	28	 	 	 	—	 	 	 	28	 	
Notes payable to Williams	 	 	2,261	 	 	 	—	 	 	 	2,261	 	 	 	1,216	 	 	 	—	 	 	 	1,216	 	
Derivative liabilities	 	 	146	 	 	 	—	 	 	 	146	 	 	 	578	 	 	 	—	 	 	 	578	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total current liabilities	 	 	3,148	 	 	 	19	 	 	 	3,167	 	 	 	2,539	 	 	 	13	 	 	 	2,552	 	
Deferred income taxes	 	 	1,629	 	 	 	—	 	 	 	1,629	 	 	 	1,841	 	 	 	—	 	 	 	1,841	 	
Derivative liabilities	 	 	143	 	 	 	—	 	 	 	143	 	 	 	428	 	 	 	—	 	 	 	428	 	
Asset retirement obligations	 	 	282	 	 	 	—	 	 	 	282	 	 	 	235	 	 	 	—	 	 	 	235	 	
Other noncurrent liabilities	 	 	125	 	 	 	—	 	 	 	125	 	 	 	92	 	 	 	—	 	 	 	92	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Contingent liabilities and commitments (Note 11)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Equity:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Owner’s net equity:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Owner’s net investment	 	 	4,280	 	 	 	(20	)	 	 	4,260	 	 	 	5,284	 	 	 	(15	)	 	 	5,269	 	
Accumulated other comprehensive income	 	 	168	 	 	 	—	 	 	 	168	 	 	 	72	 	 	 	—	 	 	 	72	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total owner’s net equity	 	 	4,448	 	 	 	(20	)	 	 	4,428	 	 	 	5,356	 	 	 	(15	)	 	 	5,341	 	
Noncontrolling interests in combined subsidiaries	 	 	72	 	 	 	—	 	 	 	72	 	 	 	64	 	 	 	—	 	 	 	64	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total equity	 	 	4,520	 	 	 	(20	)	 	 	4,500	 	 	 	5,420	 	 	 	(15	)	 	 	5,405	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total liabilities and equity	 	$	9,847	 	 	$	(1	)	 	$	9,846	 	 	 	10,555	 	 	$	(2	)	 	 	10,553	 	

 

			
(1)		Includes reclassifications made to report the financial position of our Arkoma properties as held for sale (See Note 1).	
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WPX Energy
 
Notes to Combined Financial Statements—(Continued)

3.  	Discontinued Operations	
 
Summarized Results of Discontinued Operations

 	 	2010	 	 	2009	 	 	2008	 	
 		
Revenues	 	$	16	 	 	$	17	 	 	$	43	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Income (loss) from discontinued operations before impairments, gain on sale and income taxes	 	$	(13	)	 	$	(11	)	 	$	4	 	
(Impairments) and gain on sale	 	 	—	 	 	 	—	 	 	 	(140	)	
Benefit for income taxes	 	 	5	 	 	 	4	 	 	 	49	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Loss from discontinued operations	 	$	(8	)	 	$	(7	)	 	$	(87	)	

 
(Impairments) and gain on sale for 2008 includes $148 million of impairments related to properties in the Arkoma Basin and the final proceeds from the 2007 sale of Williams’ former power business.
 
The assets of our holdings in the Arkoma Basin comprise significantly less than 1% of our total assets as of December 31, 2010 and 2009 and are reported in other assets and other noncurrent assets on our Combined Balance Sheet. Liabilities of our discontinued operations are insignificant for these periods.

4.  	Related Party Transactions	
 
Transactions with Williams and Other Affiliated Entities
 
Our employees are also employees of Williams. Williams charges us for the payroll and benefit costs associated with operations employees (referred to as direct employees) and carries the obligations for many employee-related benefits in its financial statements, including the liabilities related to employee retirement and medical plans. Our share of those costs is charged to us through affiliate billings and reflected in lease and facility operating and general and administrative within costs and expenses in the accompanying Combined Statement of Operations.
 
In addition, Williams charges us for certain employees of Williams who provide general and administrative services on our behalf (referred to as indirect employees). These charges are either directly identifiable or allocated to our operations. Direct charges include goods and services provided by Williams at our request. Allocated general corporate costs are based on our relative usage of the service or on a three-factor formula, which considers revenues; properties and equipment; and payroll. Our share of direct general and administrative expenses and our share of allocated general corporate expenses is reflected in general and administrative expense in the accompanying Combined Statement of Operations. In management’s estimation, the allocation methodologies used are reasonable and result in a reasonable allocation to us of our costs of doing business incurred by Williams. We also have operating activities with WPZ and another Williams subsidiary. Our revenues include revenues from the following types of transactions:

 	•  	Sales of natural gas liquids (NGLs) related to our production to WPZ at market prices at the time of sale and included within our oil and gas sales revenues; and	
 		
 	•  	Sale to WPZ and another Williams subsidiary of natural gas procured by Williams Gas Marketing Services for those companies’ fuel and shrink replacement at market prices at the time of sale and included in our gas management revenues.	
 
Our costs and operating expenses include the following services provided by WPZ:

 	•  	Gathering, treating and processing services under several contracts for our production primarily in the San Juan and Piceance Basins; and	

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WPX Energy
 
Notes to Combined Financial Statements—(Continued)

			
 	•  	Pipeline transportation for both our oil and gas sales and gas management activities which includes commitments totaling $442 million (see Note 11 for capacity commitments with affiliates).	
 
In addition, through an agency agreement, we manage the jurisdictional merchant gas sales for Transcontinental Gas Pipe Line Company LLC (“Transco”), an indirect, wholly owned subsidiary of WPZ. We are authorized to make gas sales on Transco’s behalf in order to manage its gas purchase obligations. Although there is no exchange of payments between us and Transco for these transactions, we receive all margins associated with jurisdictional merchant gas sales business and, as Transco’s agent, assume all market and credit risk associated with such sales. Gas sales and purchases related to our management of these jurisdictional merchant gas sales are included in gas management revenues and expenses, respectively in the Combined Statement of Operations and the margins we realized related to these activities totaled less than $1 million in each of the years ended December 31, 2010, 2009 and 2008.
 
We manage a transportation capacity contract for WPZ. To the extent the transportation is not fully utilized or does not recover full-rate demand expense, WPZ reimburses us for these transportation costs. These reimbursements to us totaled approximately $10 million, $9 million and $11 million for the years ended December 31, 2010, 2009 and 2008, respectively, and are included in gas management revenues.
 
WPZ periodically enters into derivative contracts with us to hedge their forecasted NGL sales and natural gas purchases. We enter into offsetting derivative contracts with third parties at equivalent pricing and volumes. These contracts are included in derivative assets and liabilities on the Combined Balance Sheet (see Note 15).
 
Williams utilizes a centralized approach to cash management and the financing of its businesses. Cash receipts from the Company’s domestic operations are transferred to Williams on a regular basis and cleared through unsecured promissory note agreements with Williams. Cash expenditures for property operating and development costs and expenses are also cleared through these unsecured promissory note agreements with Williams. The amounts receivable or due under the note agreements are due on demand, however, Williams has agreed to not make demand on these notes payable prior to the completion of the Offering. Williams has also agreed to forgive or contribute any amounts outstanding on these note agreements prior to or concurrent with the Contribution. The notes bear interest based on Williams’ weighted average cost of debt and such interest is added monthly to the note principal. The interest rate for the notes payable to Williams was 8.08% and 8.01% at December 31, 2010 and 2009, respectively. As of December 31, 2010 and 2009, our net amounts due to Williams are reflected as notes payable to Williams. None of Williams’ cash or debt at the Williams corporate level has been allocated to the Company in the financial statements. Changes in the notes represent any funding required from Williams for working capital, acquisitions or capital expenditures and after giving effect to the Company’s transfers to Williams from its cash flows from operations or proceeds from sales of assets. Concurrently with or shortly following the consummation of the Offering, we expect to issue up to $1.5 billion aggregate principal amount of senior unsecured notes. Furthermore, we expect to distribute the net proceeds from the Offering and the issuance of the notes in excess of approximately $500 million to Williams.
 
Under Williams’ cash-management system, certain cash accounts reflect negative balances to the extent checks written have not been presented for payment. These negative amounts represent obligations and have been reclassified to accounts payable-affiliate. Accounts payable-affiliate includes approximately $38 million and $26 million of these negative balances at December 31, 2010 and 2009, respectively.

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WPX Energy
 
Notes to Combined Financial Statements—(Continued)
 
Below is a summary of the related party transactions discussed above:

 	 	2010	 	 	2009	 	 	2008	 	
 	 	(Millions)	 	
 		
Oil and gas sales revenues—sales of NGLs to WPZ	 	$	277	 	 	$	116	 	 	$	36	 	
Gas management revenues—sales of natural gas for fuel and shrink to WPZ and another Williams subsidiary	 	 	509	 	 	 	431	 	 	 	1,042	 	
Lease and facility operating expenses from Williams-direct employee salary and benefit costs	 	 	23	 	 	 	23	 	 	 	19	 	
Gathering, processing and transportation expense from	 	 	 	 	 	 	 	 	 	 	 	 	
WPZ:	 	 	 	 	 	 	 	 	 	 	 	 	
Gathering and processing	 	 	163	 	 	 	72	 	 	 	44	 	
Transportation	 	 	25	 	 	 	28	 	 	 	34	 	
General and administrative from Williams:	 	 	 	 	 	 	 	 	 	 	 	 	
Direct employee salary and benefit costs	 	 	102	 	 	 	100	 	 	 	92	 	
Charges for general and administrative services	 	 	58	 	 	 	60	 	 	 	60	 	
Allocated general corporate costs	 	 	64	 	 	 	63	 	 	 	56	 	
Other	 	 	12	 	 	 	13	 	 	 	12	 	
Interest expense on notes payable to Williams	 	 	119	 	 	 	92	 	 	 	64	 	

In addition, the current amount due to or from affiliates consists of normal course receivables and payables resulting from the sale of products to and cost of gathering services provided by WPZ. Below is a summary of these payables and receivables which are settled monthly:

 	 	December 31,	 	
 	 	2010	 	 	2009	 	
 	 	(Millions)	 	
 		
Current:	 	 	 	 	 	 	 	 	
Accounts receivable:	 	 	 	 	 	 	 	 	
Due from WPZ and another Williams subsidiary	 	$	60	 	 	$	54	 	
 	 	 	 	 	 	 	 	 	
Accounts payable:	 	 	 	 	 	 	 	 	
Due to WPZ	 	$	12	 	 	$	2	 	
Due to Williams for cash overdraft. 	 	 	38	 	 	 	26	 	
Due to Williams for accrued payroll and benefits	 	 	14	 	 	 	9	 	
 	 	 	 	 	 	 	 	 	
 	 	$	64	 	 	$	37	 	

 
As discussed in Note 1, the Company sold certain gathering and processing assets in Colorado’s Piceance Basin to WPZ. Under an Omnibus Agreement entered into in connection with this transaction, we are obligated to reimburse WPZ for (i) amounts incurred by WPZ or its subsidiaries for any costs required to complete the pipeline and compression projects known collectively as the Ryan Gulch Expansion Project, (ii) amounts incurred by WPZ or its subsidiaries prior to January 31, 2011, related to the development of a cryogenic processing arrangement with a subsidiary of Williams, up to $20 million, and (iii) amounts incurred by WPZ or its subsidiaries for notice of violation or enforcement actions related to compression station land use permits or other losses, costs and expenses related to certain surface lease use agreements. In addition, WPZ is obligated to reimburse us for any costs related to the pipeline and compression projects known collectively as the Kokopelli Expansion irrespective of whether those costs were incurred prior to the effective date of the transaction. Estimated amounts for these obligations were recorded at the time of the sale and were less than $5 million. Differences in the estimated amounts and actual payments will be reflected within

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WPX Energy
 
Notes to Combined Financial Statements—(Continued)
 
Owner’s Net Investment consistent with the treatment of the difference in the net book value and proceeds from sale.

5.  	Investment Income and Other	
 
Investment income and other for the years ended December 31, 2010, 2009 and 2008, is as follows:

 	 	Years Ended December 31,	 	
 	 	2010	 	 	2009	 	 	2008	 	
 	 	(Millions)	 	
 		
Equity earnings	 	$	20	 	 	$	18	 	 	$	20	 	
Impairment of cost-based investment	 	 	—	 	 	 	(11	)	 	 	—	 	
Other	 	 	1	 	 	 	1	 	 	 	2	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total investment income and other	 	$	21	 	 	$	8	 	 	$	22	 	

 
Impairment of cost-based investment in 2009 reflects an $11 million full impairment of our 4 percent interest in a Venezuelan corporation that owns and operates oil and gas activities in Venezuela.
 
Investments
 
Investment balance as of December 31, 2010 and 2009 is as follows:

 	 	December 31,	 	
 	 	2010	 	 	2009	 	
 	 	(Millions)	 	
 		
Petrolera Entre Lomas S.A.—40.8%	 	$	82	 	 	$	81	 	
Other	 	 	23	 	 	 	14	 	
 	 	 	 	 	 	 	 	 	
 	 	$	105	 	 	$	95	 	

 
Dividends and distributions received from companies accounted for by the equity method were $19 million in 2010, $9 million in 2009 and $11 million in 2008.

6.  	Asset Sales, Impairments, Exploration Expenses and Other Accruals	
 
The following table presents a summary of significant gains or losses reflected in impairment of producing properties and costs of acquired unproved reserves, goodwill impairment and other—net within costs and expenses:

 	 	Years Ended December 31,	 	
 	 	2010	 	 	2009	 	 	2008	 	
 	 	(Millions)	 	
 		
Goodwill impairment	 	$	1,003	 	 	$	—	 	 	$	—	 	
Impairment of producing properties and costs of acquired unproved reserves*	 	 	678	 	 	 	15	 	 	 	—	 	
Penalties from early release of drilling rigs included in other (income) expense—net	 	 	—	 	 	 	32	 	 	 	—	 	
Gain on sale of contractual right to an international production payment	 	 	—	 	 	 	—	 	 	 	(148	)	
(Gain) loss on sales of other assets	 	 	(22	)	 	 	1	 	 	 	1	 	

 
			
*		Excludes unproved leasehold property impairment, amortization and expiration included in exploration expenses.	

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WPX Energy
 
Notes to Combined Financial Statements—(Continued)

As a result of significant declines in forward natural gas prices during 2010, we performed an interim impairment assessment of our capitalized costs related to goodwill and domestic producing properties. As a result of these assessments, we recorded an impairment of goodwill, as noted above, and impairments of our capitalized costs of certain natural gas producing properties in the Barnett Shale of $503 million and capitalized costs of certain acquired unproved reserves in the Piceance Highlands acquired in 2008 of $175 million (see Note 14).
 
Based on a comparison of the estimated fair value to the carrying value, we recorded a $15 million impairment in 2009 related to costs of acquired unproved reserves resulting from a 2008 acquisition in the Fort Worth Basin (see Note 14).
 
Our impairment analyses included an assessment of undiscounted (except for the costs of acquired unproved reserves) and discounted future cash flows, which considered information obtained from drilling, other activities, and natural gas reserve quantities.
 
In July 2010, we sold a portion of our gathering and processing facilities in the Piceance Basin to a third party for cash proceeds of $30 million resulting in a gain of $12 million. The remaining portion of the facilities was part of the Piceance Sale (see Note 1). Also in 2010, we exchanged undeveloped leasehold acreage in different areas with a third party resulting in a $7 million gain.
 
In January 2008, we sold a contractual right to a production payment on certain future international hydrocarbon production for $148 million. We obtained this interest (for which we allocated no value) through the acquisition of Barrett Resources Corporation in 2001 and there were no operations associated with this interest. As a result of the contract termination, we have no further interests associated with the crude oil concession which is located in Peru.
 
The following presents a summary of exploration expenses:

 	 	Years Ended December 31	 	
 	 	2010	 	 	2009	 	 	2008	 	
 	 	(Millions)	 	
 		
Geologic and geophysical costs	 	$	22	 	 	$	33	 	 	$	13	 	
Dry hole costs	 	 	17	 	 	 	11	 	 	 	16	 	
Unproved leasehold property impairment, amortization and expiration	 	 	34	 	 	 	10	 	 	 	8	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total exploration expense	 	$	73	 	 	$	54	 	 	$	37	 	

 
Additional Items
 
Production and ad valorem taxes in 2008 include a $34 million accrual (which was reduced by $5 million in 2009) for additional Wyoming severance and ad valorem taxes associated with our initial estimate for settlement of an assessment initially for production years 2000 through 2002, but expanded through 2008 by the Wyoming Department of Audit (DOA), of additional severance tax and interest and notification of an increase in the taxable value of our interests for ad valorem tax purposes. Associated with this charge is an interest expense accrual of $4 million. All matters related to this issue have been settled with the State and respective counties for the amounts accrued.

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Notes to Combined Financial Statements—(Continued)

7.  	Properties and Equipment	
 
Properties and equipment is carried at cost and consists of the following:

 	 	Estimated	 	 	 	 	 	 	 	
 	 	Useful Life(a)	 	 	December 31,	 	
 	 	(Years)	 	 	2010	 	 	2009	 	
 	 	 	 	 	(Millions)	 	
 		
Proved properties	 	 	(b)	 	 	$	9,822	 	 	$	8,784	 	
Unproved properties	 	 	(c)	 	 	 	1,893	 	 	 	922	 	
Gathering, processing and other facilities	 	 	15-25	 	 	 	119	 	 	 	787	 	
Construction in progress	 	 	(c)	 	 	 	603	 	 	 	573	 	
Other	 	 	3-25	 	 	 	127	 	 	 	123	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total properties and equipment, at cost	 	 	 	 	 	 	12,564	 	 	 	11,189	 	
Accumulated depreciation, depletion and amortization	 	 	 	 	 	 	(4,115	)	 	 	(3,527	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Properties and equipment—net	 	 	 	 	 	$	8,449	 	 	$	7,662	 	

 

			
(a)		Estimated useful lives are presented as of December 31, 2010.	
 		
(b)		Proved properties are depreciated, depleted and amortized using the units-of-production method (see Note 1).	
 		
(c)		Unproved properties and construction in progress are not yet subject to depreciation and depletion.	
 
Unproved properties consist primarily of non-producing leasehold in the Williston Basin (Bakken Shale) and the Appalachian Basin (Marcellus Shale) and acquired unproved reserves in the Powder River and Piceance Basins.
 
On December 21, 2010, we closed the acquisition of 100 percent of the equity of Dakota-3 E&P Company LLC for $949 million, including closing adjustments. This company holds approximately 85,800 net acres on the Fort Berthold Indian Reservation in the Williston Basin of North Dakota. Approximately 85% of the acreage is undeveloped. Approximately $400 million of the purchase price was recorded as proved properties, $542 million as unproved properties within properties and equipment and $5 million of prepaid drilling costs (no significant working capital was acquired). Revenues and earnings for the acquired company were nominal and thus insignificant to us for the three years ended December 31, 2010, 2009 and 2008; accordingly, pro forma operating results would be substantially similar to those reflected on our historical Combined Statement of Operations.
 
As discussed in Notes 1 and 4, the Company sold certain gathering and processing assets in Colorado’s Piceance Basin with a net book value of $458 million to WPZ.
 
In May 2010, we entered into a purchase agreement consisting primarily of non-producing leasehold acreage in the Appalachian Basin and a 5 percent overriding royalty interest associated with the acreage position for $599 million. We also acquired additional non-producing leasehold acreage in the Appalachian Basin for $164 million during the year.
 
Construction in progress includes $142 million in 2010 and $136 million in 2009 related to wells located in Powder River. In order to produce gas from the coal seams, an extended period of dewatering is required prior to natural gas production.
 
In 2009, we adopted Accounting Standards Update No. 2010-03, which aligned oil and gas reserve estimation and disclosure requirements to those in the Securities and Exchange Commission’s final rule related thereto. Accordingly, our fourth quarter 2009 depreciation, depletion and amortization expense was approximately $17 million more than had it been computed under the prior requirements.

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Notes to Combined Financial Statements—(Continued)
 
Asset Retirement Obligations
 
Our asset retirement obligations relate to producing wells, gas gathering well connections and related facilities. At the end of the useful life of each respective asset, we are legally obligated to plug producing wells and remove any related surface equipment and to cap gathering well connections at the wellhead and remove any related facility surface equipment.
 
A rollforward of our asset retirement obligation for the years ended 2010 and 2009 is presented below.

 	 	2010	 	 	2009	 	
 	 	(Millions)	 	
 		
Balance, January 1	 	$	242	 	 	$	194	 	
Liabilities incurred during the period	 	 	43	 	 	 	18	 	
Liabilities settled during the period	 	 	(2	)	 	 	(1	)	
Liabilities associated with assets sold	 	 	(22	)	 	 	—	 	
Estimate revisions	 	 	3	 	 	 	15	 	
Accretion expense*	 	 	21	 	 	 	16	 	
 	 	 	 	 	 	 	 	 	
Balance, December 31	 	$	285	 	 	$	242	 	
 	 	 	 	 	 	 	 	 	
Amount reflected as current	 	$	3	 	 	$	7	 	

 

			
* 		Accretion expense is included in lease and facility operating expense on the Combined Statement of Operations.	

8.  	Accrued and other current liabilities	
 
Accrued and other current liabilities as of December 31, 2010 and 2009 is as follows:

 	 	December 31,	 	
 	 	2010	 	 	2009	 	
 	 	(Millions)	 	
 		
Taxes other than income taxes	 	$	76	 	 	$	126	 	
Customer margin deposit payable	 	 	25	 	 	 	31	 	
Other	 	 	57	 	 	 	74	 	
 	 	 	 	 	 	 	 	 	
 	 	$	158	 	 	$	231	 	

 
		
9.  	Unsecured Credit Agreement	
 
We have an unsecured credit agreement with certain banks in order to reduce margin requirements related to our hedging activities as well as lower transaction fees. In July 2010, the term of this facility was extended from December 2013 to December 2015. Under the credit agreement, we are not required to post collateral as long as the value of our domestic natural gas reserves, as determined under the provisions of the agreement, exceeds by a specified amount certain of our obligations including any outstanding debt and the aggregate out-of-the-money positions on hedges entered into under the credit agreement. We are subject to additional covenants under the credit agreement including restrictions on hedge limits (70% of annual forecasted production as defined in the agreement), the creation of liens, the incurrence of debt, the sale of assets and properties, and making certain payments during an event of default, such as dividends. In December 2010, a waiver with the same terms and restrictions as the original agreement, was executed that will allow us to also hedge up to 70% of annual forecasted oil production, as defined in the agreement.

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Notes to Combined Financial Statements—(Continued)

10.  	Income Taxes	
 
The Company’s domestic operations are included in the consolidated federal and state income tax returns for Williams, except for certain separate state filings. The income tax provision for the Company has been calculated on a separate return basis, except for certain state and federal tax attributes (primarily minimum tax credit carry-forwards) for which the actual allocation (if any) cannot be determined until the consolidated tax returns are complete for the year in which an income tax deconsolidation event occurs. If the income tax deconsolidation event had occurred December 31, 2010, the Company’s allocated share of minimum tax credit carry-forwards are estimated to be in the range of $35 to $45 million. This estimate of potential tax attributes has not been included in these financial statements. The valuation allowance at December 31, 2010 and 2009 serves to reduce the recognized tax assets of $22 million associated with state losses, net of federal benefit, to an amount that will more likely than not be realized by the Company. There have been no significant effects on the income tax provision associated with changes in the valuation allowance for the years ended December 31, 2010, 2009 and 2008. Williams manages its tax position based upon its entire portfolio which may not be indicative of tax planning strategies available to us if we were operating as an independent company.
 
The provision (benefit) for income taxes from continuing operations includes:

 	 	Years Ended December 31,	 	
 	 	2010	 	 	2009	 	 	2008	 	
 	 	(Millions)	 	
 		
Provision (benefit):	 	 	 	 	 	 	 	 	 	 	 	 	
Current:	 	 	 	 	 	 	 	 	 	 	 	 	
Federal	 	$	7	 	 	$	(17	)	 	$	(52	)	
State	 	 	1	 	 	 	(1	)	 	 	(3	)	
Foreign	 	 	11	 	 	 	9	 	 	 	8	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	19	 	 	 	(9	)	 	 	(47	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Deferred:	 	 	 	 	 	 	 	 	 	 	 	 	
Federal	 	 	(159	)	 	 	97	 	 	 	470	 	
State	 	 	(10	)	 	 	6	 	 	 	30	 	
Foreign	 	 	—	 	 	 	—	 	 	 	(1	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	(169	)	 	 	103	 	 	 	499	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total provision (benefit)	 	$	(150	)	 	$	94	 	 	$	452	 	

 
Reconciliations from the provision (benefit) for income taxes from continuing operations at the federal statutory rate to the realized provision (benefit) for income taxes are as follows:

 	 	Years Ended December 31,	 	
 	 	2010	 	 	2009	 	 	2008	 	
 	 	(Millions)	 	
 		
Provision (benefit) at statutory rate	 	$	(498	)	 	$	85	 	 	$	444	 	
Increases (decreases) in taxes resulting from:	 	 	 	 	 	 	 	 	 	 	 	 	
State income taxes (net of federal benefit)	 	 	(6	)	 	 	3	 	 	 	18	 	
Foreign operations—net	 	 	3	 	 	 	5	 	 	 	(2	)	
Goodwill impairment	 	 	351	 	 	 	—	 	 	 	—	 	
Other—net	 	 	—	 	 	 	1	 	 	 	(8	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Provision (benefit) for income taxes	 	$	(150	)	 	$	94	 	 	$	452	 	

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Notes to Combined Financial Statements—(Continued)
 
Income (loss) from continuing operations before income taxes includes $36 million, $21 million, and $30 million of foreign income in 2010, 2009, and 2008, respectively.
 
Significant components of deferred tax liabilities and deferred tax assets are as follows:

 	 	December 31,	 	
 	 	2010	 	 	2009	 	
 	 	(Millions)	 	
 		
Deferred tax liabilities:	 	 	 	 	 	 	 	 	
Properties and equipment	 	$	1,723	 	 	$	1,939	 	
Derivatives, net	 	 	110	 	 	 	61	 	
 	 	 	 	 	 	 	 	 	
Total deferred tax liabilities	 	 	1,833	 	 	 	2,000	 	
 	 	 	 	 	 	 	 	 	
Deferred tax assets:	 	 	 	 	 	 	 	 	
Accrued liabilities and other	 	 	117	 	 	 	131	 	
State loss carryovers	 	 	22	 	 	 	22	 	
 	 	 	 	 	 	 	 	 	
Total deferred tax assets	 	 	139	 	 	 	153	 	
Less: valuation allowance	 	 	22	 	 	 	22	 	
 	 	 	 	 	 	 	 	 	
Total net deferred tax assets	 	 	117	 	 	 	131	 	
 	 	 	 	 	 	 	 	 	
Net deferred tax liabilities	 	$	1,716	 	 	$	1,869	 	

 
Undistributed earnings of certain combined foreign subsidiaries at December 31, 2010, totaled approximately $109 million. No provision for deferred U.S. income taxes has been made for these subsidiaries because we intend to permanently reinvest such earnings in foreign operations.
 
The payments and receipts for domestic income taxes were made to or received from Williams via the notes payable to parent (see Note 4) in accordance with our historical tax allocation procedure. The cash payments for domestic income taxes (net of refunds) were $5 million in 2010. Cash receipts for domestic income taxes (net of payments) were $13 million and $44 million in 2009 and 2008, respectively. Additionally, payments made directly to international taxing authorities were $8 million, $4 million, and $8 million in 2010, 2009, and 2008, respectively.
 
We recognize related interest and penalties as a component of income tax expense. The amounts accrued for interest and penalties are insignificant.
 
As of December 31, 2010, the amount of unrecognized tax benefits is insignificant.
 
During the first quarter of 2011, Williams finalized settlements with the IRS for 1997 through 2008. These settlements will not have a material impact on our unrecognized tax benefits. The statute of limitations for most states expires one year after expiration of the IRS statute. Income tax returns for our Colombian (2008 through 2010), Venezuelan (2006 through 2010) and Argentine (2003 through 2010) entities are also open to audit.
 
During the next 12 months, we do not expect ultimate resolution of any uncertain tax position associated with a domestic or international matter will result in a significant increase or decrease of our unrecognized tax benefit.

11.  	Contingent Liabilities and Commitments	
 
Royalty litigation
 
In September 2006, royalty interest owners in Garfield County, Colorado, filed a class action suit in District Court, Garfield County Colorado, alleging we improperly calculated oil and gas royalty payments, failed to account for the proceeds that we received from the sale of natural gas and extracted products, improperly charged certain expenses and failed to refund amounts withheld in excess of ad valorem tax obligations. Plaintiffs sought to certify as a class of royalty interest owners, recover underpayment of royalties and obtain corrected payments resulting from calculation errors. We entered into a final partial settlement agreement. The partial settlement agreement defined the class members for class certification, reserved two claims for court resolution, resolved all other class

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Notes to Combined Financial Statements—(Continued)
 
claims relating to past calculation of royalty and overriding royalty payments, and established certain rules to govern future royalty and overriding royalty payments. This settlement resolved all claims relating to past withholding for ad valorem tax payments and established a procedure for refunds of any such excess withholding in the future. The first reserved claim is whether we are entitled to deduct in our calculation of royalty payments a portion of the costs we incur beyond the tailgates of the treating or processing plants for mainline pipeline transportation. We received a favorable ruling on our motion for summary judgment on the first reserved claim. Plaintiffs appealed that ruling and the Colorado Court of Appeals found in our favor in April 2011. The second reserved claim relates to whether we are required to have proportionately increased the value of natural gas by transporting that gas on mainline transmission lines and, if required, whether we did so and are thus entitled to deduct a proportionate share of transportation costs in calculating royalty payments. We anticipate trial on the second reserved claim following resolution of the first reserved claim. We believe our royalty calculations have been properly determined in accordance with the appropriate contractual arrangements and Colorado law. At this time, the plaintiffs have not provided us a sufficient framework to calculate an estimated range of exposure related to their claims. However, it is reasonably possible that the ultimate resolution of this item could result in a future charge that may be material to our results of operations.
 
Other producers have been in litigation or discussions with a federal regulatory agency and a state agency in New Mexico regarding certain deductions, comprised primarily of processing, treating and transportation costs, used in the calculation of royalties. Although we are not a party to these matters, we have monitored them to evaluate whether their resolution might have the potential for unfavorable impact on our results of operations. One of these matters involving federal litigation was decided on October 5, 2009. The resolution of this specific matter is not material to us. However, other related issues in these matters that could be material to us remain outstanding. We received notice from the U.S. Department of Interior Office of Natural Resources Revenue (ONRR) in the fourth quarter of 2010, intending to clarify the guidelines for calculating federal royalties on conventional gas production applicable to our federal leases in New Mexico. The ONRR’s guidance provides its view as to how much of a producer’s bundled fees for transportation and processing can be deducted from the royalty payment. We believe using these guidelines would not result in a material difference in determining our historical federal royalty payments for our leases in New Mexico. No similar specific guidance has been issued by ONRR for leases in other states, but such guidelines are expected in the future. However, the timing of receipt of the necessary guidelines is uncertain. In addition, these interpretive guidelines on the applicability of certain deductions in the calculation of federal royalties are extremely complex and will vary based upon the ONRR’s assessment of the configuration of processing, treating and transportation operations supporting each federal lease. From January 2004 through December 2010, our deductions used in the calculation of the royalty payments in states other than New Mexico associated with conventional gas production total approximately $55 million. Based on correspondence in 2009 with the ONRR’s predecessor, we believe our assumptions in the calculations have been consistent with the requirements. The issuance of similar guidelines in Colorado and other states could affect our previous royalty payments and the effect could be material to our results of operations.
 
Environmental matters
 
The EPA and various state regulatory agencies routinely promulgate and propose new rules, and issue updated guidance to existing rules. These new rules and rulemakings include, but are not limited to, rules for reciprocating internal combustion engine maximum achievable control technology, new air quality standards for ground level ozone, and one hour nitrogen dioxide emission limits. We are unable to estimate the costs of asset additions or modifications necessary to comply with these new regulations due to uncertainty created by the various legal challenges to these regulations and the need for further specific regulatory guidance.
 
Matters related to Williams’ former power business
 
California energy crisis
 
Our former power business was engaged in power marketing in various geographic areas, including California. Prices charged for power by us and other traders and generators in California and other western

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Notes to Combined Financial Statements—(Continued)
 
states in 2000 and 2001 were challenged in various proceedings, including those before the FERC. We have entered into settlements with the State of California (State Settlement), major California utilities (Utilities Settlement), and others that substantially resolved each of these issues with these parties.
 
Although the State Settlement and Utilities Settlement resolved a significant portion of the refund issues among the settling parties, we continue to have potential refund exposure to nonsettling parties, including various California end users that did not participate in the Utilities Settlement. We are currently in settlement negotiations with certain California utilities aimed at eliminating or substantially reducing this exposure. If successful, and subject to a final “true-up” mechanism, the settlement agreement would also resolve our collection of accrued interest from counterparties as well as our payment of accrued interest on refund amounts. Thus, as currently contemplated by the parties, the settlement agreement would resolve most, if not all, of our legal issues arising from the 2000-2001 California Energy Crisis. With respect to these matters, amounts accrued are not material to our financial position.
 
Certain other issues also remain open at the FERC and for other nonsettling parties.
 
Reporting of natural gas-related information to trade publications
 
Civil suits based on allegations of manipulating published gas price indices have been brought against us and others, in each case seeking an unspecified amount of damages. We are currently a defendant in class action litigation and other litigation originally filed in state court in Colorado, Kansas, Missouri and Wisconsin brought on behalf of direct and indirect purchasers of natural gas in those states. These cases were transferred to the federal court in Nevada. In 2008, the court granted summary judgment in the Colorado case in favor of us and most of the other defendants based on plaintiffs’ lack of standing. On January 8, 2009, the court denied the plaintiffs’ request for reconsideration of the Colorado dismissal and entered judgment in our favor. We expect that the Colorado plaintiffs will appeal, but the appeal cannot occur until the case against the remaining defendant is concluded.
 
In the other cases, our joint motions for summary judgment to preclude the plaintiffs’ state law claims based upon federal preemption have been pending since late 2009. If the motions are granted, we expect a final judgment in our favor which the plaintiffs could appeal. If the motions are denied, the current stay of activity would be lifted, class certification would be addressed, and discovery would be completed as the cases proceed towards trial. Because of the uncertainty around these current pending unresolved issues, including an insufficient description of the purported classes and other related matters, we cannot reasonably estimate a range of potential exposures at this time. However, it is reasonably possible that the ultimate resolution of these items could result in future charges that may be material to our results of operations.
 
Other Divestiture Indemnifications
 
Pursuant to various purchase and sale agreements relating to divested businesses and assets, we have indemnified certain purchasers against liabilities that they may incur with respect to the businesses and assets acquired from us. The indemnities provided to the purchasers are customary in sale transactions and are contingent upon the purchasers incurring liabilities that are not otherwise recoverable from third parties. The indemnities generally relate to breach of warranties, tax, historic litigation, personal injury, environmental matters, right of way and other representations that we have provided.
 
At December 31, 2010, we do not expect any of the indemnities provided pursuant to the sales agreements to have a material impact on our future financial position. However, if a claim for indemnity is brought against us in the future, it may have a material adverse effect on our results of operations in the period in which the claim is made.
 
In addition to the foregoing, various other proceedings are pending against us which are incidental to our operations.

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Notes to Combined Financial Statements—(Continued)
 
Summary
 
Litigation, arbitration, regulatory matters, and environmental matters are subject to inherent uncertainties. Were an unfavorable ruling to occur, there exists the possibility of a material adverse impact on the results of operations in the period in which the ruling occurs. As of December 31, 2010 and 2009, the Company had accrued approximately $21 million and $30 million, respectively, for loss contingencies associated with royalty litigation, reporting of natural gas information to trade publications and other contingencies. Management, including internal counsel, currently believes that the ultimate resolution of the foregoing matters, taken as a whole and after consideration of amounts accrued, insurance coverage, recovery from customers or other indemnification arrangements, is not expected to have a materially adverse effect upon our future liquidity or financial position; however, it could be material to our results of operations in any given year.
 
Commitments
 
As part of managing our commodity price risk, we utilize contracted pipeline capacity (including capacity on affiliates’ systems, resulting in a total of $442 million for all years) primarily to move our natural gas production to other locations in an attempt to obtain more favorable pricing differentials. Our commitments under these contracts are as follows:

 	 	(Millions)	 	
 		
2011	 	$	204	 	
2012	 	 	208	 	
2013	 	 	200	 	
2014	 	 	174	 	
2015	 	 	166	 	
Thereafter	 	 	635	 	
 	 	 	 	 	
Total	 	$	1,587	 	

 
We have certain commitments to an equity investee and others for natural gas gathering and treating services, which total $447 million over approximately eleven years.
 
We have a long-term obligation to deliver on a firm basis 200,000 MMBtu per day of natural gas to a buyer at the White River Hub (Greasewood-Meeker, Colorado), which is the major market hub exiting the Piceance Basin. This obligation expires in 2014.
 
In connection with a gathering agreement entered into by WPZ with a third party in December 2010, we concurrently agreed to buy up to 200,000 MMBtu per day of natural gas at Transco Station 515 (Marcellus Basin) at market prices from the same third party. Purchases under the 12-year contract are expected to begin in the third quarter of 2011. We expect to sell this natural gas in the open market and may utilize available transportation capacity to facilitate the sales.

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Notes to Combined Financial Statements—(Continued)

Future minimum annual rentals under noncancelable operating leases as of December 31, 2010, are payable as follows:

 	 	(Millions)	 	
 		
2011	 	$	14	 	
2012	 	 	10	 	
2013	 	 	9	 	
2014	 	 	4	 	
2015	 	 	3	 	
Thereafter	 	 	15	 	
 	 	 	 	 	
Total	 	$	55	 	

 
Total rent expense, excluding month-to-month rentals, was $13 million, $22 million and $21 million in 2010, 2009 and 2008, respectively. Rent charges incurred for drilling rig rentals are capitalized under the successful efforts method of accounting.

12.  	Employee Benefit Plans	
 
Certain benefit costs associated with direct employees who support our operations are determined based on a specific employee basis and are charged to us by Williams as described below. These pension and post retirement benefit costs include amounts associated with vested participants who are no longer employees. As described in Note 4, Williams also charges us for the allocated cost of certain indirect employees of Williams who provide general and administrative services on our behalf. Williams includes an allocation of the benefit costs associated with these Williams employees based upon a Williams’ determined benefit rate, not necessarily specific to the employees providing general and administrative services on our behalf. As a result, the information described below is limited to amounts associated with the direct employees supporting our operations.
 
For the periods presented, we were not the plan sponsor for these plans. Accordingly, our Combined Balance Sheet does not reflect any assets or liabilities related to these plans.
 
Pension plans
 
Williams is the sponsor of noncontributory defined benefit pension plans that provide pension benefits for its eligible employees. Pension expense charged to us by Williams for 2010, 2009 and 2008 totaled $7 million, $7 million and $3 million, respectively.
 
Other postretirement benefits
 
Williams is the sponsor of subsidized retiree medical and life insurance benefit plans (other postretirement benefits) that provides benefits to certain eligible participants, generally including employees hired on or before December 31, 1991, and other miscellaneous defined participant groups. The allocation of cost for the plan anticipates future cost-sharing changes to the plan that are consistent with Williams’ expressed intent to increase the retiree contribution level, generally in line with health care cost increases. Other postretirement benefit expense charged to us by Williams for 2010, 2009, and 2008 totaled less than $1 million for each period.
 
Defined contribution plan
 
Williams also is the sponsor of a defined contribution plan that provides benefits to certain eligible participants and thus has charged us compensation expense of $5 million, $5 million and $4 million in 2010,

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Notes to Combined Financial Statements—(Continued)
 
2009 and 2008, respectively, for Williams’ matching contributions to this plan. Additionally, Apco maintains a defined contribution plan for its employees. Total annual compensation expense related to Apco’s plan was approximately $0.1 million for each period.

13.  	Stock-Based Compensation	
 
Certain of our direct employees participate in The Williams Companies, Inc. 2007 Incentive Plan, which provides for Williams common-stock-based awards to both employees and Williams’ nonmanagement directors. The plan permits the granting of various types of awards including, but not limited to, stock options and restricted stock units. Awards may be granted for no consideration other than prior and future services or based on certain financial performance targets. Additionally, certain of direct our employees participate in Williams’ Employee Stock Purchase Plan (ESPP). The ESPP enables eligible participants to purchase through payroll deductions a limited amount of Williams’ common stock at a discounted price.
 
We are charged by Williams for stock-based compensation expense related to our direct employees. Williams also charges us for the allocated costs of certain indirect employees of Williams (including stock-based compensation) who provide general and administrative services on our behalf and may become our employees in the future. However, information included in this note is limited to stock-based compensation associated with the direct employees (see Note 4 for total costs charged to us by Williams).
 
Total stock-based compensation expense included in general and administrative expense for the years ended December 31, 2010, 2009 and 2008 was $14 million, $13 million, and $11 million, respectively.
 
Employee stock-based awards
 
Stock options are valued at the date of award, which does not precede the approval date, and compensation cost is recognized on a straight-line basis, net of estimated forfeitures, over the requisite service period. The purchase price per share for stock options may not be less than the market price of the underlying stock on the date of grant.
 
Stock options generally become exercisable over a three-year period from the date of grant and generally expire ten years after the grant.
 
Restricted stock units are generally valued at market value on the grant date and generally vest over three years. Restricted stock unit compensation cost, net of estimated forfeitures, is generally recognized over the vesting period on a straight-line basis.

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Notes to Combined Financial Statements—(Continued)
 
Stock Options
 
The following summary reflects stock option activity and related information for the year ended December 31, 2010.

 	 	 	 	 	Weighted-	 	 	 	 	
 	 	 	 	 	Average	 	 	Aggregate	 	
 	 	 	 	 	Exercise	 	 	Intrinsic	 	
Stock Options	 	Options	 	 	Price	 	 	Value	 	
 	 	(Millions)	 	 	 	 	 	(Millions)	 	
 		
Outstanding at December 31, 2009	 	 	1.6	 	 	$	17.47	 	 	 	 	 	
Granted	 	 	0.2	 	 	$	21.22	 	 	 	 	 	
Exercised	 	 	(0.1	)	 	$	7.65	 	 	$	2	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Expired	 	 	(0.1	)	 	$	42.29	 	 	 	 	 	
Forfeited	 	 	—	 	 	$	—	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Outstanding at December 31, 2010	 	 	1.6	 	 	$	18.23	 	 	$	13	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Exercisable at December 31, 2010	 	 	1.2	 	 	$	18.20	 	 	$	10	 	

 
The total intrinsic value of options exercised during the years ended December 31, 2010, 2009, and 2008 was $2 million, $0.2 million, and $7 million, respectively.
 
The following summary provides additional information about stock options that are outstanding and exercisable at December 31, 2010.

