WPX ENERGY, INC., 10-Q filed on 11/1/2012
Quarterly Report
Document and Entity Information
9 Months Ended
Sep. 30, 2012
Oct. 26, 2012
Entity Information [Line Items]
 
 
Document Type
10-Q 
 
Amendment Flag
false 
 
Document Period End Date
Sep. 30, 2012 
 
Document Fiscal Year Focus
2012 
 
Document Fiscal Period Focus
Q3 
 
Trading Symbol
WPX 
 
Entity Registrant Name
WPX ENERGY, INC. 
 
Entity Central Index Key
0001518832 
 
Current Fiscal Year End Date
--12-31 
 
Entity Filer Category
Non-accelerated Filer 
 
Entity Common Stock, Shares Outstanding
 
199,189,894 
Consolidated Balance Sheet (Unaudited) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2012
Dec. 31, 2011
Current assets:
 
 
Cash and cash equivalents
$ 240 
$ 526 
Accounts receivable, net of allowance of $10 at September 30, 2012 and $13 at December 31, 2011
385 
509 
Derivative assets
159 
506 
Inventories
71 
73 
Other
32 
60 
Total current assets
887 
1,674 
Investments
143 
125 
Properties and equipment (successful efforts method of accounting)
13,170 
12,199 
Less-accumulated depreciation, depletion and amortization
(4,757)
(3,977)
Properties and equipment, net
8,413 
8,222 
Derivative assets
10 
Other noncurrent assets
131 
401 
Total assets
9,583 
10,432 
Current liabilities:
 
 
Accounts payable
441 
702 
Accrued and other current liabilities
170 
186 
Deferred income taxes
28 
116 
Derivative liabilities
42 
152 
Total current liabilities
681 
1,156 
Deferred income taxes
1,459 
1,556 
Long-term debt
1,509 
1,503 
Derivative liabilities
Asset retirement obligations
311 
283 
Other noncurrent liabilities
126 
168 
Contingent liabilities and commitments (Note 8)
   
   
Stockholders' equity:
 
 
Preferred stock (100 million shares authorized at $0.01 par value; no shares issued)
   
   
Common stock (2 billion shares authorized at $0.01 par value; 199.1 million shares issued at September 30, 2012 and 197.1 million shares issued at December 31, 2011)
Additional paid-in-capital
5,465 
5,457 
Accumulated deficit
(117)
 
Accumulated other comprehensive income
55 
219 
Total stockholders' equity
5,405 
5,678 
Noncontrolling interests in consolidated subsidiaries
91 
81 
Total equity
5,496 
5,759 
Total liabilities and equity
$ 9,583 
$ 10,432 
Consolidated Balance Sheet (Unaudited) (Parenthetical) (USD $)
In Millions, except Share data, unless otherwise specified
Sep. 30, 2012
Dec. 31, 2011
Allowance for doubtful accounts
$ 10 
$ 13 
Preferred stock, par value
$ 0.01 
$ 0.01 
Preferred stock, shares authorized
100,000,000 
100,000,000 
Preferred stock, shares issued
   
   
Common stock, par value
$ 0.01 
$ 0.01 
Common stock, shares authorized
2,000,000,000 
2,000,000,000 
Common stock, shares issued
199,100,000 
197,100,000 
Consolidated Statement of Operations (USD $)
In Millions, except Per Share data, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2012
Sep. 30, 2011
Sep. 30, 2012
Sep. 30, 2011
Product revenues:
 
 
 
 
Natural gas sales
$ 331 
$ 440 
$ 1,000 
$ 1,271 
Natural gas liquid sales
65 
110 
236 
302 
Oil and condensate sales
118 
84 
346 
219 
Total product revenues
514 
634 
1,582 
1,792 
Gas management
186 
347 
710 
1,092 
Net gain (loss) on derivatives not designated as hedges (Note 10)
(22)
12 
63 
20 
Other
(1)
Total revenues
677 
995 
2,362 
2,912 
Costs and expenses:
 
 
 
 
Lease and facility operating
68 
70 
202 
194 
Gathering, processing and transportation
124 
130 
379 
363 
Taxes other than income
23 
32 
78 
105 
Gas management, including charges for unutilized pipeline capacity
200 
359 
749 
1,120 
Exploration
22 
74 
60 
100 
Depreciation, depletion and amortization
243 
239 
719 
670 
Impairment of costs of acquired unproved reserves (Note 4)
 
 
117 
 
General and administrative
67 
70 
206 
200 
Other-net
(1)
Total costs and expenses
752 
973 
2,518 
2,756 
Operating income (loss)
(75)
22 
(156)
156 
Interest expense
(25)
 