 	 	Stock Options Outstanding	 	 	Stock Options Exercisable	 	
 	 	 	 	 	 	 	 	Weighted-	 	 	 	 	 	 	 	 	Weighted-	 	
 	 	 	 	 	Weighted-	 	 	Average	 	 	 	 	 	Weighted-	 	 	Average	 	
 	 	 	 	 	Average	 	 	Remaining	 	 	 	 	 	Average	 	 	Remaining	 	
 	 	 	 	 	Exercise	 	 	Contractual	 	 	 	 	 	Exercise	 	 	Contractual	 	
Range of Exercise Prices	 	Options	 	 	Price	 	 	Life	 	 	Options	 	 	Price	 	 	Life	 	
 	 	(Millions)	 	 	 	 	 	(Years)	 	 	(Millions)	 	 	 	 	 	(Years)	 	
 		
$2.58 to $11.84	 	 	0.6	 	 	$	8.79	 	 	 	4.9	 	 	 	0.5	 	 	$	7.88	 	 	 	3.4	 	
$11.85 to 21.67	 	 	0.6	 	 	$	20.32	 	 	 	6.1	 	 	 	0.4	 	 	$	19.79	 	 	 	4.3	 	
$21.68 to $33.65	 	 	0.2	 	 	$	27.84	 	 	 	6.0	 	 	 	0.2	 	 	$	27.84	 	 	 	6.0	 	
$33.66 to $36.50	 	 	0.2	 	 	$	36.21	 	 	 	5.9	 	 	 	0.1	 	 	$	36.09	 	 	 	5.5	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	 	1.6	 	 	$	18.23	 	 	 	5.6	 	 	 	1.2	 	 	$	18.20	 	 	 	4.4	 	

 
The estimated fair value at date of grant of options for Williams common stock granted in each respective year, using the Black-Scholes option pricing model, is as follows:

 	 	2010	 	 	2009	 	 	2008	 	
 		
Weighted-average grant date fair value of options granted	 	$	7.02	 	 	$	5.60	 	 	$	12.83	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Weighted-average assumptions:	 	 	 	 	 	 	 	 	 	 	 	 	
Dividend yield	 	 	2.6	%	 	 	1.6	%	 	 	1.2	%	
Volatility	 	 	39.0	%	 	 	60.8	%	 	 	33.4	%	
Risk-free interest rate	 	 	3.0	%	 	 	2.3	%	 	 	3.5	%	
Expected life (years)	 	 	6.5	 	 	 	6.5	 	 	 	6.5	 	

The expected dividend yield is based on the average annual dividend yield as of the grant date. Expected volatility is based on the historical volatility of Williams stock and the implied volatility of Williams stock based on traded options. In calculating historical volatility, returns during calendar year 2002 were excluded as the extreme volatility during that time is not reasonably expected to be repeated in the future. The risk-free interest rate is based on the U.S. Treasury Constant Maturity rates as of the grant date. The expected life of the option is based on historical exercise behavior and expected future experience.

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Nonvested Restricted Stock Units
 
The following summary reflects nonvested restricted stock unit activity and related information for the year ended December 31, 2010.

 	 	 	 	 	Weighted-	 	
 	 	 	 	 	Average	 	
Restricted Stock Units	 	Shares	 	 	Fair Value*	 	
 	 	(Millions)	 	 	 	 	
 		
Nonvested at December 31, 2009	 	 	1.7	 	 	$	18.24	 	
Granted	 	 	0.6	 	 	$	21.19	 	
Forfeited	 	 	(0.1	)	 	$	19.36	 	
Cancelled	 	 	(0.1	)	 	$	0.00	 	
Vested	 	 	(0.3	)	 	$	28.35	 	
 	 	 	 	 	 	 	 	 	
Nonvested at December 31, 2010	 	 	1.8	 	 	$	17.96	 	

 

			
*		Performance-based shares are primarily valued using the end-of-period market price until certification that the performance objectives have been completed, a value of zero once it has been determined that it is unlikely that performance objectives will be met, or a valuation pricing model. All other shares are valued at the grant-date market price.	
 
Other restricted stock unit information

 	 	2010	 	 	2009	 	 	2008	 	
 		
Weighted-average grant date fair value of restricted stock units granted during the year, per share	 	$	21.19	 	 	$	10.53	 	 	$	32.34	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total fair value of restricted stock units vested during the year ($’s in millions)	 	$	9	 	 	$	8	 	 	$	6	 	

 
		
14.  	Fair Value Measurements	
 
Fair value is the amount received to sell an asset or the amount paid to transfer a liability in an orderly transaction between market participants (an exit price) at the measurement date. Fair value is a market-based measurement considered from the perspective of a market participant. We use market data or assumptions that we believe market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation. These inputs can be readily observable, market corroborated, or unobservable. We apply both market and income approaches for recurring fair value measurements using the best available information while utilizing valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.
 
The fair value hierarchy prioritizes the inputs used to measure fair value, giving the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). We classify fair value balances based on the observability of those inputs. The three levels of the fair value hierarchy are as follows:

 	•  	Level 1—Quoted prices for identical assets or liabilities in active markets that we have the ability to access. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 primarily consists of financial instruments that are exchange traded;	
 		
 	•  	Level 2—Inputs are other than quoted prices in active markets included in Level 1, that are either directly or indirectly observable. These inputs are either directly observable in the marketplace or	

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Notes to Combined Financial Statements—(Continued)

 		indirectly observable through corroboration with market data for substantially the full contractual term of the asset or liability being measured. Our Level 2 primarily consists of over-the-counter (OTC) instruments such as forwards, swaps, and options. These options, which hedge future sales of production, are structured as costless collars and are financially settled. They are valued using an industry standard Black-Scholes option pricing model. Prior to 2009, these options were included in Level 3 because a significant input to the model, implied volatility by location, was considered unobservable. However, due to the increased transparency, we now consider this input to be observable and have included these options in Level 2; and	

 	•  	Level 3—Inputs that are not observable for which there is little, if any, market activity for the asset or liability being measured. These inputs reflect management’s best estimate of the assumptions market participants would use in determining fair value. Our Level 3 consists of instruments valued using industry standard pricing models and other valuation methods that utilize unobservable pricing inputs that are significant to the overall fair value.	
 
In valuing certain contracts, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. For disclosure purposes, assets and liabilities are classified in their entirety in the fair value hierarchy level based on the lowest level of input that is significant to the overall fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels.
 
The following table presents, by level within the fair value hierarchy, our assets and liabilities that are measured at fair value on a recurring basis.
 
Fair Value Measurements Using:

 	 	December 31, 2010	 	 	December 31, 2009	 	
 	 	Level 1	 	 	Level 2	 	 	Level 3	 	 	Total	 	 	Level 1	 	 	Level 2	 	 	Level 3	 	 	Total	 	
 	 	(Millions)	 	 	(Millions)	 	
 		
Energy derivative assets	 	$	97	 	 	$	474	 	 	$	2	 	 	$	573	 	 	$	178	 	 	$	912	 	 	$	4	 	 	$	1,094	 	
Energy derivative liabilities	 	$	78	 	 	$	210	 	 	$	1	 	 	$	289	 	 	$	177	 	 	$	826	 	 	$	3	 	 	$	1,006	 	

Energy derivatives include commodity based exchange-traded contracts and OTC contracts. Exchange-traded contracts include futures, swaps, and options. OTC contracts include forwards, swaps and options.
 
Many contracts have bid and ask prices that can be observed in the market. Our policy is to use a mid-market pricing (the mid-point price between bid and ask prices) convention to value individual positions and then adjust on a portfolio level to a point within the bid and ask range that represents our best estimate of fair value. For offsetting positions by location, the mid-market price is used to measure both the long and short positions.
 
The determination of fair value for our assets and liabilities also incorporates the time value of money and various credit risk factors which can include the credit standing of the counterparties involved, master netting arrangements, the impact of credit enhancements (such as cash collateral posted and letters of credit) and our nonperformance risk on our liabilities. The determination of the fair value of our liabilities does not consider noncash collateral credit enhancements.
 
Exchange-traded contracts include New York Mercantile Exchange and Intercontinental Exchange contracts and are valued based on quoted prices in these active markets and are classified within Level 1.
 
Forward, swap, and option contracts included in Level 2 are valued using an income approach including present value techniques and option pricing models. Option contracts, which hedge future sales of our production, are structured as costless collars and are financially settled. They are valued using an industry standard Black-Scholes option pricing model. Significant inputs into our Level 2 valuations include commodity

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Notes to Combined Financial Statements—(Continued)
 
prices, implied volatility by location, and interest rates, as well as considering executed transactions or broker quotes corroborated by other market data. These broker quotes are based on observable market prices at which transactions could currently be executed. In certain instances where these inputs are not observable for all periods, relationships of observable market data and historical observations are used as a means to estimate fair value. Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2.
 
Our energy derivatives portfolio is largely comprised of exchange-traded products or like products and the tenure of our derivatives portfolio is relatively short with more than 99 percent of the value of our derivatives portfolio expiring in the next 24 months. Due to the nature of the products and tenure, we are consistently able to obtain market pricing. All pricing is reviewed on a daily basis and is formally validated with broker quotes and documented on a monthly basis.
 
Certain instruments trade with lower availability of pricing information. These instruments are valued with a present value technique using inputs that may not be readily observable or corroborated by other market data. These instruments are classified within Level 3 when these inputs have a significant impact on the measurement of fair value. The instruments included in Level 3 at December 31, 2010, consist primarily of natural gas index transactions that are used to manage our physical requirements.
 
Reclassifications of fair value between Level 1, Level 2, and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. No significant transfers in or out of Level 1 and Level 2 occurred during the year ended December 31, 2010. In 2009, certain options which hedge future sales of production were transferred from Level 3 to Level 2. These options were originally included in Level 3 because a significant input to the model, implied volatility by location, was considered unobservable. Due to increased transparency, this input was considered observable, and we transferred these options to Level 2.
 
The following tables present a reconciliation of changes in the fair value of our net energy derivatives and other assets classified as Level 3 in the fair value hierarchy.
 
Level 3 Fair Value Measurements Using Significant Unobservable Inputs

 	 	Year Ended December 31,	 	
 	 	2010	 	 	2009	 	 	2008	 	
 	 	Net Energy	 	 	Net Energy	 	 	Net Energy	 	
 	 	Derivatives	 	 	Derivatives	 	 	Derivatives	 	
 	 	(Millions)	 	 	 	 	
 		
Beginning balance	 	$	1	 	 	$	506	 	 	$	(5	)	
Realized and unrealized gains (losses):	 	 	 	 	 	 	 	 	 	 	 	 	
Included in income (loss) from continuing operation s	 	 	1	 	 	 	476	 	 	 	96	 	
Included in other comprehensive income (loss)	 	 	—	 	 	 	(329	)	 	 	478	 	
Purchases, issuances, and settlements	 	 	(1	)	 	 	(479	)	 	 	(61	)	
Transfers into Level 3	 	 	—	 	 	 	—	 	 	 	3	 	
Transfers out of Level 3	 	 	—	 	 	 	(173	)	 	 	(5	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Ending balance	 	$	1	 	 	$	1	 	 	$	506	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Unrealized gains included in income from continuing operations relating to instruments held at December 31	 	$	—	 	 	$	—	 	 	$	—	 	

 
Realized and unrealized gains (losses) included in income (loss) from continuing operations for the above periods are reported in revenues in our Combined Statement of Operations.

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Notes to Combined Financial Statements—(Continued)
 
The following table presents impairments associated with certain assets that have been measured at fair value on a nonrecurring basis within Level 3 of the fair value hierarchy.
 
Fair Value Measurements Using:

 	 	Total Losses for the Years	 	
 	 	Ended December 31,	 	
 	 	2010	 	 	2009	 	
 	 	(Millions)	 	
 		
Impairments:	 	 	 	 	 	 	 	 	
Goodwill (see Note 6)	 	$	1,003	(a)	 	$	—	 	
Producing properties and costs of acquired unproved reserves (see Note 6)	 	 	678	(b)	 	 	15	(c)	
Cost-based investment (see Note 5)	 	 	—	 	 	 	11	(d)	
 	 	 	 	 	 	 	 	 	
 	 	$	1,681	 	 	$	26	 	

 

			
(a)		Due to a significant decline in forward natural gas prices across all future production periods during 2010, we determined that we had a trigger event and thus performed an interim impairment assessment of the approximate $1 billion of goodwill related to our domestic natural gas production operations (the reporting unit). Forward natural gas prices through 2025 as of September 30, 2010, used in our analysis declined more than 22 percent on average compared to the forward prices as of December 31, 2009. We estimated the fair value of the reporting unit on a stand-alone basis by valuing proved and unproved reserves, as well as estimating the fair values of other assets and liabilities which are identified to the reporting unit. We used an income approach (discounted cash flow) for valuing reserves. The significant inputs into the valuation of proved and unproved reserves included reserve quantities, forward natural gas prices, anticipated drilling and operating costs, anticipated production curves, income taxes, and appropriate discount rates. To estimate the fair value of the reporting unit and the implied fair value of goodwill under a hypothetical acquisition of the reporting unit, we assumed a tax structure where a buyer would obtain a step-up in the tax basis of the net assets acquired. Significant assumptions in valuing proved reserves included reserves quantities of more than 4.4 trillion cubic feet of gas equivalent; forward prices averaging approximately $4.65 per thousand cubic feet of gas equivalent (Mcfe) for natural gas (adjusted for locational differences), natural gas liquids and oil; and an after-tax discount rate of 11 percent. Unproved reserves (probable and possible) were valued using similar assumptions adjusted further for the uncertainty associated with these reserves by using after- tax discount rates of 13 percent and 15 percent, respectively, commensurate with our estimate of the risk of those reserves. In our assessment as of September 30, 2010, the carrying value of the reporting unit, including goodwill, exceeded its estimated fair value. We then determined that the implied fair value of the goodwill was zero. As a result of our analysis, we recognized a full $1 billion impairment charge related to this goodwill.	
 		
(b)		As of September 30, 2010, we also believed we had a trigger event as a result of recent significant declines in forward natural gas prices and therefore, we assessed the carrying value of our natural gas-producing properties and costs of acquired unproved reserves for impairments. Our assessment utilized estimates of future cash flows. Significant judgments and assumptions in these assessments are similar to those used in the goodwill evaluation and include estimates of natural gas reserve quantities, estimates of future natural gas prices using a forward NYMEX curve adjusted for locational basis differentials, drilling plans, expected capital costs, and an applicable discount rate commensurate with risk of the underlying cash flow estimates. The assessment performed at September 30, 2010, identified certain properties with a carrying value in excess of their calculated fair values. As a result, we recorded a $678 million impairment charge in the	

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Notes to Combined Financial Statements—(Continued)

		third-quarter 2010 as further described below. Fair value measured for these properties at September 30, 2010, was estimated to be approximately $320 million.	

 	•  	$503 million of the impairment charge related to natural gas-producing properties in the Barnett Shale. Significant assumptions in valuing these properties included proved reserves quantities of more than 227 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $4.67 per Mcfe for natural gas (adjusted for locational differences), natural gas liquids and oil, and an after-tax discount rate of 11 percent.	
 		
 	•  	$175 million of the impairment charge related to acquired unproved reserves in the Piceance Highlands acquired in 2008 Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 13 percent.	

(c)		Fair value of costs of acquired reserves in the Barnett Shale measured at December 31, 2009, was $22 million. Significant assumption in valuing these unproved reserves included evaluation of probable and possible reserves quantities, drilling plans, forward natural gas prices (adjusted for locational differences) and an after-tax discount rate of 11 percent.	
 		
(d)		Fair value measured at March 31, 2009, was zero. This value was based on an other-than-temporary decline in the value of our investment considering the deteriorating financial condition of a Venezuelan corporation in which we own a 4 percent interest.	

15.  	Financial Instruments, Derivatives, Guarantees and Concentration of Credit Risk	
 
We use the following methods and assumptions in estimating our fair-value disclosures for financial instruments:
 
Cash and cash equivalents and restricted cash :   The carrying amounts reported in the Combined Balance Sheet approximate fair value due to the nature of the instrument and/or the short-term maturity of these instruments.
 
Other :   Includes margin deposits and customer margin deposits payable for which the amounts reported in the Combined Balance Sheet approximate fair value.
 
Energy derivatives :   Energy derivatives include futures, forwards, swaps, and options. These are carried at fair value in the Combined Balance Sheet. See Note 14 for a discussion of valuation of energy derivatives.
 
Carrying amounts and fair values of our financial instruments were as follows:

 	 	December 31,	 	
 	 	2010	 	 	2009	 	
 	 	Carrying	 	 	Fair	 	 	Carrying	 	 	Fair	 	
Asset (Liability)	 	Amount	 	 	Value	 	 	Amount	 	 	Value	 	
 	 	(Millions)	 	
 		
Cash and cash equivalents	 	$	37	 	 	$	37	 	 	$	34	 	 	$	34	 	
Restricted cash	 	 	24	 	 	 	24	 	 	 	19	 	 	 	19	 	
Other	 	 	(25	)	 	 	(25	)	 	 	(26	)	 	 	(26	)	
Net energy derivatives:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Energy commodity cash flow hedges	 	 	266	 	 	 	266	 	 	 	180	 	 	 	180	 	
Other energy derivatives	 	 	18	 	 	 	18	 	 	 	(92	)	 	 	(92	)	

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Energy Commodity Derivatives
 
We are exposed to market risk from changes in energy commodity prices within our operations. We utilize derivatives to manage exposure to the variability in expected future cash flows from forecasted sales of natural gas attributable to commodity price risk. Certain of these derivatives utilized for risk management purposes have been designated as cash flow hedges, while other derivatives have not been designated as cash flow hedges or do not qualify for hedge accounting despite hedging our future cash flows on an economic basis.
 
We produce, buy and sell natural gas at different locations throughout the United States. To reduce exposure to a decrease in revenues from fluctuations in natural gas market prices, we enter into natural gas futures contracts, swap agreements, and financial option contracts to mitigate the price risk on forecasted sales of natural gas. We have also entered into basis swap agreements to reduce the locational price risk associated with our producing basins. These cash flow hedges are expected to be highly effective in offsetting cash flows attributable to the hedged risk during the term of the hedge. However, ineffectiveness may be recognized primarily as a result of locational differences between the hedging derivative and the hedged item. Our financial option contracts are either purchased options or a combination of options that comprise a net purchased option or a zero-cost collar. Our designation of the hedging relationship and method of assessing effectiveness for these option contracts are generally such that the hedging relationship is considered perfectly effective and no ineffectiveness is recognized in earnings.
 
The following table sets forth the derivative volumes designated as hedges of production volumes as of December 31, 2010:

 	 	 	 	 	 	 	 	 	 	 	 	Weighted Average	
 	 	 	 	 	 	 	 	 	Notional Volume	 	 	Price	
Commodity	 	Period	 	 	Contract Type	 	Location	 	(BBtu)	 	 	($/MMBtu)	
 		
Natural Gas	 	 	2011	 	 	Costless Collar	 	Rockies	 	 	16,425	 	 	$5.30 - $7.10	
Natural Gas	 	 	2011	 	 	Costless Collar	 	San Juan	 	 	32,850	 	 	$5.27 - $7.06	
Natural Gas	 	 	2011	 	 	Costless Collar	 	MidCon	 	 	29,200	 	 	$5.10 - $7.00	
Natural Gas	 	 	2011	 	 	Costless Collar	 	SoCal	 	 	10,950	 	 	$5.83 - $7.56	
Natural Gas	 	 	2011	 	 	Costless Collar	 	Appalachia	 	 	10,950	 	 	$6.50 - $8.14	
Natural Gas	 	 	2011	 	 	Location Swaps	 	Rockies	 	 	27,375	 	 	$5.57	
Natural Gas	 	 	2011	 	 	Location Swaps	 	San Juan	 	 	38,325	 	 	$5.14	
Natural Gas	 	 	2011	 	 	Location Swaps	 	MidCon	 	 	7,300	 	 	$5.22	
Natural Gas	 	 	2011	 	 	Location Swaps	 	SoCal	 	 	7,300	 	 	$5.34	
Natural Gas	 	 	2011	 	 	Location Swaps	 	Appalachia	 	 	23,725	 	 	$5.59	
Natural Gas	 	 	2012	 	 	Location Swaps	 	Rockies	 	 	25,620	 	 	$4.79	
Natural Gas	 	 	2012	 	 	Location Swaps	 	San Juan	 	 	26,535	 	 	$5.06	
Natural Gas	 	 	2012	 	 	Location Swaps	 	MidCon	 	 	14,640	 	 	$4.74	
Natural Gas	 	 	2012	 	 	Location Swaps	 	SoCal	 	 	9,150	 	 	$5.22	
Natural Gas	 	 	2012	 	 	Location Swaps	 	Appalachia	 	 	20,130	 	 	$5.93	

We also enter into forward contracts to buy and sell natural gas to maximize the economic value of transportation agreements and storage capacity agreements. To reduce exposure to a decrease in margins from fluctuations in natural gas market prices, we may enter into futures contracts, swap agreements, and financial option contracts to mitigate the price risk associated with these contracts. Hedges for transportation contracts are designated as cash flow hedges and are expected to be highly effective in offsetting cash flows attributable to the hedged risk during the term of the hedge. However, ineffectiveness may be recognized primarily as a result of locational differences between the hedging derivative and the hedged item. Hedges for storage

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Notes to Combined Financial Statements—(Continued)
 
contracts have not been designated as hedging instruments, despite economically hedging the expected cash flows generated by those agreements.
 
We also enter into commodity derivatives for other than risk management purposes, including managing certain remaining legacy natural gas contracts and positions from our former power business and providing services to third parties. These legacy natural gas contracts include substantially offsetting positions and have had an insignificant net impact on earnings.
 
The following table depicts the notional amounts of the net long (short) positions which we did not designate as hedges of our production in our commodity derivatives portfolio as of December 31, 2010. Natural gas is presented in millions of British Thermal Units (MMBtu). All of the Central hub risk realizes in 2011 and 99% of the basis risk realizes in 2011. The net index position includes contracts for the future sale of physical natural gas related to our production. Offsetting these sales are contracts for the future production of physical natural gas related to WPZ’s natural gas shrink requirements. These contracts result in minimal commodity price risk exposure and have a value of less than $1 million at December 31, 2010.

 	 	Unit of	 	 	Central Hub	 	 	Basis	 	 	Index	 	
Derivative Notional Volumes	 	Measure	 	 	Risk(a)	 	 	Risk(b)	 	 	Risk(c)	 	
 		
Not Designated as Hedging Instruments	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Risk Management	 	 	MMBtu	 	 	 	(9,077,499	)	 	 	(20,195,000	)	 	 	16,586,059	 	
Other	 	 	MMBtu	 	 	 	150,400	 	 	 	(14,766,500	)	 	 	 	 	

 
			
(a)		includes physical and financial derivative transactions that settle against the Henry Hub price;	
 		
(b)		includes financial derivative transactions priced off the difference in value between the Central Hub and another specific delivery point;	
 		
(c)		includes physical derivative transactions at an unknown future price, including purchases of 84,583,157 MMBtu primarily on behalf of WPZ and sales of 67,997,098 MMBtu.	
 
Fair values and gains (losses)
 
The following table presents the fair value of energy commodity derivatives. Our derivatives are presented as separate line items in our Combined Balance Sheet as current and noncurrent derivative assets and liabilities. Derivatives are classified as current or noncurrent based on the contractual timing of expected future net cash flows of individual contracts. The expected future net cash flows for derivatives classified as current are expected to occur within the next 12 months. The fair value amounts are presented on a gross basis and do not reflect the netting of asset and liability positions permitted under the terms of our master netting arrangements. Further, the amounts below do not include cash held on deposit in margin accounts that we have received or remitted to collateralize certain derivative positions.

 	 	December 31,	 	
 	 	2010	 	 	2009	 	
 	 	Assets	 	 	Liabilities	 	 	Assets	 	 	Liabilities	 	
 	 	(Millions)	 	
 		
Designated as hedging instruments	 	$	288	 	 	$	22	 	 	$	352	 	 	$	172	 	
Not designated as hedging instruments:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Legacy natural gas contracts from former power business	 	 	186	 	 	 	187	 	 	 	505	 	 	 	526	 	
Hedges for storage contracts and other	 	 	99	 	 	 	80	 	 	 	237	 	 	 	308	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total derivatives not designated as hedging instruments	 	 	285	 	 	 	267	 	 	 	742	 	 	 	834	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total derivatives	 	$	573	 	 	$	289	 	 	$	1,094	 	 	$	1,006	 	

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Notes to Combined Financial Statements—(Continued)
 
The following table presents pre-tax gains and losses for our energy commodity derivatives designated as cash flow hedges, as recognized in accumulated other comprehensive income (AOCI) or revenues.

 	 	Years Ended December 31,	 	 	 	 	
 	 	2010	 	 	2009	 	 	Classification	 	
 	 	(Millions)	 	 	 	 	
 		
Net gain recognized in other comprehensive income (loss) (effective portion)	 	$	505	 	 	$	266	 	 	 	AOCI	 	
Net gain reclassified from accumulated other comprehensive income (loss) into income (effective portion)(1)	 	$	354	 	 	$	621	 	 	 	Revenues	 	
Gain recognized in income (ineffective portion)	 	$	9	 	 	$	4	 	 	 	Revenues	 	

 
			
(1)		Gains reclassified from accumulated other comprehensive income (loss) primarily represent realized gains associated with our production reflected in oil and gas sales.	
 
There were no gains or losses recognized in income as a result of excluding amounts from the assessment of hedge effectiveness.
 
The following table presents pre-tax gains and losses for our energy commodity derivatives not designated as hedging instruments.

 	 	Years Ended	 	
 	 	December 31,	 	
 	 	2010	 	 	2009	 	
 	 	(Millions)	 	
 		
Gas management revenues	 	$	47	 	 	$	33	 	
Gas management expenses	 	 	28	 	 	 	33	 	
 	 	 	 	 	 	 	 	 	
Net gain	 	$	19	 	 	$	—	 	

 
The cash flow impact of our derivative activities is presented in the Combined Statement of Cash Flows as changes in current and noncurrent derivative assets and liabilities.
 
Credit-risk-related features
 
Certain of our derivative contracts contain credit-risk-related provisions that would require us, in certain circumstances, to post additional collateral in support of our net derivative liability positions. These credit-risk-related provisions require us to post collateral in the form of cash or letters of credit when our net liability positions exceed an established credit threshold. The credit thresholds are typically based on our senior unsecured debt ratings from Standard and Poor’s and/or Moody’s Investors Service. Under these contracts, a credit ratings decline would lower our credit thresholds, thus requiring us to post additional collateral. We also have contracts that contain adequate assurance provisions giving the counterparty the right to request collateral in an amount that corresponds to the outstanding net liability. Additionally, we have an unsecured credit agreement with certain banks related to hedging activities. We are not required to provide collateral support for net derivative liability positions under the credit agreement as long as the value of our domestic natural gas reserves, as determined under the provisions of the agreement, exceeds by a specified amount certain of its obligations including any outstanding debt and the aggregate out-of-the-money position on hedges entered into under the credit agreement.
 
As of December 31, 2010, we have collateral totaling $8 million, all of which is in the form of letters of credit, posted to derivative counterparties, to support the aggregate fair value of our net derivative liability position (reflecting master netting arrangements in place with certain counterparties) of $36 million, which includes a reduction of less than $1 million to our liability balance for our own nonperformance risk. At

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Notes to Combined Financial Statements—(Continued)
 
December 31, 2009, we had collateral totaling $96 million posted to derivative counterparties, all of which was in the form of letters of credit, to support the aggregate fair value of our net derivative liabilities position (reflecting master netting arrangements in place with certain counterparties) of $164 million, which included a reduction of $3 million to our liability balance for our own nonperformance risk. The additional collateral that we would have been required to post, assuming our credit thresholds were eliminated and a call for adequate assurance under the credit risk provisions in our derivative contracts was triggered, was $29 million and $71 million at December 31, 2010 and December 31, 2009, respectively.
 
Cash flow hedges
 
Changes in the fair value of our cash flow hedges, to the extent effective, are deferred in other comprehensive income and reclassified into earnings in the same period or periods in which the hedged forecasted purchases or sales affect earnings, or when it is probable that the hedged forecasted transaction will not occur by the end of the originally specified time period. As of December 31, 2010, we have hedged portions of future cash flows associated with anticipated energy commodity purchases and sales for up to two years. Based on recorded values at December 31, 2010, $148 million of net gains (net of income tax provision of $88 million) will be reclassified into earnings within the next year. These recorded values are based on market prices of the commodities as of December 31, 2010. Due to the volatile nature of commodity prices and changes in the creditworthiness of counterparties, actual gains or losses realized within the next year will likely differ from these values. These gains or losses are expected to substantially offset net losses or gains that will be realized in earnings from previous unfavorable or favorable market movements associated with underlying hedged transactions.
 
Concentration of Credit Risk
 
Cash equivalents
 
Our cash equivalents are primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government.
 
Accounts receivable
 
The following table summarizes concentration of receivables (other than as relates to affiliates), net of allowances, by product or service as of December 31:

 	 	2010	 	 	2009	 	
 	 	(Millions)	 	
 		
Receivables by product or service:	 	 	 	 	 	 	 	 	
Sale of natural gas and related products and services	 	$	272	 	 	$	286	 	
Joint interest owners	 	 	83	 	 	 	66	 	
Other	 	 	7	 	 	 	7	 	
 	 	 	 	 	 	 	 	 	
Total	 	$	362	 	 	$	359	 	

 
Natural gas customers include pipelines, distribution companies, producers, gas marketers and industrial users primarily located in the eastern and northwestern United States, Rocky Mountains and Gulf Coast. As a general policy, collateral is not required for receivables, but customers’ financial condition and credit worthiness are evaluated regularly.
 
Derivative assets and liabilities
 
We have a risk of loss from counterparties not performing pursuant to the terms of their contractual obligations. Counterparty performance can be influenced by changes in the economy and regulatory issues,

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Notes to Combined Financial Statements—(Continued)
 
among other factors. Risk of loss is impacted by several factors, including credit considerations and the regulatory environment in which a counterparty transacts. We attempt to minimize credit-risk exposure to derivative counterparties and brokers through formal credit policies, consideration of credit ratings from public ratings agencies, monitoring procedures, master netting agreements and collateral support under certain circumstances. Collateral support could include letters of credit, payment under margin agreements, and guarantees of payment by credit worthy parties.
 
We also enter into master netting agreements to mitigate counterparty performance and credit risk. During 2010 and 2009, we did not incur any significant losses due to counterparty bankruptcy filings.
 
The gross credit exposure from our derivative contracts as of December 31, 2010, is summarized as follows.

 	 	Investment	 	 	 	 	
Counterparty Type	 	Grade*	 	 	Total	 	
 	 	(Millions)	 	
 		
Gas and electric utilities	 	$	7	 	 	$	8	 	
Energy marketers and traders	 	 	—	 	 	 	133	 	
Financial institutions	 	 	432	 	 	 	432	 	
 	 	 	 	 	 	 	 	 	
 	 	$	439	 	 	 	573	 	
 	 	 	 	 	 	 	 	 	
Credit reserves	 	 	 	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	
Gross credit exposure from derivatives	 	 	 	 	 	$	573	 	

 
We assess our credit exposure on a net basis to reflect master netting agreements in place with certain counterparties. We offset our credit exposure to each counterparty with amounts we owe the counterparty under derivative contracts. The net credit exposure from our derivatives as of December 31, 2010, excluding collateral support discussed below, is summarized as follows.

 	 	Investment	 	 	 	 	
Counterparty Type	 	Grade*	 	 	Total	 	
 	 	(Millions)	 	
 		
Gas and electric utilities	 	$	3	 	 	$	3	 	
Financial institutions	 	 	317	 	 	 	317	 	
 	 	 	 	 	 	 	 	 	
 	 	$	320	 	 	 	320	 	
 	 	 	 	 	 	 	 	 	
Credit reserves	 	 	 	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	
Net credit exposure from derivatives	 	 	 	 	 	$	320	 	

 

			
*		We determine investment grade primarily using publicly available credit ratings. We include counterparties with a minimum Standard & Poor’s rating of BBB- or Moody’s Investors Service rating of Baa3 in investment grade.	
 
Our nine largest net counterparty positions represent approximately 99 percent of our net credit exposure from derivatives and are all with investment grade counterparties. Included within this group are eight counterparty positions, representing 81 percent of our net credit exposure from derivatives, associated with our hedging facility (see Note 9). Under certain conditions, the terms of this credit agreement may require the participating financial institutions to deliver collateral support to a designated collateral agent (which is another participating financial institution in the agreement). The level of collateral support required is dependent on whether the net position of the counterparty financial institution exceeds specified thresholds.

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Notes to Combined Financial Statements—(Continued)
 
The thresholds may be subject to prescribed reductions based on changes in the credit rating of the counterparty financial institution.
 
At December 31, 2010, the designated collateral agent holds $19 million of collateral support on our behalf under our hedging facility. In addition, we hold collateral support, which may include cash or letters of credit, of $15 million related to our other derivative positions.
 
Revenues
 
During 2010, BP Energy Company accounted for 13% of our combined revenues. During 2009, and 2008, there were no customers for which our sales exceeded 10 percent of our combined revenues. Management believes that the loss of any individual purchaser would not have a long-term material adverse impact on the financial position or results of operations of the Company.
 
Net Assets of Operations in Foreign Locations
 
Net assets of operations in Argentina were $231 million and $208 million as of December 31, 2010 and 2009, respectively.

16.  	Subsequent Events	
 
Information subsequent to initial date of independent registered public accounting firm report
 
On June 3, 2011, WPX Energy, Inc., as borrower, entered into a new $1.5 billion five-year senior unsecured revolving credit facility agreement (the “Credit Facility Agreement”), together with the lenders named therein, and Citibank N.A. (“Citi”), as administrative agent and swingline lender. Under the terms of the Credit Facility Agreement and subject to certain requirements, WPX Energy, Inc. may request an increase in the commitments of up to an additional $300 million by either commitments from new lenders or increased commitments from existing lenders. Borrowings under the Credit Facility Agreement may be used for working capital, acquisitions, capital expenditures and other general corporate purposes.
 
Under the Credit Facility Agreement, WPX Energy, Inc. may also obtain same day funds by requesting a swingline loan of up to an amount of $125 million from the swingline lender. Interest on swingline loans will be payable at a fluctuating base rate equal to Citi’s adjusted base rate plus the applicable margin.
 
The Credit Facility Agreement will not be effective until the date on which certain conditions listed in the agreement (including, among others, the completion of the initial public offering of WPX Energy, Inc.) have been met or waived; provided that the effective date must be on or before November 30, 2011 or such later date as may be agreed to by WPX Energy, Inc. and the lenders. If the effective date has not occurred by November 30, 2011, the Credit Facility Agreement will automatically terminate unless otherwise extended by WPX Energy, Inc. and the lenders.
 
Interest on borrowings under the Credit Facility Agreement will be payable at rates per annum equal to, at the option of WPX Energy, Inc.: (1) a fluctuating base rate equal to Citi’s adjusted base rate plus the applicable margin, or (2) a periodic fixed rate equal to LIBOR plus the applicable margin. The adjusted base rate will be the highest of (i) the federal funds rate plus 0.5 percent, (ii) Citi’s publicly announced base rate, and (iii) one-month LIBOR plus 1.0 percent. WPX Energy, Inc. will be required to pay a commitment fee based on the unused portion of the commitments under the Credit Facility Agreement. The applicable margin and the commitment fee will be determined by reference to a pricing schedule based on WPX Energy, Inc.’s senior unsecured debt ratings.
 
Under the Credit Facility Agreement, prior to the occurrence of the Investment Grade Date (as defined below), WPX Energy, Inc. will be required to maintain a ratio of PV to debt (each as defined in the Credit Facility Agreement) of at least 1.50 to 1.00. PV is determined as of the end of each fiscal year and reflects the

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WPX Energy
 
Notes to Combined Financial Statements—(Continued)
 
present value, discounted at 9 percent, of projected future cash flows of domestic proved oil and gas reserves (with a limitation of no more than 35% of proved undeveloped reserves), based on lender projected commodity price assumptions and after giving effect to hedge arrangements. Also, for WPX Energy, Inc. and its consolidated subsidiaries, the ratio of debt to capitalization (defined as net worth plus debt) will not be permitted to be greater than 60%. Each of the above ratios will be tested beginning June 30, 2011 at the end of each fiscal quarter. Investment Grade Date means the first date on which WPX Energy, Inc.’s long-term senior unsecured debt ratings are BBB- or better by S&P or Baa3 or better by Moody’s (without negative outlook or negative watch), provided that the other of the two ratings is at least BB+ by S&P or Ba1 by Moody’s.
 
The Credit Facility Agreement contains customary representations and warranties and affirmative, negative and financial covenants which were made only for the purposes of the Credit Facility Agreement and as of the specific date (or dates) set forth therein, and may be subject to certain limitations as agreed upon by the contracting parties. The covenants limit, among other things, the ability of WPX Energy, Inc.’s subsidiaries to incur indebtedness, WPX Energy, Inc. and its material subsidiaries from granting certain liens supporting indebtedness, making investments, loans or advances and entering into certain hedging agreements, WPX Energy, Inc.’s ability to merge or consolidate with any person or sell all or substantially all of its assets to any person, enter into certain affiliate transactions, make certain distributions during the continuation of an event of default and allow material changes in the nature of its business. In addition, the representations, warranties and covenants contained in the Credit Facility Agreement may be subject to standards of materiality applicable to the contracting parties that differ from those applicable to investors. Investors are not third-party beneficiaries of the Credit Facility Agreement and should not rely on the representations, warranties and covenants contained therein, or any descriptions thereof, as characterizations of the actual state of facts or conditions of WPX Energy, Inc.
 
The Credit Facility Agreement includes customary events of default, including events of default relating to non-payment of principal, interest or fees, inaccuracy of representations and warranties in any material respect when made or when deemed made, violation of covenants, cross payment-defaults, cross acceleration, bankruptcy and insolvency events, certain unsatisfied judgments and a change of control. If an event of default with respect to a borrower occurs under the Credit Facility Agreement, the lenders will be able to terminate the commitments and accelerate the maturity of the loans of the defaulting borrower under the Credit Facility Agreement and exercise other rights and remedies.
 
As discussed in Note 4., cash receipts and cash expenditures related to the Company’s domestic operations have historically been transferred to or from Williams on a regular basis and cleared through unsecured promissory note agreements with Williams. On June 30, 2011, Williams contributed all amounts outstanding on these note agreements to our capital.

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Supplemental Oil and Gas Disclosures
(Unaudited)
 
We have significant oil and gas producing activities primarily in the Rocky Mountain, Northeast and Mid-continent areas of the United States. Additionally, we have international oil and gas producing activities, primarily in Argentina. This information also excludes our gas management activities.
 
With the exception of the Results of Operations, the following information includes our Arkoma Basin operations which have been reported as discontinued operations in our combined financial statements. These operations represent approximately one percent or less of our total domestic and international proved reserves for all periods presented.
 
Capitalized Costs

 	 	As of December 31, 2009	 	
 	 	 	 	 	 	 	 	 	 	 	Entity’s share of	 	
 	 	 	 	 	 	 	 	 	 	 	international	 	
 	 	 	 	 	 	 	 	Consolidated	 	 	equity method	 	
 	 	Domestic	 	 	International	 	 	Total	 	 	investee	 	
 		
Proved Properties	 	$	9,176	 	 	$	180	 	 	$	9,356	 	 	$	187	 	
Unproved properties	 	 	945	 	 	 	3	 	 	 	948	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	10,121	 	 	 	183	 	 	 	10,304	 	 	 	187	 	
Accumulated depreciation, depletion and amortization and valuation provisions	 	 	(3,213	)	 	 	(94	)	 	 	(3,307	)	 	 	(109	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net capitalized costs	 	$	6,908	 	 	$	89	 	 	$	6,997	 	 	$	78	 	

 
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	As of December 31, 2010	 	
 	 	 	 	 	 	 	 	 	 	 	Entity’s share of	 	
 	 	 	 	 	 	 	 	 	 	 	international	 	
 	 	 	 	 	 	 	 	Consolidated	 	 	equity method	 	
 	 	Domestic	 	 	International	 	 	Total	 	 	investee	 	
 		
Proved Properties	 	$	9,854	 	 	$	213	 	 	$	10,067	 	 	$	220	 	
Unproved properties	 	 	2,094	 	 	 	3	 	 	 	2,097	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	11,948	 	 	 	216	 	 	 	12,164	 	 	 	220	 	
Accumulated depreciation, depletion and amortization and valuation provisions	 	 	(3,867	)	 	 	(109	)	 	 	(3,976	)	 	 	(129	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net capitalized costs	 	$	8,081	 	 	 	107	 	 	$	8,188	 	 	$	91	 	

 
			
 	•  	Excluded from capitalized costs are equipment and facilities in support of oil and gas production of $312 million and $727 million, net, for 2010 and 2009, respectively.	
 		
 	•  	Proved properties include capitalized costs for oil and gas leaseholds holding proved reserves, development wells including uncompleted development well costs, and successful exploratory wells.	
 		
 	•  	Unproved properties consist primarily of unproved leasehold costs and costs for acquired unproven reserves.	

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WPX Energy
 
Supplemental Oil and Gas Disclosures—(Continued)
(Unaudited)
 
Cost Incurred

 	 	 	 	 	 	 	 	Entity’s share of	 	
 	 	 	 	 	 	 	 	international	 	
 	 	 	 	 	 	 	 	equity method	 	
 	 	Domestic	 	 	International	 	 	investee	 	
 	 	(Millions)	 	
 		
For the Year Ended December 31, 2008	 	 	 	 	 	 	 	 	 	 	 	 	
Acquisition	 	$	543	 	 	$	—	 	 	$	—	 	
Exploration	 	 	38	 	 	 	9	 	 	 	7	 	
Development	 	 	1,699	 	 	 	27	 	 	 	25	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	$	2,280	 	 	$	36	 	 	$	32	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
For the Year Ended December 31, 2009	 	 	 	 	 	 	 	 	 	 	 	 	
Acquisition	 	$	305	 	 	$	3	 	 	$	—	 	
Exploration	 	 	51	 	 	 	3	 	 	 	3	 	
Development	 	 	878	 	 	 	19	 	 	 	21	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	$	1,234	 	 	$	25	 	 	$	24	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
For the Year Ended December 31, 2010	 	 	 	 	 	 	 	 	 	 	 	 	
Acquisition	 	$	1,731	 	 	$	—	 	 	$	—	 	
Exploration	 	 	22	 	 	 	13	 	 	 	3	 	
Development	 	 	988	 	 	 	27	 	 	 	25	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	$	2,741	 	 	$	40	 	 	$	28	 	

 
			
 	•  	Costs incurred include capitalized and expensed items.	
 		
 	•  	Acquisition costs are as follows: The 2010 costs are primarily for additional leasehold in the Williston and Marcellus Basins and include approximately $422 million of proved property values. The 2009 costs are primarily for additional leasehold and reserve acquisitions in the Piceance Basin, and include $85 million of proved property values. The 2008 costs are primarily for additional leasehold and reserve acquisitions in the Piceance and Fort Worth Basins. Included in the 2008 acquisition amounts is $140 million of proved property values and $71 million related to an interest in a portion of acquired assets that a third party subsequently exercised its contractual option to purchase from us, on the same terms and conditions.	
 		
 	•  	Exploration costs include the costs incurred for geological and geophysical activity, drilling and equipping exploratory wells, including costs incurred during the year for wells determined to be dry holes, exploratory lease acquisitions, and retaining undeveloped leaseholds.	
 		
 	•  	Development costs include costs incurred to gain access to and prepare well locations for drilling and to drill and equip wells in our development basins.	
 		
 	•  	We have classified our step-out drilling and site preparation costs in the Powder River Basin as development, although the immediate offsets are frequently in the dewatering stages in as much as it better reflects the low risk profile of the costs incurred.	

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Supplemental Oil and Gas Disclosures—(Continued)
(Unaudited)
 
Results of Operations

 	 	Domestic	 	 	International	 	 	Total	 	
 	 	(Millions)	 	
 		
For the Year Ended December 31, 2008	 	 	 	 	 	 	 	 	 	 	 	 	
Revenues:	 	 	 	 	 	 	 	 	 	 	 	 	
Oil and gas revenues	 	$	2,810	 	 	$	72	 	 	$	2,882	 	
Other revenues	 	 	32	 	 	 	—	 	 	 	32	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total revenues	 	 	2,842	 	 	 	72	 	 	 	2,914	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Costs:	 	 	 	 	 	 	 	 	 	 	 	 	
Lease and facility operating	 	 	255	 	 	 	17	 	 	 	272	 	
Gathering, processing and transportation	 	 	229	 	 	 	—	 	 	 	229	 	
Taxes other than income	 	 	242	 	 	 	12	 	 	 	254	 	
Exploration expenses	 	 	31	 	 	 	6	 	 	 	37	 	
Depreciation, depletion and amortization	 	 	724	 	 	 	14	 	 	 	738	 	
General and administrative	 	 	217	 	 	 	7	 	 	 	224	 	
Gain on sale of international production payment right	 	 	—	 	 	 	(148	)	 	 	(148	)	
Other (income) expense	 	 	4	 	 	 	2	 	 	 	6	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total costs	 	 	1,702	 	 	 	(90	)	 	 	1,612	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Results of operations	 	 	1,140	 	 	 	162	 	 	 	1,302	 	
(Provision) benefit for income taxes	 	 	(416	)	 	 	(59	)	 	 	(475	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Exploration and production net income (loss)	 	$	724	 	 	$	103	 	 	$	827	 	

 

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Supplemental Oil and Gas Disclosures—(Continued)
(Unaudited)

 	 	Domestic	 	 	International	 	 	Total	 	
 	 	(Millions)	 	
 		
For the Year Ended December 31, 2009	 	 	 	 	 	 	 	 	 	 	 	 	
Revenues:	 	 	 	 	 	 	 	 	 	 	 	 	
Oil and gas revenues	 	$	2,090	 	 	$	78	 	 	$	2,168	 	
Other revenues	 	 	39	 	 	 	—	 	 	 	39	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total revenues	 	 	2,129	 	 	 	78	 	 	 	2,207	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Costs:	 	 	 	 	 	 	 	 	 	 	 	 	
Lease and facility operating	 	 	247	 	 	 	16	 	 	 	263	 	
Gathering, processing and transportation	 	 	273	 	 	 	—	 	 	 	273	 	
Taxes other than income	 	 	80	 	 	 	13	 	 	 	93	 	
Exploration expenses	 	 	52	 	 	 	2	 	 	 	54	 	
Depreciation, depletion and amortization	 	 	870	 	 	 	17	 	 	 	887	 	
Impairment of costs of acquired unproved reserves	 	 	15	 	 	 	—	 	 	 	15	 	
General and administrative	 	 	221	 	 	 	9	 	 	 	230	 	
Other (income) expense	 	 	33	 	 	 	—	 	 	 	33	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total costs	 	 	1,791	 	 	 	57	 	 	 	1,848	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Results of operations	 	 	338	 	 	 	21	 	 	 	359	 	
(Provision) benefit for income taxes	 	 	(123	)	 	 	(8	)	 	 	(131	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Exploration and production net income (loss)	 	$	215	 	 	$	13	 	 	$	228	 	

 
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WPX Energy
 
Supplemental Oil and Gas Disclosures—(Continued)
(Unaudited)

 	 	Domestic	 	 	International	 	 	Total	 	
 	 	(Millions)	 	
 		
For the Year Ended December 31, 2010	 	 	 	 	 	 	 	 	 	 	 	 	
Revenues:	 	 	 	 	 	 	 	 	 	 	 	 	
Oil and gas revenues	 	$	2,136	 	 	$	89	 	 	$	2,225	 	
Other revenues	 	 	40	 	 	 	—	 	 	 	40	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total revenues	 	 	2,176	 	 	 	89	 	 	 	2,265	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Costs:	 	 	 	 	 	 	 	 	 	 	 	 	
Lease and facility operating	 	 	267	 	 	 	19	 	 	 	286	 	
Gathering, processing and transportation	 	 	326	 	 	 	—	 	 	 	326	 	
Taxes other than income	 	 	109	 	 	 	16	 	 	 	125	 	
Exploration expenses	 	 	67	 	 	 	6	 	 	 	73	 	
Depreciation, depletion and amortization	 	 	858	 	 	 	17	 	 	 	875	 	
Impairment of certain natural gas properties in the Ft. Worth Basin	 	 	503	 	 	 	—	 	 	 	503	 	
Impairment of costs of acquired unproved reserves	 	 	175	 	 	 	—	 	 	 	175	 	
Goodwill impairment	 	 	1,003	 	 	 	—	 	 	 	1,003	 	
General and administrative	 	 	225	 	 	 	9	 	 	 	234	 	
Other (income) expense	 	 	(19	)	 	 	—	 	 	 	(19	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total costs	 	 	3,514	 	 	 	67	 	 	 	3,581	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Results of operations	 	 	(1,338	)	 	 	22	 	 	 	(1,316	)	
(Provision) benefit for income taxes	 	 	123	 	 	 	(8	)	 	 	115	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Exploration and production net income (loss)	 	$	(1,215	)	 	$	14	 	 	$	(1,201	)	

 
			
 	•  	Amount for all years exclude the equity earnings from the international equity method investee. Equity earnings from this investee were $16 million, $14 million and $16 million in 2010, 2009 and 2008.	
 		
 	•  	Oil and gas revenues consist primarily of natural gas production sold and includes the impact of hedges.	
 		
 	•  	Other revenues consist of activities that are an indirect part of the producing activities. Other expenses in 2009 also include $32 million of expense related to penalties from the early release of drilling rigs.	
 		
 	•  	Exploration expenses include the costs of geological and geophysical activity, drilling and equipping exploratory wells determined to be dry holes, and the cost of retaining undeveloped leaseholds including lease amortization and impairments.	
 		
 	•  	Depreciation, depletion and amortization includes depreciation of support equipment. Additionally, 2009 includes $17 million additional depreciation, depletion and amortization as a result of our recalculation of fourth quarter depreciation, depletion and amortization utilizing our year-end reserves which were lower than 2008. The lower reserves are primarily a result of the application of new rules issued by the SEC.	
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WPX Energy
 
Supplemental Oil and Gas Disclosures—(Continued)
(Unaudited)

Proved Reserves

 	 	 	 	 	 	 	 	Entity’s share of	 	 	 	 	
 	 	 	 	 	 	 	 	international	 	 	 	 	
 	 	 	 	 	 	 	 	equity method	 	 	 	 	
 	 	Domestic	 	 	International(1)	 	 	investee(2)	 	 	Combined	 	
 	 	(Bcfe)	 	 	(MMBoe)	 	 	(MMBoe)	 	 	(Bcfe)	 	
 		
For The Year Ended December 31, 2008	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Proved reserves at the beginning of period	 	 	4,143	 	 	 	21	 	 	 	15	 	 	 	4,357	 	
Revisions	 	 	(220	)	 	 	1	 	 	 	—	 	 	 	(208	)	
Purchases	 	 	31	 	 	 	—	 	 	 	—	 	 	 	31	 	
Extensions and discoveries	 	 	791	 	 	 	2	 	 	 	1	 	 	 	810	 	
Wellhead production	 	 	(406	)	 	 	(2	)	 	 	(2	)	 	 	(434	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Proved reserves at the end of period	 	 	4,339	 	 	 	22	 	 	 	14	 	 	 	4,556	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Proved developed reserves at end of period	 	 	2,456	 	 	 	15	 	 	 	10	 	 	 	2,607	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
For the year ended December 31, 2009	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Proved reserves at the beginning of period	 	 	4,339	 	 	 	22	 	 	 	14	 	 	 	4,556	 	
Revisions	 	 	(859	)	 	 	2	 	 	 	1	 	 	 	(841	)	
Purchases	 	 	159	 	 	 	—	 	 	 	—	 	 	 	159	 	
Extensions and discoveries	 	 	1,051	 	 	 	5	 	 	 	7	 	 	 	1,123	 	
Wellhead production	 	 	(435	)	 	 	(3	)	 	 	(2	)	 	 	(466	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Proved reserves at the end of period	 	 	4,255	 	 	 	26	 	 	 	20	 	 	 	4,531	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Proved developed reserves at end of period	 	 	2,387	 	 	 	17	 	 	 	12	 	 	 	2,562	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
For the year ended December 31, 2010	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Proved reserves at the beginning of period	 	 	4,255	 	 	 	26	 	 	 	20	 	 	 	4,531	 	
Revisions	 	 	(233	)	 	 	(2	)	 	 	1	 	 	 	(242	)	
Purchases	 	 	162	 	 	 	—	 	 	 	—	 	 	 	162	 	
Extensions and discoveries	 	 	508	 	 	 	4	 	 	 	4	 	 	 	557	 	
Wellhead production	 	 	(420	)	 	 	(3	)	 	 	(2	)	 	 	(450	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Proved reserves at the end of period	 	 	4,272	 	 	 	25	 	 	 	23	 	 	 	4,558	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Proved developed reserves at end of period	 	 	2,498	 	 	 	15	 	 	 	14	 	 	 	2,671	 	

 

			
(1)		Reserves attributable to a consolidated subsidiary (Apco) in which there is a 31 percent noncontrolling interest.	
 		
(2)		Represents Apco’s 40.8% interest in reserves of Petrolera Entre Lomas S.A.	

 	•  	The SEC defines proved oil and gas reserves (Rule 4-10(a) of Regulation S-X) as those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is	

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WPX Energy
 
Supplemental Oil and Gas Disclosures—(Continued)
(Unaudited)

 		reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Proved reserves consist of two categories, proved developed reserves and proved undeveloped reserves. Proved developed reserves are currently producing wells and wells awaiting minor sales connection expenditure, recompletion, additional perforations or borehole stimulation treatments. Proved undeveloped reserves are those reserves which are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Proved reserves on undrilled acreage are generally limited to those that can be developed within five years according to planned drilling activity. Proved reserves on undrilled acreage also can include locations that are more than one offset away from current producing wells where there is a reasonable certainty of production when drilled or where it can be demonstrated with reasonable certainty that there is continuity of production from the existing productive formation.	

 	•  	Purchases in 2008, 2009 and 2010 include proved developed reserves of 17 Bcfe, 2.4 Bcfe and 42 Bcfe, respectively.	
 		
 	•  	Revisions in 2010 primarily relate to the reclassification of reserves from proved to probable reserves attributable to locations not expected to be developed within five years. A significant portion of the revisions for 2009 are a result of the impact of the new SEC rules. Proved reserves are lower because of the lower 12-month average, first-of-the-month price as compared to the 2008 year-end price, and the revision of proved undeveloped reserve estimates based on new guidance. Approximately one-half of the revisions for 2008 relate to the impact of lower average year-end natural gas prices used in 2008 compared to the 2007.	
 		
 	•  	Extensions and discoveries in 2009 are higher than other years due in part to the expanded definition of oil and gas reserves supported by reliable technology and reasonable certainty used for reserves estimation.	
 		
 	•  	Natural gas reserves are computed at 14.73 pounds per square inch absolute and 60 degrees Fahrenheit. Domestic crude oil reserves are insignificant and have been included in the domestic proved reserves on a basis of billion cubic feet equivalents (Bcfe).	
 
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
 
The following is based on the estimated quantities of proved reserves. In 2009, we adopted prescribed accounting revisions associated with oil and gas authoritative guidance. Those revisions include using the 12-month average price computed as an unweighted arithmetic average of the price as of the first day of each month, unless prices are defined by contractual arrangements. These revisions are reflected in our 2010 and 2009 amounts. For the years ended December 31, 2010 and 2009, the average domestic natural gas equivalent price, including deductions for gathering, processing and transportation, used in the estimates was $3.78 and $2.76 per MMcfe, respectively. For the year ended December 31, 2008, the average domestic year-end natural gas equivalent price used in the estimates was $4.41 per MMcfe. Future income tax expenses have been computed considering applicable taxable cash flows and appropriate statutory tax rates. The discount rate of 10 percent is as prescribed by authoritative guidance. Continuation of year-end economic conditions also is assumed. The calculation is based on estimates of proved reserves, which are revised over time as new data becomes available. Probable or possible reserves, which may become proved in the future, are not considered. The calculation also requires assumptions as to the timing of future production of proved reserves, and the timing and amount of future development and production costs.
 
Numerous uncertainties are inherent in estimating volumes and the value of proved reserves and in projecting future production rates and timing of development expenditures. Such reserve estimates are subject

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WPX Energy
 
Supplemental Oil and Gas Disclosures—(Continued)
(Unaudited)
 
to change as additional information becomes available. The reserves actually recovered and the timing of production may be substantially different from the reserve estimates.
 
Standardized Measure of Discounted Future Net Cash Flows

 	 	 	 	 	 	 	 	Entity’s share	 	
 	 	 	 	 	 	 	 	of international	 	
 	 	 	 	 	 	 	 	equity method	 	
As of December 31, 2009	 	Domestic	 	 	International(1)	 	 	investee(2)	 	
 	 	(Millions)	 	
 		
Future cash inflows	 	$	11,729	 	 	$	664	 	 	$	614	 	
Less:	 	 	 	 	 	 	 	 	 	 	 	 	
Future production costs	 	 	3,990	 	 	 	227	 	 	 	228	 	
Future development costs	 	 	2,833	 	 	 	83	 	 	 	91	 	
Future income tax provisions	 	 	1,404	 	 	 	67	 	 	 	73	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Future net cash flows	 	 	3,502	 	 	 	287	 	 	 	222	 	
Less 10 percent annual discount for estimated timing of cash flows	 	 	(1,789	)	 	 	(112	)	 	 	(93	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Standardized measure of discounted future net cash inflows	 	$	1,713	 	 	$	175	 	 	$	129	 	

 
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	Entity’s share	 	
 	 	 	 	 	 	 	 	of international	 	
 	 	 	 	 	 	 	 	equity method	 	
As of December 31, 2010	 	Domestic	 	 	International(1)	 	 	investee(2)	 	
 		
Future cash inflows	 	$	16,151	 	 	$	779	 	 	$	787	 	
Less:	 	 	 	 	 	 	 	 	 	 	 	 	
Future production costs	 	 	4,927	 	 	 	273	 	 	 	278	 	
Future development costs	 	 	2,960	 	 	 	89	 	 	 	92	 	
Future income tax provisions	 	 	2,722	 	 	 	98	 	 	 	114	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Future net cash flows	 	 	5,542	 	 	 	319	 	 	 	303	 	
Less 10 percent annual discount for estimated timing of cash flows	 	 	(2,728	)	 	 	(121	)	 	 	(117	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Standardized measure of discounted future net cash inflows	 	$	2,814	 	 	$	198	 	 	$	186	 	

 

			
(1)		Amounts attributable to a consolidated subsidiary (Apco) in which there is a 31 percent noncontrolling interest.	
 		
(2)		Represents Apco’s 40.8% interest in Petrolera Entre Lomas S.A.	

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WPX Energy
 
Supplemental Oil and Gas Disclosures—(Continued)
(Unaudited)

Sources of Change in Standardized Measure of Discounted Future Net Cash Flows

 	 	 	 	 	 	 	 	Entity’s share	 	
 	 	 	 	 	 	 	 	of international	 	
 	 	 	 	 	 	 	 	equity method	 	
For the Year Ended December 31, 2008	 	Domestic	 	 	International(1)	 	 	investee(2)	 	
 	 	(Millions)	 	
 		
Standardized measure of discounted future net cash flows beginning of period	 	$	4,803	 	 	$	149	 	 	$	115	 	
Changes during the year:	 	 	 	 	 	 	 	 	 	 	 	 	
Sales of oil and gas produced, net of operating costs	 	 	(2,091	)	 	 	(55	)	 	 	(55	)	
Net change in prices and production costs	 	 	(2,548	)	 	 	25	 	 	 	34	 	
Extensions, discoveries and improved recovery, less estimated future costs	 	 	1,423	 	 	 	—	 	 	 	—	 	
Development costs incurred during year	 	 	817	 	 	 	33	 	 	 	25	 	
Changes in estimated future development costs	 	 	(724	)	 	 	(36	)	 	 	(36	)	
Purchase of reserves in place, less estimated future costs	 	 	55	 	 	 	—	 	 	 	—	 	
Revisions of previous quantity estimates	 	 	(395	)	 	 	50	 	 	 	38	 	
Accretion of discount	 	 	714	 	 	 	13	 	 	 	18	 	
Net change in income taxes	 	 	1,108	 	 	 	3	 	 	 	—	 	
Other	 	 	11	 	 	 	(7	)	 	 	(8	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Net changes	 	 	(1,630	)	 	 	26	 	 	 	16	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Standardized measure of discounted future net cash flows end of period	 	$	3,173	 	 	$	175	 	 	$	131	 	

 

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WPX Energy
 
Supplemental Oil and Gas Disclosures—(Continued)
(Unaudited)

 	 	 	 	 	 	 	 	Entity’s share	 	
 	 	 	 	 	 	 	 	of international	 	
 	 	 	 	 	 	 	 	equity method	 	
For the Year Ended December 31, 2009	 	Domestic	 	 	International(1)	 	 	investee(2)	 	
 	 	(Millions)	 	
 		
Standardized measure of discounted future net cash flows beginning of period	 	$	3,173	 	 	$	175	 	 	$	131	 	
Changes during the year:	 	 	 	 	 	 	 	 	 	 	 	 	
Sales of oil and gas produced, net of operating costs	 	 	(1,006	)	 	 	(49	)	 	 	(45	)	
Net change in prices and production costs	 	 	(3,310	)	 	 	(35	)	 	 	(49	)	
Extensions, discoveries and improved recovery, less estimated future costs	 	 	1,131	 	 	 	—	 	 	 	—	 	
Development costs incurred during year	 	 	389	 	 	 	17	 	 	 	21	 	
Changes in estimated future development costs	 	 	701	 	 	 	(1	)	 	 	(3	)	
Purchase of reserves in place, less estimated future costs	 	 	171	 	 	 	—	 	 	 	—	 	
Revisions of previous quantity estimates	 	 	(923	)	 	 	79	 	 	 	88	 	
Accretion of discount	 	 	450	 	 	 	21	 	 	 	17	 	
Net change in income taxes	 	 	932	 	 	 	(4	)	 	 	(2	)	
Other	 	 	5	 	 	 	(28	)	 	 	(29	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Net changes	 	 	(1,460	)	 	 	—	 	 	 	(2	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Standardized measure of discounted future net cash flows end of period	 	$	1,713	 	 	$	175	 	 	$	129	 	

 
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WPX Energy
 
Supplemental Oil and Gas Disclosures—(Continued)
(Unaudited)

 	 	 	 	 	 	 	 	Entity’s share	 	
 	 	 	 	 	 	 	 	of international	 	
 	 	 	 	 	 	 	 	equity method	 	
For the Year Ended December 31, 2010	 	Domestic	 	 	International(1)	 	 	investee(2)	 	
 	 	(Millions)	 	
 		
Standardized measure of discounted future net cash flows beginning of period	 	$	1,713	 	 	$	175	 	 	$	129	 	
Changes during the year:	 	 	 	 	 	 	 	 	 	 	 	 	
Sales of oil and gas produced, net of operating costs	 	 	(1,446	)	 	 	(59	)	 	 	(55	)	
Net change in prices and production costs	 	 	1,921	 	 	 	34	 	 	 	43	 	
Extensions, discoveries and improved recovery, less estimated future costs	 	 	724	 	 	 	—	 	 	 	—	 	
Development costs incurred during year	 	 	633	 	 	 	26	 	 	 	25	 	
Changes in estimated future development costs	 	 	(292	)	 	 	(12	)	 	 	(15	)	
Purchase of reserves in place, less estimated future costs	 	 	439	 	 	 	2	 	 	 	—	 	
Revisions of previous quantity estimates	 	 	(332	)	 	 	26	 	 	 	63	 	
Accretion of discount	 	 	220	 	 	 	22	 	 	 	17	 	
Net change in income taxes	 	 	(758	)	 	 	(13	)	 	 	(20	)	
Other	 	 	(8	)	 	 	(3	)	 	 	(1	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Net changes	 	 	1,101	 	 	 	23	 	 	 	57	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Standardized measure of discounted future net cash flows end of period	 	$	2,814	 	 	$	198	 	 	$	186	 	

 

			
(1)		Amounts attributable to a consolidated subsidiary (Apco) in which there is a 31 percent noncontrolling interest.	
 		
(2)		Represents Apco’s 40.8% interest in Petrolera Entre Lomas S.A.	
 
In relation to the SEC rules adopted in 2009, we estimated that the domestic standardized measure of discounted future net cash flows in 2009 declined approximately $840 million on a before tax basis and excluding the overall price rule impact. The significant components of this decline included an estimated $640 million decrease included in revisions of previous quantity estimates and a related $430 million decrease included in the net change in prices and production costs, partially offset by a $210 million increase included in extensions, discoveries and improved recovery, less estimated future costs. Additionally, we estimated that a significant portion of the remaining net change in domestic price and production costs is due to the application of the new pricing rules which resulted in the use of lower prices at December 31, 2009, than would have resulted under the previous rules.
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           Shares

WPX Energy, Inc.
 
Class A Common Stock

Prospectus
          , 2011

Barclays Capital
Citigroup
J.P. Morgan
BofA Merrill Lynch

Deutsche Bank Securities
Goldman, Sachs & Co.
Morgan Stanley
Wells Fargo Securities

Credit Suisse
RBC Capital Markets
Scotia Capital
UBS Investment Bank
Howard Weil Incorporated

Table of Contents
PART II
 
INFORMATION NOT REQUIRED IN PROSPECTUS

Item 13.   	Other Expenses of Issuance and Distribution.	
 
The following table sets forth the expenses (other than underwriting compensation expected to be incurred) in connection with this offering. All of such amounts (except the SEC registration fee and FINRA filing fee) are estimated.

 	 	 	 	 	 	 	 	 	
SEC registration fee	 	$	87,075	 	 	 	 	 	
FINRA filing fee	 	 	75,500	 	 	 	 	 	
NYSE listing fee	 	 	250,000	 	 	 	 	 	
Printing and engraving expenses	 	 	800,000	 	 	 	 	 	
Legal fees and expenses	 	 	1,000,000	 	 	 	 	 	
Accounting fees and expenses	 	 	2,150,000	 	 	 	 	 	
Transfer agent and Registrar fees	 	 	2,000	 	 	 	 	 	
Miscellaneous	 	 	300,000	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	
Total	 	$	4,664,575	 	 	 	 	 	

 

			
*		To be provided by amendment	

Item 14.   	Indemnification of Officers and Directors.	
 
Our certificate of incorporation provides that a director will not be liable to the corporation or its stockholders for monetary damages for breach of fiduciary duty as a director to the fullest extent that the Delaware General Corporation Law (“DGCL”) or any other law of the State of Delaware permits. If the DGCL or any other law of the State of Delaware is amended to authorize the further elimination or limitation of the liability of directors, then the liability of a director will be limited to the fullest extent permitted by the amended DGCL or other law, as applicable.
 
We are empowered by Section 145 of the DGCL, subject to the procedures and limitations stated therein, to indemnify any person against expenses (including attorneys’ fees), judgments, fines, and amounts paid in settlement actually and reasonably incurred by them in connection with any threatened, pending, or completed action, suit, or proceeding in which such person is made party by reason of their being or having been a director, officer, employee, or agent of the Company. The statute provides that indemnification pursuant to its provisions is not exclusive of other rights of indemnification to which a person may be entitled under any bylaw, agreement, vote of stockholders or disinterested directors, or otherwise. Our bylaws provide for indemnification by us of our directors and officers to the fullest extent permitted by the DGCL.

Williams currently maintains, and after the spin-off, the Company will maintain, policies of insurance under which our directors and officers are insured, within the limits and subject to the limitations of the policies, against certain expenses in connection with the defense of actions, suits, or proceedings, and certain liabilities which might be imposed as a result of such actions, suits or proceedings, to which they are parties by reason of being or having been such directors or officers.

		
Item 15.   	Recent Sales of Unregistered Securities.	
 
Except for the issuance of shares to Williams, we have not issued any securities in unregistered transactions. The issuance of shares to Williams was exempt from the registration requirements of the Securities Act pursuant to Section 4(2) thereof.

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Item 16.   	Exhibits and Financial Statement Schedules.	

 	(a)  	Exhibits	
 
A list of exhibits filed as part of this registration statement is set forth in the Exhibit Index, which is incorporated herein by reference.

 	(b)  	Financial Statement Schedules	
 
Schedule II—Valuation and Qualifying Accounts for the three years ended December 31, 2010, 2009 and 2008
 
SCHEDULE II—VALUATION AND QUALIFYING ACCOUNTS

 	 	 	 	 	Charged	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	(Credited)	 	 	 	 	 	 	 	 	 	 	
 	 	Beginning	 	 	to Costs and	 	 	 	 	 	 	 	 	Ending	 	
 	 	Balance	 	 	Expenses	 	 	Other	 	 	Deductions	 	 	Balance	 	
 	 	(Millions)	 	
 		
2010:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Allowance for doubtful accounts—accounts and notes receivable(a)	 	$	19	 	 	$	(3	)	 	$	—	 	 	$	—	 	 	$	16	 	
Price-risk management credit
reserves—liabilities(b)	 	 	(3	)	 	 	3	(d)	 	 	—	 	 	 	—	 	 	 	—	 	
2009:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Allowance for doubtful accounts—accounts and notes receivable(a)	 	 	25	 	 	 	3	 	 	 	—	 	 	 	(9	)(c)	 	 	19	 	
Price-risk management credit
reserves—assets(a)	 	 	6	 	 	 	(3	)(d)	 	 	(3	)(e)	 	 	—	 	 	 	—	 	
Price-risk management credit
reserves—liabilities(b)	 	 	(15	)	 	 	12	(d)	 	 	—	 	 	 	—	 	 	 	(3	)	
2008:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Allowance for doubtful accounts—accounts and notes receivable(a)	 	 	14	 	 	 	12	 	 	 	—	 	 	 	(1	)(c)	 	 	25	 	
Price-risk management credit
reserves—assets(a)	 	 	1	 	 	 	1	(d)	 	 	4	(e)	 	 	—	 	 	 	6	 	
Price-risk management credit reserves—liabilities(b)	 	 	—	 	 	 	(16	)(d)	 	 	1	(e)	 	 	—	 	 	 	(15	)	

 
			
(a)		Deducted from related assets.	
 		
(b)		Deducted from related liabilities.	
 		
(c)		Represents recoveries of balances previously written off.	
 		
(d)		Included in revenues.	
 		
(e)		Included in accumulated other comprehensive income (loss).	

Item 17.   	Undertakings.	
 
The undersigned registrant hereby undertakes that:
 
(1) The undersigned will provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.
 
(2) For purposes of determining any liability under the Securities Act of 1933, as amended, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1)

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or (4) or 497(h) under the Securities Act of 1933, as amended, shall be deemed to be part of this registration statement as of the time it was declared effective.
 
(3) For the purpose of determining any liability under the Securities Act of 1933, as amended, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.
 
Insofar as indemnification for liabilities arising under the Securities Act of 1933, as amended, may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act of 1933, as amended, and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act of 1933, as amended, and will be governed by the final adjudication of such issue.

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Signatures

Pursuant to the requirements of the Securities Act of 1933, the registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Tulsa, State of Oklahoma, on September 1, 2011.

WPX ENERGY, INC.
(Registrant)

 	By: 	/s/  Ralph A. Hill	

Ralph A. Hill
Chief Executive Officer
 
Pursuant to the requirements of the Securities Act of 1933, this registration statement has been signed below by the following persons in the capacities and on the dates indicated:

 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	
Date: September 1, 2011	 	 	 	By:	 	/s/  Ralph A. Hill

Ralph A. Hill, Chief Executive Officer(Principal Executive Officer)	
 	 	 	 	 	 	 	
Date: September 1, 2011	 	 	 	By:	 	*

Donald R. Chappel, Chief Financial Officer
(Principal Financial Officer)	
 	 	 	 	 	 	 	
Date: September 1, 2011	 	 	 	By:	 	/s/  Ted T. Timmermans

Ted T. Timmermans, Chief Accounting Officer
(Principal Accounting Officer)	
 	 	 	 	 	 	 	
Date: September 1, 2011	 	 	 	By:	 	/s/  Alan S. Armstrong

Alan S. Armstrong, Chairman of the Board	
 	 	 	 	 	 	 	 	 	
* By:	 	/s/  Ralph A. Hill

Ralph A. Hill
Attorney-in-fact	 	 	 	 	 	 	

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EXHIBIT INDEX

 	 	 	 	 	
Exhibit No.	 	Description	
 		
 	1	.1	 	Form of Underwriting Agreement	
 	(2	.1)	 	Contribution Agreement, dated as of October 26, 2010, by and among Williams Production RMT Company LLC, Williams Energy Services, LLC, Williams Partners GP LLC, Williams Partners L.P., Williams Partners Operating LLC and Williams Field Services Group, LLC	
 	(3	.1)	 	Form of Amended and Restated Certificate of Incorporation of WPX Energy, Inc.	
 	(3	.2)	 	Form of Amended and Restated Bylaws of WPX Energy, Inc.	
 	(4	.1)	 	Form of Specimen Class A Common Stock Certificate	
 	(5	.1)	 	Opinion of Gibson, Dunn & Crutcher LLP	
 	10	.1	 	Form of Separation and Distribution Agreement	
 	(10	.2)	 	Form of Administrative Services Agreement	
 	(10	.3)	 	Form of Transition Services Agreement	
 	(10	.4)	 	Form of Tax Sharing Agreement	
 	(10	.5)	 	Form of Registration Rights Agreement	
 	(10	.6)	 	Credit Agreement, dated as of June 3, 2011, by and among WPX Energy, Inc., the lenders named therein, and Citibank, N.A., as Administrative Agent and Swingline Lender	
 	(10	.7)#	 	Amended and Restated Gas Gathering, Processing, Dehydrating and Treating Agreement by and among Williams Field Services Company, LLC, Williams Production RMT Company LLC, Williams Production Ryan Gulch LLC and WPX Energy Marketing, LLC, effective as of August 1, 2011	
 	(10	.8)	 	Form of WPX Energy, Inc. 2011 Incentive Plan	
 	(10	.9)	 	Form of WPX Energy, Inc. 2011 Employee Stock Purchase Plan	
 	(21	.1)	 	List of Subsidiaries	
 	(23	.1)	 	Consent of Gibson, Dunn & Crutcher LLP (included in Exhibit 5.1)	
 	23	.2	 	Consent of Ernst & Young LLP	
 	23	.3	 	Consent of Independent Petroleum Engineers and Geologists, Netherland, Sewell & Associates, Inc.	
 	23	.4	 	Consent of Independent Petroleum Engineers and Geologists, Miller and Lents, Ltd.	
 	23	.5	 	Consent of Independent Petroleum Engineers, Ralph E. Davis Associates, Inc.	
 	(24	.1)	 	Powers of Attorney (included on signature page of the initial registration statement)	
 	(99	.1)	 	Report of Independent Petroleum Engineers and Geologists, Netherland, Sewell & Associates, Inc.	
 	(99	.2)	 	Report of Independent Petroleum Engineers and Geologists, Miller and Lents, Ltd.	
 	(99	.3)	 	Report of Independent Petroleum Engineers, Ralph E. Davis Associates, Inc.	
 	(99	.4)	 	Consent of Prospective Director, George A. Lorch	
 	(99	.5)	 	Consent of Prospective Director, William G. Lowrie	

 

			
( )		Previously filed with this registration statement	
 		
# 		Certain portions have been omitted pursuant to a pending confidential treatment request. Omitted information has been filed separately with the SEC.	

Exhibit 1.1
                        Shares
WPX ENERGY, INC.
Class A Common Stock
FORM OF UNDERWRITING AGREEMENT
August      , 2011
Barclays Capital Inc.
Citigroup Global Markets Inc.
J.P. Morgan Securities LLC
Merrill Lynch, Pierce, Fenner & Smith
                         Incorporated ,
As Representatives of the several
Underwriters named in Schedule I attached hereto,
c/o Barclays Capital Inc.
745 Seventh Avenue
New York, New York 10019
Ladies and Gentlemen:
          WPX Energy, Inc., a Delaware corporation (the “ Company ”) and a direct wholly-owned subsidiary of The Williams Companies, Inc., a Delaware corporation (“ Parent ”), proposes to sell                               shares (the “ Firm Stock ”) of the Company’s Class A common stock, par value $1.00 per share (the " Class A Common Stock ”). In addition, the Company proposes to grant to the underwriters (the " Underwriters ”) named in Schedule I attached to this agreement (this “ Agreement ”) an option to purchase up to                               additional shares of the Class A Common Stock on the terms set forth in Section 3 (the “ Option Stock ”). The Firm Stock and the Option Stock, if purchased, are hereinafter collectively called the “ Stock .” This Agreement is to confirm the agreement concerning the purchase of the Stock from the Company by the Underwriters.
          Prior to the Initial Delivery Date (as defined below):
     (a) Parent will contribute and transfer to the Company the assets and liabilities associated with the Company’s business and will forgive or contribute to the Company’s capital all intercompany debt associated with the Company’s business;
     (b) the Company will effect a recapitalization whereby the outstanding shares of the Company’s common stock, all of which are owned by Parent, will be reclassified into                               shares of Class B common stock (the “ Class B Common Stock ,” and together with the Class A Common Stock, the " Common Stock ”) in partial consideration for all of the assets (net of the liabilities assumed) contributed to the Company by Parent, and the Class A Common Stock will be authorized; and

 

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     (c) the Company will amend and restate its certificate of incorporation and restate its bylaws.
          These transactions are defined herein as the “ Restructuring Transactions .”
     As used in this Agreement:
     (i) “ Applicable Time ” means     [a.m.][p.m.] (New York City time) on           ;
     (ii) “ Effective Date ” means the date and time as of which such registration statement was declared effective by the Commission;
     (iii) “ Issuer Free Writing Prospectus ” means each “free writing prospectus” (as defined in Rule 405 under the Securities Act) prepared by or on behalf of the Company or used or referred to by the Company in connection with the offering of the Stock;
     (iv) “ Preliminary Prospectus ” means any preliminary prospectus relating to the Stock included in such registration statement or filed with the Commission pursuant to Rule 424(b) under the Securities Act;
     (v) “ Pricing Disclosure Package ” means, as of the Applicable Time, the most recent Preliminary Prospectus, together with the information included in Schedule III hereto and each Issuer Free Writing Prospectus filed or used by the Company on or before the Applicable Time, other than a road show that is an Issuer Free Writing Prospectus but is not required to be filed under Rule 433 under the Securities Act;
     (vi) “ Prospectus ” means the final prospectus relating to the Stock, as filed with the Commission pursuant to Rule 424(b) under the Securities Act; and
     (vii) “ Registration Statement ” means such registration statement, as amended as of the Effective Date, including any Preliminary Prospectus or the Prospectus, all exhibits to such registration statement and including the information deemed by virtue of Rule 430A under the Securities Act to be part of such registration statement as of the Effective Date. Any reference herein to the term “Registration Statement” shall be deemed to include the abbreviated registration statement to register additional shares of Class A Common Stock under Rule 462(b) under the Securities Act (the “ Rule  462(b) Registration Statement ”).
Any reference to the “ most recent Preliminary Prospectus ” shall be deemed to refer to the latest Preliminary Prospectus included in the Registration Statement or filed pursuant to Rule 424(b) under the Securities Act prior to or on the date hereof.

 

 3 
          1. Representations, Warranties and Agreements of the Company . The Company represents, warrants and agrees that:
     (a) A registration statement on Form S-1 (File No. 333-173808) relating to the Stock has (i) been prepared by the Company in conformity with the requirements of the Securities Act of 1933, as amended (the “ Securities Act ”), and the rules and regulations of the Securities and Exchange Commission (the “ Commission ”) thereunder; (ii) been filed with the Commission under the Securities Act; and (iii) become effective under the Securities Act. Copies of such registration statement and any amendment thereto have been delivered by the Company to you as the representatives (the “ Representatives ”) of the Underwriters. The Commission has not issued any order preventing or suspending the use of any Preliminary Prospectus or the Prospectus or suspending the effectiveness of the Registration Statement, and no proceeding or examination for such purpose has been instituted or threatened by the Commission.
     (b) The Company was not at the time of initial filing of the Registration Statement and at the earliest time thereafter that the Company or another offering participant made a bona fide offer (within the meaning of Rule 164(h)(2) under the Securities Act) of the Stock, is not on the date hereof and will not be on the applicable Delivery Date (as defined in Section 5), an “ineligible issuer” (as defined in Rule 405 under the Securities Act).
     (c) The Registration Statement conformed and will conform in all material respects on the Effective Date and on the applicable Delivery Date, and any amendment to the Registration Statement filed after the date hereof will conform in all material respects when filed, to the requirements of the Securities Act and the rules and regulations thereunder. The most recent Preliminary Prospectus conformed, and the Prospectus will conform, in all material respects when filed with the Commission pursuant to Rule 424(b) under the Securities Act and on the applicable Delivery Date to the requirements of the Securities Act and the rules and regulations thereunder.
     (d) The Registration Statement did not, as of the Effective Date, contain an untrue statement of a material fact or omit to state a material fact required to be stated therein or necessary to make the statements therein not misleading; provided that no representation or warranty is made as to information contained in or omitted from the Registration Statement in reliance upon and in conformity with written information furnished to the Company through the Representatives by or on behalf of any Underwriter specifically for inclusion therein, which information is specified in Section 9(f).
     (e) The Prospectus will not, as of its date or as of the applicable Delivery Date, contain an untrue statement of a material fact or omit to state a material fact necessary to make the statements therein, in the light of the circumstances under which they were made, not misleading; provided that no representation or warranty is made as to information contained in or omitted from the Prospectus in reliance upon and in conformity with written information furnished to the Company through the

 

 4 
Representatives by or on behalf of any Underwriter specifically for inclusion therein, which information is specified in Section 9(f).
     (f) The Pricing Disclosure Package did not, as of the Applicable Time, contain an untrue statement of a material fact or omit to state a material fact necessary to make the statements therein, in the light of the circumstances under which they were made, not misleading; provided that no representation or warranty is made as to information contained in or omitted from the Pricing Disclosure Package in reliance upon and in conformity with written information furnished to the Company through the Representatives by or on behalf of any Underwriter specifically for inclusion therein, which information is specified in Section 9(f).
     (g) The Pricing Disclosure Package, when taken together with each Issuer Free Writing Prospectus listed in Schedule IV hereto, did not, as of the Applicable Time, contain an untrue statement of a material fact or omit to state a material fact necessary to make the statements therein, in the light of the circumstances under which they were made, not misleading; provided that no representation or warranty is made as to information contained in or omitted from the Pricing Disclosure Package (or any Issuer Free Writing Prospectus listed in Schedule IV hereto) in reliance upon and in conformity with written information furnished to the Company through the Representatives by or on behalf of any Underwriter specifically for inclusion therein, which information is specified in Section 9(f).
     (h) Each Issuer Free Writing Prospectus conformed or will conform in all material respects to the requirements of the Securities Act and the rules and regulations thereunder on the date of first use, and the Company has complied with all prospectus delivery and any filing requirements applicable to such Issuer Free Writing Prospectus pursuant to the Securities Act and rules and regulations thereunder. The Company has not made any offer relating to the Stock that would constitute an Issuer Free Writing Prospectus without the prior written consent of the Representatives. The Company has retained in accordance with the Securities Act and the rules and regulations thereunder all Issuer Free Writing Prospectuses that were not required to be filed pursuant to the Securities Act and the rules and regulations thereunder. The Company has taken all actions necessary so that any “road show” (as defined in Rule 433 under the Securities Act) in connection with the offering of the Stock will not be required to be filed pursuant to the Securities Act and the rules and regulations thereunder.
     (i) The Company and each of its “significant subsidiaries,” as defined in Rule 1-02(w) of Regulation S-X under the Securities Exchange Act of 1934, as amended (the “ Exchange Act ”) (each, a “ Significant Subsidiary ”), has been duly organized, is validly existing and in good standing as a corporation or other business entity under the laws of its jurisdiction of organization and is duly qualified to do business and in good standing as a foreign corporation or other business entity in each jurisdiction in which its ownership or lease of property or the conduct of its businesses requires such qualification, except where the failure to be so qualified or in good standing would not have a material adverse effect on the financial condition, results of operations, business or prospects of the Company and its subsidiaries taken as a whole (a “ Material Adverse

 

 5 
Effect ”). Each of the Company and its Significant Subsidiaries has all power and authority necessary to own or hold its properties and to conduct its businesses as described in the Pricing Disclosure Package and the Prospectus. The subsidiaries listed on Schedule V hereto are the only “significant subsidiaries” of the Company, as defined in Rule 1-02(w) of Regulation S-X under the Exchange Act.
     (j) The Company has an authorized capitalization as set forth in each of the most recent Preliminary Prospectus and the Prospectus, and all of the issued shares of capital stock of the Company have been duly authorized and validly issued, are fully paid and non-assessable, conform to the description thereof contained in the most recent Preliminary Prospectus and are not subject to any preemptive right, resale right, right of first refusal or similar right. No options, warrants or other rights to purchase or exchange any securities for shares of the Company’s capital stock are outstanding. All of the issued shares of capital stock or other equity interests of each Significant Subsidiary of the Company have been duly authorized and validly issued, are fully paid and non-assessable and are owned directly or indirectly by the Company (except as set forth in the most recent Preliminary Prospectus), free and clear of all liens, encumbrances, equities or claims, except for such liens, encumbrances, equities or claims as would not, in the aggregate, reasonably be expected to have a Material Adverse Effect.
     (k) The shares of the Stock to be issued and sold by the Company to the Underwriters hereunder have been duly authorized and, upon payment and delivery in accordance with this Agreement, will be validly issued, fully paid and non-assessable, will conform to the description thereof contained in the most recent Preliminary Prospectus and will be free of statutory and contractual preemptive rights, rights of first refusal and similar rights.
     (l) The Company has all requisite corporate power and authority to execute, deliver and perform its obligations under this Agreement. This Agreement has been duly and validly authorized, executed and delivered by the Company.
     (m) The Company has all requisite corporate power and authority to execute, deliver and perform its obligations under (i) that certain Separation and Distribution Agreement by and between Parent and the Company (the “ Separation and Distribution Agreement ”), (ii) that certain Administrative Services Agreement by and between Parent and the Company (the “ Administrative Services Agreement ”), (iii) that certain Transition Services Agreement by and between Parent and the Company (the “ Transition Services Agreement ”), (iv) that certain Registration Rights Agreement by and between Parent and the Company (the “ Registration Rights Agreement ”), and (v) that certain Tax Sharing Agreement by and between Parent and the Company (the “ Tax Sharing Agreement ,” and collectively with the Separation and Distribution Agreement, the Administrative Services Agreement, the Transition Services Agreement and the Registration Rights Agreement, the “ Separation Agreements ”). Each of the Separation Agreements has been duly and validly authorized by the Company and, assuming due authorization, execution and delivery by each of the other parties thereto, upon execution and delivery by the Company will constitute a valid and legally binding agreement of the Company, enforceable against the Company in accordance with its terms, except as such

 

 6 
enforceability may be limited by bankruptcy, insolvency, fraudulent transfer, reorganization, moratorium and other similar laws relating to or affecting creditor’s rights generally, by general equitable principles (regardless of whether such enforceability is considered in a proceeding in equity or at law) and, as to rights of indemnification and contribution, by federal or state securities law or principles of public policy.
     (n) The issue and sale of the Stock, the execution, delivery and performance of this Agreement and each of the Separation Agreements by the Company, the consummation of the transactions contemplated hereby and thereby (including the Restructuring Transactions), the application of the proceeds from the sale of the Stock as described under “Use of Proceeds” in the most recent Preliminary Prospectus will not (i) conflict with or result in a breach or violation of any of the terms or provisions of, impose any lien, charge or encumbrance upon any property or assets of the Company and its Significant Subsidiaries under, or constitute a default under, any indenture, mortgage, deed of trust, loan agreement, license, lease or other agreement or instrument to which the Company or any of its Significant Subsidiaries is a party or by which the Company or any of its Significant Subsidiaries is bound or to which any of the property or assets of the Company or any of its Significant Subsidiaries is subject; (ii) result in any violation of the provisions of the charter or by-laws (or similar organizational documents) of the Company or any of its Significant Subsidiaries; or (iii) result in any violation of any statute or any judgment, order, decree, rule or regulation of any court or governmental agency or body having jurisdiction over the Company or any of its Significant Subsidiaries or any of their properties or assets, except with respect to clauses (i) and (iii), conflicts, breaches, violations or defaults that would not, individually or in the aggregate, reasonably be expected to have a Material Adverse Effect.
     (o) No consent, approval, authorization or order of, or filing, registration or qualification with, any court or governmental agency or body having jurisdiction over the Company or any of its Significant Subsidiaries or any of their properties or assets is required for the issue and sale of the Stock, the execution, delivery and performance of this Agreement and each of the Separation Agreements by the Company, the consummation of the transactions contemplated hereby and thereby (including the Restructuring Transactions), and the application of the proceeds from the sale of the Stock as described under “Use of Proceeds” in the most recent Preliminary Prospectus, (A) except in each case for (i) the registration of the Stock under the Securities Act and the Exchange Act; (ii) the registration under the Securities Act of Common Stock held by Parent following this offering pursuant to the Registration Rights Agreement; (iii) such consents, approvals, authorizations, orders, filings, registrations or qualifications as may be required by the Financial Industry Regulatory Authority, Inc. (“ FINRA ”) or under applicable state securities laws in connection with the purchase and sale of the Stock by the Underwriters; and (iv) such filings as may be required by the Exchange Act; and (B) except where, with respect to the Separation and Distribution Agreement, the failure to obtain such consents, approvals, authorizations, orders, filings, registrations or qualifications would not reasonably be expected to have a Material Adverse Effect.
     (p) The historical financial statements (including the related notes and supporting schedules) included in the most recent Preliminary Prospectus comply as to

 

 7 
form in all material respects with the requirements of Regulation S-X under the Securities Act and present fairly in all material respects the financial condition, results of operations and cash flows of the combined businesses purported to be shown thereby at the dates and for the periods indicated and have been prepared in conformity with accounting principles generally accepted in the United States applied on a consistent basis throughout the periods involved (subject, in the case of unaudited interim statements, to normal and recurring adjustments and the absence of certain notes that are included in an annual filing).
     (q) The unaudited pro forma financial statements included in the most recent Preliminary Prospectus include assumptions that provide a reasonable basis for presenting the significant effects directly attributable to the transactions and events described therein, the related pro forma adjustments give appropriate effect to those assumptions, and the pro forma adjustments reflect the proper application of those adjustments to the historical financial statement amounts in the unaudited pro forma financial statements included in the most recent Preliminary Prospectus. The unaudited pro forma financial statements included in the most recent Preliminary Prospectus comply as to form in all material respects with the applicable requirements of Regulation S-X under the Act.
     (r) Ernst & Young LLP, who have certified the audited financial statements of the Company included in the most recent Preliminary Prospectus, whose report appears in the most recent Preliminary Prospectus and who have delivered the initial letter referred to in Section 8(h) hereof, are independent public accountants as required by the Securities Act and the rules and regulations thereunder.
     (s) The Company maintains a system of internal control over financial reporting (as such term is defined in Rule 13a-15(f) of the Exchange Act) that complies with the requirements of the Exchange Act and that has been designed by, or under the supervision of, the Company’s principal executive and principal financial officers, or persons performing similar functions, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles in the United States. The Company maintains internal accounting controls sufficient to provide reasonable assurance that (i) transactions are executed in accordance with management’s general or specific authorization, (ii) transactions are recorded as necessary to permit preparation of the Company’s financial statements in conformity with accounting principles generally accepted in the United States and to maintain accountability for its assets, and (iii) access to the Company’s assets is permitted only in accordance with management’s general or specific authorization. As of the date of the most recent balance sheet of the Company reviewed or audited by Ernst & Young LLP and the audit committee of the board of directors of the Company, there were no material weaknesses in the Company’s internal controls, except as disclosed in the Preliminary Prospectus and the Prospectus.
     (t) (i) The Company maintains disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act), (ii) such

 

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disclosure controls and procedures are designed to ensure that information required to be disclosed by the Company in the reports it files or submits under the Exchange Act is accumulated and communicated to management of the Company, including its principal executive officers and principal financial officers, as appropriate, to allow timely decisions regarding required disclosure and (iii) except with respect to the material weaknesses in internal controls disclosed in the Preliminary Prospectus and the Prospectus, such disclosure controls and procedures are effective at a reasonable assurance level to perform the functions for which they were established.
     (u) Except as disclosed in the most recent preliminary prospectus, since the date of the most recent balance sheet of the Company reviewed or audited by Ernst & Young LLP and the audit committee of the board of directors of the Company, (i) the Company has not been advised of or become aware of (A) any significant deficiencies in the design or operation of internal controls that could adversely affect the ability of the Company or any of its subsidiaries to record, process, summarize and report financial data, or any material weaknesses in internal controls, and (B) any fraud, whether or not material, that involves management or other employees who have a significant role in the internal controls of the Company and each of its subsidiaries; and (ii) there have been no significant changes in internal controls or in other factors that could significantly affect internal controls, including any corrective actions with regard to significant deficiencies and material weaknesses.
     (v) The Company is in compliance in all material respects with the applicable provisions of the Sarbanes-Oxley Act of 2002 and the rules and regulations promulgated in connection therewith.
     (w) Since the date of the latest audited financial statements included in the most recent Preliminary Prospectus, neither the Company nor any of its Significant Subsidiaries has sustained any loss or interference with its business from fire, explosion, flood or other calamity, whether or not covered by insurance, or from any labor dispute or court or governmental action, order or decree, or incurred any material liability or obligation, direct or contingent, other than liabilities and obligations that were incurred in the ordinary course of business, which would be reasonably likely to result in any Material Adverse Effect, or any development involving a material adverse change in or affecting the financial condition, results of operations, business or prospects of the Company and its subsidiaries taken as a whole, otherwise than as disclosed in the Pricing Disclosure Package and the Prospectus. Since the respective dates as of which information is given in the Pricing Disclosure Package and the Prospectus or since the date of the Pricing Disclosure Package, there has not been (i) any change in the capital stock or long-term debt of the Company or its Significant Subsidiaries (taken as a whole), (ii) any material adverse change in or affecting the financial condition, results of operations, business or prospects of the Company or its Significant Subsidiaries (taken as a whole), or (iii) any transaction entered into by any of the Company or its Significant Subsidiaries, other than in the ordinary course of business, that is material to the Company or its Significant Subsidiaries (taken as a whole) other than as disclosed, in the case of each of (i), (ii) or (iii) above, in the Pricing Disclosure Package and the Prospectus (exclusive of any amendment or supplement thereto).

 

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     (x) Except as described in the most recent Preliminary Prospectus, the Company, directly or indirectly through its subsidiaries, has good and marketable title to all real property and good title to all personal property described in the Pricing Disclosure Package and the Prospectus as being owned by it and valid, legal and defensible title to the interests in oil and gas properties underlying the estimates of the Company’s proved reserves described in the Pricing Disclosure Package, in each case free and clear of all liens, encumbrances and defects except (i) as are described in the most recent Preliminary Prospectus and the Prospectus, (ii) as do not materially interfere with the use made in the aggregate of such properties, as described in the most recent Preliminary Prospectus and the Prospectus, (iii) as are permitted under the Company’s Credit Agreement dated as of June 3, 2011, or (iv) as would not reasonably be expected to have a Material Adverse Effect; and the working interests derived from oil, gas and mineral leases or mineral interests which constitute a portion of the real property held or leased by the Company and its subsidiaries reflect in all material respects the right of the Company and its subsidiaries to explore, develop or produce hydrocarbons from such real property, and the care taken by the Company and its subsidiaries with respect to acquiring or otherwise procuring such leases or mineral interests was generally consistent with standard industry practices in the areas in which the Company and its subsidiaries operate for acquiring or procuring leases and interests therein to explore, develop or produce hydrocarbons.
     (y) The Company and each of its Significant Subsidiaries have such permits, licenses, patents, franchises, certificates of need and other approvals or authorizations of governmental or regulatory authorities (“ Permits ”) as are necessary under applicable law to own, hold or lease, as the case may be, and to operate their properties and conduct their businesses in the manner described in the most recent Preliminary Prospectus, except where the failure to possess such Permits would not reasonably be expected to have a Material Adverse Effect. Neither the Company nor any of its Significant Subsidiaries has received notice of any revocation or modification of any such Permits except to the extent that any such revocation or modification would not have a Material Adverse Effect.
     (z) The Company and each of its Significant Subsidiaries own, possess, or can acquire on reasonable terms, adequate rights to use all material patents, patent applications, trademarks, service marks, trade names, trademark registrations, service mark registrations, copyrights, licenses and know-how (including trade secrets and other unpatented and/or unpatentable proprietary or confidential information, systems or procedures) necessary for the conduct of their respective businesses as described in the most recent Preliminary Prospectus and have no reason to believe that the conduct of their respective businesses will conflict with, and have not received any notice of any claim of conflict with, any such rights of others that, if determined adversely to the Company or any of its Significant Subsidiaries, would reasonably be expected to have a Material Adverse Effect.
     (aa) Except as described in the most recent Preliminary Prospectus, there are no legal or governmental proceedings pending to which the Company or any of its subsidiaries is a party or of which any property or assets of the Company or any of its subsidiaries is the subject that would, in the aggregate, reasonably be expected to have a Material Adverse Effect or would, in the aggregate, reasonably be expected to have a

 

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material adverse effect on the performance of this Agreement or each of the Separation Agreements or the consummation of the transactions contemplated hereby and thereby; and to the Company’s knowledge, no such proceedings are threatened or contemplated by governmental authorities or others.
     (bb) The statements made in the most recent Preliminary Prospectus and the Prospectus under the captions “Business—Environmental Matters and Regulation;” “Business—Other Regulation of the Oil and Gas Industry;” “Business—Legal Proceedings;” “Arrangements Between Williams and Our Company;” “Other Related Party Transactions;” “Description of Our Concurrent Financing Transactions;” “Description of Capital Stock;” and “Certain U.S. Federal Income Tax Considerations,” insofar as they purport to constitute summaries of the terms of statutes, rules or regulations, legal or governmental proceedings or contracts and other documents, constitute accurate summaries of the terms of such statutes, rules and regulations, legal and governmental proceedings and contracts and other documents in all material respects.
     (cc) The Company and each of its Significant Subsidiaries carry, or are covered by, insurance in such amounts and covering such risks as is reasonable in accordance with customary practices for companies engaged in similar businesses in similar industries for the conduct of their respective businesses and the value of their respective properties.
     (dd) No labor disturbance by or dispute with the employees of the Company or any of its affiliates that are dedicated to the Company’s business exists or, to the knowledge of the Company, is imminent that would reasonably be expected to have a Material Adverse Effect.
     (ee) Neither the Company nor any of its Significant Subsidiaries (i) is in violation of its charter or by-laws (or similar organizational documents), (ii) is in default, and no event has occurred that, with notice or lapse of time or both, would constitute such a default, in the due performance or observance of any term, covenant, condition or other obligation contained in any indenture, mortgage, deed of trust, loan agreement, license or other agreement or instrument to which it is a party or by which it is bound or to which any of its properties or assets is subject, or (iii) is in violation of any statute or any order, rule or regulation of any court or governmental agency or body having jurisdiction over it or its property or assets or has failed to obtain any license, permit, certificate, franchise or other governmental authorization or permit necessary to the ownership of its property or to the conduct of its business, except in the case of clauses (ii) and (iii), to the extent any such conflict, breach, violation or default would not, in the aggregate, reasonably be expected to have a Material Adverse Effect.
     (ff) The Company and each of its Significant Subsidiaries (i) are in compliance with all laws, regulations, ordinances, rules, orders, judgments, decrees, permits or other legal requirements of any governmental authority, including without limitation any international, foreign, national, state, provincial, regional, or local authority, relating to pollution, the protection of human health or safety, the environment, or natural resources, or to use, handling, storage, manufacturing, transportation,

 

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treatment, discharge, disposal or release of hazardous or toxic substances or wastes, pollutants or contaminants (“ Environmental Laws ”) applicable to such entity, which compliance includes, without limitation, obtaining, maintaining and complying with all permits and authorizations and approvals required by Environmental Laws to conduct their respective businesses, and (ii) have not received notice or otherwise have knowledge of any actual or alleged violation of Environmental Laws, or of any actual or potential liability for or other obligation concerning the presence, disposal or release of hazardous or toxic substances or wastes, pollutants or contaminants, except, with respect to (i) and (ii), as may be disclosed in the Pricing Disclosure Package and the Prospectus and except where such noncompliance with Environmental Laws, failure to obtain or maintain required permits, authorizations or approvals or failure to comply with the terms and conditions of such permits, authorizations or approvals would not be reasonably likely to have a Material Adverse Effect.
     (gg) The Company and all of its subsidiaries have filed all federal, state, local and foreign income and franchise tax returns which are required to be filed by them and have paid all taxes due, other than those which, if not filed or paid, would not be reasonably expected to have a Material Adverse Effect, or which are being contested in good faith by appropriate proceedings. Except as would not be reasonably expected to have a Material Adverse Effect, no tax deficiency has been determined adversely to the Company or any of its subsidiaries, and the Company has no knowledge of any tax deficiencies that have been, or would reasonably be expected to be asserted.
     (hh) Except to the extent that a breach of any of the following representations would not reasonably be expected to result in a Material Adverse Effect: (i) any “employee benefit plan” (within the meaning of Section 3(3) of the Employee Retirement Security Act of 1974, as amended (“ ERISA ”)) established or maintained by the Company or any of its subsidiaries are in compliance in all material respects with applicable law, including ERISA and the Internal Revenue Code of 1986, as amended (the “Code”), and, to the knowledge of the Company, each “multiemployer plan” (as defined in Section 4001 of ERISA) to which the Company or any of its subsidiaries contributes (a “Multiemployer Plan”) is in compliance with applicable law, including ERISA and the Code; (ii) with respect to any “employee benefit plan” which is subject to Title IV of ERISA or Section 412 of the Code or Section 302 of ERISA and established or maintained by the Company or any of its subsidiaries or any ERISA Affiliate (as defined below), (A) no “reportable event” (as defined under Section 4043(c) of ERISA and the regulations issued thereunder) has occurred or is reasonably expected to occur, (B) no failure to meet the minimum funding requirements of Sections 412 and 430 of the Code or Sections 302 and 303 of ERISA, whether or not waived, or to make by its due date a required installment under Section 430(j) of the Code or Section 303(j) of ERISA by the Company or any of its subsidiaries or any ERISA Affiliate has occurred or is reasonably expected to occur, and (C) no such “employee benefit plan,” if terminated, would have any “amount of unfunded benefit liabilities” (as defined under Section 4001(a)(18) of ERISA); (iii) none of the Company or any of its subsidiaries or any ERISA Affiliate has incurred or reasonably expects to incur any liability under (A) Title IV of ERISA with respect to termination of, or withdrawal from, any “employee benefit plan” or (B) Sections 412, 4971, 4975 or 4980B of the Code; (iv) no “employee benefit plan”

 

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established or maintained by the Company or any of its subsidiaries provides health or welfare benefits for any retired or former employee of the Company or any of its subsidiaries except to the extent required under Section 4980B of the Code or similar state laws and (v) each “employee benefit plan” established or maintained by the Company or any of its subsidiaries that is intended to be qualified under Section 401 of the Code is so qualified and nothing has occurred, whether by action or failure to act, which would be reasonably likely to cause the loss of such qualification. “ERISA Affiliate” means, with respect to the Company, any trade or business (whether or not incorporated) under common control with the Company within the meaning of Section 414(b) or (c) of the Code and Sections 414(m) and (o) of the Code for purposes of provisions relating to Section 412 of the Code.
     (ii) The statistical and market-related data included in the most recent Preliminary Prospectus is based on or derived from sources that the Company believes to be reliable in all material respects.
     (jj) The Company is not, and as of the applicable Delivery Date and, after giving effect to the offer and sale of the Stock and the application of the proceeds therefrom as described under “Use of Proceeds” in the most recent Preliminary Prospectus and the Prospectus, will not be, an “investment company” within the meaning of the Investment Company Act of 1940, as amended, and the rules and regulations of the Commission thereunder.
     (kk) Netherland Sewell & Associates, Inc., who issued an audit report with respect to certain of the Company’s oil and natural gas reserves and who has delivered the letter referred to in Section 8(i) hereof, was, as of the date of such report, and is, as of the date hereof, an independent petroleum engineer with respect to the Company.
     (ll) Miller and Lents, Ltd., who issued an audit report with respect to certain of the Company’s oil and natural gas reserves, was, as of the date of such report, and is, as of the date hereof, an independent petroleum engineer with respect to the Company.
     (mm) Ralph E. Davis Associates, Inc., who issued an audit report with respect to the oil and natural gas reserves of Apco Oil and Gas International Inc., a Cayman Islands corporation (“ Apco ”), was, as of the date of such report, and is, as of the date hereof, an independent petroleum engineer with respect to the Company and Apco.
     (nn) The factual information underlying the estimates of reserves of the Company, which was supplied to the Company’s independent petroleum engineers for the purposes of preparing the audit reports of the estimates of proved reserves included in the Pricing Disclosure Package and the Prospectus, including, without limitation, production, costs of operation and development, current prices for production, agreements relating to current and future operations and sales of production, was true and correct in all material respects on the dates such estimates were made and such information was supplied and was prepared in accordance with customary industry practices; other than normal production of the reserves, intervening market commodity price fluctuations, fluctuations in demand for such products, adverse weather conditions,

 

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unavailability or increased costs of rigs, equipment, supplies or personnel, the timing of third party operations and other factors, in each case in the ordinary course of business, the Company is not aware of any facts or circumstances that would result in a material adverse change in the aggregate net reserves, or the present value of future net cash flows therefrom, as described in the Pricing Disclosure Package and the Prospectus; estimates of such reserves and present values as described in the Pricing Disclosure Package and the Prospectus comply in all material respects with the applicable requirements of Regulation S-X and Subpart 1200 of Regulation S-K under the Securities Act.
     (oo) Except for the Registration Rights Agreement between the Company and Parent, and except as described in the most recent Preliminary Prospectus, there are no contracts, agreements or understandings between the Company and any person granting such person the right to require the Company to file a registration statement under the Securities Act with respect to any securities of the Company owned or to be owned by such person or to require the Company to include such securities in the securities registered pursuant to the Registration Statement.
     (pp) Neither the Company nor any of its subsidiaries is a party to any contract, agreement or understanding with any person (other than this Agreement) that would give rise to a valid claim against any of them or the Underwriters for a brokerage commission, finder’s fee or like payment in connection with the offering and sale of the Stock.
     (qq) The Company has not sold or issued any securities that would reasonably be expected to be integrated with the offering of the Stock contemplated by this Agreement pursuant to the Securities Act, the rules and regulations thereunder or the interpretations thereof by the Commission.
     (rr) The Company and its affiliates have not taken, directly or indirectly, any action designed to or that has constituted or that could reasonably be expected to cause or result in the stabilization or manipulation of the price of any security of the Company in connection with the offering of the shares of the Stock.
     (ss) Neither the Company nor any of its subsidiaries, nor, to the knowledge of the Company, any director, officer, agent, employee or other person associated with or acting on behalf of the Company or any of its subsidiaries, has (i) used any corporate funds for any unlawful contribution, gift, entertainment or other unlawful expense relating to political activity; (ii) made any direct or indirect unlawful payment to any foreign or domestic government official or employee from corporate funds; (iii) violated or is in violation of any provision of the U.S. Foreign Corrupt Practices Act of 1977; or (iv) made any bribe, rebate, payoff, influence payment, kickback or other unlawful payment.
     (tt) The operations of the Company and its subsidiaries are and have been conducted at all times in compliance with applicable financial recordkeeping and reporting requirements of the Currency and Foreign Transactions Reporting Act of 1970, as amended, the applicable money laundering statutes of any other jurisdiction to which the Company is subject, the rules and regulations thereunder and any related or similar

 

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rules, regulations or guidelines, issued, administered or enforced by any governmental agency (collectively, the “ Money Laundering Laws ”) and no action, suit or proceeding by or before any court or governmental agency, authority or body or any arbitrator involving the Company or any of its subsidiaries with respect to the Money Laundering Laws is pending or, to the knowledge of the Company, threatened.
     (uu) Neither the Company nor any of its subsidiaries nor, to the knowledge of the Company, any director, officer, agent, employee or affiliate of the Company or any of its subsidiaries is currently subject to any U.S. sanctions administered by the Office of Foreign Assets Control of the U.S. Treasury Department (“ OFAC ”); and the Company will not, directly or indirectly, use the proceeds of the offering, or lend, contribute or otherwise make available such proceeds to any subsidiary, joint venture partner or other person or entity, for the purpose of financing the activities of any person currently subject to any U.S. sanctions administered by OFAC.
     (vv) None of the Directed Shares distributed in connection with the Directed Share Program (each as defined in Section 4) will be offered or sold outside of the United States.
     (ww) The Company has offered, or caused Barclays Capital Inc. to offer, Stock pursuant to the Directed Share Program only to employees or directors of the Company or its affiliates.
          Any certificate signed by any officer of the Company and delivered to the Representatives or counsel for the Underwriters in connection with the offering of the Stock shall be deemed a representation and warranty by the Company, as to matters covered thereby, to each Underwriter.
          2. Representations, Warranties and Agreements of Parent . Parent represents, warrants and agrees that:
     (a) To the best of Parent’s knowledge, the representations and warranties of the Company contained in Sections 1(a), 1(b), 1(c), 1(d), 1(e), 1(f), 1(g), 1(h), 1(w), 1(x), 1(y), and 1(nn) of this Agreement are true and correct.
     (b) Parent has been duly organized, is validly existing and in good standing as a corporation or other business entity under the laws of its jurisdiction of organization.
     (c) Parent has all requisite corporate power and authority to execute, deliver and perform its obligations under this Agreement. This Agreement has been duly and validly authorized, executed and delivered by Parent.
     (d) Parent has all requisite corporate power and authority to execute, deliver and perform its obligations under the Separation Agreements. Each of the Separation Agreements has been duly and validly authorized by Parent and, assuming due authorization, execution and delivery by each of the other parties thereto, upon execution and delivery by Parent will constitute a valid and legally binding agreement of Parent, enforceable against Parent in accordance with its terms, except as such enforceability

 

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may be limited by bankruptcy, insolvency, fraudulent transfer, reorganization, moratorium and other similar laws relating to or affecting creditor’s rights generally, by general equitable principles (regardless of whether such enforceability is considered in a proceeding in equity or at law) and, as to rights of indemnification and contribution, by federal or state securities law or principles of public policy.
     (e) The issue and sale of the Stock, the execution, delivery and performance of this Agreement and each of the Separation Agreements by Parent, the consummation of the transactions contemplated hereby and thereby and the application of the proceeds from the sale of the Stock as described under “Use of Proceeds” in the most recent Preliminary Prospectus and the Restructuring Transactions will not (i) conflict with or result in a breach or violation of any of the terms or provisions of, impose any lien, charge or encumbrance upon any property or assets of Parent, or constitute a default under, any indenture, mortgage, deed of trust, loan agreement, license, lease or other agreement or instrument to which Parent is a party or by which Parent is bound or to which any of the property or assets of Parent is subject; (ii) result in any violation of the provisions of the charter or by-laws (or similar organizational documents) of Parent; or (iii) result in any violation of any statute or any judgment, order, decree, rule or regulation of any court or governmental agency or body having jurisdiction over Parent or any of its properties or assets, except with respect to clauses (i) and (iii), conflicts, breaches, violations or defaults that would not, individually or in the aggregate, reasonably be expected to materially and adversely affect the power or ability of Parent to perform its obligations under this Agreement or to consummate the transactions contemplated by the Separation Agreements.
     (f) No consent, approval, authorization or order of, or filing, registration or qualification with, any court or governmental agency or body having jurisdiction over Parent or any of its properties or assets is required for the issue and sale of the Stock, the execution, delivery and performance of this Agreement and each of the Separation Agreements by Parent, the consummation of the transactions contemplated hereby and thereby (including the Restructuring Transactions), and the application of the proceeds from the sale of the Stock as described under “Use of Proceeds” in the most recent Preliminary Prospectus, (A) except in each case for (i) the registration of the Stock under the Securities Act and the Exchange Act; (ii) the registration under the Securities Act of Common Stock held by Parent following this offering pursuant to the Registration Rights Agreement; (iii) such consents, approvals, authorizations, orders, filings, registrations or qualifications as may be required by FINRA or under applicable state securities laws in connection with the purchase and sale of the Stock by the Underwriters; and (iv) such filings as may be required by the Exchange Act; and (B) except where, with respect to the Separation and Distribution Agreement, such consents, approvals, authorizations, orders, filings, registrations or qualifications would not reasonably be expected have a Material Adverse Effect.
          3. Purchase of the Stock by the Underwriters. On the basis of the representations, warranties and covenants contained in, and subject to the terms and conditions of, this Agreement, the Company agrees to sell            shares of Firm Stock to the several Underwriters, and each of the Underwriters, severally and not jointly, agrees to purchase the

 

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number of shares of Firm Stock set forth opposite that Underwriter’s name in Schedule I hereto. The respective purchase obligations of the Underwriters with respect to the Firm Stock shall be rounded among the Underwriters to avoid fractional shares, as the Representatives may determine.
          In addition, the Company grants to the Underwriters an option to purchase up to                     additional shares of Option Stock. Such option is exercisable in the event that the Underwriters sell more shares of Class A Common Stock than the number of shares of Firm Stock in the offering and as set forth in Section 5 hereof. Each Underwriter agrees, severally and not jointly, to purchase the number of shares of Option Stock (subject to such adjustments to eliminate fractional shares as the Representatives may determine) that bears the same proportion to the total number of shares of Option Stock to be sold on such Delivery Date as the number of shares of Firm Stock set forth in Schedule I hereto opposite the name of such Underwriter bears to the total number of shares of Firm Stock. Any shares of Option Stock purchased by the Underwriters pursuant to the option described in this Section 3 will not increase the total number of shares of Common Stock outstanding after the offering of the Firm Stock, but rather the number of shares of Class B Common Stock owned by Parent will be reduced share for share by the number of shares of Option Stock purchased by the Underwriters pursuant to such option.
          The purchase price payable by the Underwriters for the Firm Stock is $  per share and any Option Stock is $  per share, less an amount per share equal to any dividends or distributions declared by the Company and payable on the Firm Stock but not payable on the Option Stock.
          The Company is not obligated to deliver any of the Firm Stock or Option Stock to be delivered on the applicable Delivery Date, except upon payment for all such Stock to be purchased on such Delivery Date as provided herein.
          4. Offering of Stock by the Underwriters . Upon authorization by the Representatives of the release of the Firm Stock, the several Underwriters propose to offer the Firm Stock for sale upon the terms and conditions to be set forth in the Prospectus.
          It is understood that approximately            shares of Firm Stock (the “ Directed Shares ”) will initially be reserved by the several Underwriters for offer and sale upon the terms and conditions to be set forth in the most recent Preliminary Prospectus and in accordance with the rules and regulations of FINRA to employees of the Company and its subsidiaries and affiliates who have heretofore delivered to Barclays Capital Inc. offers to purchase shares of Firm Stock in form reasonably satisfactory to Barclays Capital Inc. (such program, the “ Directed Share Program ”) and that any allocation of such Firm Stock among such persons will be made in accordance with timely directions received by Barclays Capital Inc. from the Company; provided that under no circumstances will Barclays Capital Inc. or any Underwriter be liable to the Company or to any such person for any action taken or omitted in good faith in connection with such Directed Share Program. It is further understood that any Directed Shares not affirmatively reconfirmed for purchase by any participant in the Directed Share Program by :00 A.M., New York City time, on the first business day following the date hereof or otherwise are not purchased by such persons will be offered by the Underwriters to the public upon the terms and conditions set forth in the Prospectus.
          The Company agrees to pay all reasonable fees and disbursements incurred by the Underwriters in connection with the Directed Share Program and any stamp duties or other taxes incurred by the Underwriters in connection with the Directed Share Program.

 

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          5. Delivery of and Payment for the Stock. Delivery of and payment for the Firm Stock shall be made at the offices of Latham & Watkins LLP, 717 Texas Ave., Houston, Texas 77002 at 10:00 A.M., New York City time, on the fourth full business day following the date of this Agreement or at such other date or place as shall be determined by agreement between the Representatives and the Company. This date and time are sometimes referred to as the “ Initial Delivery Date .” Delivery of the Firm Stock shall be made to the Representatives for the account of each Underwriter against payment by the several Underwriters through the Representatives and of the respective aggregate purchase prices of the Firm Stock being sold by the Company to or upon the order of the Company of the purchase price by wire transfer in immediately available funds to the accounts specified by the Company. Time shall be of the essence, and delivery at the time and place specified pursuant to this Agreement is a further condition of the obligation of each Underwriter hereunder. The Company shall deliver the Firm Stock through the facilities of The Depository Trust Company (“ DTC ”) unless the Representatives shall otherwise instruct.
          The option granted in Section 3 will expire 30 days after the date of this Agreement and may be exercised in whole or from time to time in part by written notice being given to the Company by the Representatives; provided that if such date falls on a day that is not a business day, the option granted in Section 3 will expire on the next succeeding business day. Such notice shall set forth the aggregate number of shares of Option Stock as to which the option is being exercised, the names in which the shares of Option Stock are to be registered, the denominations in which the shares of Option Stock are to be issued and the date and time, as determined by the Representatives, when the shares of Option Stock are to be delivered; provided, however , that this date and time shall not be earlier than the Initial Delivery Date nor later than the fifth business day after the date on which the option shall have been exercised. Each date and time the shares of Option Stock are delivered is sometimes referred to as an “ Option Stock Delivery Date ”, and the Initial Delivery Date and any Option Stock Delivery Date are sometimes each referred to as a " Delivery Date .”
          Delivery of the Option Stock by the Company and payment for the Option Stock by the several Underwriters through the Representatives shall be made at 10:00 A.M., New York City time, on the date specified in the corresponding notice described in the preceding paragraph or at such other date or place as shall be determined by agreement between the Representatives and the Company. On the Option Stock Delivery Date, the Company shall deliver or cause to be delivered the Option Stock to the Representatives for the account of each Underwriter against payment by the several Underwriters through the Representatives and of the respective aggregate purchase prices of the Option Stock being sold by the Company to or upon the order of the Company of the purchase price by wire transfer in immediately available funds to the accounts specified by the Company. Time shall be of the essence, and delivery at the time and place specified pursuant to this Agreement is a further condition of the obligation of each Underwriter hereunder. The Company shall deliver the Option Stock through the facilities of DTC unless the Representatives shall otherwise instruct.
          6. Further Agreements of Parent, the Company and the Underwriters . (a) The Company agrees (and in the case of Section 6(a)(x), Parent and the Company agree):
     (i) To prepare the Prospectus in a form approved by the Representatives and to file such Prospectus pursuant to Rule 424(b) under

 

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the Securities Act not later than the Commission’s close of business on the second business day following the execution and delivery of this Agreement; to make no further amendment or any supplement to the Registration Statement or the Prospectus prior to the last Delivery Date except as provided herein; to advise the Representatives, promptly after it receives notice thereof, of the time when any amendment or supplement to the Registration Statement or the Prospectus has been filed and to furnish the Representatives with copies thereof; to advise the Representatives, promptly after it receives notice thereof, of the issuance by the Commission of any stop order or of any order preventing or suspending the use of the Prospectus or any Issuer Free Writing Prospectus, of the suspension of the qualification of the Stock for offering or sale in any jurisdiction, of the initiation or threatening of any proceeding or examination for any such purpose or of any request by the Commission for the amending or supplementing of the Registration Statement, the Prospectus or any Issuer Free Writing Prospectus or for additional information; and, in the event of the issuance of any stop order or of any order preventing or suspending the use of the Prospectus or any Issuer Free Writing Prospectus or suspending any such qualification, to use promptly its best efforts to obtain its withdrawal.
     (ii) To furnish promptly to each of the Representatives and to counsel for the Underwriters a signed copy of the Registration Statement as originally filed with the Commission, and each amendment thereto filed with the Commission, including all consents and exhibits filed therewith.
     (iii) To deliver promptly to the Representatives such number of the following documents as the Representatives shall reasonably request: (A) conformed copies of the Registration Statement as originally filed with the Commission and each amendment thereto (in each case excluding exhibits other than this Agreement and the computation of per share earnings), (B) each Preliminary Prospectus, the Prospectus and any amended or supplemented Prospectus, and (C) each Issuer Free Writing Prospectus; and, if the delivery of a prospectus is required at any time after the date hereof in connection with the offering or sale of the Stock or any other securities relating thereto and if at such time any events shall have occurred as a result of which the Prospectus as then amended or supplemented would include an untrue statement of a material fact or omit to state any material fact necessary in order to make the statements therein, in the light of the circumstances under which they were made when such Prospectus is delivered, not misleading, or, if for any other reason it shall be necessary to amend or supplement the Prospectus in order to comply with the Securities Act, to notify the Representatives and, upon their request, to file such document and to prepare and furnish without charge to each Underwriter and to any dealer in securities as many copies as the Representatives may from time to time reasonably request of

 

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an amended or supplemented Prospectus that will correct such statement or omission or effect such compliance.
     (iv) To file promptly with the Commission any amendment or supplement to the Registration Statement or the Prospectus that may, in the reasonable judgment of the Company or the Representatives, be required by the Securities Act or requested by the Commission.
     (v) Prior to filing with the Commission any amendment or supplement to the Registration Statement or the Prospectus, to furnish a copy thereof to the Representatives and counsel for the Underwriters and obtain the consent of the Representatives to the filing, which consent shall not be unreasonably withheld or delayed; provided that, the foregoing provision shall not apply if such filing is, in the written opinion of counsel to the Company, required by law.
     (vi) Not to make any offer relating to the Stock that would constitute an Issuer Free Writing Prospectus without the prior written consent of the Representatives.
     (vii) To comply with all applicable requirements of Rule 433 under the Securities Act with respect to any Issuer Free Writing Prospectus. If at any time after the date hereof any events shall have occurred as a result of which any Issuer Free Writing Prospectus, as then amended or supplemented, would conflict with the information in the Registration Statement, the most recent Preliminary Prospectus or the Prospectus or would include an untrue statement of a material fact or omit to state any material fact necessary in order to make the statements therein, in the light of the circumstances under which they were made, not misleading, or, if for any other reason it shall be necessary to amend or supplement any Issuer Free Writing Prospectus, to notify the Representatives and, upon their request, to file such document and to prepare and furnish without charge to each Underwriter as many copies as the Representatives may from time to time reasonably request of an amended or supplemented Issuer Free Writing Prospectus that will correct such conflict, statement or omission or effect such compliance.
     (viii) As soon as practicable after the Effective Date (it being understood that the Company shall have until at least 410 days or, if the fourth quarter following the fiscal quarter that includes the Effective Date is the last fiscal quarter of the Company’s fiscal year, 455 days after the end of the Company’s current fiscal quarter), to make generally available via the Commission’s Electronic Data Gathering, Analysis and Retrieval System, to the Company’s security holders and to the Representatives an earnings statement of the Company and its subsidiaries (which need not be audited) complying with Section 11(a) of the Securities Act and the rules

 

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and regulations thereunder (including, at the option of the Company, Rule 158).
     (ix) Promptly from time to time to take such action as the Representatives may reasonably request to qualify the Stock for offering and sale under the securities or Blue Sky laws of Canada and such other jurisdictions as the Representatives may request and to comply with such laws so as to permit the continuance of sales and dealings therein in such jurisdictions for as long as may be necessary to complete the distribution of the Stock; provided that in connection therewith the Company shall not be required to (i) qualify as a foreign corporation in any jurisdiction in which it would not otherwise be required to so qualify, (ii) file a general consent to service of process in any such jurisdiction, or (iii) subject itself to taxation in any jurisdiction in which it would not otherwise be subject.
     (x) For a period commencing on the date hereof and ending on the 180th day after the date of the Prospectus (the “ Lock-Up Period ”), not to, directly or indirectly, (A) offer for sale, sell, pledge, or otherwise dispose of (or enter into any transaction or device that is designed to, or could be expected to, result in the disposition by any person at any time in the future of) any shares of Class A Common Stock or securities convertible into or exercisable or exchangeable for Class A Common Stock (other than the Stock and shares and equity-based compensation awards issued pursuant to stock incentive plans or other employee compensation plans existing on the date hereof or pursuant to currently outstanding options, warrants or rights or equity-based compensation awards assumed by the Company after the date hereof), or sell or grant options, rights or warrants with respect to any shares of Class A Common Stock or securities convertible into or exchangeable for Class A Common Stock (other than the grant of options and/or other equity-based compensation awards pursuant to stock incentive plans existing on the date hereof), (B) enter into any swap or other derivatives transaction that transfers to another, in whole or in part, any of the economic benefits or risks of ownership of such shares of Class A Common Stock, whether any such transaction described in clause (A) or (B) above is to be settled by delivery of Class A Common Stock or other securities, in cash or otherwise, (C) file or cause to be filed a registration statement, including any amendments thereto, with respect to the registration of any shares of Class A Common Stock or securities convertible, exercisable or exchangeable into Class A Common Stock or any other securities of the Company (other than any registration statement on Form S-8), or (D) publicly disclose the intention to do any of the foregoing, in each case (i) without the prior written consent of Barclays Capital Inc., on behalf of the Underwriters, and to cause each officer and director of the Company set forth on Schedule II hereto to furnish to the Representatives, prior to the Initial Delivery Date, a letter or letters, substantially in the form of Exhibit A hereto (the “ Lock-Up Agreements ”); notwithstanding the foregoing, if

 

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     (x) during the last 17 days of the Lock-Up Period, the Company issues an earnings release or material news or a material event relating to the Company occurs, or (y) prior to the expiration of the Lock-Up Period, the Company announces that it will release earnings results during the 16-day period beginning on the last day of the Lock-Up Period, then the restrictions imposed in this paragraph shall continue to apply until the expiration of the 18-day period beginning on the issuance of the earnings release or the announcement of the material news or the occurrence of the material event, unless Barclays Capital Inc., on behalf of the Underwriters, agree not to require such extension in writing.
     Notwithstanding anything in this Agreement to the contrary, the restrictions in this Section 6(a)(x) shall not apply to (i) the issuance and sale of Stock pursuant to this Agreement, (ii) the reclassification of the Company’s Class A Common Stock into Class B Common Stock, or any reduction by any means in the number of shares of such Class B Common Stock, as disclosed in the Preliminary Prospectus and the Prospectus, or (iii) the distribution to holders of Parent’s common stock the outstanding shares of Class A Common Stock then owned by Parent, or any public disclosure by the Company or Parent related thereto, following the 120 th day after the date of the Prospectus.
     (xi) If Barclays Capital Inc., in its sole discretion, agrees to release or waive the restrictions set forth in a Lock-Up Agreement for an officer or director of the Company and provides the Company with notice of the impending release or waiver at least three business days before the effective date of the release or waiver, the Company agrees to announce the impending release or waiver by issuing a press release substantially in the form of Exhibit B hereto, and containing such other information as Barclays Capital Inc. may require with respect to the circumstances of the release or waiver and/or the identity of the officer(s) and/or director(s) with respect to which the release or waiver applies, through a major news service at least two business days before the effective date of the release or waiver.
     (xii) To apply the net proceeds from the sale of the Stock being sold by the Company substantially in accordance with the description as set forth in the Prospectus under the caption “Use of Proceeds.”
     (xiii) To file with the Commission such information on Form 10-Q or Form 10-K as may be required by Rule 463 under the Securities Act.
     (xiv) If the Company elects to rely upon Rule 462(b) under the Securities Act, the Company shall file a Rule 462(b) Registration Statement with the Commission in compliance with Rule 462(b) under the Securities Act by 10:00 P.M., Washington, D.C. time, on the date of this

 

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Agreement, and the Company shall at the time of filing pay the Commission the filing fee for the Rule 462(b) Registration Statement.
     (xv) In connection with the Directed Share Program, to ensure that the Directed Shares will be restricted from sale, transfer, assignment, pledge or hypothecation to the same extent as sales and dispositions of Common Stock by the Company are restricted pursuant to Section 6(a)(x). Barclays Capital Inc. will notify the Company as to which Directed Share Participants will need to be so restricted and, at the request of Barclays Capital Inc., the Company will direct the transfer agent to place stop transfer restrictions upon such securities for such period of time as is consistent with Section 6(a)(x).
     (xvi) The Company and its affiliates will not take, directly or indirectly, any action designed to or that has constituted or that reasonably would be expected to cause or result in the stabilization or manipulation of the price of any security of the Company in connection with the offering of the Stock.
     (xvii) The Company will do and perform all things required or necessary to be done and performed under this Agreement by it prior to each Delivery Date, and to satisfy all conditions precedent to the Underwriters’ obligations hereunder to purchase the Stock.
     (b) Each Underwriter severally agrees that such Underwriter shall not (i) include any “issuer information” (as defined in Rule 433 under the Securities Act) in any “free writing prospectus” (as defined in Rule 405 under the Securities Act) used or referred to by such Underwriter without the prior consent of the Company (any such issuer information with respect to whose use the Company has given its consent, “ Permitted Issuer Information ”); provided that (A) no such consent shall be required with respect to any such issuer information contained in any document filed by the Company with the Commission prior to the use of such free writing prospectus, and (B) “issuer information,” as used in this Section 6(b), shall not be deemed to include information prepared by or on behalf of such Underwriter on the basis of or derived from issuer information, and (ii) take any action that would result in the Company being required to file with the Commission under Rule 433 under the Securities Act a free writing prospectus prepared by or on behalf of such Underwriter that otherwise would not be required to be filed by the Company thereunder, but for the action of the Underwriter.
     (c) The Company and Parent agree that any shares of Option Stock purchased by the Underwriters pursuant to the option described in Section 3 of this Agreement will not increase the total number of shares of Common Stock outstanding after the offering of the Firm Stock, but rather the number of shares of Class B Common Stock owned by Parent will be reduced share for share by the number of shares of Option Stock purchased by the Underwriters pursuant to such option and such shares of Class B Common Stock owned by Parent will be canceled.
          7. Expenses. The Company agrees, whether or not the transactions contemplated by this Agreement are consummated or this Agreement is terminated, to pay all expenses, costs, fees and taxes incident to and in connection with (a) the authorization, issuance, sale and delivery of the Stock and any stamp duties or other taxes payable in that connection, and the preparation and printing of certificates for the Stock; (b) the preparation, printing and filing under the Securities Act of the Registration Statement (including any exhibits thereto), any Preliminary Prospectus, the Prospectus, any Issuer Free Writing Prospectus and any amendment or supplement thereto; (c) the distribution of the Registration Statement (including any exhibits thereto), any Preliminary Prospectus, the Prospectus, any Issuer Free Writing Prospectus and any

 

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amendment or supplement thereto, all as provided in this Agreement; (d) the production and distribution of this Agreement, any supplemental agreement among Underwriters, and any other related documents in connection with the offering, purchase, sale and delivery of the Stock; (e) any required review by the Financial Industry Regulatory Authority, Inc. (the “ FINRA ”) of the terms of sale of the Stock (including reasonable related fees and expenses of counsel to the Underwriters in an amount that is not greater than $15,000); (f) the listing of the Stock on the New York Stock Exchange and/or any other exchange; (g) the qualification of the Stock under the securities laws of the several jurisdictions as provided in Section 6(a)(ix) and the preparation, printing and distribution of a Blue Sky Memorandum (including reasonable related fees and expenses of counsel to the Underwriters); (h) the preparation, printing and distribution of one or more versions of the Preliminary Prospectus and the Prospectus for distribution in Canada, often in the form of a Canadian “wrapper” (including reasonable related fees and expenses of Canadian counsel to the Underwriters); (i) the offer and sale of shares of the Stock by the Underwriters in connection with the Directed Share Program, including the reasonable fees and disbursements of counsel to the Underwriters related thereto, the costs and expenses of preparation, printing and distribution of the Directed Share Program material and all stamp duties or other taxes incurred by the Underwriters in connection with the Directed Share Program; (j) the investor presentations on any “road show” undertaken in connection with the marketing of the Stock, including, without limitation, expenses associated with any electronic road show, travel and lodging expenses of the representatives and officers of the Company and the cost of any aircraft chartered (to the extent Parent does not provide its own aircraft) in connection with the road show; and (k) all other costs and expenses incident to the performance of the obligations of the Company under this Agreement; provided that, except as provided in this Section 7 and in Section 12, the Underwriters shall pay their own costs and expenses, including the costs and expenses of their counsel, any transfer taxes on the Stock which they may sell and the expenses of advertising any offering of the Stock made by the Underwriters, and any transfer taxes payable in connection with its sale of Stock to the Underwriters and reimburse the Company for its pro rata share of the fees and expenses paid by the Company in connection with the offering of the Stock.
          8. Conditions of Underwriters’ Obligations . The respective obligations of the Underwriters hereunder are subject to the accuracy, when made and on each Delivery Date, of the representations and warranties of the Company and Parent contained herein, to the performance by the Company and Parent of their respective obligations hereunder, and to each of the following additional terms and conditions:
     (a) The Prospectus shall have been timely filed with the Commission in accordance with Section 6(a)(i). The Company shall have complied with all filing requirements applicable to any Issuer Free Writing Prospectus used or referred to after the date hereof; no stop order suspending the effectiveness of the Registration Statement or preventing or suspending the use of the Prospectus or any Issuer Free Writing Prospectus shall have been issued and no proceeding or examination for such purpose shall have been initiated or threatened by the Commission; and any request of the Commission for inclusion of additional information in the Registration Statement or the Prospectus or otherwise shall have been complied with. If the Company has elected to rely upon Rule 462(b) under the Securities Act, the Rule 462(b) Registration Statement shall have become effective by 10:00 P.M., Washington, D.C. time, on the date of this Agreement.

 

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     (b) No Underwriter shall have discovered and disclosed to the Company on or prior to such Delivery Date that the Registration Statement, the Prospectus or the Pricing Disclosure Package, or any amendment or supplement thereto, contains an untrue statement of a fact which, in the reasonable opinion of Latham & Watkins LLP, counsel for the Underwriters, is material or omits to state a fact which, in the reasonable opinion of such counsel, is material and is required to be stated therein or is necessary to make the statements therein not misleading in light of the circumstances under which such statements were made.
     (c) All corporate proceedings and other legal matters incident to the authorization, form and validity of this Agreement, the Stock, the Registration Statement, the Prospectus and any Issuer Free Writing Prospectus, and all other legal matters relating to this Agreement and the transactions contemplated hereby shall be reasonably satisfactory in all material respects to counsel for the Underwriters, and the Company shall have furnished to such counsel all documents and information that they may reasonably request to enable them to pass upon such matters.
     (d) Gibson, Dunn & Crutcher LLP shall have furnished to the Representatives its written opinion and negative assurance letter, as counsel to the Company, addressed to the Underwriters and dated such Delivery Date, in form and substance reasonably satisfactory to the Representatives.
     (e) The Representatives shall have received from James J. Bender, internal counsel to the Company, his written opinion and negative assurance statement, addressed to the Underwriters and dated such Delivery Date, in form and substance reasonably satisfactory to the Representatives.
     (f) The Representatives shall have received from Latham & Watkins LLP, counsel for the Underwriters, such opinion or opinions, dated such Delivery Date, with respect to the issuance and sale of the Stock, the Registration Statement, the Prospectus and the Pricing Disclosure Package and other related matters as the Representatives may reasonably require, and the Company shall have furnished to such counsel such documents as they reasonably request for the purpose of enabling them to pass upon such matters.
     (g) At the time of execution of this Agreement, the Representatives shall have received from Ernst & Young LLP a letter, in form and substance satisfactory to the Representatives, addressed to the Underwriters and dated the date hereof (i) confirming that they are independent public accountants within the meaning of the Securities Act and are in compliance with the applicable requirements relating to the qualification of accountants under Rule 2-01 of Regulation S-X of the Commission, and (ii) stating, as of the date hereof (or, with respect to matters involving changes or developments since the respective dates as of which specified financial information is given in the most recent Preliminary Prospectus, as of a date not more than three days prior to the date hereof), the conclusions and findings of such firm with respect to the financial information and other matters ordinarily covered by accountants’ “comfort letters” to underwriters in connection with registered public offerings.
     (h) With respect to the letter of Ernst & Young LLP referred to in the preceding paragraph and delivered to the Representatives concurrently with the execution of this

 

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Agreement (the “ initial letter ”), the Company shall have furnished to the Representatives a letter (the “ bring-down letter ”) of such accountants, addressed to the Underwriters and dated such Delivery Date (i) confirming that they are independent public accountants within the meaning of the Securities Act and are in compliance with the applicable requirements relating to the qualification of accountants under Rule 2-01 of Regulation S-X of the Commission, (ii) stating, as of the date of the bring-down letter (or, with respect to matters involving changes or developments since the respective dates as of which specified financial information is given in the Prospectus, as of a date not more than three days prior to the date of the bring-down letter), the conclusions and findings of such firm with respect to the financial information and other matters covered by the initial letter, and (iii) confirming in all material respects the conclusions and findings set forth in the initial letter.
     (i) At the time of execution of this Agreement, the Representatives shall have received from Netherland, Sewell and Associates, Inc. an initial letter (the “ initial NSAI letter ”), in form and substance reasonably satisfactory to the Representatives, addressed to the Underwriters and dated the date hereof and a subsequent letter dated as of the Delivery Date, which such letter shall cover the period from any initial NSAI letter to the Delivery Date, stating the conclusions and findings of such firm with respect to information about the oil and gas reserves of the Company as is customarily included in reserves engineers’ “confirmation letters” to underwriters in connection with registered public offerings.
     (j) The Company shall have furnished to the Representatives a certificate, dated such Delivery Date, of its Chief Executive Officer and its Chief Financial Officer as to such matters as the Representatives may reasonably request, including, without limitation, a statement that:
     (i) The representations, warranties and agreements of the Company in Section 1 are true and correct on and as of such Delivery Date, and the Company has complied with all its agreements contained herein and satisfied all the conditions on its part to be performed or satisfied hereunder at or prior to such Delivery Date;
     (ii) No stop order suspending the effectiveness of the Registration Statement has been issued; and no proceedings or examination for that purpose have been instituted or, to the knowledge of such officers, threatened; and
     (iii) Since the respective dates as of which information is given in the Registration Statement, the Pricing Disclosure Package and the Prospectus (exclusive of any amendment or supplement thereto), there has been no material adverse change or any development that would reasonably be expected to result in a prospective material adverse change in the financial condition, earnings, business or operations of the Company and its subsidiaries (taken as a whole) from that set forth or contemplated in the Registration Statement, the Pricing Disclosure Package and the Prospectus (exclusive of any amendment or supplement thereto).

 

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     (k) Parent shall have furnished to the Representatives a certificate, dated such Delivery Date, of an executive officer of the Parent, stating: the representations, warranties and agreements of Parent in Section 2 are true and correct on and as of such Delivery Date, and Parent has complied with all its agreements contained herein and satisfied all the conditions on its part to be performed or satisfied hereunder at or prior to such Delivery Date.
     (l) Neither the Company nor any of its Significant Subsidiaries shall have sustained, since the date of the latest audited financial statements included in the most recent Preliminary Prospectus, any loss or interference with its business from fire, explosion, flood or other calamity, whether or not covered by insurance, or from any labor dispute or court or governmental action, order or decree, or incurred any material liability or obligation, direct or contingent, other than liabilities and obligations that were incurred in the ordinary course of business, which would be reasonably likely to result in any Material Adverse Effect, or any development involving a material adverse change in or affecting the financial condition, results of operations, business or prospects of the Company and its subsidiaries (taken as a whole) from that set forth in the Pricing Disclosure Package or Prospectus, the effect of which is, in the judgment of the Representatives, impracticable or inadvisable to proceed with the public offering or delivery of the Stock being delivered on such Delivery Date on the terms and in the manner contemplated in the Prospectus.
     (m) Subsequent to the execution and delivery of this Agreement (i) no downgrading shall have occurred in the rating accorded the Company’s debt securities by any “nationally recognized statistical rating organization” (as that term is defined by the Commission for purposes of Rule 436(g)(2) under the Securities Act), and (ii) no such organization shall have publicly announced that it has under surveillance or review, with possible negative implications, its rating of any of the Company’s debt securities.
     (n) Subsequent to the execution and delivery of this Agreement there shall not have occurred any of the following: (i) trading in securities generally on The New York Stock Exchange, The NASDAQ Global Select Market, The NASDAQ Global Market, The NASDAQ Capital Market, or The American Stock Exchange or in the over-the-counter market, or trading in any securities of the Company on any exchange or in the over-the-counter market, shall have been suspended or materially limited or the settlement of such trading generally shall have been materially disrupted or minimum prices shall have been established on any such exchange or such market by the Commission, by such exchange or by any other regulatory body or governmental authority having jurisdiction, (ii) a general moratorium on commercial banking activities shall have been declared by federal or state authorities, (iii) the United States shall have become engaged in hostilities, there shall have been an escalation in hostilities involving the United States or there shall have been a declaration of a national emergency or war by the United States, or (iv) there shall have occurred such a material adverse change in general economic, political or financial conditions, including, without limitation, as a result of terrorist activities after the date hereof (or the effect of international conditions on the financial markets in the United States shall be such), in the case of clauses (i) through (iv), as to make it, in the judgment of the Representatives, impracticable or inadvisable to proceed with the public offering or delivery of the Stock being delivered on such Delivery Date on the terms and in the manner contemplated in the Prospectus.

 

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     (o) The New York Stock Exchange shall have approved the Stock for listing, subject only to official notice of issuance and evidence of satisfactory distribution.
     (p) The Lock-Up Agreements between the Representatives and the officers and directors of the Company set forth on Schedule II, delivered to the Representatives on or before the date of this Agreement, shall be in full force and effect on such Delivery Date.
     (q) On or prior to each Delivery Date, the Company shall have furnished to the Underwriters such further certificates and documents as the Representatives may reasonably request.
          All opinions, letters, evidence and certificates mentioned above or elsewhere in this Agreement shall be deemed to be in compliance with the provisions hereof only if they are in form and substance reasonably satisfactory to counsel for the Underwriters.
          9. Indemnification and Contribution.
     (a) The Company hereby agrees to indemnify and hold harmless each Underwriter, its affiliates, agents, directors, officers and employees and each person, if any, who controls any Underwriter within the meaning of Section 15 of the Securities Act or Section 20 of the Exchange Act, from and against any loss, claim, damage or liability, joint or several, or any action in respect thereof (including, but not limited to, any loss, claim, damage, liability or action relating to purchases and sales of Stock), to which that Underwriter, affiliate, agent, director, officer, employee or controlling person may become subject, under the Securities Act or otherwise, insofar as such loss, claim, damage, liability or action arises out of, or is based upon, (i) any untrue statement or alleged untrue statement of a material fact contained in (A) any Preliminary Prospectus, the Registration Statement, the Prospectus or in any amendment or supplement thereto (in the case of any Preliminary Prospectus or the Prospectus, in light of the circumstances under which any such statements were made), (B) any Issuer Free Writing Prospectus or in any amendment or supplement thereto, in light of the circumstances under which any such statements were made or (C) any Permitted Issuer Information used or referred to in any “free writing prospectus” (as defined in Rule 405 under the Securities Act) used or referred to by any Underwriter, or (ii) the omission or alleged omission to state in any Preliminary Prospectus, the Registration Statement, the Prospectus, any Issuer Free Writing Prospectus, in any amendment or supplement thereto or in any Permitted Issuer Information, any material fact required to be stated therein or necessary to make the statements therein (except in the case of the Registration Statement, in light of the circumstances under which they were made) not misleading, and shall reimburse each Underwriter and each such affiliate, agent, director, officer, employee or controlling person promptly upon demand for any legal or other expenses reasonably incurred by that Underwriter, affiliate, agent, director, officer, employee or controlling person in connection with investigating or defending or preparing to defend against any such loss, claim, damage, liability or action as such expenses are incurred; provided , however , that the Company shall not be liable in any such case to the extent that any such loss, claim, damage, liability or action arises out of, or is based upon, any untrue statement or alleged untrue statement or omission or alleged omission made in any Preliminary Prospectus, the Registration Statement, the Prospectus, any Issuer Free Writing Prospectus, in any such amendment or supplement thereto or in any Permitted Issuer Information, in reliance upon and in

 

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conformity with written information concerning such Underwriter furnished to the Company through the Representatives by or on behalf of any Underwriter specifically for inclusion therein, which information consists solely of the information specified in Section 9(f). The foregoing indemnity agreement is in addition to any liability which the Company may otherwise have to any Underwriter or to any affiliate, agent, director, officer, employee or controlling person of that Underwriter.
     (b) Parent shall indemnify and hold harmless each Underwriter, its affiliates, agents, directors, officers and employees, and each person, if any, who controls any Underwriter within the meaning of Section 15 of the Securities Act or Section 20 of the Exchange Act, from and against any loss, claim, damage or liability, joint or several, or any action in respect thereof (including, but not limited to, any loss, claim, damage, liability or action relating to purchases and sales of Stock), to which that Underwriter, affiliate, agent, director, officer, employee or controlling person may become subject, under the Securities Act or otherwise, insofar as such loss, claim, damage, liability or action arises out of, or is based upon, (i) any untrue statement or alleged untrue statement of a material fact contained in any Preliminary Prospectus, the Registration Statement, the Prospectus, any Issuer Free Writing Prospectus or in any amendment or supplement thereto (in the case of any Preliminary Prospectus, the Prospectus, any Issuer Free Writing Prospectus, in light of the circumstances under which any such statements were made) or in any Permitted Issuer Information, or (ii) the omission or alleged omission to state in any Preliminary Prospectus, Registration Statement, the Prospectus, any Issuer Free Writing Prospectus, in any amendment or supplement thereto or in any Permitted Issuer Information, any material fact required to be stated therein or necessary to make the statements therein (except in the case of the Registration Statement, in light of the circumstances under which they were made) not misleading, and shall reimburse each Underwriter, its affiliates, agents, directors, officers and employees and each such controlling person promptly upon demand for any legal or other expenses reasonably incurred by that Underwriter, its affiliates, agents, directors, officers and employees or controlling persons in connection with investigating or defending or preparing to defend against any such loss, claim, damage, liability or action as such expenses are incurred, but only with reference to information relating to Parent furnished by or on behalf of Parent for use in the Registration Statement, the Prospectus, any Issuer Free Writing Prospectus, in any such amendment or supplement thereto or in any Permitted Issuer Information; provided , however , that Parent shall not be liable in any such case to the extent that any such loss, claim, damage, liability or action arises out of, or is based upon, any untrue statement or alleged untrue statement or omission or alleged omission made in any Preliminary Prospectus, the Registration Statement, the Prospectus, any Issuer Free Writing Prospectus, in any such amendment or supplement thereto or in any Permitted Issuer Information, in reliance upon and in conformity with written information concerning such Underwriter furnished to the Company through the Representatives by or on behalf of any Underwriter specifically for inclusion therein, which information consists solely of the information specified in Section 9(f). The liability of Parent under the indemnity agreement contained in this paragraph shall be limited to an amount equal to the total net proceeds (before deducting expenses) from the offering of the shares of the Stock purchased under this Agreement distributed to Parent, as set forth in the Prospectus. The foregoing indemnity agreement is in addition to any liability that Parent may otherwise have to any Underwriter or any affiliate, agent, director, officer, employee or controlling person of that Underwriter.

 

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     (c) Each Underwriter, severally and not jointly, shall indemnify and hold harmless the Company, Parent, their respective directors (including any person who, with his or her consent, is named in the Registration Statement as about to become a director of the Company), officers and employees, and each person, if any, who controls the Company or Parent within the meaning of Section 15 of the Securities Act or Section 20 of the Exchange Act, from and against any loss, claim, damage or liability, joint or several, or any action in respect thereof, to which the Company, Parent or any such director, officer, employee or controlling person may become subject, under the Securities Act or otherwise, insofar as such loss, claim, damage, liability or action arises out of, or is based upon, (i) any untrue statement or alleged untrue statement of a material fact contained in any Preliminary Prospectus, the Registration Statement, the Prospectus, any Issuer Free Writing Prospectus or in any amendment or supplement thereto, or (ii) the omission or alleged omission to state in any Preliminary Prospectus, the Registration Statement, the Prospectus, any Issuer Free Writing Prospectus or in any amendment or supplement thereto, any material fact required to be stated therein or necessary to make the statements therein not misleading, but in each case only to the extent that the untrue statement or alleged untrue statement or omission or alleged omission was made in reliance upon and in conformity with written information concerning such Underwriter furnished to the Company through the Representatives by or on behalf of that Underwriter specifically for inclusion therein, which information is limited to the information set forth in Section 9(f). The foregoing indemnity agreement is in addition to any liability that any Underwriter may otherwise have to the Company, Parent or any such director, officer, employee or controlling person.
     (d) Promptly after receipt by an indemnified party under this Section 9 of notice of any claim or the commencement of any action, the indemnified party shall, if a claim in respect thereof is to be made against the indemnifying party under this Section 9, notify the indemnifying party in writing of the claim or the commencement of that action; provided , however , that the failure to notify the indemnifying party shall not relieve it from any liability which it may have under this Section 9 except to the extent it has been materially prejudiced by such failure and, provided , further , that the failure to notify the indemnifying party shall not relieve it from any liability which it may have to an indemnified party otherwise than under this Section 9. If any such claim or action shall be brought against an indemnified party, and it shall notify the indemnifying party thereof, the indemnifying party shall be entitled to participate therein and, to the extent that it wishes, jointly with any other similarly notified indemnifying party, to assume the defense thereof with counsel reasonably satisfactory to the indemnified party. After notice from the indemnifying party to the indemnified party of its election to assume the defense of such claim or action, the indemnifying party shall not be liable to the indemnified party under this Section 9 for any legal or other expenses subsequently incurred by the indemnified party in connection with the defense thereof other than reasonable costs of investigation; provided, however , that the indemnified party shall have the right to employ separate counsel to represent jointly the indemnified party and those other indemnified parties and their respective directors, officers, employees and controlling persons who may be subject to liability arising out of any claim in respect of which indemnity may be sought under this Section 9 if (i) the indemnified party and the indemnifying party shall have so mutually agreed; (ii) the indemnifying party has failed within a reasonable time to retain counsel reasonably satisfactory to the indemnified party; (iii) the indemnified party and its directors, officers, employees and controlling persons shall have reasonably concluded that there may be legal defenses available to them that are different from or in addition to those available to the indemnifying party; or (iv) the

 

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named parties in any such proceeding (including any impleaded parties) include both the indemnified parties or their respective directors, officers, employees or controlling persons, on the one hand, and the indemnifying party, on the other hand, and representation of both sets of parties by the same counsel would present such counsel with a conflict of interest, and in any such event the fees and expenses of such separate counsel shall be paid by the indemnifying party. No indemnifying party shall (x) without the prior written consent of the indemnified parties (which consent shall not be unreasonably withheld), settle or compromise or consent to the entry of any judgment with respect to any pending or threatened claim, action, suit or proceeding in respect of which indemnification or contribution may be sought hereunder (whether or not the indemnified parties are actual or potential parties to such claim or action) unless such settlement, compromise or consent includes an unconditional release of each indemnified party from all liability arising out of such claim, action, suit or proceeding and does not include a statement as to, or an admission of fault, culpability or a failure to act by or on behalf of any indemnified party, or (y) be liable for any settlement of any such action effected without its written consent (which consent shall not be unreasonably withheld), but if settled with the consent of the indemnifying party or if there be a final judgment for the plaintiff in any such action, the indemnifying party agrees to indemnify and hold harmless any indemnified party from and against any loss or liability by reason of such settlement or judgment.
     (e) If the indemnification provided for in this Section 9 shall for any reason be unavailable to or insufficient to hold harmless an indemnified party under Section 9(a), 9(b), 9(c) or 9(g) in respect of any loss, claim, damage or liability, or any action in respect thereof, referred to therein, then each indemnifying party shall, in lieu of indemnifying such indemnified party, contribute to the amount paid or payable by such indemnified party as a result of such loss, claim, damage or liability, or action in respect thereof, (i) in such proportion as shall be appropriate to reflect the relative benefits received by the Company and Parent, on the one hand, and the Underwriters, on the other, from the offering of the Stock, or (ii) if the allocation provided by clause (i) above is not permitted by applicable law, in such proportion as is appropriate to reflect not only the relative benefits referred to in clause (i) above but also the relative fault of the Company and Parent, on the one hand, and the Underwriters, on the other, with respect to the statements or omissions that resulted in such loss, claim, damage or liability, or action in respect thereof, as well as any other relevant equitable considerations. The relative benefits received by the Company, on the one hand, and the Underwriters on the other hand, in connection with the offering of the Stock shall be deemed to be in the same respective proportions as the net proceeds from the offering of the Stock (before deducting expenses) received by the Company and the total underwriting discounts and commissions received by the Underwriters, in each case as set forth in the table on the cover of the Prospectus, bear to the aggregate public offering price of the Stock. The relative fault shall be determined by reference to whether the untrue or alleged untrue statement of a material fact or omission or alleged omission to state a material fact relates to information supplied by the Company, Parent or the Underwriters, the intent of the parties and their relative knowledge, access to information and opportunity to correct or prevent such statement or omission. The Company, Parent and the Underwriters agree that it would not be just and equitable if contributions pursuant to this Section 9(e) were to be determined by pro rata allocation (even if the Underwriters were treated as one entity for such purpose) or by any other method of allocation that does not take into account the equitable considerations referred to herein. The amount paid or payable by an indemnified party as a result of the loss, claim, damage or liability, or action in respect thereof,

 

 31 
referred to above in this Section 9(e) shall be deemed to include, for purposes of this Section 9(e), any legal or other expenses reasonably incurred by such indemnified party in connection with investigating or defending any such action or claim. Notwithstanding the provisions of this Section 9(e), in no event shall an Underwriter be required to contribute any amount in excess of the amount by which the total underwriting discounts and commissions received by such Underwriter with respect to the offering of the Stock exceeds the amount of any damages that such Underwriter has otherwise been required to pay by reason of such untrue or alleged untrue statement or omission or alleged omission. No person guilty of fraudulent misrepresentation (within the meaning of Section 11(f) of the Securities Act) shall be entitled to contribution from any person who was not guilty of such fraudulent misrepresentation. The Underwriters’ obligations to contribute as provided in this Section 9(e) are several in proportion to their respective underwriting obligations and not joint.
     (f) The Underwriters severally confirm and each of the Company and Parent acknowledges and agrees that (i) the statements regarding delivery of shares by the Underwriters set forth on the cover page of, and (ii) the first sentence of the second full paragraph under the heading “Commissions and Expenses” and the paragraphs relating to stabilization by the Underwriters appearing under the caption “Underwriting” in, the most recent Preliminary Prospectus and the Prospectus are correct and constitute the only information concerning such Underwriters furnished in writing to the Company by or on behalf of the Underwriters specifically for inclusion in any Preliminary Prospectus, the Registration Statement, the Prospectus, any Issuer Free Writing Prospectus or in any amendment or supplement thereto.
     (g) The Company shall indemnify and hold harmless Barclays Capital Inc. (including its affiliates, agents, directors, officers and employees) and each person, if any, who controls Barclays Capital Inc. within the meaning of Section 15 of the Securities Act or Section 20 of the Exchange Act (“ Barclays Entities ”), from and against any loss, claim, damage or liability or any action in respect thereof to which any of the Barclays Entities may become subject, under the Securities Act or otherwise, insofar as such loss, claim, damage, liability or action (i) arises out of, or is based upon, any untrue statement or alleged untrue statement of a material fact contained in any material prepared by or with the approval of the Company for distribution to Directed Share Participants in connection with the Directed Share Program or any omission or alleged omission to state therein a material fact required to be stated therein or necessary to make the statements therein, when considered in conjunction with the Prospectus, the Pricing Disclosure Package or any applicable Preliminary Prospectus, not misleading, (ii) arises out of, or is based upon, the failure of the Directed Share Participant to pay for and accept delivery of Directed Shares that were subject to an agreement to purchase between the Directed Share Participant and the Barclays Entities, or (iii) is otherwise related to the Directed Share Program; provided that the Company shall not be liable under this clause (iii) for any loss, claim, damage, liability or action that is determined in a final judgment by a court of competent jurisdiction to have resulted from the gross negligence, bad faith or willful misconduct of the Barclays Entities. The Company shall reimburse the Barclays Entities promptly upon demand for any legal or other expenses reasonably incurred by them in connection with investigating or defending or preparing to defend against any such loss, claim, damage, liability or action as such expenses are incurred.

 

 32 
          10. Defaulting Underwriters .
     (a) If, on any Delivery Date, any Underwriter defaults in its obligations to purchase the Stock that it has agreed to purchase under this Agreement, the remaining non-defaulting Underwriters may in their discretion arrange for the purchase of such Stock by the non-defaulting Underwriters or other persons satisfactory to the Company on the terms contained in this Agreement. If, within 36 hours after any such default by any Underwriter, the non-defaulting Underwriters do not arrange for the purchase of such Stock, then the Company shall be entitled to a further period of 36 hours within which to procure other persons satisfactory to the non-defaulting Underwriters to purchase such Stock on such terms. In the event that within the respective prescribed periods, the non-defaulting Underwriters notify the Company that they have so arranged for the purchase of such Stock, or the Company notifies the non-defaulting Underwriters that it has so arranged for the purchase of such Stock, either the non-defaulting Underwriters or the Company may postpone such Delivery Date for up to seven full business days in order to effect any changes that in the opinion of counsel for the Company or counsel for the Underwriters may be necessary in the Registration Statement, the Prospectus or in any other document or arrangement, and the Company agrees to promptly prepare any amendment or supplement to the Registration Statement, the Prospectus or in any such other document or arrangement that effects any such changes. As used in this Agreement, the term “Underwriter” includes, for all purposes of this Agreement unless the context requires otherwise, any party not listed in Schedule I hereto that, pursuant to this Section 10, purchases Stock that a defaulting Underwriter agreed but failed to purchase.
     (b) If, after giving effect to any arrangements for the purchase of the Stock of a defaulting Underwriter or Underwriters by the non-defaulting Underwriters and the Company as provided in paragraph (a) above, the total number of shares of the Stock that remains unpurchased does not exceed one-eleventh of the total number of shares of all the Stock, then the Company shall have the right to require each non-defaulting Underwriter to purchase the total number of shares of Stock that such Underwriter agreed to purchase hereunder plus such Underwriter’s pro rata share (based on the total number of shares of Stock that such Underwriter agreed to purchase hereunder) of the Stock of such defaulting Underwriter or Underwriters for which such arrangements have not been made; provided that the non-defaulting Underwriters shall not be obligated to purchase more than 110% of the total number of shares of Stock that it agreed to purchase on such Delivery Date pursuant to the terms of Section 3.
     (c) If, after giving effect to any arrangements for the purchase of the Stock of a defaulting Underwriter or Underwriters by the non-defaulting Underwriters and the Company as provided in paragraph (a) above, the total number of shares of Stock that remains unpurchased exceeds one-eleventh of the total number of shares of all the Stock, or if the Company shall not exercise the right described in paragraph (b) above, then this Agreement shall terminate without liability on the part of the non-defaulting Underwriters. Any termination of this Agreement pursuant to this Section 10 shall be without liability on the part of the Company, except that the Company will continue to be liable for the payment of expenses as set forth in Sections 7 and 12 and except that the provisions of Section 9 shall not terminate and shall remain in effect.
     (d) Nothing contained herein shall relieve a defaulting Underwriter of any liability it may have to the Company or any non-defaulting Underwriter for damages caused by its default.

 

 33 
          11. Termination. The obligations of the Underwriters hereunder may be terminated by the Representatives by notice given to and received by the Company prior to delivery of and payment for the Firm Stock if, prior to that time, any of the events described in Sections 8(l), 8(m) and 8(n) shall have occurred or if the Underwriters shall decline to purchase the Stock for any reason permitted under this Agreement.
          12. Reimbursement of Underwriters’ Expenses. If the Company shall fail to tender the Stock for delivery to the Underwriters by reason of any failure, refusal or inability on the part of the Company to perform any agreement on its part to be performed, or because any other condition of the Underwriters’ obligations hereunder required to be fulfilled by the Company is not fulfilled, the Company will reimburse the Underwriters for all reasonable out-of-pocket expenses (including reasonable fees and disbursements of counsel for the Underwriters) incurred by the Underwriters in connection with this Agreement and the proposed purchase of the Stock, and upon demand the Company shall pay the full amount thereof to the Representatives. If this Agreement is terminated pursuant to Section 10 by reason of the default of one or more Underwriters, the Company shall not be obligated to reimburse any defaulting Underwriter on account of those expenses.
          13. Research Analyst Independence. The Company and Parent acknowledge that the Underwriters’ research analysts and research departments are required to be independent from their respective investment banking divisions and are subject to certain regulations and internal policies, and that such Underwriters’ research analysts may hold views and make statements or investment recommendations and/or publish research reports with respect to the Company and/or the offering that differ from the views of their respective investment banking divisions. The Company and Parent hereby waive and release, to the fullest extent permitted by law, any claims that the Company or Parent may have against the Underwriters with respect to any conflict of interest that may arise from the fact that the views expressed by their independent research analysts and research departments may be different from or inconsistent with the views or advice communicated to the Company or Parent by such Underwriters’ investment banking divisions. The Company and Parent acknowledge that each of the Underwriters is a full service securities firm and as such from time to time, subject to applicable securities laws, may effect transactions for its own account or the account of its customers and hold long or short positions in debt or equity securities of the Company or Parent.
          14. No Fiduciary Duty . The Company and Parent acknowledge and agree that in connection with this offering, sale of the Stock or any other services the Underwriters may be deemed to be providing hereunder, notwithstanding any preexisting relationship, advisory or otherwise, between the parties or any oral representations or assurances previously or subsequently made by the Underwriters: (a) no fiduciary or agency relationship between the Company, Parent and any other person, on the one hand, and the Underwriters, on the other, exists; (b) the Underwriters are not acting as advisors, expert or otherwise, to either the Company or Parent, and such relationship between the Company and Parent, on the one hand, and the Underwriters, on the other, is entirely and solely commercial, based on arms-length negotiations; (c) any duties and obligations that the Underwriters may have to the Company or Parent shall be limited to those duties and obligations specifically stated herein; and (d) the Underwriters and their respective affiliates may have interests that differ from those of the Company and Parent. Furthermore, the Company and Parent agree that they are solely responsible for making their

 

 34 
own judgments and decisions in connection with this offering. The Company and Parent hereby waive any claims that the Company or Parent may have against the Underwriters with respect to any breach of fiduciary duty in connection with this offering.
          15. Notices, etc. All statements, requests, notices and agreements hereunder shall be in writing, and:
     (a) if to the Underwriters, shall be delivered or sent by mail or facsimile transmission to: (i) Barclays Capital Inc., 200 Park Avenue, New York, New York 10166, Attention: Syndicate Registration (Fax: 646-834-8133), with a copy, in the case of any notice pursuant to Section 9(d), to the Director of Litigation, Office of the General Counsel, Barclays Capital Inc., 200 Park Avenue, New York, New York 10166; (ii) Citigroup Global Markets Inc., General Counsel (fax no.: (212) 816-7912) and confirmed to the General Counsel, Citigroup Global Markets Inc., at 388 Greenwich Street, New York, New York, 10013, Attention: General Counsel; (iii) J.P. Morgan Securities LLC, 383 Madison Avenue, 4th Floor, NYC 10179, Attention: Equity Syndicate Desk, Fax: 212-622-8358; and (iv) Merrill Lynch, Pierce, Fenner & Smith Incorporated, One Bryant Park, New York, NY 10036, Attention: Syndicate Department and confirmed to ECM Legal; and
     (b) if to the Company or Parent, shall be delivered or sent by mail or facsimile transmission to the address of the Company set forth in the Registration Statement, Attention: General Counsel (Fax: (918)-573-5942), with a copy delivered or sent by mail or facsimile transmission to Gibson, Dunn & Crutcher LLP, Attn: Richard M. Russo (Fax: (303) 313-2838) and confirmed at (303) 298-5715).
Any such statements, requests, notices or agreements shall take effect at the time of receipt thereof. The Company and Parent shall be entitled to act and rely upon any request, consent, notice or agreement given or made on behalf of the Underwriters by Barclays Capital Inc. on behalf of the Representatives.
          16. Persons Entitled to Benefit of Agreement . This Agreement shall inure to the benefit of and be binding upon the Underwriters, the Company, Parent and their respective successors. This Agreement and the terms and provisions hereof are for the sole benefit of only those persons, except that (a) the representations, warranties, indemnities and agreements of the Company and Parent contained in this Agreement shall also be deemed to be for the benefit of the directors, officers and employees of the Underwriters and each person or persons, if any, who control any Underwriter within the meaning of Section 15 of the Securities Act, and (b) the indemnity agreement of the Underwriters contained in Section 9(c) of this Agreement shall be deemed to be for the benefit of the directors of the Company, the officers of the Company who have signed the Registration Statement and any person controlling the Company within the meaning of Section 15 of the Securities Act. Nothing in this Agreement is intended or shall be construed to give any person, other than the persons referred to in this Section 16, any legal or equitable right, remedy or claim under or in respect of this Agreement or any provision contained herein.
          17. Survival. The respective indemnities, representations, warranties and agreements of the Company, Parent and the Underwriters contained in this Agreement or made

 

 35 
by or on behalf of them, respectively, pursuant to this Agreement, shall survive the delivery of and payment for the Stock and shall remain in full force and effect, regardless of any investigation made by or on behalf of any of them or any person controlling any of them.
          18. Definition of the Terms “Business Day,” “Affiliate” and “subsidiary.” For purposes of this Agreement, (a) “ business day ” means each Monday, Tuesday, Wednesday, Thursday or Friday that is not a day on which banking institutions in New York are generally authorized or obligated by law or executive order to close, and (b) “ affiliate ” and “ subsidiary ” have the respective meanings set forth in Rule 405 under the Securities Act.
          19. Governing Law . THIS AGREEMENT IS GOVERNED BY THE LAW OF THE STATE OF NEW YORK WITHOUT REGARD TO THE CONFLICTS OF LAWS PROVISIONS THEREOF THAT WOULD APPLY THE LAWS OF ANY OTHER STATE. PARENT, THE COMPANY AND THE UNDERWRITERS EACH WAIVE TRIAL BY JURY IN ANY ACTION, PROCEEDING OR COUNTERCLAIM BROUGHT BY OR ON BEHALF OF ANY PARTY WITH RESPECT TO ANY MATTER WHATSOEVER RELATING TO OR ARISING OUT OF THE TERMS OF THIS AGREEMENT AND THE OFFERING CONTEMPLATED HEREBY.
          20. Waiver of Jury Trial . The parties hereby irrevocably submit to the non-exclusive jurisdiction of any New York State or federal court sitting in the Borough of Manhattan in The City of New York in any action or proceeding arising out of or relating to the terms of this Agreement and the offering contemplated hereby, and the parties hereby irrevocably agree that all claims in respect of such action or proceeding may be heard and determined in such New York State or federal court. The parties hereby irrevocably waive, to the fullest extent that they may legally do so, the defense of an inconvenient forum to the maintenance of such action or proceeding and each party irrevocably consents to the service of any and all process in any action or proceeding by the mailing or delivery of copies of such process to it at the office of the party set forth under Section 15 herein. The parties agree that a final judgment in any such action or proceeding shall be conclusive and may be enforced in other jurisdictions by suit on the judgment or in any other manner provided by law. To the extent that any party has or hereafter may acquire any immunity from jurisdiction of any court or from any legal process (whether through service or notice, attachment prior to judgment, attachment in aid of execution or otherwise) with respect to its obligations hereunder, such party waives such immunity to the extent permitted by applicable law.
          21. Patriot Act . In accordance with the requirements of the USA Patriot Act (Title III of Pub. L. 107-56 (signed into law October 26, 2001)), the underwriters are required to obtain, verify and record information that identifies their respective clients, including the Company, which information may include the name and address of their respective clients, as well as other information that will allow the underwriters to properly identify their respective clients.
          22. Counterparts. This Agreement may be executed in one or more counterparts and, if executed in more than one counterpart, the executed counterparts shall each be deemed to be an original but all such counterparts shall together constitute one and the same instrument.

 

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          23. Headings. The headings herein are inserted for convenience of reference only and are not intended to be part of, or to affect the meaning or interpretation of, this Agreement.

 

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     If the foregoing correctly sets forth the agreement among the Company, Parent and the Underwriters, please indicate your acceptance in the space provided for that purpose below.
 	 	 	 	 	
 	Very truly yours,

WPX Energy, Inc.
 	 	
 	By:  	 	 	
 	 	Name:  	 	 	
 	 	Title:  	 	 	
 	
 	The Williams Companies, Inc.
 	 	
 	By:  	 	 	
 	 	Name:  	 	 	
 	 	Title:  	 	 	

 

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Accepted:
Barclays Capital Inc.
Citigroup Global Markets Inc.
J.P. Morgan Securities LLC
Merrill Lynch, Pierce, Fenner & Smith
                        Incorporated,
For themselves and as Representatives
of the several Underwriters named
in Schedule I hereto
By: Barclays Capital Inc.

 	By:  	 	 	
 	 	Authorized Representative  	 	

By: Citigroup Global Markets Inc.

 	By:  	 	 	
 	 	Authorized Representative  	 	

By: J.P. Morgan Securities LLC

 	By:  	 	 	
 	 	Authorized Representative  	 	

By: Merrill Lynch, Pierce, Fenner & Smith
                               Incorporated

 	By:  	 	 	
 	 	Authorized Representative  	 	

 

SCHEDULE I
 	 	 	 	 	
 	 	Number of Shares of	 	
Underwriters	 	Firm Stock	 	
Barclays Capital Inc.	 	 	 	 	
Citigroup Global Markets Inc.	 	 	 	 	
J.P. Morgan Securities LLC	 	 	 	 	
Merrill Lynch, Pierce, Fenner & Smith
        Incorporated	 	 	 	 	
Deutsche Bank Securities Inc.	 	 	 	 	
Goldman, Sachs & Co.	 	 	 	 	
Morgan Stanley & Co. Incorporated	 	 	 	 	
Wells Fargo Securities, LLC	 	 	 	 	
Credit Suisse Securities (USA) LLC	 	 	 	 	
RBC Capital Markets, LLC	 	 	 	 	
Scotia Capital (USA) Inc.	 	 	 	 	
UBS Securities LLC	 	 	 	 	
Howard Weil Incorporated	 	 	 	 	
 	 	 	 	
Total	 	 	 	 	

 

SCHEDULE II
PERSONS DELIVERING LOCK-UP AGREEMENTS
Directors
Alan S. Armstrong
George A. Lorch
Williams G. Lowrie
Officers
Ralph A. Hill
Donald R. Chappel
Ted T. Timmermans
James J. Bender
Robyn L. Ewing
Rodney J. Sailor

 

SCHEDULE III
ORALLY CONVEYED PRICING INFORMATION
1. [ Public offering price ]
2. [ Number of shares offered ]

 

SCHEDULE IV
ISSUER FREE WRITING PROSPECTUSES — ROAD SHOW MATERIALS
Insert list of certain “road show” materials

 

SCHEDULE V
SIGNIFICANT SUBSIDIARIES
Williams Production Holdings LLC
Williams Production RMT Company LLC
Dakota-3 E&P Company, LLC
Williams Production Company, LLC
Williams Production Keystone LLC
Williams Production Appalachia LLC

 

EXHIBIT A
LOCK-UP LETTER AGREEMENT
LOCK-UP LETTER AGREEMENT
Barclays Capital Inc.
Citigroup Global Markets Inc.
J.P. Morgan Securities LLC
Merrill Lynch, Pierce, Fenner & Smith
                         Incorporated,
As Representatives of the several
   Underwriters named in Schedule I
   of the Underwriting Agreement,
c/o Barclays Capital Inc.
200 Park Avenue
New York, New York 10166
Ladies and Gentlemen:
          The undersigned understands that you and certain other firms (the “ Underwriters ”) propose to enter into an Underwriting Agreement (the “ Underwriting Agreement ”) providing for the purchase by the Underwriters of shares (the “ Stock ”) of Class A common stock, par value $1.00 per share (the “ Common Stock ”), of WPX Energy, Inc., a Delaware corporation (the “ Company ”), and that the Underwriters propose to reoffer the Stock to the public (the “ Offering ”).
          In consideration of the execution of the Underwriting Agreement by the Underwriters, and for other good and valuable consideration, the undersigned hereby irrevocably agrees that, without the prior written consent of Barclays Capital Inc., on behalf of the Underwriters, the undersigned will not, directly or indirectly, (1) offer for sale, sell, pledge, or otherwise dispose of (or enter into any transaction or device that is designed to, or could be expected to, result in the disposition by any person at any time in the future of) any shares of Common Stock (including, without limitation, shares of Common Stock that may be deemed to be beneficially owned by the undersigned in accordance with the rules and regulations of the Securities and Exchange Commission and shares of Common Stock that may be issued upon exercise of any options or warrants) or securities convertible into or exercisable or exchangeable for Common Stock owned by the undersigned on the date of execution of this Lock-Up Letter Agreement or on the date of the completion of the Offering, (2) enter into any swap or other derivatives transaction that transfers to another, in whole or in part, any of the economic benefits or risks of ownership of shares of Common Stock, whether any such transaction described in clause (1) or (2) above is to be settled by delivery of Common Stock or other securities, in cash or otherwise, (3) make any demand for or exercise any right or cause to be filed a registration statement, including any amendments thereto, with respect to the registration of any shares of Common Stock or securities convertible into or exercisable or exchangeable for Common Stock or any other securities of the Company, or (4) publicly disclose the intention to do any of the foregoing for a period commencing on the
Exhibit A-1

 

date hereof and ending on the 180th day after the date of the Prospectus relating to the Offering (such 180-day period, the “ Lock-Up Period ”).
          If the undersigned is an officer or director of the Company, (i) Barclays Capital Inc. agrees that, at least three business days before the effective date of any release or waiver of the foregoing restrictions in connection with a transfer of shares of Common Stock, Barclays Capital Inc. will notify the Company of the impending release or waiver, and (ii) the Company has agreed in the Underwriting Agreement to announce the impending release or waiver by issuing a press release through a major news service at least two business days before the effective date of the release or waiver. Any release or waiver granted by Barclays Capital Inc. hereunder to any such officer or director shall only be effective two business days after the publication date of such press release. The provisions of this paragraph will not apply if both (a) the release or waiver is effected solely to permit a transfer not for consideration, and (b) the transferee has agreed in writing to be bound by the same terms described in this letter that are applicable to the transferor, to the extent and for the duration that such terms remain in effect at the time of the transfer. The undersigned further agrees that the foregoing provisions shall be equally applicable to any issuer-directed securities the undersigned may purchase in the offering.
          Notwithstanding the foregoing, if (1) during the last 17 days of the Lock-Up Period, the Company issues an earnings release or material news or a material event relating to the Company occurs, or (2) prior to the expiration of the Lock-Up Period, the Company announces that it will release earnings results during the 16-day period beginning on the last day of the Lock-Up Period, then the restrictions imposed by this Lock-Up Letter Agreement shall continue to apply until the expiration of the 18-day period beginning on the issuance of the earnings release or the announcement of the material news or the occurrence of the material event, unless the Representatives agree not to require such extension in writing. The undersigned hereby further agrees that, prior to engaging in any transaction or taking any other action that is subject to the terms of this Lock-Up Letter Agreement during the period from the date of this Lock-Up Letter Agreement to and including the 34 th day following the expiration of the Lock-Up Period, it will give notice thereof to the Company and will not consummate such transaction or take any such action unless it has received written confirmation from the Company that the Lock-Up Period (as such may have been extended pursuant to this paragraph) has expired.
          If the undersigned is an officer or director of the issuer, the undersigned further agrees that the foregoing provisions shall be equally applicable to any issuer-directed Common Stock the undersigned may purchase in the offering.
          In furtherance of the foregoing, the Company and its transfer agent are hereby authorized to decline to make any transfer of securities if such transfer would constitute a violation or breach of this Lock-Up Letter Agreement.
Exhibit A-2

 

          It is understood that, if the Company notifies the Underwriters that it does not intend to proceed with the Offering, if the Underwriting Agreement does not become effective, or if the Underwriting Agreement (other than the provisions thereof which survive termination) shall terminate or be terminated prior to payment for and delivery of the Stock, the undersigned will be released from its obligations under this Lock-Up Letter Agreement.
          The undersigned understands that the Company and the Underwriters will proceed with the Offering in reliance on this Lock-Up Letter Agreement.
          Whether or not the Offering actually occurs depends on a number of factors, including market conditions. Any Offering will only be made pursuant to an Underwriting Agreement, the terms of which are subject to negotiation among the Company and the Underwriters.
[Signature page follows]
Exhibit A-3

 

The undersigned hereby represents and warrants that the undersigned has full power and authority to enter into this Lock-Up Letter Agreement and that, upon request, the undersigned will execute any additional documents necessary in connection with the enforcement hereof. Any obligations of the undersigned shall be binding upon the heirs, personal representatives, successors and assigns of the undersigned.
 	 	 	 	 	
 	Very truly yours,
 	 	
 	By:  	 	 	
 	 	Name:  	 	 	
 	 	Title:  	 	 	
 	
Dated: _______________
Exhibit A-4

 

EXHIBIT B
[Form of Press Release]
WPX Energy, Inc.
[ Insert date ]
WPX Energy, Inc., (the “ Company ”) announced today that Barclays Capital Inc., a lead book-running manager (along with Citigroup Global Markets Inc., J.P. Morgan Securities LLC and Merrill Lynch, Pierce, Fenner & Smith Incorporated) in the Company’s recent public sale of            shares of Class A common stock is [waiving] [releasing] a lock-up restriction with respect to            shares of the Company’s common stock held by [certain officers or directors] [an officer or director] of the Company. The [waiver] [release] will take effect on [ insert date ], and the shares may be sold or otherwise disposed of on or after such date.
This press release is not an offer for sale of the securities in the United States or in any other jurisdiction where such offer is prohibited, and such securities may not be offered or sold in the United States absent registration or an exemption from registration under the United States Securities Act of 1933, as amended.
Exhibit B

Exhibit 10.1
 
FORM OF SEPARATION AND DISTRIBUTION AGREEMENT
by and between
THE WILLIAMS COMPANIES, INC.,
and
WPX ENERGY, INC.
Dated as of           , 2011

 

TABLE OF CONTENTS
 	 	 	 	 	
 	 	Page	 	
ARTICLE I DEFINITIONS	 	 	2	 	
 		
Section 1.1 Table of Definitions	 	 	2	 	
Section 1.2 Certain Defined Terms	 	 	3	 	
 	 	 	 	 	
ARTICLE II THE CONTRIBUTION	 	 	9	 	
 	 	 	 	 	
Section 2.1 Contribution of WPX Assets	 	 	9	 	
Section 2.2 Assumption of Liabilities	 	 	9	 	
Section 2.3 Effective Date; Deliveries	 	 	10	 	
Section 2.4 Transfers Not Effected on or before the Effective Date	 	 	10	 	
Section 2.5 Shared Contracts	 	 	11	 	
Section 2.6 Termination of Agreements	 	 	11	 	
Section 2.7 Governmental Approvals and Consents	 	 	12	 	
Section 2.8 Disclaimer of Representations and Warranties	 	 	12	 	
 	 	 	 	 	
ARTICLE III THE IPO	 	 	13	 	
 	 	 	 	 	
Section 3.1 Actions Prior to the IPO	 	 	13	 	
Section 3.2 Use of Proceeds; Consideration for WPX Assets	 	 	13	 	
Section 3.3 Conditions to the IPO	 	 	14	 	
Section 3.4 Conversion of Outstanding WPX Common Stock into WPX Class B Common Stock	 	 	14	 	
 	 	 	 	 	
ARTICLE IV THE DISTRIBUTION	 	 	15	 	
 	 	 	 	 	
Section 4.1 The Distribution	 	 	15	 	
Section 4.2 Actions Prior to the Distribution	 	 	15	 	
Section 4.3 Conditions to the Distribution	 	 	16	 	
Section 4.4 Certain Stockholder Matters.	 	 	17	 	
 	 	 	 	 	
ARTICLE V FINANCIAL AND OTHER COVENANTS	 	 	18	 	
 	 	 	 	 	
Section 5.1 Financial and Other Information.	 	 	18	 	
Section 5.2 Other Covenants	 	 	20	 	
Section 5.3 Covenants Regarding the Incurrence of Indebtedness.	 	 	21	 	
 	 	 	 	 	
ARTICLE VI EXCHANGE OF INFORMATION; CONFIDENTIALITY	 	 	22	 	
 	 	 	 	 	
Section 6.1 Agreement for Exchange of Information	 	 	22	 	
Section 6.2 Ownership of Information	 	 	23	 	
Section 6.3 Compensation for Providing Information	 	 	23	 	
Section 6.4 Record Retention	 	 	23	 	

 

 	 	 	 	 	
 	 	Page	 	
Section 6.5 Limitation of Liability	 	 	23	 	
Section 6.6 Other Agreements Providing for Exchange of Information	 	 	23	 	
Section 6.7 Cooperation	 	 	23	 	
Section 6.8 Confidentiality	 	 	24	 	
Section 6.9 Protective Arrangements	 	 	24	 	
 	 	 	 	 	
ARTICLE VII ADDITIONAL COVENANTS AND OTHER MATTERS	 	 	25	 	
 	 	 	 	 	
Section 7.1 Further Assurances	 	 	25	 	
Section 7.2 Use of Names, Logos and Information	 	 	25	 	
Section 7.3 Non-Solicitation	 	 	26	 	
Section 7.4 Conduct of WPX Business between Effective Date and Distribution Date	 	 	27	 	
Section 7.5 WMB Guarantees	 	 	27	 	
Section 7.6 Directors’ and Officers’ Insurance	 	 	27	 	

ARTICLE VIII MUTUAL RELEASES; INDEMNIFICATION	 	 	27	 	
 	 	 	 	 	
Section 8.1 Mutual Releases	 	 	27	 	
Section 8.2 Indemnification by WPX	 	 	29	 	
Section 8.3 Indemnification by WMB	 	 	29	 	
Section 8.4 Indemnification Obligations Net of Insurance Proceeds and Other Amounts	 	 	30	 	
Section 8.5 Third-Party Claims	 	 	31	 	
Section 8.6 Additional Matters	 	 	32	 	
Section 8.7 Remedies Cumulative	 	 	33	 	
Section 8.8 Survival of Indemnities	 	 	33	 	
Section 8.9 Limitation on Liability	 	 	33	 	
 	 	 	 	 	
ARTICLE IX TERMINATION	 	 	33	 	
 	 	 	 	 	
Section 9.1 Termination	 	 	33	 	
Section 9.2 Effect of Termination	 	 	34	 	
 	 	 	 	 	
ARTICLE X DISPUTE RESOLUTION	 	 	34	 	
 	 	 	 	 	
Section 10.1 Disputes	 	 	34	 	
Section 10.2 Escalation; Mediation	 	 	34	 	
Section 10.3 Court Actions	 	 	36	 	
 	 	 	 	 	
ARTICLE XI MISCELLANEOUS	 	 	36	 	
 	 	 	 	 	
Section 11.1 Corporate Power	 	 	36	 	
Section 11.2 Coordination with Certain Ancillary Agreements; Conflicts	 	 	36	 	
Section 11.3 Expenses	 	 	37	 	
Section 11.4 Amendment and Modification.	 	 	37	 	
Section 11.5 Waiver	 	 	37	 	
 ii 

 

 	 	 	 	 	
 	 	Page	 	
Section 11.6 Notices	 	 	37	 	
Section 11.7 Interpretation	 	 	38	 	
Section 11.8 Entire Agreement	 	 	38	 	
Section 11.9 No Third Party Beneficiaries	 	 	38	 	
Section 11.10 Governing Law	 	 	38	 	
Section 11.11 Submission to Jurisdiction	 	 	39	 	
Section 11.12 Assignment	 	 	39	 	
Section 11.13 Severability	 	 	39	 	
Section 11.14 Waiver of Jury Trial	 	 	39	 	
Section 11.15 Counterparts	 	 	39	 	
Section 11.16 Facsimile Signature	 	 	40	 	
 	 	 	 	 	
Exhibit A            Contributed Entities	 	 	 	 	
 	 	 	 	 	
Schedule 2.6(b)(v) Surviving Agreements	 	 	 	 	
Schedule 8.3(d) California Gas Marketing Proceedings	 	 	 	 	
Schedule 8.3(e) Gas Price Indices Proceedings	 	 	 	 	
 iii 

 

SEPARATION AND DISTRIBUTION AGREEMENT
     SEPARATION AND DISTRIBUTION AGREEMENT, dated as of      , 2011 (this “ Agreement ”), by and between The Williams Companies, Inc., a Delaware corporation (“ WMB ”), and WPX Energy, Inc., a Delaware corporation (“ WPX ”).
RECITALS
     A. The WMB Board has determined that it would be appropriate, desirable and in the best interests of WMB and WMB’s stockholders to separate the WPX Business from WMB.
     B. In connection with the separation of the WPX Business from WMB, WMB desires to contribute or otherwise transfer, and to cause certain of its Subsidiaries to contribute or otherwise transfer, certain Assets and Liabilities associated with the WPX Business, including the stock or other equity interests of certain of WMB’s Subsidiaries dedicated to the WPX Business, to WPX and certain of WPX’s Subsidiaries (collectively, the “ Contribution ”).
     C. WPX intends to offer and sell for its own account a limited number of shares of WPX Class A Common Stock pursuant to an initial public offering of such shares (the “ IPO ”), and in furtherance thereof, WPX has previously filed the IPO Registration Statement with the SEC.
     D. In connection with the Contribution and in exchange for the WPX Assets contributed by WMB directly to WPX, WPX intends to (i) convert the WPX Common Stock held by WMB into shares of WPX Class B Common Stock such that WMB will own all of the outstanding WPX Class B Common Stock immediately following the consummation of the IPO, (ii) distribute to WMB a portion of the IPO proceeds and WPX Borrowing proceeds, and (iii) assume the WPX Liabilities.
     E. WMB intends (i) to distribute to WMB creditors the proceeds received from WPX referred to in clause (ii) in Recital D above and (ii) after the IPO, to distribute to holders of shares of WMB Common Stock the outstanding shares of WPX Common Stock then owned by WMB (the “ Distribution ”).
     F. WMB and WPX intend that the Contribution pursuant to Section 2.1 of this Agreement, the Distribution and the distribution by WMB to its creditors of the proceeds received from WPX referred to in clause (ii) in Recital D above, taken together, will qualify as a reorganization for U.S. federal income tax purposes pursuant to which no gain or loss will be recognized by WMB or its stockholders under Section 355, 361(b)(3), 368(a)(1)(D) and related provisions of the Code, and that this Agreement is intended to be, and is hereby adopted as, a plan of reorganization under Section 368 of the Code.
     G. The parties intend this Agreement and the Ancillary Agreements to set forth the principal arrangements between them regarding the Contribution, the IPO and the Distribution.

 

AGREEMENT
     In consideration of the foregoing and the mutual covenants and agreements herein contained, and intending to be legally bound hereby, the parties agree as follows:
ARTICLE I
DEFINITIONS
     Section 1.1 Table of Definitions . The following terms have the meanings set forth on the pages referenced below:

 	 	 	 	 	
Definition	 	Page	 	
Action	 	 	3	 	
Administrative Services Agreement	 	 	3	 	
Affiliate	 	 	3	 	
Agreement	 	 	1	 	
Ancillary Agreements	 	 	3	 	
Assets	 	 	3	 	
Bad Act	 	 	9	 	
Business Day	 	 	4	 	
Code	 	 	4	 	
Consents	 	 	4	 	
Contract	 	 	4	 	
Contribution	 	 	1	 	
CPR	 	 	34	 	
Distribution	 	 	1	 	
Distribution Agent	 	 	17	 	
Distribution Date	 	 	4	 	
Effective Date	 	 	4	 	
Environmental Laws	 	 	35	 	
Environmental Liabilities	 	 	35	 	
Exchange Act	 	 	4	 	
Financial Statements	 	 	4	 	
GAAP	 	 	4	 	
Governmental Approvals	 	 	4	 	
Governmental Authority	 	 	4	 	
Group	 	 	4	 	
Hazardous Substances	 	 	36	 	
Indemnifying Party	 	 	30	 	
Indemnitee	 	 	30	 	
Indemnity Payment	 	 	30	 	
Information	 	 	4	 	
Insurance Proceeds	 	 	5	 	
Intended Transferee	 	 	10	 	
Intended Transferor	 	 	10	 	
IPO	 	 	1	 	

 	 	 	 	 	
Definition	 	Page	 	
IPO Closing Date	 	 	5	 	
IPO Prospectus	 	 	5	 	
IPO Registration Statement	 	 	5	 	
IRS	 	 	5	 	
Law	 	 	5	 	
Liabilities	 	 	5	 	
Next Step Up Representatives	 	 	34	 	
Ordinary Course of Business	 	 	5	 	
Person	 	 	6	 	
Proceeding	 	 	39	 	
Record Date	 	 	6	 	
Registration Rights Agreement	 	 	6	 	
Regulation S-K	 	 	6	 	
Regulation S-X	 	 	6	 	
SEC	 	 	6	 	
Securities Act	 	 	6	 	
Subsidiary	 	 	6	 	
Tax Control	 	 	6	 	
Tax or Taxes	 	 	6	 	
Tax Sharing Agreement	 	 	6	 	
Third-Party Claim	 	 	31	 	
Transition Services Agreement	 	 	7	 	
Underwriters	 	 	7	 	
Underwriting Agreement	 	 	7	 	
WMB	 	 	1	 	
WMB Annual Statements	 	 	19	 	
WMB Board	 	 	7	 	
WMB Business	 	 	7	 	
WMB Common Stock	 	 	7	 	
WMB Entities	 	 	7	 	
WMB Group	 	 	7	 	
WMB Indemnitees	 	 	29	 	
WMB Liabilities	 	 	7	 	
WMB Shared Contract	 	 	7	 	

 2 

 

Table of Definitions (cont.)

 	 	 	 	 	
Definition	 	Page	 	
WMB’s Auditors	 	 	19	 	
WPX	 	 	1	 	
WPX Assets	 	 	7	 	
WPX Borrowing	 	 	8	 	
WPX Business	 	 	8	 	
WPX Class A Common Stock	 	 	8	 	
WPX Class B Common Stock	 	 	8	 	
WPX Common Stock	 	 	8	 	
WPX Credit Facility	 	 	8	 	
WPX Entities	 	 	8	 	
 	 	 	 	 	
Definition	 	Page	 	
WPX Group	 	 	8	 	
WPX Indebtedness	 	 	8	 	
WPX Indemnitees	 	 	30	 	
WPX Liabilities	 	 	8	 	
WPX Notes	 	 	9	 	
WPX Shared Contract	 	 	9	 	
WPX Transfer Agent	 	 	9	 	
WPX Voting Stock	 	 	20	 	
WPX’s Auditors	 	 	18	 	

     Section 1.2 Certain Defined Terms . For the purposes of this Agreement:
          “ Action ” means any claim, demand, action, suit, countersuit, audit, arbitration, inquiry, proceeding or investigation by or before any Governmental Authority or any United States or non-United States federal, state, local or international arbitration or mediation tribunal.
          “ Administrative Services Agreement ” means the Administrative Services Agreement, dated as of the date hereof, between WMB and WPX, as may be amended or modified from time to time, which provides for WMB’s provision of certain services to WPX between the IPO Closing Date and the Distribution Date.
          “ Affiliate ” of any Person means a Person that controls, is controlled by, or is under common control with such Person; provided , however , that for purposes of this Agreement and the Ancillary Agreements, none of the WMB Entities shall be deemed to be an Affiliate of any WPX Entity and none of the WPX Entities shall be deemed to be an Affiliate of any WMB Entity. As used herein, “control” means the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of such entity, whether through ownership of voting securities or other interests, by contract or otherwise.
          “ Ancillary Agreements ” means the Transition Services Agreement, the Administrative Services Agreement, the Tax Sharing Agreement, the Registration Rights Agreement and any other instruments, assignments, documents and agreements executed in connection with the implementation of the transactions contemplated by this Agreement.
          “ Assets ” means assets, properties and rights (including goodwill and rights arising under Contracts), wherever located (including in the possession of vendors, other Persons or elsewhere), whether real, personal or mixed, tangible, intangible or contingent, in each case whether or not recorded or reflected or required to be recorded or reflected on the books and records or financial statements of any Person.
 3 

 

          “ Business Day ” means a day other than a Saturday, Sunday or other day on which commercial banks in the State of Oklahoma are authorized or required by law to close.
          “ Code ” means the Internal Revenue Code of 1986, as amended.
          “ Consents ” means any consents, waivers or approvals from, or notification requirements to, any Person other than a member of either Group.
          “ Contract ” means any contract, agreement, lease, license, sales order, purchase order, instrument or other commitment that is binding on any Person or any part of its property under applicable law.
          “ Distribution Date ” means the date on which the Distribution occurs.
          “ Effective Date ” means 11:59 p.m., Tulsa, Oklahoma time, on the date that is immediately prior to the IPO Closing Date, or such other date as may be fixed by WMB.
          “ Exchange Act ” means the Securities Exchange Act of 1934, as amended, together with the rules and regulations promulgated thereunder.
          “ Financial Statements ” means the Annual Financial Statements and Quarterly Financial Statements collectively.
          “ GAAP ” means U.S. generally accepted accounting principles.
          “ Governmental Approvals ” means any notices, reports or other filings to be given to or made with, or any releases, Consents, substitutions, approvals, amendments, registrations, permits or authorizations to be obtained from, any Governmental Authority.
          “ Governmental Authority ” means any United States or non-United States federal, state, local, territorial, tribal or international court, government, department, commission, board, bureau, agency, official or other legislative, judicial, regulatory, administrative or governmental authority.
          “ Group ” means the WMB Group or the WPX Group, as the context requires.
          “ Information ” means information, including books and records, whether or not patentable or copyrightable, in written, oral, electronic or other tangible or intangible forms, stored in any medium, including studies, reports, records, books, contracts, instruments, surveys, discoveries, ideas, concepts, know-how, techniques, designs, specifications, drawings, blueprints, diagrams, models, prototypes, samples, flow charts, data, computer data, disks, diskettes, tapes, computer programs or other software, marketing plans, customer names, communications by or to attorneys (including attorney-client privileged communications), memos and other materials prepared by attorneys or under their direction (including attorney work product), and other technical, financial, employee or business information or data.
 4 

 

          “ Insurance Proceeds ” means, with respect to any Liability to be reimbursed by an Indemnifying Party that may be covered, in whole or in part, by insurance policies written by third-party providers, the amount of insurance proceeds actually received in cash under such insurance policy with respect to such Liability, net of any costs in seeking such collection.
          “ IPO Closing Date ” means the first date on which the proceeds of any sale of WPX Common Stock to the Underwriters are received.
          “ IPO Prospectus ” means the prospectus included in the IPO Registration Statement, including any prospectus subject to completion, final prospectus, or any supplement to or amendment of any of the foregoing.
          “ IPO Registration Statement ” means the Registration Statement on Form S-1 of WPX filed with the SEC pursuant to the Securities Act, registering the shares of WPX Common Stock to be issued in the IPO, together with all amendments thereto.
          “ IRS ” means the U.S. Internal Revenue Service.
          “ Law ” means any statute, law, regulation, ordinance, rule, judgment, rule of common law, order, decree, government approval, concession, grant, franchise, license, agreement, directive, guideline, policy, requirement or other governmental restriction or any similar form of decision of, or determination by, or any interpretation or administration of any of the foregoing by, any Governmental Authority, whether now or hereinafter in effect and, in each case, as amended.
          “ Liabilities ” means any and all losses, claims, charges, debts, demands, Actions, damages, obligations, payments, costs and expenses, sums of money, bonds, indemnities and similar obligations, penalties, covenants, Contracts, controversies, agreements, promises, omissions, guarantees, make whole agreements and similar obligations, and other liabilities, including all contractual obligations, whether absolute or contingent, inchoate or otherwise, matured or unmatured, liquidated or unliquidated, accrued or unaccrued, known or unknown, whenever arising, and including those arising under any Law, Action, threatened or contemplated Action (including the costs and expenses of demands, assessments, judgments, settlements and compromises relating thereto and attorneys’ fees and any and all costs and expenses (including allocated costs of in-house counsel and other personnel), whatsoever incurred in investigating, preparing or defending against any such Actions or threatened or contemplated Actions), order or consent decree of any Governmental Authority or any award of any arbitrator of any kind, and those arising under any contract, commitment or undertaking, including those arising under this Agreement or any Ancillary Agreement or incurred by a party hereto or thereto in connection with enforcing its rights to indemnification hereunder or thereunder, in each case, whether or not recorded or reflected or required to be recorded or reflected on the books and records or financial statements of any Person.
          “ Ordinary Course of Business ” means the ordinary course of the WPX Business as conducted by WMB and its Subsidiaries prior to the Effective Date consistent
 5 

 

with historical custom and practice during normal day-to-day operations and not requiring any special authorization of any nature.
          “ Person ” means an individual, corporation, partnership, limited liability company, limited liability partnership, syndicate, person, trust, association, organization or other entity, including any Governmental Authority, and including any successor, by merger or otherwise, of any of the foregoing.
          “ Record Date ” means the close of business on the date to be determined by WMB’s Board of Directors as the record date for determining the stockholders of WMB entitled to receive shares of WPX Common Stock pursuant to the Distribution.
          “ Registration Rights Agreement ” means the Registration Rights Agreement, dated as of the date hereof, between WMB and WPX, as may be amended or modified from time to time.
          “ Regulation S-K ” means Regulation S-K of the General Rules and Regulations promulgated by the SEC pursuant to the Securities Act.
          “ Regulation S-X ” means Regulation S-X of the General Rules and Regulations promulgated by the SEC pursuant to the Securities Act.
          “ SEC ” means the U.S. Securities and Exchange Commission.
          “ Securities Act ” means the Securities Act of 1933, as amended, together with the rules and regulations promulgated thereunder.
          “ Subsidiary ” of any Person means any corporation or other organization, whether incorporated or unincorporated, of which at least a majority of the securities or interests having by the terms thereof ordinary voting power to elect at least a majority of the board of directors or others performing similar functions with respect to such corporation or other organization is directly or indirectly owned or controlled by such Person or by any one or more of its Subsidiaries, or by such Person and one or more of its Subsidiaries; provided , however , that no Person that is not directly or indirectly wholly owned by any other Person shall be a Subsidiary of such other Person unless such other Person controls, or has the right, power or ability to control, that Person.
          “ Tax Control ” means the definition of “control” set forth in Section 368(c) of the Code.
          “ Tax ” or “ Taxes ” shall have the same meaning as ascribed to such term in the Tax Sharing Agreement.
          “ Tax Sharing Agreement ” means the Tax Sharing Agreement, dated as of the date hereof, between WMB and WPX, as may be amended or modified from time to time.
 6 

 

          “ Transition Services Agreement ” means the Transition Services Agreement, dated as of the date hereof, between WMB and WPX, as may be amended or modified from time to time, which provides for WMB’s provision of certain services to WPX on and after the Distribution Date.
          “ Underwriters ” means the managing underwriters for the IPO as described in the IPO Registration Statement.
          “ Underwriting Agreement ” means the Underwriting Agreement between WMB, WPX and the Underwriters relating to the IPO, as amended from time to time.
          “ WMB Board ” means the Board of Directors of WMB or an authorized committee thereof.
          “ WMB Business ” means the business and operations other than the WPX Business conducted by WMB and the WMB Entities (whether conducted independently or in association with one or more third parties through a partnership, joint venture or other mutual enterprise) at any time prior to, on or after the Effective Date.
          “ WMB Common Stock ” means the common stock, par value $1.00 per share, of WMB.
          “ WMB Entities ” means the members of the WMB Group.
          “ WMB Group ” means WMB and each direct or indirect Subsidiary of WMB, other than Persons in the WPX Group.
          “ WMB Liabilities ” means (without duplication): (a) any and all Liabilities that are expressly contemplated by this Agreement or any Ancillary Agreement to be retained or assumed by WMB or any WMB Entity, and all agreements, obligations and Liabilities of any WMB Entity under this Agreement or any of the Ancillary Agreements; (b) all Liabilities to the extent relating to, arising out of or resulting from the operation of the WMB Business, as conducted at any time prior to, on or after the Effective Date; and (c) all other Liabilities of any member of the WMB Group that are not WPX Liabilities.
          “ WMB Shared Contract ” means any Contract relating in part to the WPX Business not included in the WPX Assets.
          “ WPX Assets ” means all of WMB’s and its Subsidiaries’ right, title and interest in and to:
          (a) any and all Assets of WMB and its Subsidiaries that are used exclusively or held for use exclusively in the WPX Business, including without limitation all of WMB’s direct or indirect stock or other equity interests in the entities set forth on Exhibit A ; and
 7 

 

          (b) any and all Assets that are expressly listed, scheduled or otherwise clearly described in any Ancillary Agreement as Assets to be transferred to any WPX Entity.
          “ WPX Borrowing ” means the new indebtedness of WPX to be incurred pursuant to the issuance of the WPX Notes and the closing of the WPX Credit Facility (and any subsequent borrowings under the WPX Credit Facility).
          “ WPX Business ” means the exploration and production business and any other business and operations conducted by WPX and the WPX Entities (whether conducted independently or in association with one or more third parties through a partnership, joint venture or other mutual enterprise) at any time prior to, on or after the Effective Date.
          “ WPX Class A Common Stock ” means the Class A Common Stock, par value $1.00 per share, of WPX.
          “ WPX Class B Common Stock ” means the Class B Common Stock, par value $1.00 per share, of WPX.
          “ WPX Common Stock ” means, collectively, the Class A Common Stock and the Class B Common Stock and any other class or series of common stock of WPX currently existing or hereinafter created.
          “ WPX Credit Facility ” means the senior unsecured credit facility contemplated to be entered into by WPX concurrently with the IPO with a syndicate of bank and institutional lenders on such terms and conditions as agreed to by WMB, WPX and the other parties to the WPX Credit Facility.
          “ WPX Entities ” means the members of the WPX Group.
          “ WPX Group ” means WPX and each direct or indirect Subsidiary of WPX.
          “ WPX Indebtedness ” means the aggregate principal amount of total Liabilities (whether long-term or short-term) for borrowed money (including capitalized leases) of the WPX Group collectively, as determined for purposes of its Financial Statements prepared in accordance with GAAP.
          “ WPX Liabilities ” means (without duplication):
          (a) any and all Liabilities to the extent arising out of or relating to the WPX Business or the WPX Assets, in each case whether such Liabilities arise or accrue prior to, on or after the Effective Date (other than Tax-related Liabilities, which are exclusively governed by the Tax Sharing Agreement);
          (b) any and all Liabilities to the extent arising out of or relating to the operation of any business conducted by any WPX Entity at any time after the Effective Date;
 8 

 

          (c) any and all Liabilities that are expressly listed, scheduled or otherwise clearly described in any Ancillary Agreement as Liabilities to be assumed by WPX or any WPX Entity; and
          (d) all obligations of the WPX Group under or pursuant to this Agreement, any Ancillary Agreement or any other instrument entered into in connection herewith or therewith.
          “ WPX Notes ” means the senior unsecured notes contemplated to be issued by WPX concurrently with the IPO on such terms and conditions as agreed to by WMB, WPX and the underwriters for the WPX Notes.
          “ WPX Shared Contract ” means any Contract included in the WPX Assets relating in part to the WMB Business.
          “ WPX Transfer Agent ” means the transfer agent and registrar for the WPX Class A Common Stock.
ARTICLE II
THE CONTRIBUTION
     Section 2.1 Contribution of WPX Assets . Unless otherwise provided in this Agreement or in any Ancillary Agreement, on or before the Effective Date, WMB will (and WMB will cause its applicable Subsidiaries to) assign, transfer and convey to WPX and its applicable Subsidiaries, and WPX will receive and accept from WMB and its applicable Subsidiaries, all of WMB’s and its applicable Subsidiaries’ right, title and interest in and to the WPX Assets. Such assignments, transfers and conveyances will be effective at such times as provided in each respective Ancillary Agreement and will be subject to the terms and conditions of this Agreement and any applicable Ancillary Agreement.
     Section 2.2 Assumption of Liabilities . Unless otherwise provided in this Agreement or in any Ancillary Agreement, on or before the Effective Date, WPX will (and WPX will cause its applicable Subsidiaries to) assume, and on a timely basis pay, perform, satisfy and discharge the WPX Liabilities in accordance with their respective terms. WPX and its applicable Subsidiaries will be responsible for all WPX Liabilities, regardless of (a) when or where such Liabilities arose or arise, (b) whether the facts on which they are based occurred on, prior to or subsequent to the Effective Date, (c) where or against whom such Liabilities are asserted or determined, (d) whether asserted or determined on, prior to or subsequent to the Effective Date, or (e) whether arising from or alleged to arise from negligence, recklessness, violation of law, fraud or misrepresentation (each, a “ Bad Act ”) by any member of the WMB Group, the WPX Group or any of their respective past or present representatives; provided , however , that this Section 2.2 will not limit WPX’s right to make a claim against a WMB Group member for Losses suffered by it to the extent that such Losses are a direct result of a Bad Act committed by a WMB Group member subsequent to the Effective Date. Such assumptions of WPX Liabilities will be effective at
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such times as provided in each respective Ancillary Agreement and will be subject to the terms and conditions of this Agreement and any applicable Ancillary Agreement.
     Section 2.3 Effective Date; Deliveries . In furtherance of the assignment, transfer and conveyance of the WPX Assets and the assumption of the WPX Liabilities as set forth in this Agreement and the Ancillary Agreements, unless otherwise provided in this Agreement or in any Ancillary Agreement, on or before the Effective Date, the parties will execute and deliver, and they will cause their respective Subsidiaries and representatives, as applicable, to execute and deliver: (a) each of the Ancillary Agreements; (b) such bills of sale, stock powers, certificates of title, assignments of Contracts, subleases and other instruments of transfer, conveyance and assignment as, and to the extent, necessary or convenient to evidence the transfer, conveyance and assignment to WPX (or, as applicable, its Subsidiaries) of all of WMB’s (or, as applicable, its Subsidiaries’) right, title and interest in and to the WPX Assets; and (c) such assumptions of Contracts and other instruments of assumption as, and to the extent, necessary or convenient to evidence the valid and effective assumption of the WPX Liabilities by WPX (or, as applicable, its Subsidiaries).
     Section 2.4 Transfers Not Effected on or before the Effective Date .
          (a) The parties acknowledge and agree that some of the transfers contemplated by this Article II may not be effected on or before the Effective Date due to the inability of the parties to obtain necessary Consents or approvals or the inability of the parties to take certain other actions necessary to effect such transfers on or before the Effective Date. To the extent any transfers contemplated by this Article II have not been fully effected on or before the Effective Date, WMB and WPX will cooperate and use commercially reasonable efforts (and will cause the applicable members of its respective Group to use such efforts) to obtain any necessary Consents or approvals or take any other actions necessary to effect such transfers as promptly as practicable following the Effective Date.
          (b) Nothing in this Agreement will be deemed to require the transfer or assignment of any Contract or other Asset by any WMB Entity (an “ Intended Transferor ”) to any WPX Entity (an “ Intended Transferee ”) to the extent that such transfer or assignment would constitute a material breach of such Contract or cause forfeiture or loss of such Asset; provided , however , that even if such Contract or other Asset cannot be so transferred or assigned, such Contract or other Asset will be deemed a WPX Asset solely for purposes of determining whether any Liability is a WPX Liability.
          (c) If an attempted assignment would be ineffective or would impair an Intended Transferee’s rights under any such WPX Asset so that the Intended Transferee would not receive all such rights, then the parties will use commercially reasonable efforts to provide to, or cause to be provided to, the Intended Transferee, to the extent permitted by law, the rights of any such WPX Asset and take such other actions as may reasonably be requested by the other party in order to place the Intended Transferee, insofar as reasonably possible, in the same position as if such WPX Asset had been transferred as contemplated hereby. In connection therewith, (i) the Intended Transferor will promptly
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pass along to the Intended Transferee when received all benefits derived by the Intended Transferor with respect to any such WPX Asset, and (ii) the Intended Transferee will pay, perform and discharge on behalf of the Intended Transferor all of the Intended Transferor’s obligations with respect to any such WPX Asset in a timely manner and in accordance with the terms thereof which it may do without breach. If and when such Consents or approvals are obtained or such other required actions have been taken, the transfer of the applicable WPX Asset will be effected in accordance with the terms of this Agreement and any applicable Ancillary Agreement.
     Section 2.5 Shared Contracts . The parties agree as follows:
          (a) At the written request of WPX, WMB will, and will cause other members of the WMB Group to, to the extent permitted by the applicable WMB Shared Contract and applicable law, make available to WPX or applicable members of the WPX Group the benefits and rights under the WMB Shared Contracts (except where the benefits or rights under such WMB Shared Contracts are specifically provided pursuant to an Ancillary Agreement) which are substantially equivalent to the benefits and rights enjoyed by the WMB Group under each WMB Shared Contract for which such request is made by WPX, to the extent such benefits relate to the WPX Business; provided , however , that the applicable members of the WPX Group will assume and discharge (or promptly reimburse WMB for) the obligations and liabilities under the relevant WMB Shared Contracts associated with the benefits and rights so made available to them.
          (b) At the written request of WMB, WPX will, and will cause other members of the WPX Group to, to the extent permitted by the applicable WPX Shared Contract and applicable law, make available to WMB or applicable members of the WMB Group the benefits and rights under the WPX Shared Contracts (except where the benefits or rights under such WPX Shared Contracts are specifically provided pursuant to an Ancillary Agreement) which are substantially equivalent to the benefits and rights enjoyed by the WPX Group under each WPX Shared Contract for which such request is made by WMB, to the extent such benefits relate to the WMB Business; provided , however , that the applicable members of the WMB Group will assume and discharge (or promptly reimburse WPX for) the obligations and liabilities under the relevant WPX Shared Contracts associated with the benefits and rights so made available to them.
          (c) The parties’ rights and obligations pursuant to this Section 2.5 will terminate upon the earliest to occur of (i) the Distribution Date, (ii) the termination of WMB’s obligation to effect the Distribution pursuant to Section 9.1, and (iii) with respect to any WMB Shared Contract or WPX Shared Contract in particular, such time that the arrangement pursuant to this Section 2.5 is no longer permitted thereunder.
     Section 2.6 Termination of Agreements .
          (a) Except as set forth in Section 2.6(b), the WMB Entities, on the one hand, and the WPX Entities, on the other hand, hereby terminate any and all agreements, arrangements, commitments or understandings (including intercompany work orders), whether or not in writing, between or among any WMB Entity, on the one hand, and any
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WPX Entity, on the other hand, effective as of the Effective Date. No such terminated agreement, arrangement, commitment or understanding (including any provision thereof that purports to survive termination) shall be of any further force or effect from and after the Effective Date. Each party shall, at the reasonable request of the other party, take, or cause to be taken, such other actions as may be necessary to effect the foregoing.
          (b) The provisions of Section 2.6(a) shall not apply to any of the following agreements, arrangements, commitments or understandings (or to any of the provisions thereof):
               (i) this Agreement and the Ancillary Agreements (and each other agreement or instrument expressly contemplated by this Agreement or any Ancillary Agreement to be entered into by any WMB Entity or WPX Entity);
               (ii) any agreements, arrangements, commitments or understandings to which any non-wholly owned Subsidiary or non-wholly owned Affiliate of WMB or WPX, as the case may be, is a party;
               (iii) any other agreements, arrangements, commitments or understandings that this Agreement or any Ancillary Agreement expressly contemplates will survive the Effective Date;
               (iv) any confidentiality or non-disclosure agreements among any members of either Group or employees of any member of either Group, including any obligation not to disclose proprietary or privileged information; and
               (v) any agreements, arrangements, commitments or understandings listed or described on Schedule 2.6(b)(v) .
          (c) Except as otherwise expressly and specifically provided in this Agreement or any Ancillary Agreement, all intercompany receivables, payables, loans and other accounts between any WMB Entity, on the one hand, and any WPX Entity, on the other hand, in existence as of immediately prior to the Effective Date shall be satisfied and/or settled by the relevant members of the WMB Group and the WPX Group no later than the Effective Date by (i) forgiveness by the relevant obligor or (ii) one or a related series of repayments, distributions of and/or contributions to capital, in each case as determined by WMB.
     Section 2.7 Governmental Approvals and Consents . To the extent that any of the transactions contemplated by this Agreement or any Ancillary Agreement requires any Governmental Approval or Consent, the parties will use their reasonable best efforts to obtain such Governmental Approval or Consent.
     Section 2.8 Disclaimer of Representations and Warranties . Each of WMB (on behalf of itself and each other WMB Entity) and WPX (on behalf of itself and each other WPX Entity) understands and agrees that, except as expressly set forth herein or in any Ancillary Agreement, no party (including its Affiliates) to this Agreement, any
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Ancillary Agreement or any other agreement or document contemplated by this Agreement, any Ancillary Agreement or otherwise, is making any representations or warranties relating in any way to the Contribution, Distribution or WPX Assets.
ARTICLE III
THE IPO
     Section 3.1 Actions Prior to the IPO . Subject to the conditions hereof, WMB and WPX will use their commercially reasonable efforts to consummate the IPO, including, without limitation, by taking the actions specified in this Section 3.1.
          (a) WPX will file such amendments or supplements to the IPO Registration Statement as may be necessary in order to cause the IPO Registration Statement to become and remain effective as required by applicable law or by the Underwriters, including, without limitation, filing such amendments and supplements thereto as may be required by the Underwriting Agreement, the SEC or applicable securities laws.
          (b) WPX will enter into the Underwriting Agreement, in form and substance reasonably satisfactory to each party, and each party will comply with its respective obligations thereunder.
          (c) WPX will use its commercially reasonable efforts to take all such action as may be necessary or appropriate under applicable state securities and blue sky laws of the United States (and any comparable laws under any foreign jurisdictions) in connection with the IPO.
          (d) WPX will prepare, file and use commercially reasonable efforts to seek to make effective, an application for listing of the WPX Class A Common Stock to be issued in the IPO on the New York Stock Exchange, subject to official notice of issuance.
          (e) WPX will participate in the preparation of materials and presentations that WMB and the Underwriters will deem necessary or desirable.
          (f) WPX will cooperate in all respects with WMB in connection with the pricing and timing of the WPX Class A Common Stock to be issued in the IPO and will, at WMB’s direction, promptly take any and all actions necessary or desirable to consummate the IPO as contemplated by the IPO Registration Statement and the Underwriting Agreement.
     Section 3.2 Use of Proceeds; Consideration for WPX Assets . The IPO will be a primary offering of WPX Class A Common Stock, and WPX shall use the net proceeds from the IPO as set forth in the IPO Prospectus. The contribution or other transfer of WPX Assets by WMB to WPX in connection with the Contribution will be in exchange for (a) the conversion of the WPX Common Stock held by WMB into shares of WPX Class B Common Stock such that WMB will own all of the outstanding WPX Class B Common Stock immediately following the consummation of the IPO, (b) the distribution to WMB of a portion of the IPO and WPX Borrowing net proceeds (as described in the IPO Prospectus), and (c) the assumption by WPX of WPX Liabilities.
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     Section 3.3 Conditions to the IPO . The obligations of the parties to consummate the IPO will be subject to such conditions as WMB will determine in its sole and absolute discretion, which conditions will be for the sole benefit of WMB, may be waived by WMB in its sole and absolute discretion, and any determination by WMB regarding the satisfaction or waiver of any of such conditions will be conclusive. Such conditions will include, without limitation, the conditions specified in this Section 3.3.
          (a) The IPO Registration Statement will have been declared effective by the SEC, and there will be no stop order in effect with respect thereto and no proceeding for that purpose will have been instituted by the SEC.
          (b) The actions and filings with regard to state securities and blue sky laws of the United States (and any comparable laws under any foreign jurisdictions) referred to in Section 3.1 will have been taken and, where applicable, have become effective or been accepted.
          (c) The WPX Class A Common Stock to be issued in the IPO will have been accepted for listing on the New York Stock Exchange, subject to official notice of issuance.
          (d) WPX will have entered into the Underwriting Agreement and all conditions to the obligations of WPX and the Underwriters thereunder will have been satisfied or waived.
          (e) WMB will be satisfied in its sole and absolute discretion that (i) it will possess Tax Control of WPX immediately following the consummation of the IPO, (ii) all other matters regarding the Tax consequences of the Distribution will, to the extent applicable as of the time the IPO is consummated, be satisfied or can reasonably be anticipated to be satisfied, and (iii) there will be no event or condition that may cause any of such conditions not to be satisfied as of the time of the Distribution or thereafter.
          (f) No order, injunction or decree issued by any court or agency of competent jurisdiction or other legal restraint or prohibition preventing the consummation of the IPO or any of the other transactions contemplated by this Agreement or any Ancillary Agreement will be in effect.
          (g) WMB will have determined that the terms of the IPO, including the timing and pricing thereof, and other material matters in connection therewith, are acceptable to WMB.
          (h) WPX will have incurred the WPX Borrowing on terms and with lender(s) acceptable to WMB.
          (i) This Agreement will not have been terminated.
     Section 3.4 Conversion of Outstanding WPX Common Stock into WPX Class B Common Stock . Prior to the consummation of the IPO, WMB and WPX will each take all actions (including, without limitation, such actions that are required to effect the adoption
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by WPX of an amended and restated certificate of incorporation) that WMB determines, in its sole discretion, may be required to provide for the conversion of the issued and outstanding shares of WPX Common Stock held by WMB as of the date hereof into a number of shares of WPX Class B Common Stock determined by WMB, and in any case such that WMB possesses Tax Control of WPX directly and of Apco Oil and Gas International Inc. indirectly at all times before, at the time of, and immediately following, the consummation of the IPO.
ARTICLE IV
THE DISTRIBUTION
     Section 4.1 The Distribution . WMB intends, following the consummation of the IPO, to complete the Distribution in 2012. WMB will, in its sole and absolute discretion, determine the date of the consummation of the Distribution and all terms of the Distribution, including without limitation, the form, structure and terms of any transaction(s) and/or offering(s) to effect the Distribution and the timing of and conditions to the consummation of the Distribution. In addition, WMB may, at any time and from time to time until the completion of the Distribution, modify or change the terms of the Distribution, including, without limitation, by accelerating or delaying the timing of the consummation of all or part of the Distribution. WPX will cooperate with WMB in all respects to accomplish the Distribution and will, at WMB’s direction, promptly take any and all actions necessary or desirable to effect the Distribution, including, without limitation, to the extent necessary, the registration under the Securities Act and the Exchange Act of the WPX Common Stock on an appropriate registration form or forms to be designated by WMB. WMB will select any investment banker(s) and manager(s) in connection with the Distribution, as well as any financial printer, solicitation and/or exchange agent and financial, legal, accounting and other advisors for WMB, provided , however , that nothing in this Agreement will prohibit WPX from engaging (at its own expense) its own financial, legal, accounting and other advisors in connection with the Distribution.
     Section 4.2 Actions Prior to the Distribution . In connection with the Distribution, the parties will take the actions set forth in this Section 4.2.
          (a) WMB and WPX will prepare and mail, prior to any Distribution Date, to the holders of WMB Common Stock, such information concerning WPX and the Distribution and such other matters as WMB reasonably determines and as may be required by law. WMB and WPX will prepare, and WPX will, to the extent required by applicable law, file with the SEC any such documentation that WMB determines is necessary or desirable to effect the Distribution, and WMB and WPX will each use its commercially reasonable efforts to obtain all necessary approvals from the SEC with respect thereto as soon as practicable.
          (b) WPX will use its commercially reasonable efforts to take all such action as may be necessary or desirable under applicable state securities and blue sky laws of the United States (and any comparable laws under any foreign jurisdictions) in connection with the Distribution.
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          (c) WPX will prepare, file and use commercially reasonable efforts to seek to make effective, an application for listing of the WPX Common Stock to be distributed in the Distribution on the New York Stock Exchange, subject to official notice of issuance.
          (d) WPX will take all reasonable steps necessary or desirable to cause the conditions set forth in Section 4.3 to be satisfied and to effect the Distribution.
     Section 4.3 Conditions to the Distribution . The consummation of the Distribution will be subject to the satisfaction, or waiver by WMB in its sole and absolute discretion, of the conditions set forth in this Section 4.3. Any determination by WMB regarding the satisfaction or waiver of any of such conditions will be conclusive. For the avoidance of doubt, in the event that WMB determines not to consummate the Distribution because one or more of such conditions is not satisfied or for any other reason, such determination by WMB will not impact the effectiveness of the Contribution or the IPO.
          (a) The receipt by WMB, in form and substance satisfactory to it, of a ruling by the IRS and an opinion from its legal advisors regarding the tax consequences of the Distribution and such other matters, as it will determine to be necessary or advisable in its sole and absolute discretion.
          (b) The receipt of any Governmental Approvals and material Consents necessary to consummate the Distribution, which Governmental Approvals and Consents will be in full force and effect.
          (c) No order, injunction, decree or regulation issued by any court or agency of competent jurisdiction or other legal restraint or prohibition preventing the consummation of the Distribution will be in effect and no other event outside the control of WMB will have occurred or failed to occur that prevents the consummation of the Distribution.
          (d) The actions and filings necessary or appropriate under applicable securities laws in connection with the Distribution will have been taken or made, and, where applicable, have become effective or been accepted.
          (e) The WPX Common Stock to be distributed in the Distribution will have been accepted for listing on the New York Stock Exchange, subject to official notice of issuance.
          (f) The receipt by WMB, in form and substance satisfactory to it, of (i) an opinion from Delaware counsel, selected by WMB in its sole and absolute discretion, regarding the appropriateness of the determination by the WMB Board that WMB has sufficient surplus under Delaware law to permit the Distribution, (ii) an opinion from its financial advisor with respect to (A) the fairness, as of the date of such opinion, to holders of WMB Common Stock, from a financial point of view, of the Distribution, and (B) the ability of WMB and WPX, given their respective capital structures following the Distribution, to finance their respective operating and capital requirements through a specified date based on conditions in the capital markets as of the date of such opinion, and
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(iii) appropriate certificates from WPX and/or WPX’s senior management with respect to factual matters required by the advisors to render the opinions referenced in (i) and (ii).
     Section 4.4 Certain Stockholder Matters.
          (a) Subject to Section 4.3 hereof, on or prior to the Distribution Date, WMB will deliver to a distribution agent to be appointed by WMB (the “ Distribution Agent ”) for the benefit of holders of record of WMB Common Stock on the Record Date, a single stock certificate, endorsed by WMB in blank, representing all of the outstanding shares of WPX Common Stock then owned by WMB, and WMB will instruct the Distribution Agent to deliver to the WPX Transfer Agent true, correct and complete copies of the stock and transfer records reflecting the holders of WMB Common Stock entitled to receive shares of WPX Common Stock in connection with the Distribution. WMB will cause its transfer agent to instruct the Distribution Agent to distribute on the Distribution Date or as soon as reasonably practicable thereafter the appropriate number of shares of WPX Common Stock to each such holder or designated transferee(s) of such holder. WMB will cooperate, and will instruct the Distribution Agent to cooperate, with WPX and the WPX Transfer Agent, and WPX will cooperate, and will instruct the WPX Transfer Agent to cooperate, with WMB and the Distribution Agent, in connection with all aspects of the Distribution and all other matters relating to the issuance and delivery of certificates representing, or other evidence of ownership of, the shares of WPX Common Stock to be distributed to the holders of WMB Common Stock in connection with the Distribution.
          (b) Subject to Section 4.4(d), each holder of WMB Common Stock on the Record Date (or such holder’s designated transferee(s)) will be entitled to receive in the Distribution a number of shares of WPX Common Stock equal to the number of shares of WMB Common Stock held by such holder on the Record Date, multiplied by a fraction, (i) the numerator of which is the number of shares of WPX Common Stock beneficially owned by WMB or any other member of the WMB Group on the Record Date, and (ii) the denominator of which is the number of Shares of WMB Common Stock outstanding on the Record Date. In the event that the Distribution consists of more than one class of WPX Common Stock, each holder of WMB Common Stock will receive shares of WPX Common Stock, calculated as provided above, except that the calculation will be performed separately for each such class of stock. WMB, in its sole discretion, may distribute cash in lieu of any fractional shares received by a holder of WMB Common Stock.
          (c) Until such WPX Common Stock is duly transferred in accordance with applicable law, WPX will regard the Persons entitled to receive such WPX Common Stock as record holders of WPX Common Stock in accordance with the terms of the Distribution without requiring any action on the part of such Persons. WPX agrees that, subject to any transfers of such stock, (i) each such holder will be entitled to receive all dividends payable on, and exercise voting rights and all other rights and privileges with respect to, the shares of WPX Common Stock then held by such holder, and (ii) each such holder will be entitled, without any action on the part of such holder, to receive one or more certificates representing, or other evidence of ownership of, the shares of WPX Common Stock then held by such holder.
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          (d) Notwithstanding anything to the contrary in this Section 4.4, in the event that the Distribution is not made in the form of a pro rata distribution of WPX Common Stock to holders of WMB Common Stock, the above provisions of this Section 4.4 will not apply to the Distribution.
          (e) If WMB determines (in its sole discretion) to effect the separation of WPX from WMB through a transaction other than the Distribution (whether by means of a split off, a share exchange or otherwise), WPX shall use commercially reasonable efforts to take all actions (or refrain from any actions) reasonably requested by WMB in connection therewith.
ARTICLE V
FINANCIAL AND OTHER COVENANTS
     Section 5.1 Financial and Other Information.
          (a) Financial Information . WPX agrees that, for so long as WMB is required to consolidate the results of operations and financial position of WPX and any other members of the WPX Group or to account for its investment in WPX under the equity method of accounting (determined in accordance with GAAP consistently applied and consistent with SEC reporting requirements), WPX will: (i) comply with all requirements under applicable law regarding disclosure controls and procedures and internal control over financial reporting; (ii) maintain internal systems and procedures that will provide WMB with reasonable assurance that WPX’s financial statements and other publicly reported information is reliable and timely prepared in accordance with GAAP and any other applicable law; and (iii) provide WMB with financial reports, including consolidated financial statements (and notes thereto) and discussion and analysis by management of WPX’s financial condition and liquidity, in the form, and in accordance with the dates, specified by WMB.
          (b) Auditors and Audits; Annual Statements and Accounting . WPX agrees that, for so long as WMB is required to consolidate WPX’s results of operations and financial position or to account for its investment in WPX under the equity method of accounting (in accordance with GAAP):
               (i)  Selection of WPX Auditors . Unless required by law, WPX will not select a different accounting firm than Ernst & Young LLP (or its affiliate accounting firms) (unless so directed by WMB in accordance with a change by WMB in its accounting firm) to serve as its (and the WPX Affiliates’) independent certified public accountants (“ WPX’s Auditors ”) without WMB’s prior written consent (which will not be unreasonably withheld); provided, however, that, to the extent any such WPX Affiliates are currently using a different accounting firm to serve as their independent certified public accountants, such WPX Affiliates may continue to use such accounting firm provided such accounting firm is reasonably satisfactory to WMB.
               (ii)  Audit Timing . WPX will use its commercially reasonable efforts to enable WPX’s Auditors to complete their audit such that they will date their
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opinion on the Annual Financial Statements on the same date that WMB’s independent certified public accountants (“ WMB’s Auditors ” ) date their opinion on WMB’s audited annual financial statements (the “WMB Annual Statements”), and to enable WMB to meet its timetable for the printing, filing and public dissemination of the WMB Annual Statements, all in accordance with Section 5.1(a) hereof and as required by applicable law.
               (iii)  Information Needed by WMB . WPX will provide to WMB on a timely basis all information that WMB reasonably requires to meet its schedule for the preparation, printing, filing, and public dissemination of the WMB Annual Statements in accordance with Section 5.1(a) hereof and as required by applicable law. Without limiting the generality of the foregoing, WPX will provide all required financial information with respect to the WPX Group to WPX’s Auditors in a sufficient and reasonable time and in sufficient detail to permit WPX’s Auditors to take all steps and perform all reviews necessary to provide sufficient assistance to WMB’s Auditors with respect to information to be included or contained in the WMB Annual Statements.
               (iv)  Access to WPX Auditors . WPX will authorize WPX’s Auditors to make available to WMB’s Auditors both the personnel who performed, or are performing, the annual audit of WPX and work papers related to the annual audit of WPX, in all cases within a reasonable time prior to WPX’s Auditors’ opinion date, so that WMB’s Auditors are able to perform the procedures they consider necessary to take responsibility for the work of WPX’s Auditors as it relates to WMB’s Auditors’ report on WMB’s statements, all within sufficient time to enable WMB to meet its timetable for the printing, filing and public dissemination of the WMB Annual Statements.
               (v)  Access to Records . If WMB determines in good faith that there may be some inaccuracy in a WPX Group member’s financial statements or deficiency in a WPX Group member’s internal accounting controls or operations that could materially impact WMB’s financial statements, at WMB’s request, WPX will provide WMB’s internal auditors with access to the WPX Group’s books and records so that WMB may conduct reasonable audits relating to the financial statements provided by WPX under this Agreement as well as to the internal accounting controls and operations of the WPX Group.
               (vi)  Notice of Changes . Subject to Section 5.1(a)(vii), WPX will give WMB as much prior notice as reasonably practicable of any proposed determination of, or any significant changes in, WPX’s accounting estimates or accounting principles from those in effect on the Effective Date. WPX will consult with WMB and, if requested by WMB, WPX will consult with WMB’s Auditors with respect thereto. WPX will not make any such determination or changes without WMB’s prior written consent if such a determination or a change would be sufficiently material to be required to be disclosed in WPX’s or WMB’s financial statements as filed with the SEC or otherwise publicly disclosed therein.
               (vii)  Accounting Changes Requested by WMB . Notwithstanding clause (vi) above, WPX will make any changes in its accounting estimates or accounting
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principles that are requested by WMB in order for WPX’s accounting practices and principles to be consistent with those of WMB.
               (viii)  Special Reports of Deficiencies or Violations . WPX will report in reasonable detail to WMB the following events or circumstances promptly after any executive officer of WPX or any member of the WPX Board of Directors becomes aware of such matter: (A) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect WPX’s ability to record, process, summarize and report financial information; (B) any fraud, whether or not material, that involves management or other employees who have a significant role in WPX’s internal control over financial reporting; (C) any illegal act within the meaning of Section 10A(b) and (f) of the Exchange Act; and (D) any report of a material violation of law that an attorney representing any WPX Group member has formally made to any officers or directors of WPX pursuant to the SEC’s attorney conduct rules (17 C.F.R. Part 205).
     Section 5.2 Other Covenants . In addition to the other covenants contained in this Agreement and the Ancillary Agreements, WPX hereby covenants and agrees that, for so long as WMB beneficially owns at least 50% of the total voting power of all classes of then outstanding capital stock of WPX entitled to vote generally in the election of directors (“ WPX Voting Stock ”):
          (a) WPX will not, without the prior written consent of WMB (which WMB may withhold in its sole and absolute discretion), take, or cause to be taken, directly or indirectly, any action, including making or failing to make any election under the law of any state, which has the effect, directly or indirectly, of restricting or limiting the ability of WMB to freely sell, transfer, assign, pledge or otherwise dispose of shares of WPX Common Stock or would restrict or limit the rights of any transferee of WMB as a holder of WPX Common Stock. Without limiting the generality of the foregoing, WPX will not, without the prior written consent of WMB (which WMB may withhold in its sole and absolute discretion), take any action, or take any action to recommend to its stockholders any action, which would among other things, limit the legal rights of, or deny any benefit to, WMB as a WPX stockholder either (i) solely as a result of the amount of Common Stock owned by WMB or (ii) in a manner not applicable to WPX stockholders generally.
          (b) WPX will not, without the prior written consent of WMB (which it may withhold in its sole and absolute discretion), issue any shares of WPX Common Stock or any rights, warrants or options to acquire WPX Common Stock (including, without limitation, securities convertible into or exchangeable for WPX Common Stock), if after giving effect to such issuances and considering all of the shares of WPX Common Stock acquirable pursuant to such rights, warrants and options to be outstanding on the date of such issuance (whether or not then exercisable), WMB would own (i) less than 50% of the total value of all classes of stock of WPX, (ii) less than 80% of the WPX Voting Stock, (iii) less than 80% of any class of stock other than WPX Voting Stock or (iv) less than 80% of the total value of all classes of stock of WPX.
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          (c) To the extent that WMB is a party to any Contracts that provide that certain actions or inactions of WMB Affiliates (which for purposes of such Contract includes any member of the WPX Group) may result in WMB being in breach of or in default under such Contracts and WMB has advised WPX of the existence, and has furnished WPX with copies, of such Contracts (or the relevant portions thereof), WPX will not take or fail to take, as applicable, and WPX will cause the other members of the WPX Group not to take or fail to take, as applicable, any actions that reasonably could result in WMB being in breach of or in default under any such Contract. The parties acknowledge and agree that from time to time WMB may in good faith (and not solely with the intention of imposing restrictions on WPX pursuant to this covenant) enter into additional Contracts or amendments to existing Contracts that provide that certain actions or inactions of WMB Subsidiaries or Affiliates (including, for purposes of this Section 5.2(c), members of the WPX Group) may result in WMB being in breach of or in default under such Contracts. In such event, provided WMB has notified WPX of such additional Contracts or amendments to existing Contracts, WPX will not thereafter take or fail to take, as applicable, and WPX will cause the other members of the WPX Group not to take or fail to take, as applicable, any actions that reasonably could result in WMB being in breach of or in default under any such additional Contracts or amendments to existing Contracts. WMB acknowledges and agrees that WPX will not be deemed in breach of this Section 5.2(c) to the extent that, prior to being notified by WMB of an additional Contract or an amendment to an existing Contract pursuant to this Section 5.2(c), a WPX Group member already has taken or failed to take one or more actions that would otherwise constitute a breach of this Section 5.2(c) had such action(s) or inaction(s) occurred after such notification, provided that WPX does not, after notification by WMB, take any further action or fail to take any action that contributes further to such breach or default. WPX agrees that any Information provided to it pursuant to this Section 5.2(c) will constitute Information that is subject to WPX’s obligations under Article VI.
     Section 5.3 Covenants Regarding the Incurrence of Indebtedness.
          (a) WPX hereby covenants and agrees that, for so long as WMB is required to consolidate the results of operations and financial position of WPX and any other members of the WPX Group or to account for its investment in WPX under the equity method of accounting (determined in accordance with GAAP consistently applied and consistent with SEC reporting requirements), WPX will not, and WPX will not permit any other member of the WPX Group to, without WMB’s prior written consent (which WMB may withhold in its sole and absolute discretion), create, incur, assume or suffer to exist any WPX Indebtedness (other than the WPX Borrowing).
          (b) In order to implement this Section 5.3, WPX will notify WMB in writing at least 45 Business Days prior to the time it or any other member of the WPX Group contemplates incurring any WPX Indebtedness of its intention to do so and will obtain WMB’s prior written consent to the incurrence of such proposed additional WPX Indebtedness. Any such written notification from WPX to WMB will include documentation of any existing WPX Indebtedness and estimated WPX Indebtedness after giving effect to such proposed incurrence of additional WPX Indebtedness. WMB will have the right to verify the accuracy of such information and WPX will cooperate fully
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with WMB in such effort (including, without limitation, by providing WMB with access to the working papers and underlying documentation related to any calculations used in determining such information).
ARTICLE VI
EXCHANGE OF INFORMATION; CONFIDENTIALITY
     Section 6.1 Agreement for Exchange of Information .
          (a) Except in the case of an adversarial Action or threatened adversarial Action related to a request hereunder by any member of either the WMB Group or the WPX Group against any member of the other Group (which shall be governed by such discovery rules as may be applicable thereto), and subject to Section 6.1(b), each of WMB and WPX, on behalf of the members of its respective Group, shall use reasonable best efforts to provide (except as otherwise provided in this Agreement or any Ancillary Agreement, at the sole cost and expense of the requesting party), or cause to be provided, to the other Group, at any time before or after the Effective Date, as soon as reasonably practicable after written request therefor, any Information in the possession or under the control of the members of such respective Group that the requesting party reasonably requests (i) in connection with reporting, disclosure, filing or other requirements imposed on the requesting party (including under applicable securities, defense contracting or tax Laws) by a Governmental Authority having jurisdiction over the requesting party, (ii) for use in any other judicial, regulatory, administrative, tax, insurance or other proceeding or in order to satisfy audit, accounting, claims, regulatory, investigation, litigation, tax or other similar requirements, or (iii) to comply with its obligations under this Agreement, any Ancillary Agreement or the WPX Borrowing. The receiving party shall use any Information received pursuant to this Section 6.1(a) solely to the extent reasonably necessary to satisfy the applicable obligations or requirements described in the immediately preceding sentence and shall otherwise take reasonable steps to protect such Information. Nothing in this Section 6.1 shall be construed as obligating a party to create Information not already in its possession or control.
          (b) In the event that any party determines that the exchange of any Information pursuant to Section 6.1(a) is reasonably likely to violate any Law or binding agreement, or waive or jeopardize any attorney-client privilege, or attorney work product protection, such party shall not be required to provide access to or furnish such Information to the other party; provided , however , that the parties shall take all reasonable measures to permit compliance with Section 6.1(a) in a manner that avoids any such harm or consequence. WMB and WPX intend that any provision of access to or the furnishing of Information that would otherwise be within the ambit of any legal privilege shall not operate as a waiver of such privilege.
          (c) After the Effective Date, each of WMB and WPX shall maintain in effect systems and controls reasonably intended to enable the members of the other Group to satisfy their respective known reporting, accounting, disclosure, audit and other obligations.
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     Section 6.2 Ownership of Information . Any Information owned by a member of one Group that is provided to a requesting party pursuant to Section 6.1 shall be deemed to remain the property of the providing party. Except as specifically set forth herein, nothing contained in this Agreement shall be construed as granting or conferring rights of license or otherwise in any such Information.
     Section 6.3 Compensation for Providing Information . The party requesting Information pursuant to Section 6.1 agrees to reimburse the party providing such Information for the reasonable costs, if any, of creating, gathering and copying such Information, to the extent that such costs are incurred for the benefit of the requesting party. Except as may be otherwise specifically provided elsewhere in this Agreement or in any other agreement between the parties, such costs shall be computed in accordance with the providing party’s standard methodology and procedures.
     Section 6.4 Record Retention . To facilitate the possible exchange of Information pursuant to this Article VI and other provisions of this Agreement from and after the Effective Date, each of the parties agrees to use reasonable best efforts to retain all Information in accordance with WMB’s “Records and Information Management Policy” as in effect immediately prior to the Effective Date or as modified in good faith thereafter.
     Section 6.5 Limitation of Liability . No party shall have any liability to any other party in the event that any Information exchanged or provided pursuant to this Agreement that is an opinion, estimate or forecast, or that is based on an opinion, estimate or forecast, is found to be inaccurate, in the absence of willful misconduct by the party providing such Information. No party shall have any liability to any other party if any Information is destroyed after reasonable best efforts by such party to comply with the provisions of Section 6.4.
     Section 6.6 Other Agreements Providing for Exchange of Information . The rights and obligations granted under this Article VI shall be subject to any specific limitations, qualifications or additional provisions on the sharing, exchange or confidential treatment of Information set forth in any Ancillary Agreement.
     Section 6.7 Cooperation .
          (a) From and after the Effective Date, except in the case of an adversarial Action or threatened adversarial Action by any member of either the WMB Group or the WPX Group against any member of the other Group (which shall be governed by such discovery rules as may be applicable thereto), each party, upon reasonable written request of the other party, shall use reasonable efforts to cooperate and consult in good faith with the other party to the extent such cooperation and consultation is reasonably necessary with respect to (i) any Action, (ii) this Agreement or any of the Ancillary Agreements or any of the transactions contemplated hereby or thereby or (iii) any audit, investigation or any other legal requirement, and, upon reasonable written request of the other party, shall use reasonable efforts to make available to such other party the former, current and future directors, officers, employees, other personnel and agents of
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the members of its respective Group (whether as witnesses or otherwise). The requesting party shall bear all costs and expenses in connection therewith.
          (b) Notwithstanding the foregoing, Section 6.7(a) shall not require a party to take any step that would significantly interfere, or that such party reasonably determines could significantly interfere, with its business.
     Section 6.8 Confidentiality .
          (a) Subject to Section 6.9, each of WMB and WPX, on behalf of itself and each member of its Group, shall hold, and shall cause its respective directors, officers, employees, agents, accountants, counsel and other advisors and representatives to hold, in strict confidence and not release or disclose, with at least the same degree of care, but no less than a reasonable degree of care, that it applies to its own business sensitive and proprietary information, all Information concerning the other Group or its business that is either in its possession (including Information in its possession prior to the Distribution) or furnished by any member of such other Group or its respective directors, officers, employees, agents, accountants, counsel and other advisors and representatives at any time pursuant to this Agreement, any Ancillary Agreement or otherwise, and shall not use any such Information other than for such purposes as shall be expressly permitted hereunder or thereunder, except, in each case, to the extent that such Information is (i) in the public domain through no fault of such party or any member of such Group or any of their respective directors, officers, employees, agents, accountants, counsel and other advisors and representatives, (ii) later lawfully acquired from other sources by such party (or any member of such party’s Group), which sources are not themselves bound by a confidentiality obligation, or (iii) independently generated without reference to any proprietary or confidential Information of the disclosing party or its Group.
          (b) No receiving party shall release or disclose, or permit to be released or disclosed, any such Information concerning the other Group to any other Person, except its directors, officers, employees, agents, accountants, counsel and other advisors and representatives who need to know such Information (who shall be advised of their obligations hereunder with respect to such Information), except in compliance with Section 6.9. Without limiting the foregoing, when any Information concerning the other Group or its business is no longer needed for the purposes contemplated by this Agreement or any Ancillary Agreement, each disclosing party will, promptly after the request of the receiving party, either return to the disclosing party all Information in a tangible form (including all copies thereof and all notes, extracts or summaries based thereon) or certify to the disclosing party that it has destroyed such Information (and such copies thereof and such notes, extracts or summaries based thereon).
     Section 6.9 Protective Arrangements . In the event that any party or any member of its Group either determines on the advice of its counsel that it should disclose any Information pursuant to applicable Law or receives any demand under lawful process or from any Governmental Authority or properly constituted arbitral authority to disclose or provide Information of any other party (or any member of any other party’s Group) that is subject to the confidentiality provisions hereof, the Person required to disclose the
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Information shall give the applicable Person prompt, and to the extent reasonably practicable, prior written notice of such disclosure and an opportunity to contest such disclosure, and shall use reasonable best efforts to cooperate, at the expense of the requesting Person, in seeking any reasonable protective arrangements requested by such Person. In the event that such appropriate protective arrangement or order or other remedy is not obtained, the Person that is required to disclose such Information shall furnish, or cause to be furnished, only that portion of such Information that is legally required to be disclosed and shall use reasonable best efforts to ensure that confidential treatment is accorded such Information. This Section 6.9 shall not apply to the disclosure of any Information to any Governmental Authority that is reasonably necessary to respond to any inquiry by any Governmental Authority.
ARTICLE VII
ADDITIONAL COVENANTS AND OTHER MATTERS
     Section 7.1 Further Assurances .
          (a) In addition to the actions specifically provided for elsewhere in this Agreement, each of the parties shall use its reasonable best efforts, prior to, on and after the Effective Date, to take, or cause to be taken, all actions, and to do, or cause to be done, all things, reasonably necessary, proper or advisable under applicable Law, regulations and agreements to consummate and make effective the transactions contemplated by this Agreement and the Ancillary Agreements.
          (b) On or prior to the Effective Date, WMB and WPX in their respective capacities as direct and indirect stockholders of their respective Subsidiaries, shall each ratify any actions that are reasonably necessary or desirable to be taken by WMB and WPX or any other Subsidiary of WMB or WPX, as the case may be, to effectuate the transactions contemplated by this Agreement.
     Section 7.2 Use of Names, Logos and Information .
          (a) No later than the Distribution Date, WPX shall cause to be filed with the Secretary of State (or other appropriate Governmental Authority) of the states in which its Subsidiaries are located or are doing business, an amendment to their certificates of incorporation or similar governing documents or qualification to do business to change the name of any Subsidiary with “Williams” in its name to a new name not confusingly similar to WMB’s name.
          (b) No later than the Distribution Date, WPX shall use reasonable best efforts to remove, and WPX shall cause each member of the WPX Group to remove, from their websites, and any other publicly distributed material (other than material required to be submitted for the purpose of regulatory filings and other similar documentation), any reference to WMB, and its business lines and plans and any names, logos, or trademarks associated therewith. WPX and each other member of the WPX Group shall cease all use of the WMB name (and any name confusingly similar thereto) and all trademarks and service marks associated therewith no later than the Distribution Date; provided that, if any
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member of the WPX Group is unable to comply with the foregoing requirements of this Section 6.2(b) for reasons outside of its reasonable control, WPX may request WMB to grant an extension of time beyond the Distribution Date, and WMB agrees not to unreasonably withhold or delay the granting of any such requested extension. Nothing in this Section 6.2(b) shall preclude WPX or its Subsidiaries from using the WMB name to indicate that WPX and members of the WPX Group were formerly associated with WMB, or from referring to WMB by its name for non-trademark and non-branding purposes as is permitted by applicable Law.
          (c) WPX shall not, and shall cause each member of the WPX Group not to, take any action, purport to take any action or otherwise hold itself out as having any authority to act on behalf of or represent in any way any member of the WMB Group. WPX shall indemnify, defend and hold harmless each of the WMB Indemnitees from and against any and all Liabilities of the WMB Indemnitees relating to, arising out of or resulting from a breach of this Section 7.2(c).
     Section 7.3 Non-Solicitation .
          (a) Without the prior consent of WMB, during the terms of the Administrative Services Agreement and the Transition Services Agreement and for a period of one year thereafter, WPX will not (and will cause each other WPX Entity not to) solicit for employment, directly or indirectly, any employee or contractor (including any contractor employed by a third party) of the WMB Entities that (i) is providing services to any WMB Entity or WPX Entity in connection with this Agreement or any Ancillary Agreement, or (ii) with whom any WPX Entity has, or will have, more than incidental contact pursuant to this Agreement or any Ancillary Agreement.
          (b) Without the prior consent of WPX, during the terms of the Administrative Services Agreement and the Transition Services Agreement and for a period of one year thereafter, WMB will not (and will cause each other WMB Entity not to) solicit for employment, directly or indirectly, any employee of WPX involved in the performance of WPX obligations under this Agreement or any Ancillary Agreement.
          (c) With respect to each of Sections 7.3(a) and 7.3(b) above, the prohibition on solicitation shall extend 90 days after the termination of any employee’s employment or, in the case of WMB employees, 90 days after the cessation of such employee’s involvement in the performance of all “Services” (as defined under the Administrative Services Agreement or the Transition Services Agreement). This provision shall not operate or be construed to prevent or limit any employee’s right to practice his or her profession or to utilize his or her skills for another employer or to restrict any employee’s freedom of movement or association.
          (d) Neither the publication of classified advertisements in newspapers, periodicals, Internet bulletin boards, or other publications of general availability or circulation, nor the consideration and hiring of persons responding to such advertisements, shall be deemed a breach of this Section 7.3, unless the advertisement and solicitation is
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undertaken as a means to circumvent or conceal a violation of this provision and/or the hiring party acts with knowledge of this hiring prohibition.
          (e) Each of the parties (i) acknowledges and agrees that money damages would not be a sufficient remedy for any breach of this Section 7.3 by such party (or any other member of such party’s Group), (ii) consents to a court of competent jurisdiction entering an order finding that the non-breaching party has been irreparably harmed as a result of any such breach and (iii) consents to the granting of injunctive relief without proof of actual damages as a remedy for any such breach. Such remedies shall not be deemed to be the exclusive remedies for a breach of this Section 7.3 but shall be in addition to all other remedies available at law or equity to the non-breaching party.
     Section 7.4 Conduct of WPX Business between Effective Date and Distribution Date . Subject to any additional restrictions in the Ancillary Agreements, during the period from the Effective Date through the Distribution Date, WPX covenants and agrees that the WPX Group as a whole will not, without WMB’s prior written consent (which WMB may withhold in its sole and absolute discretion): (a) acquire any businesses or other Assets, by means of merger, consolidation or otherwise, of any other Person, with an aggregate value of more than $50 million for all such acquisitions, (b) dispose of Assets held by the WPX Group, by sale or otherwise, with an aggregate value of more than $50 million for all such dispositions, or (c) acquire any equity or debt securities of any other Person, with an aggregate value of more than $50 million for all such acquisitions.
     Section 7.5 WMB Guarantees . During the period from the Effective Date through the Distribution Date, each of the parties shall use its reasonable best efforts to remove WMB as a guarantor under any guarantee relating exclusively to the WPX Business.
     Section 7.6 Directors’ and Officers’ Insurance . During the period from the Effective Date through the Distribution Date, WMB shall maintain in effect directors’ and officers’ liability insurance policies providing coverage for WPX’s directors and officers on terms and at limits no less favorable than those then in effect for WMB’s directors and officers. In addition, during the six-year period commencing on the Distribution Date, WMB shall maintain in effect directors’ and officers’ liability insurance policies providing coverage with respect to acts or omissions occurring or commencing prior to the Distribution Date for those WPX directors and officers who are covered by WMB’s directors’ and officers’ liability insurance policies as of or prior to the Distribution Date, at limits no less than those in effect for such WPX directors and officers as of the Distribution Date and on terms no less favorable than those in effect for WMB’s directors and officers. Other than as expressly provided in this Section 7.6, no WMB Entity shall have any obligation to maintain directors’ and officers’ liability insurance policies providing coverage for WPX’s directors and officers.
ARTICLE VIII
MUTUAL RELEASES; INDEMNIFICATION
     Section 8.1 Mutual Releases .
          (a) Except (i) as provided in Section 8.1(c), (ii) as may be otherwise provided in this Agreement or any Ancillary Agreement and (iii) for any matter for which any WPX Indemnitee is entitled to indemnification pursuant to this Article VIII, effective as of the Effective Date, WPX does hereby, for itself and each other WPX Entity and their respective Affiliates, predecessors, successors and assigns, and, to the extent WPX legally may, all Persons that at any time prior or subsequent to the Effective Date have been stockholders, directors, officers, members, agents or employees of WPX or any other WPX Entity (in each case, in their respective capacities as such), remise, release and forever discharge each WMB Entity, their respective Affiliates, successors and assigns, and all Persons that at any time prior to the Effective Date have been stockholders, directors, officers, members, agents or employees of WMB or any other WMB Entity (in each case, in their respective capacities as such), and their respective heirs, executors, administrators, successors and assigns, from any and all Liabilities whatsoever, whether at law or in equity, whether arising under any contract or agreement, by operation of law or otherwise,
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existing or arising from or relating to any acts or events occurring or failing to occur or alleged to have occurred or to have failed to occur or any conditions existing or alleged to have existed on or before the Effective Date, whether or not known as of the Effective Date.
          (b) Except (i) as provided in Section 8.1(c), (ii) as may be otherwise provided in this Agreement or any Ancillary Agreement and (iii) for any matter for which any WMB Indemnitee is entitled to indemnification pursuant to this Article VIII, WMB does hereby, for itself and each other WMB Entity and their respective Affiliates, successors and assigns, and, to the extent WMB legally may, all Persons that at any time prior to the Effective Date have been stockholders, directors, officers, members, agents or employees of WMB or any other WMB Entity (in each case, in their respective capacities as such), remise, release and forever discharge each WPX Entity, their respective Affiliates, successors and assigns, and all Persons that at any time prior to the Effective Date have been stockholders, directors, officers, members, agents or employees of WPX or any other WPX Entity (in each case, in their respective capacities as such), and their respective heirs, executors, administrators, successors and assigns, from any and all Liabilities whatsoever, whether at law or in equity, whether arising under any contract or agreement, by operation of law or otherwise, existing or arising from any acts or events occurring or failing to occur or alleged to have occurred or to have failed to occur or any conditions existing or alleged to have existed on or before the Effective Date, whether or not known as of the Effective Date.
          (c) Nothing contained in Section 8.1(a) or 8.1(b) shall impair any right of any Person to enforce this Agreement, any Ancillary Agreement, including the applicable Schedules hereto and thereto, or any arrangement that is not to terminate as of the Effective Date, as specified in Section 2.6(b). Nothing contained in Section 8.1(a) or 8.1(b) shall release any Person from:
               (i) any Liability provided in or resulting from any agreement among any WMB Entities and any WPX Entities that is not to terminate as of the Effective Date, as specified in Section 2.6(b), or any other Liability that is not to terminate as of the Effective Date, as specified in Section 2.6(b);
               (ii) any Liability, contingent or otherwise, assumed, transferred, assigned or allocated to the Group of which such Person is a member in accordance with, or any other Liability of any member of any Group under, this Agreement or any Ancillary Agreement; or
               (iii) any Liability the release of which would result in the release of any Person other than a Person released pursuant to this Section 8.1; provided that the parties agree not to bring suit or permit any of their Subsidiaries to bring suit against any Person with respect to any Liability to the extent that such Person would be released with respect to such Liability by this Section 8.1 but for the provisions of this clause (iii).
          (d) WPX shall not make, and shall not permit any other WPX Entity to make, any claim or demand, or commence any Action asserting any claim or demand,
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including any claim for indemnification, against any WMB Entity, or any other Person released pursuant to Section 8.1(a), with respect to any Liabilities released pursuant to Section 8.1(a). WMB shall not, and shall not permit any other WMB Entity, to make any claim or demand, or commence any Action asserting any claim or demand, including any claim for indemnification, against any WPX Entity, or any other Person released pursuant to Section 8.1(b), with respect to any Liabilities released pursuant to Section 8.1(b).
          (e) At any time, at the request of any other party, each party shall cause each member of its respective Group to execute and deliver releases in form reasonably satisfactory to the other party reflecting the provisions of this Section 8.1.
     Section 8.2 Indemnification by WPX . Subject to Section 8.4, WPX shall, and shall cause each of its Subsidiaries that is in the WPX Group as of the Effective Date to, jointly and severally indemnify, defend and hold harmless WMB, each WMB Entity and each of their respective current, former and future directors, officers and employees, and each of the heirs, executors, successors and assigns of any of the foregoing (collectively, the “ WMB Indemnitees ”), from and against any and all Liabilities of the WMB Indemnitees relating to, arising out of or resulting from any of the following items (without duplication):
          (a) any WPX Liability, including the failure of WPX or any other member of the WPX Group or any other Person to pay, perform or otherwise promptly discharge any WPX Liabilities in accordance with their respective terms, whether prior to, on or after the Effective Date;
          (b) the WPX Business;
          (c) any breach by any WPX Entity of this Agreement or any of the Ancillary Agreements; and
          (d) any untrue statement or alleged untrue statement of a material fact or omission or alleged omission to state a material fact required to be stated therein or necessary to make the statements therein not misleading, with respect to all information (i) contained in the IPO Registration Statement or any IPO Prospectus, (ii) contained in any public filings made by WPX with the SEC following the Effective Date, and (iii) provided by WPX to WMB specifically for inclusion in WMB’s annual or quarterly reports following the Effective Date; provided , however , that the indemnity provided in clauses (i) and (ii) of this Section 8.2(d) shall not apply to any WMB Indemnitee with respect to any Liability to the extent arising out of any untrue statement or omission or alleged untrue statement or omission contained in any information furnished in writing to WPX by WMB expressly for use in such filing.
Notwithstanding the foregoing, no WMB Indemnitee shall be entitled to indemnification under this Section 8.2 for any Liability for which any WPX Indemnitee is entitled to be indemnified pursuant to Sections 8.3(d) and 8.3(e) below.
     Section 8.3 Indemnification by WMB . Subject to Section 8.4, WMB shall, and shall cause each of its Subsidiaries that is in the WMB Group as of the Effective Date to,
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jointly and severally indemnify, defend and hold harmless WPX, each WPX Entity and each of their respective current, former and future directors, officers and employees, and each of the heirs, executors, successors and assigns of any of the foregoing (collectively, the “ WPX Indemnitees ”), from and against any and all Liabilities of the WPX Indemnitees relating to, arising out of or resulting from any of the following items (without duplication):
          (a) any WMB Liability, including the failure of WMB or any other member of the WMB Group or any other Person to pay, perform or otherwise promptly discharge any WMB Liabilities in accordance with their respective terms, whether prior to, on or after the Effective Date;
          (b) the WMB Business;
          (c) any breach by any WMB Entity of this Agreement or any of the Ancillary Agreements; and
          (d) any cash payment determined to be owed by any WPX Entity in any of the pending proceedings set forth on Schedule 8.3(d)(i) related to power marketing in California (except to the extent arising out of any of the Contracts set forth on Schedule 8.3(d)(ii) ); provided , that WPX shall pay, or cause to be paid, to WMB any cash that a WPX Entity receives, or is entitled to receive, in connection with such proceedings, regardless of whether such amount exceeds any amount due from WMB to WPX pursuant to this clause; and
          (e) the pending proceedings set forth on Schedule 8.3(e) related to published gas price indices, including, solely for purposes of this Section 8.3(e), any Liability for indirect, punitive or consequential damages relating to such proceeding; provided , that if all or any portion of the indemnification obligation set forth in this Section 8.3(e) is held to be invalid, illegal or unenforceable in any respect under any applicable Law or rule in any jurisdiction, then the parties will, to the extent permitted by law, take such actions as may reasonably be necessary in order to place the WPX Entities in the same position as if such obligation were fully valid, legal and enforceable.
     Section 8.4 Indemnification Obligations Net of Insurance Proceeds and Other Amounts .
          (a) The parties intend that any Liability subject to indemnification or reimbursement pursuant to this Agreement will be net of Insurance Proceeds and other amounts received that actually reduce the amount of the Liability for which indemnification is sought. Accordingly, the amount which any party (an “ Indemnifying Party ”) is required to pay to any Person entitled to indemnification or reimbursement under this Agreement (an “ Indemnitee ”) will be reduced by any Insurance Proceeds and other amounts theretofore actually recovered by or on behalf of the Indemnitee in reduction of the related Liability. If an Indemnitee receives a payment (an “ Indemnity Payment ”) required by this Agreement from an Indemnifying Party in respect of any Liability and subsequently receives Insurance Proceeds or other amounts therefor, then the Indemnitee
 30 

 

will promptly pay to the Indemnifying Party an amount equal to the excess of the Indemnity Payment received over the amount of the Indemnity Payment that would have been due if the Insurance Proceeds or other amounts had been received, realized or recovered before the Indemnity Payment was made.
          (b) An insurer that would otherwise be obligated to defend or make payment in response to any claim shall not be relieved of the responsibility with respect thereto or, solely by virtue of the indemnification provisions hereof, have any subrogation rights with respect thereto, it being expressly understood and agreed that no insurer or any other third party shall be entitled to a “windfall” (i.e., a benefit it would not be entitled to receive in the absence of the indemnification provisions of this Agreement) by virtue of the indemnification provisions hereof. For the avoidance of doubt, in no event shall any party be obligated to seek recovery from any insurer as a condition to obtaining the benefit of the indemnification provisions of this Agreement or any Ancillary Agreement.
          (c) If an indemnification claim is covered by the indemnification provisions of an Ancillary Agreement, the claim shall be made under the Ancillary Agreement to the extent applicable and the provisions thereof shall govern such claim. In no event shall any party be entitled to double recovery from the indemnification provisions of this Agreement and any Ancillary Agreement.
          (d) Payments and reimbursements with respect to Tax-related Liabilities and Tax-related indemnities are governed exclusively by the Tax Sharing Agreement. To the extent of any inconsistency or conflict between this Agreement and the Tax Sharing Agreement with respect to any matter relating to WMB’s and WPX’s respective rights, responsibilities and obligations after the Distribution with respect to Taxes, the provisions of the Tax Sharing Agreement shall apply.
     Section 8.5 Third-Party Claims .
          (a) If an Indemnitee shall receive notice or otherwise learn of the assertion by a Person (including any Governmental Authority) that is not a WMB Entity or a WPX Entity of any claim (including environmental claims and demands or requests for investigation or remediation of contamination) or of the commencement by any such Person of any Action with respect to which an Indemnifying Party may be obligated to provide indemnification to such Indemnitee pursuant to this Agreement or any Ancillary Agreement (collectively, a “ Third-Party Claim ”), such Indemnitee shall give such Indemnifying Party written notice thereof as soon as promptly practicable, but no later than 30 days after becoming aware of such Third-Party Claim. Any such notice shall describe the Third-Party Claim in reasonable detail and contain written correspondence received from the third party that relates to the Third-Party Claim. Notwithstanding the foregoing, the failure of any Indemnitee to give notice as provided in this Section 8.5(a) shall not relieve the related Indemnifying Party of its obligations under this Article VIII, except to the extent that such Indemnifying Party is prejudiced by such failure to give notice.
          (b) With respect to any Third-Party Claim:
               (i) Unless the parties otherwise agree, within 30 days after the receipt of notice from an Indemnitee in accordance with Section 8.5(a), an Indemnifying Party shall defend (and, unless the Indemnifying Party has specified any reservations or exceptions, seek to settle or compromise), at such Indemnifying Party’s own cost and expense and by such Indemnifying Party’s own counsel, any Third-Party Claim. The applicable Indemnitee shall have the right to employ separate counsel and to participate in
 31 

 

(but not control) the defense, compromise, or settlement thereof, but the fees and expenses of such counsel shall be the expense of such Indemnitee. Notwithstanding the foregoing, the Indemnifying Party shall be liable for the fees and expenses of counsel employed by the Indemnitee (A) for any period during which the Indemnifying Party has not assumed the defense of such Third-Party Claim (other than during any period in which the Indemnitee shall have failed to give notice of the Third-Party Claim in accordance with Section 8.5(a)) or (B) to the extent that such engagement of counsel is as a result of a conflict of interest, as reasonably determined by the Indemnitee acting in good faith.
               (ii) No Indemnifying Party shall consent to entry of any judgment or enter into any settlement of any Third-Party Claim without the consent of the applicable Indemnitee; provided , however , that such Indemnitee shall be required to consent to such entry of judgment or to such settlement that the Indemnifying Party may recommend if the judgment or settlement (A) contains no finding or admission of any violation of Law or any violation of the rights of any Person, (B) involves only monetary relief which the Indemnifying Party has agreed to pay and could not reasonably be expected to have a significant adverse impact (financial or non-financial) on the Indemnitee, including a significant adverse impact on the rights, obligations, operations, standing or reputation of the Indemnitee (or any of its Subsidiaries or Affiliates), and (C) includes a full and unconditional release of the Indemnitee. Notwithstanding the foregoing, in no event shall an Indemnitee be required to consent to any entry of judgment or settlement if the effect thereof is to permit any injunction, declaratory judgment, other order or other nonmonetary relief to be entered, directly or indirectly, against any Indemnitee.
          (c) Whether or not the Indemnifying Party assumes the defense of a Third-Party Claim, no Indemnitee shall admit any liability with respect to, or settle, compromise or discharge, such Third-Party Claim without the Indemnifying Party’s prior written consent, which consent shall not be unreasonably withheld or delayed.
     Section 8.6 Additional Matters .
          (a) Any claim on account of a Liability that does not result from a Third-Party Claim shall be timely asserted by written notice given by the Indemnitee to the related Indemnifying Party. Such Indemnifying Party shall have a period of 30 days after the receipt of such notice within which to respond thereto. If such Indemnifying Party does not respond within such 30-day period, such Indemnifying Party shall be deemed to have refused to accept responsibility to make payment. If such Indemnifying Party does not respond within such 30-day period or rejects such claim in whole or in part, such Indemnitee shall be free to pursue remedies as specified by this Agreement and the Ancillary Agreements.
          (b) In the event of payment by or on behalf of any Indemnifying Party to any Indemnitee in connection with any Third-Party Claim, such Indemnifying Party shall be subrogated to and shall stand in the place of such Indemnitee as to any events or circumstances in respect of which such Indemnitee may have any right, defense or claim relating to such
 32 

 

Third-Party Claim against any claimant or plaintiff asserting such Third-Party Claim or against any other Person. Such Indemnitee shall cooperate with such Indemnifying Party in a reasonable manner, and at the cost and expense of such Indemnifying Party, in prosecuting any subrogated right, defense or claim.
          (c) In the event of an Action in which the Indemnifying Party is not a named defendant, if either the Indemnitee or the Indemnifying Party shall so request, the parties shall endeavor to substitute the Indemnifying Party for the named defendant, if reasonably practicable. If such substitution or addition cannot be achieved or is not requested, the named defendant shall allow the Indemnifying Party to manage the Action as set forth in this Agreement and the Indemnifying Party shall fully indemnify the named defendant against all costs of defending the Action (including court costs, sanctions imposed by a court, attorneys’ fees, experts’ fees and all other external expenses, and the allocated costs of in-house counsel and other personnel), the costs of any judgment or settlement, and the cost of any interest or penalties relating to any judgment or settlement.
     Section 8.7 Remedies Cumulative . The remedies provided in this Article VIII shall be cumulative and shall not preclude assertion by any Indemnitee of any other rights or the seeking of any and all other remedies against any Indemnifying Party.
     Section 8.8 Survival of Indemnities . The rights and obligations of each of WMB and WPX and their respective Indemnitees under this Article VIII shall survive the sale or other transfer by any party of any assets or businesses or the assignment by it of any Liabilities.
     Section 8.9 Limitation on Liability . Except as may expressly be set forth in this Agreement, none of WMB, WPX, or any other member of either Group shall in any event have any Liability to the other or to any other member of the other’s Group, or to any other WMB Indemnitee or WPX Indemnitee, as applicable, under this Agreement (a) to the extent that any such Liability resulted from any willful violation of Law or fraud by the party seeking indemnification or (b) subject to Section 8.3(e), for any indirect, punitive or consequential damages. Notwithstanding the foregoing, the provisions of this Section 8.9 shall not limit an Indemnifying Party’s indemnification obligations with respect to any Liability that any Indemnitee may have to any third party not affiliated with any member of the WMB Group or the WPX Group.
ARTICLE IX
TERMINATION
     Section 9.1 Termination . This Agreement and any Ancillary Agreement may be terminated at any time prior to the IPO Closing Date in the sole discretion of WMB without the approval of WPX. The obligations of the parties under Article IV (including the obligation to pursue or effect the Distribution) may be terminated by WMB if any time after the IPO Closing Date it determines, in its sole and absolute discretion, that the Distribution would not be in the best interests of WMB or its stockholders.
 33 

 

     Section 9.2 Effect of Termination . In the event of any termination of this Agreement prior to the IPO Closing Date, no party (or any of its directors or officers) shall have any Liability or further obligation to any other party with respect to this Agreement.
ARTICLE X
DISPUTE RESOLUTION
     Section 10.1 Disputes . Except as otherwise specifically provided in any Ancillary Agreement, the procedures for discussion, negotiation and mediation set forth in this Article X shall apply to all disputes, controversies or claims (whether arising in contract, tort or otherwise) that may arise out of or relate to, or arise under or in connection with this Agreement or any Ancillary Agreement, or the transactions contemplated hereby or thereby (including all actions taken in furtherance of the transactions contemplated hereby or thereby on or prior to the Effective Date), or the commercial or economic relationship of the parties relating hereto or thereto, between or among any Person in the WMB Group and the WPX Group.
     Section 10.2 Escalation; Mediation .
          (a) It is the intent of the parties to use their respective commercially reasonable efforts to resolve expeditiously any dispute, controversy or claim between or among them with respect to the matters covered hereby that may arise from time to time on a mutually acceptable negotiated basis. In furtherance of the foregoing, upon the written notice of either party, each party shall appoint a representative at an authority level above the level of the individuals who have been unable to resolve the dispute (the “ Next Step Up Representatives ”). The Next Step Up Representatives shall be appointed as determined in the discretion of each party considering the importance of the relationship, the complexity of the issues, and the size of the amounts in dispute. The parties shall allow for a period of 15 Business Days after the last representative is appointed and contact information provided to the other party for the Next Step Up Representatives to negotiate a resolution of the dispute before the parties are required to move to the mediation stage. This 15 Business Day period may be waived jointly in writing.
          (b) If the parties are not able to resolve the dispute, controversy or claim (except those relating to Environmental Liabilities, which are addressed in Section 10.2(c) below) through the escalation process referred to above, then either party may submit the dispute to mediation by written notice to the other party. The parties shall jointly retain a mediator to aid the parties in their discussions and negotiations by informally providing advice to the parties. The mediator shall be selected by the parties. If the parties cannot agree on a mediator within 30 days after the notice to mediate, the International Institute for Conflict Prevention and Resolution (“ CPR ”) shall designate a mediator at the request of either party. Any mediator proposed by CPR must be reasonably acceptable to both parties. Any opinion expressed by the mediator shall be strictly advisory and shall not be binding on the parties, nor shall any opinion expressed by the mediator be admissible in any other proceeding. Costs of the mediation shall be borne equally by the parties involved in the matter, except that each party shall be responsible for its own expenses. Mediation shall be a prerequisite to the commencement of any Proceeding (except those
 34 

 

relating to Environmental Liabilities, which are addressed in Section 10.2(c) below) by either party.
          (c) If the parties are not able to resolve any technical or factual dispute, controversy or claim relating to Environmental Liabilities through the escalation process referred to above, then either party may submit the dispute to mediation by written notice to the other party. The parties shall jointly retain a technical mediator, such as a third-party environmental consultant or other person with specific technical expertise in the matter involved in the dispute, controversy or claim to aid the parties in their discussions and negotiations. The technical mediator shall be selected by the parties. If the parties cannot agree on a technical mediator within 30 days after the notice to mediate, CPR shall designate a technical mediator at the request of either party. Any technical mediator proposed by CPR must be reasonably acceptable to both parties. The technical mediator shall provide informal advice to the parties and, if requested by both parties, shall also provide a written opinion letter or report summarizing the matter in dispute, identifying any significant assumptions or informational gaps underlying that summary, and setting forth the conclusions and recommendations of the technical mediator. Unless mutually agreed by the parties in writing, any opinion expressed by the technical mediator shall be strictly advisory and shall not be binding on the parties, nor shall any opinion expressed or delivered by the technical mediator be admissible in any other proceeding. Costs related to the technical mediator’s work, including any investigation, data-gathering or sampling recommended by the technical mediator, shall be borne equally by the parties involved in the matter, except that each party shall be responsible for its own expenses. Technical mediation shall be a prerequisite to the commencement of any Proceeding relating to Environmental Liabilities by either party.
          (d) For purposes of this Section 10.2:
               (i) “ Environmental Laws ” means all federal, state, local and foreign Laws, including all judicial and administrative orders, determinations, and consent agreements or decrees, that relate, in whole or in part, to Hazardous Substances, pollution, contaminants, harmful substances, protection of the environment or human health, including those that regulate the use, manufacture, generation, handling, labeling, testing, transport, treatment, storage, processing, discharge, disposal, release, threatened release, control, or cleanup of harmful substances, pollutants, contaminants, Hazardous Substances or materials containing such substances, regardless of when enacted or effective;
               (ii) “ Environmental Liabilities ” means any Liabilities arising out of or relating to the environment, human health, any Environmental Law, Hazardous Substances or exposure to Hazardous Substances, pollutants, contaminants or other harmful substances, including (A) fines, penalties, judgments, awards, settlements, losses, damages (including consequential damages), costs, fees (including attorneys’ and consultants’ fees), expenses and disbursements, (B) costs of defense and other responses to any administrative or judicial action (including notices, claims, complaints, suits and other assertions of liability), (C) responsibility for any investigation, remediation, monitoring or cleanup costs, injunctive relief, tort claims, natural resource damages, and any other environmental compliance or remedial measures, in each case known or unknown,
 35 

 

foreseen or unforeseen, and (D) any claims, suits or actions (whether third-party or otherwise) for any Liability, including personal injury or property damage; and
               (iii) “ Hazardous Substances ” means all materials, wastes or substances defined by, or regulated under, any Environmental Laws now or in the future and any substance that can give rise to any claim, suit or action (whether third-party or otherwise) for any Liabilities, including personal injury or property damage.
     Section 10.3 Court Actions .
          (a) In the event that any party, after complying with the provisions set forth in Section 10.2 above, desires to commence an Action, such party, subject to Section 11.11, may submit the dispute, controversy or claim (or such series of related disputes, controversies or claims) to any court of competent jurisdiction.
          (b) Unless otherwise agreed in writing, the parties will continue to provide service and honor all other commitments under this Agreement and the Ancillary Agreements during the course of dispute resolution pursuant to the provisions of this Article X, except to the extent such commitments are the subject of such dispute, controversy or claim.
ARTICLE XI
MISCELLANEOUS
     Section 11.1 Corporate Power . WMB represents on behalf of itself and each other WMB Entity, and WPX represents on behalf of itself and each other WPX Entity, that:
          (a) each such Person is a corporation or other entity duly incorporated or formed, validly existing and in good standing under the Laws of the state or other jurisdiction of its incorporation or formation, and has all material corporate or other similar powers required to carry on its business as currently conducted;
          (b) each such Person has the requisite corporate or other power and authority and has taken all corporate or other action necessary in order to execute, deliver and perform this Agreement and each other Ancillary Agreement to which it is a party and to consummate the transactions contemplated hereby and thereby; and
          (c) this Agreement and each Ancillary Agreement to which it is a party has been duly executed and delivered by it and constitutes a valid and binding agreement of such Person enforceable in accordance with the terms hereof and thereof.
     Section 11.2 Coordination with Certain Ancillary Agreements; Conflicts . In the event of any conflict or inconsistency between any provision of any of the Ancillary Agreements and any provision of this Agreement, the applicable Ancillary Agreement shall control over the inconsistent provisions of this Agreement as to the matters specifically addressed in such Ancillary Agreement.
 36 

 

     Section 11.3 Expenses . Except as expressly set forth in this Agreement or in any Ancillary Agreement, all fees, costs and expenses paid or incurred in connection with the Separation and the performance of this Agreement and any Ancillary Agreement, whether performed by a third-party or internally, will be paid by the party incurring such fees or expenses, whether or not the Separation is consummated, or as otherwise agreed by the parties.
     Section 11.4 Amendment and Modification .This Agreement and the Ancillary Agreements may not be amended, modified or supplemented in any manner, whether by course of conduct or otherwise, except by an instrument in writing specifically designated as an amendment hereto, signed on behalf of each party.
     Section 11.5 Waiver . No failure or delay of any party in exercising any right or remedy hereunder shall operate as a waiver thereof, nor shall any single or partial exercise of any such right or power, or any abandonment or discontinuance of steps to enforce such right or power, or any course of conduct, preclude any other or further exercise thereof or the exercise of any other right or power. The rights and remedies of the parties hereunder are cumulative and are not exclusive of any rights or remedies that they would otherwise have hereunder. Any agreement on the part of any party to any such waiver shall be valid only if set forth in a written instrument executed and delivered by a duly authorized officer on behalf of such party.
     Section 11.6 Notices . All notices and other communications hereunder shall be in writing and shall be deemed duly given (a) on the date of delivery if delivered personally, or if by facsimile, upon written confirmation of receipt by facsimile, e-mail or otherwise, (b) on the first Business Day following the date of dispatch if delivered utilizing a next-day service by a recognized next-day courier or (c) on the earlier of confirmed receipt or the fifth Business Day following the date of mailing if delivered by registered or certified mail, return receipt requested, postage prepaid. All notices hereunder shall be delivered to the addresses set forth below, or pursuant to such other instructions as may be designated in writing by the party to receive such notice:

 	(i)	 	if to WMB or any other WMB Entity, to:	
 		
 	 	 	The Williams Companies, Inc.
One Williams Center
Tulsa, Oklahoma 74172-0172
Attention: General Counsel
Facsimile: 918-573-5942
E-mail: james.bender@williams.com	
 		
 	(ii)	 	if to WPX or any other WPX Entity, to:	
 		
 	 	 	WPX Energy, Inc.
One Williams Center	
 37 

 

 	 	 	Tulsa, Oklahoma 74172-0172
Attention: General Counsel
Facsimile: 918-573-5942
E-mail: james.bender@williams.com	
     Section 11.7 Interpretation . When a reference is made in this Agreement to a Section, Article, or Exhibit such reference shall be to a Section, Article, or Exhibit of this Agreement unless otherwise indicated. The table of contents and headings contained in this Agreement or in any Exhibit are for convenience of reference purposes only and shall not affect in any way the meaning or interpretation of this Agreement. All words used in this Agreement will be construed to be of such gender or number as the circumstances require. Any capitalized terms used in any Schedule or Exhibit but not otherwise defined therein shall have the meaning as defined in this Agreement. All Schedules and Exhibits annexed hereto or referred to herein are hereby incorporated in and made a part of this Agreement as if set forth herein. The word “including” and words of similar import when used in this Agreement shall mean “including, without limitation,” unless otherwise specified. The word “day” when used in this Agreement shall mean “calendar day,” unless otherwise specified.
     Section 11.8 Entire Agreement . This Agreement and the Ancillary Agreements and the Exhibits, Schedules and Appendices hereto and thereto constitute the entire agreement, and supersede all prior written agreements, arrangements, communications and understandings and all prior and contemporaneous oral agreements, arrangements, communications and understandings among the parties with respect to the subject matter hereof. None of this Agreement or any of the Ancillary Agreements shall be deemed to contain or imply any restriction, covenant, representation, warranty, agreement or undertaking of any party with respect to the transactions contemplated hereby and thereby other than those expressly set forth herein or therein or in any document required to be delivered hereunder or thereunder. Notwithstanding any oral agreement or course of action of the parties or their representatives to the contrary, no party to this Agreement shall be under any legal obligation to enter into or complete the transactions contemplated hereby unless and until this Agreement shall have been executed and delivered by each of the parties.
     Section 11.9 No Third Party Beneficiaries . Except for the indemnification rights under this Agreement of any WMB Indemnitee or WPX Indemnitee in their respective capacities as such, nothing in this Agreement or the Ancillary Agreements, express or implied, is intended to or shall confer upon any Person other than the parties and their respective successors and permitted assigns any legal or equitable right, benefit or remedy of any nature under or by reason of this Agreement or the Ancillary Agreements.
     Section 11.10 Governing Law . This Agreement and all disputes or controversies arising out of or relating to this Agreement or the transactions contemplated hereby shall be governed by, and construed in accordance with, the internal Laws of the State of Oklahoma, without regard to the Laws of any other jurisdiction that might be applied because of the conflicts of laws principles of the State of Oklahoma.
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     Section 11.11 Submission to Jurisdiction . Except as otherwise specifically provided in any Ancillary Agreement, with respect to any suit, action or proceeding relating to this Agreement or any Ancillary Agreement (a “ Proceeding ”), each party to this Agreement irrevocably (a) consents and submits to the exclusive jurisdiction of the state and federal courts located in Tulsa County, Oklahoma; (b) waives any objection which such party may have at any time to the laying of venue of any Proceeding brought in any such court, waives any claim that such Proceeding has been brought in an inconvenient forum and further waives the right to object, with respect to such Proceeding, that such court does not have jurisdiction over such party; and (c) consents to the service of process at the address set forth for notices in Section 11.6; provided , however , that such manner of service of process shall not preclude the service of process in any other manner permitted under applicable law.
     Section 11.12 Assignment . Except as specifically provided in any Ancillary Agreement, none of this Agreement, any of the Ancillary Agreements, or any of the rights, interests or obligations hereunder or thereunder may be assigned or delegated, in whole or in part, by operation of law or otherwise, by any party without the prior written consent of the other parties, and any such assignment without such prior written consent shall be null and void. If any party (or any of its successors or permitted assigns) (a) shall consolidate with or merge into any other Person and shall not be the continuing or surviving corporation or entity of such consolidation or merger or (b) shall transfer all or substantially all of its properties and/or assets to any Person, then, and in each such case, the party (or its successors or permitted assigns, as applicable) shall ensure that such Person assumes all of the obligations of such party (or its successors or permitted assigns, as applicable) under this Agreement and all applicable Ancillary Agreements.
     Section 11.13 Severability . Whenever possible, each provision or portion of any provision of this Agreement and the Ancillary Agreements shall be interpreted in such manner as to be effective and valid under applicable Law, but if any provision or portion of any provision of this Agreement or the Ancillary Agreements is held to be invalid, illegal or unenforceable in any respect under any applicable Law or rule in any jurisdiction, such invalidity, illegality or unenforceability shall not affect any other provision or portion of any provision in such jurisdiction, and this Agreement or the Ancillary Agreements shall be reformed, construed and enforced in such jurisdiction as if such invalid, illegal or unenforceable provision or portion of any provision had never been contained herein.
     Section 11.14 Waiver of Jury Trial . EACH OF THE PARTIES TO THIS AGREEMENT HEREBY IRREVOCABLY WAIVES ALL RIGHT TO TRIAL BY JURY IN ANY ACTION, PROCEEDING OR COUNTERCLAIM ARISING OUT OF OR RELATING TO THIS AGREEMENT, ANY OF THE ANCILLARY AGREEMENTS OR THE TRANSACTIONS CONTEMPLATED HEREBY OR THEREBY.
     Section 11.15 Counterparts . This Agreement and each Ancillary Agreement may be executed in one or more counterparts, all of which shall be considered one and the same instrument and shall become effective when one or more counterparts have been signed by each of the parties and delivered to the other parties.
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     Section 11.16 Facsimile Signature . This Agreement may be executed by facsimile signature and a facsimile signature shall constitute an original for all purposes.
[The remainder of this page is intentionally left blank.]
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     IN WITNESS WHEREOF, the parties have caused this Agreement to be executed by their duly authorized representatives as of the date first set forth above.

 	 	THE WILLIAMS COMPANIES, INC.	 	 	
 	 	 	 	 	 	 	
 	 	By:	 	 	 	 	
 	 	 	 	 
Name:	 	 	
 	 	 	 	Title:	 	 	
 	 	 	 	 	 	 	
 	 	WPX ENERGY, INC.	 	 	
 	 	 	 	 	 	 	
 	 	By:	 	 	 	 	
 	 	 	 	 
Name:	 	 	
 	 	 	 	Title:	 	 	
[Signature Page to Separation and Distribution Agreement]

 

Exhibit A
Contributed Entities
(such entities are held 100% by WPX Energy, Inc.
or its subsidiaries unless otherwise noted)
Williams Production Holdings LLC
Williams Production Ryan Gulch LLC
Williams Production RMT Company LLC
Fort Union Gas Gathering, L.L.C. (11.11%)
Bison Royalty LLC
Barrett Resources International Corporation
Dakota-3 E&P Company, LLC
D-3 Van Hook Gathering Services, LLC
Williams Production Company, LLC
Williams Production Rocky Mountain Company
Williams Production Mid-Continent Company
Williams Arkoma Gathering Company, LLC
Williams Production Keystone LLC
WPX Gas Resources Company
Williams Production Appalachia LLC
Williams Marcellus Gathering LLC
Diamond Elk, LLC
RW Gathering, LLC (50%)
Mockingbird Pipeline, L.P.
Williams Production — Gulf Coast Company, L.P.
WPX Enterprises, Inc.
WPX Energy Marketing, LLC
Northwest Argentina Corporation
Williams International Oil & Gas (Venezuela) Limited
Apco Argentina S.A.
Apco Austral, S.A.
Apco Oil & Gas International Inc. (68.96%)
Apco Properties Ltd.
[Exhibit A to Separation and Distribution Agreement]

 

Schedule 2.6(b)(v)
Surviving Contracts

1.	 	Gas Supply Fee Agreement by and between WPX Energy Marketing, LLC and Williams Energy (Canada), Inc. dated November 18, 2009.	
 		
2.	 	ISDA 2002 Master Agreement by and between WPX Energy Marketing, LLC and Williams Energy (Canada), Inc. dated January 1, 2009, along with each transaction thereunder.	
 		
3.	 	ISDA 2002 Master Agreement by and between WPX Energy Marketing, LLC and Williams Olefins, L.L.C. dated August 1, 2006, along with each transaction thereunder.	
[Schedule 2.6(b)(v) to Separation and Distribution Agreement]

 

Schedule 8.3(d)
California Gas Marketing Proceedings
Schedule 8.3(d)(i) :
 	 	 	 	 	
Case	 	Jurisdiction	 	Williams Entities Named	
San Diego Gas & Electric Company v. Sellers of Energy and Ancillary Services	 	FERC
Docket No. EL00-95-000 et al	 	The Williams Companies, Inc;
Williams Energy Marketing & Trading Company; Williams Power Company, Inc.	
 	 	 	 	 	
Investigation of Practices of the California Independent System Operator and the California Power Exchange	 	FERC
Docket No. EL00-98-000 et al	 	The Williams Companies, Inc;
Williams Energy Marketing & Trading Company; Williams Power Company, Inc.	
 	 	 	 	 	
Puget Sound Energy v. Sellers of Energy and Ancillary Services	 	FERC
Docket No. EL01-10-000 et al	 	The Williams Companies, Inc;
Williams Energy Marketing & Trading Company; Williams Power Company, nc.	
 	 	 	 	 	
California
Independent System Operator	 	FERC
Docket No. ER03-746-000	 	The Williams Companies, Inc.;
Williams Power Company, Inc.	
 	 	 	 	 	
Investigation of Anomalous Bidding Behavior and Practices in Western Markets	 	FERC
Docket No. IN03-10-000 et al	 	The Williams Companies, Inc;
Williams Energy Marketing & Trading Company; Williams Power Company, Inc.	
 	 	 	 	 	
Fact-Finding Investigation Into Possible Manipulation of Electric and Natural Gas Prices	 	FERC
Docket No. PA02-2-000 et al	 	The Williams Companies, Inc;
Williams Energy Marketing & Trading Company; Williams Power Company, Inc.	
 	 	 	 	 	
State of California, ex rel . Bill Lockyer, Attorney General, v. British Columbia Power Exchange Corp.	 	FERC
Docket No. EL02-71-000 et al	 	The Williams Companies, Inc;
Williams Energy Marketing & Trading Company; Williams Power Company, Inc.	
[Schedule 8.3(d) to Separation and Distribution Agreement]

 

Schedule 8.3(d)(ii) :
WGM Legacy Agreements with Current Deal Ending Date
 	 	 	 	 	 	 	 	 	 	 	 	 	
Max of Maturity Date	 	 	 	 	 	 	 	 	 	
Contract Type	 	Ext Legal	 	Deal #	 	 	Expiration	 	
Broker Agreement (Exchange Cleared)	 	BNPPARIBCOMMOFUTURINC - LE	 	 	21358	 	 	 	12/31/2011	 	
 	 	 	 	 	 	 	21359	 	 	 	12/31/2011	 	
 	 	 	 	 	 	 	21363	 	 	 	6/30/2011	 	
 	 	 	 	 	 	 	21364	 	 	 	12/31/2011	 	
 	 	 	 	 	 	 	21365	 	 	 	12/31/2011	 	
 	 	 	 	 	 	 	21366	 	 	 	12/31/2011	 	
 	 	 	 	 	 	 	21367	 	 	 	12/31/2011	 	
 	 	 	 	 	 	 	21368	 	 	 	12/31/2011	 	
 	 	 	 	 	 	 	21369	 	 	 	12/31/2011	 	
 	 	 	 	 	 	 	21383	 	 	 	6/30/2011	 	
 	 	 	 	 	 	 	21384	 	 	 	3/31/2011	 	
 	 	 	 	 	 	 	21386	 	 	 	6/30/2011	 	
 	 	 	 	 	 	 	21434	 	 	 	3/31/2011	 	
 	 	 	 	 	 	 	21436	 	 	 	3/31/2011	 	
 	 	 	 	 	 	 	21445	 	 	 	6/30/2011	 	
 	 	 	 	 	 	 	21446	 	 	 	9/30/2011	 	
 	 	 	 	 	 	 	21906	 	 	 	12/31/2011	 	
 	 	 	 	 	 	 	21909	 	 	 	12/31/2011	 	
 	 	 	 	 	 	 	21911	 	 	 	12/31/2011	 	
 	 	 	 	 	 	 	21912	 	 	 	12/31/2011	 	
 	 	 	 	 	 	 	21920	 	 	 	12/31/2011	 	
 	 	 	 	 	 	 	21923	 	 	 	12/31/2011	 	
 	 	 	 	 	 	 	21930	 	 	 	12/31/2011	 	
 	 	 	 	 	 	 	21945	 	 	 	12/31/2013	 	
 	 	 	 	 	 	 	21956	 	 	 	12/31/2013	 	
 	 	 	 	 	 	 	21958	 	 	 	10/31/2011	 	
 	 	 	 	 	 	 	21964	 	 	 	10/31/2011	 	
 	 	 	 	 	 	 	21965	 	 	 	10/31/2011	 	
 	 	 	 	 	 	 	21976	 	 	 	3/31/2011	 	
 	 	 	 	 	 	 	21977	 	 	 	3/31/2011	 	
 	 	 	 	 	 	 	21981	 	 	 	10/31/2011	 	
 	 	 	 	 	 	 	21982	 	 	 	10/31/2011	 	
 	 	 	 	 	 	 	21983	 	 	 	3/31/2011	 	
 	 	 	 	 	 	 	21984	 	 	 	3/31/2011	 	
 	 	 	 	 	 	 	21985	 	 	 	3/31/2011	 	
 	 	 	 	 	 	 	24008	 	 	 	12/31/2012	 	
 	 	 	 	 	 	 	24009	 	 	 	12/31/2012	 	
 	 	 	 	 	 	 	24010	 	 	 	12/31/2012	 	
 	 	 	 	 	 	 	24011	 	 	 	12/31/2012	 	
 	 	 	 	 	 	 	24014	 	 	 	12/31/2012	 	
 	 	 	 	 	 	 	24015	 	 	 	12/31/2012	 	
 	 	 	 	 	 	 	24016	 	 	 	12/31/2012	 	
 	 	 	 	 	 	 	24017	 	 	 	12/31/2012	 	
 	 	 	 	 	 	 	24053	 	 	 	12/31/2012	 	
[Schedule 8.3(d) to Separation and Distribution Agreement]

 

 	 	 	 	 	 	 	 	 	 	 	 	 	
Max of Maturity Date	 	 	 	 	 	 	 	 	 	
Contract Type	 	Ext Legal	 	Deal #	 	 	Expiration	 	
 	 	 	 	 	 	 	24054	 	 	 	12/31/2012	 	
 	 	 	 	 	 	 	24055	 	 	 	12/31/2012	 	
 	 	 	 	 	 	 	24056	 	 	 	12/31/2012	 	
 	 	 	 	 	 	 	24057	 	 	 	12/31/2012	 	
 	 	 	 	 	 	 	25677	 	 	 	12/31/2012	 	
 	 	 	 	 	 	 	25683	 	 	 	12/31/2012	 	
 	 	 	 	 	 	 	25696	 	 	 	12/31/2012	 	
 	 	 	 	 	 	 	25697	 	 	 	12/31/2012	 	
 	 	 	 	 	 	 	25698	 	 	 	12/31/2012	 	
 	 	 	 	 	 	 	27181	 	 	 	12/31/2012	 	
 	 	 	 	 	 	 	27182	 	 	 	12/31/2012	 	
 	 	 	 	 	 	 	27185	 	 	 	12/31/2012	 	
 	 	 	 	 	 	 	27186	 	 	 	12/31/2012	 	
 	 	 	 	 	 	 	27330	 	 	 	12/31/2011	 	
 	 	 	 	 	 	 	27606	 	 	 	12/31/2012	 	
 	 	 	 	 	 	 	27681	 	 	 	12/31/2012	 	
 	 	 	 	 	 	 	28950	 	 	 	12/31/2012	 	
 	 	 	 	 	 	 	29177	 	 	 	12/31/2012	 	
 	 	 	 	 	 	 	36432	 	 	 	3/31/2012	 	
 	 	 	 	 	 	 	36433	 	 	 	3/31/2012	 	
 	 	 	 	 	 	 	37318	 	 	 	3/31/2013	 	
 	 	 	 	 	 	 	37319	 	 	 	3/31/2013	 	
 	 	 	 	 	 	 	37320	 	 	 	3/31/2013	 	
 	 	 	 	 	 	 	37381	 	 	 	10/31/2012	 	
 	 	 	 	 	 	 	37382	 	 	 	10/31/2012	 	
 	 	 	 	 	 	 	37469	 	 	 	3/31/2012	 	
 	 	 	 	 	 	 	37651	 	 	 	3/31/2013	 	
 	 	 	 	 	 	 	37652	 	 	 	10/31/2013	 	
 	 	 	 	 	 	 	38606	 	 	 	3/31/2012	 	
 	 	BNPPARIBCOMMOFUTURINC - LE Total	 	 	 	 	 	 	12/31/2013	 	
Broker Agreement (Exchange Cleared) Total	 	 	 	 	 	 	 	 	 	 	12/31/2013	 	
ISDA (OTC Financial)	 	BARCLAYSBANKPLC - LE	 	 	20961	 	 	 	12/31/2012	 	
 	 	 	 	 	 	 	20962	 	 	 	12/31/2011	 	
 	 	 	 	 	 	 	20963	 	 	 	12/31/2012	 	
 	 	 	 	 	 	 	21015	 	 	 	12/31/2011	 	
 	 	 	 	 	 	 	21016	 	 	 	12/31/2011	 	
 	 	 	 	 	 	 	21042	 	 	 	10/31/2011	 	
 	 	BARCLAYSBANKPLC - LE Total	 	 	 	 	 	 	12/31/2012	 	
 	 	CITIGROUPENERGYINC - LE	 	 	20954	 	 	 	12/31/2012	 	
 	 	 	 	 	 	 	21043	 	 	 	3/31/2011	 	
 	 	CITIGROUPENERGYINC - LE Total	 	 	 	 	 	 	12/31/2012	 	
 	 	ELPASOMARKECOMPALLC - LE	 	 	20930	 	 	 	12/31/2015	 	
 	 	 	 	 	 	 	20931	 	 	 	12/31/2015	 	
 	 	 	 	 	 	 	20932	 	 	 	12/31/2013	 	
 	 	 	 	 	 	 	20933	 	 	 	12/31/2013	 	
 	 	 	 	 	 	 	20942	 	 	 	12/31/2012	 	
 	 	 	 	 	 	 	20949	 	 	 	12/31/2012	 	
 	 	ELPASOMARKECOMPALLC - LE Total	 	 	 	 	 	 	12/31/2015	 	
[Schedule 8.3(d) to Separation and Distribution Agreement]

 

 	 	 	 	 	 	 	 	 	 	 	 	 	
Max of Maturity Date	 	 	 	 	 	 	 	 	 	
Contract Type	 	Ext Legal	 	Deal #	 	 	Expiration	 	
 	 	JPMORGAVENTUENERGCORPO - LE	 	 	20969	 	 	 	6/30/2011	 	
 	 	 	 	 	 	 	20972	 	 	 	6/30/2011	 	
 	 	 	 	 	 	 	20998	 	 	 	12/31/2011	 	
 	 	 	 	 	 	 	21031	 	 	 	6/30/2011	 	
 	 	JPMORGAVENTUENERGCORPO - LE Total	 	 	 	 	 	 	12/31/2011	 	
 	 	LOUISDREYFENERGSERVILP - LE	 	 	21003	 	 	 	12/31/2011	 	
 	 	 	 	 	 	 	21004	 	 	 	12/31/2011	 	
 	 	 	 	 	 	 	21025	 	 	 	12/31/2013	 	
 	 	LOUISDREYFENERGSERVILP - LE Total	 	 	 	 	 	 	12/31/2013	 	
 	 	MERRILYNCHCOMMOINC - LE	 	 	20970	 	 	 	3/31/2011	 	
 	 	MERRILYNCHCOMMOINC - LE Total	 	 	 	 	 	 	3/31/2011	 	
 	 	MORGASTANLCAPITGROUPINC - LE	 	 	20943	 	 	 	12/31/2011	 	
 	 	 	 	 	 	 	20944	 	 	 	12/31/2012	 	
 	 	 	 	 	 	 	21001	 	 	 	12/31/2011	 	
 	 	 	 	 	 	 	21002	 	 	 	12/31/2011	 	
 	 	 	 	 	 	 	33489	 	 	 	3/31/2011	 	
 	 	MORGASTANLCAPITGROUPINC - LE Total	 	 	 	 	 	 	12/31/2012	 	
ISDA (OTC Financial) Total	 	 	 	 	 	 	 	 	 	 	12/31/2015	 	
Master Buy/Sell	 	EQUILONENTERPRISESLLC - LE	 	 	20559	 	 	 	6/30/2011	 	
 	 	EQUILONENTERPRISESLLC - LE Total	 	 	 	 	 	 	6/30/2011	 	
Master Buy/Sell Total	 	 	 	 	 	 	 	 	 	 	6/30/2011	 	
Grand Total	 	 	 	 	 	 	 	 	 	 	12/31/2015	 	
[Schedule 8.3(d) to Separation and Distribution Agreement]

 

Schedule 8.3(e)
Gas Price Indices Proceedings
 	 	 	 	 	
Case	 	Jurisdiction	 	Williams Entities Named	
In re: Western States Wholesale Natural Gas Antitrust Litigation, MDL 1566	 	District of Nevada
(Judge Pro), Base Case File No. CV-S-03-1431-PMP (PAL)	 	The Williams Companies, Inc.;
Williams Merchant Services Company, Inc.; Williams Energy Marketing & Trading (now known as Williams Gas Marketing, Inc)	
 	 	 	 	 	
Arandell Corporation, et al. v. Xcel Energy, Inc. et al.	 	Wisconsin
(Consolidated in to the above MDL 1566 matter) Case No. 02:07-CV-1019-PMP -PAL	 	The Williams Companies, Inc.;
Williams Merchant Services Company, Inc.; Williams Energy Marketing & Trading (now known as Williams Gas Marketing, Inc)	
 	 	 	 	 	
New Page Wisconsin System, Inc. v. CMS Resource Management Company et al.	 	Wisconsin
(Consolidated in to the above MDL 1566 matter) Case No.: CV-S-09-0915-PMP (PAL)	 	The Williams Companies, Inc.;
Williams Merchant Services Company, Inc.; Williams Energy Marketing & Trading (now known as Williams Gas Marketing, Inc)	
 	 	 	 	 	
Breckenridge Brewery of Colorado, LLC, et al. v. ONEOK, Inc., et al.	 	Colorado (Consolidated in to the above MDL 1566 matter) Case No. 2:06-CV-01351-PMP-PAL	 	The Williams Companies, Inc.;
Williams Merchant Services Company, Inc.; Williams Energy Marketing & Trading (now known as Williams Gas Marketing, Inc)	
 	 	 	 	 	
Heartland Regional Medical Center, et al. v. ONEOK, Inc., et al.	 	Missouri (Consolidated in to the above MDL 1566 matter) Case No. 02:07-CV-00987-PMP-PAL	 	The Williams Companies, Inc.;
Williams Merchant Services Company, Inc.; Williams Energy Marketing & Trading (now known as Williams Gas Marketing, Inc)	
 	 	 	 	 	
J.P. Morgan Trust Company v. ONEOK, In., et al.	 	Kansas (Consolidated in to the above MDL 1566 matter) Case No. 02:05-CV-01331-PMP-PAL	 	The Williams Companies, Inc.;
Williams Merchant Services Company, Inc.; Williams Energy Marketing & Trading (now known as Williams Gas Marketing, Inc)	
 	 	 	 	 	
Learjet, Inc., et al. v. ONEOK, Inc., et al.	 	Kansas (Consolidated in to the above MDL 1566 matter) Case No. 02:06-CV	 	The Williams Companies, Inc.;
Williams Merchant Services Company, Inc.; Williams Energy Marketing & Trading (now known as Williams Gas Marketing, Inc)	
 	 	 	 	 	
Scott Thompson Indemnification Claim	 	Not yet filed. Demand letter dated 12/28/10	 	The Williams Companies, Inc.;
Williams Energy Marketing & Trading (now known as Williams Gas Marketing, Inc)	
[Schedule 8.3(e) to Separation and Distribution Agreement]

Exhibit 23.2
Consent of Independent Registered Public Accounting Firm
     We consent to the reference to our firm under the caption “Experts” and to the use of our report dated April 29, 2011, except as it relates to the matter discussed in the first paragraph of “Basis of Presentation — Discontinued Operations” as set forth in Note 1, and the matter discussed in Note 2, as to which the date is June 21, 2011, and except as it relates to the matter discussed in the second paragraph of “Description of Business” as set forth in Note 1, as to which the date is July 18, 2011, in the Registration Statement (Amendment No. 4 to Form S-1) and related Prospectus of WPX Energy, Inc. dated September 1, 2011.
/s/ Ernst & Young LLP
Tulsa, Oklahoma
September 1, 2011

Exhibit 23.3
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS
We hereby consent to the reference to Netherland Sewell & Associates, Inc. under the heading “Experts” in Amendment No. 4 to the Registration Statement on Form S-1 (the “Registration Statement”) of WPX Energy, Inc., and to the reference to our audit of the proved reserves estimates of The Williams Companies, Inc. for the year ended December 31, 2010, in the Registration Statement.
 	 	 	 	 	
 	NETHERLAND, SEWELL & ASSOCIATES, INC.
 	 	
 	By:  	/s/ C.H. (Scott) Rees, III  	 	
 	 	C.H. (Scott) Rees III, P.E. 	 	
 	 	Chairman and Chief Executive Officer 	 	
 	
Dallas, Texas
September 1, 2011

Exhibit 23.4
CONSENT OF MILLER AND LENTS, LTD.
INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS
     The firm of Miller and Lents, Ltd. consents to the reference to Miller and Lents, Ltd. under the heading “Experts” in Amendment No. 4 to the Registration Statement on Form S-1 (the “Registration Statement”) of WPX Energy, Inc., and to the reference to our audit of the proved reserves estimates related to properties underlying the former Williams Coal Seam Gas Royalty Trust for the year ended December 31, 2010, in the Registration Statement.
     The analysis, conclusions, and methods contained in the report are based upon information that was in existence at the time the report was rendered and Miller and Lents, Ltd. has not updated and undertakes no duty to update anything contained in the report. While the report may be used as a descriptive resource, investors are advised that Miller and Lents, Ltd. has not verified information provided by others except as specifically noted in the report, and Miller and Lents, Ltd. makes no representation or warranty as to the accuracy of such information. Moreover, the conclusions contained in such report are based on assumptions that Miller and Lents, Ltd. believed were reasonable at the time of their preparation and that are described in such report in reasonable detail. However, there are a wide range of uncertainties and risks that are outside of the control of Miller and Lents, Ltd. which may impact these assumptions, including but not limited to unforeseen market changes, actions of governments or individuals, natural events, economic changes, and changes of laws and regulations or interpretation of laws and regulations.
 	 	 	 	 	
 	MILLER AND LENTS, LTD.
Texas Registered Engineering Firm No. F-1442
 	 	
 	By:  	/s/ Stephen M. Hamburg  	 	
 	 	Stephen M. Hamburg, P.E. 	 	
 	 	Senior Vice President 	 	
 	
Houston, Texas
September 1, 2011

Exhibit 23.5

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS
     We hereby consent to the reference to Ralph E. Davis Associates, Inc. under the heading “Experts” in Amendment No. 4 to the Registration Statement on Form S-1 (the “Registration Statement”) of WPX Energy, Inc., and to the reference to our audit of the proved reserves estimates of Apco Oil and Gas International Inc. for the year ended December 31, 2010, in the Registration Statement.

 	 	RALPH E. DAVIS ASSOCIATES, INC.	
 	 	 	 	 	
 	 		By: 		
 	 	 	 	 	
 	 	 	 	Allen C. Barron, P.E.	
 	 	 	 	President	

Houston, Texas
September 1, 2011	 	 	 	 	
		
1717 St. James Place, Suite 460 Houston, Texas 77056 Office 713-622-8955 Fax 713-626-3664 www.ralphedavis.com
Worldwide Energy Consultants Since 1924