(77)
(97)
Interest capitalized
 
Investment income and other
25 
19 
Income (loss) from continuing operations before income taxes
(91)
29 
(201)
86 
Provision (benefit) for income taxes
(28)
10 
(71)
30 
Income (loss) from continuing operations
(63)
19 
(130)
56 
Income (loss) from discontinued operations
(3)
23 
(13)
Net income (loss)
(61)
16 
(107)
43 
Less: Net income attributable to noncontrolling interests
10 
Net income (loss) attributable to WPX Energy
$ (64)
$ 14 
$ (117)
$ 36 
Basic and diluted earnings (loss) per common share (Note 3):
 
 
 
 
Income (loss) from continuing operations
$ (0.33)
$ 0.09 
$ (0.70)
$ 0.25 
Income (loss) from discontinued operations
$ 0.01 
$ (0.02)
$ 0.11 
$ (0.07)
Net income (loss)
$ (0.32)
$ 0.07 
$ (0.59)
$ 0.18 
Weighted-average shares
199.1 
197.1 
198.7 
197.1 
Consolidated Statement of Comprehensive Income (Loss) (Unaudited) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2012
Sep. 30, 2011
Sep. 30, 2012
Sep. 30, 2011
Net income (loss) attributable to WPX Energy
$ (64)
$ 14 
$ (117)
$ 36 
Other comprehensive income (loss):
 
 
 
 
Change in fair value of cash flow hedges, net of tax
(12)
133 
56 
169 
Net reclassifications into earnings of net cash flow hedge gains, net of tax
(69)
(48)
(220)
(137)
Other comprehensive income (loss), net of tax
(81)
85 
(164)
32 
Comprehensive income (loss) attributable to WPX Energy
$ (145)
$ 99 
$ (281)
$ 68 
Consolidated Statement of Changes in Equity (USD $)
In Millions, unless otherwise specified
Total
Common Stock [Member]
Additional Paid-In Capital [Member]
Accumulated Deficit [Member]
Accumulated Other Comprehensive Income [Member]
Total Stockholders' Equity [Member]
Noncontrolling Interests in Consolidated Subsidiaries [Member]
Balance at Dec. 31, 2011
$ 5,759 
$ 2 
$ 5,457 
 
$ 219 
$ 5,678 
$ 81 1
Comprehensive income (loss):
 
 
 
 
 
 
 
Net income (loss)
(107)
 
 
(117)
 
(117)
10 1
Other comprehensive loss
(164)
 
 
 
(164)
(164)
 
Comprehensive loss
(271)
 
 
 
 
 
 
Stock based compensation
 
 
 
 
Balance at Sep. 30, 2012
$ 5,496 
$ 2 
$ 5,465 
$ (117)
$ 55 
$ 5,405 
$ 91 1
Consolidated Statement of Changes in Equity (Parenthetical)
Sep. 30, 2012
Dec. 31, 2011
Noncontrolling interest, ownership percentage by noncontrolling owners
31.00% 
31.00% 
Consolidated Statement of Cash Flows (USD $)
In Millions, unless otherwise specified
9 Months Ended
Sep. 30, 2012
Sep. 30, 2011
Operating Activities
 
 
Net income (loss)
$ (107)
$ 43 
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
Depreciation, depletion and amortization
727 
704 
Deferred income tax benefit
(90)
(6)
Provision for impairment of properties and equipment (including certain exploration expenses)
160 
120 
Amortization of stock-based awards
22 
 
(Gain) loss on sale of assets
(42)
 
Cash provided (used) by operating assets and liabilities:
 
 
Accounts receivable
128 
(39)
Inventories
(5)
Margin deposits and customer margin deposit payable
(5)
(25)
Other current assets
(10)
Accounts payable
(142)
78 
Accrued and other current liabilities
(20)
31 
Changes in current and noncurrent derivative assets and liabilities
(28)
Other, including changes in other noncurrent assets and liabilities
(25)
(10)
Net cash provided by operating activities
589 
888 
Investing Activities
 
 
Capital expenditures (a)
(1,165)
(1,088)
Proceeds from sale of assets
310 
17 
Purchases of investments
(2)
(8)
Other
23 
Net cash used in investing activities
(854)
(1,056)
Financing Activities
 
 
Proceeds from common stock
 
Proceeds from long-term debt
 
Net increase in notes payable to Williams
 
159 
Net changes in Williams' net investment
 
33 
Revolving debt facility costs
 
(8)
Other
(29)
(3)
Net cash provided by (used in) financing activities
(21)
181 
Net increase (decrease) in cash and cash equivalents
(286)
13 
Cash and cash equivalents at beginning of period
526 
37 
Cash and cash equivalents at end of period
$ 240 
$ 50 
Consolidated Statement of Cash Flows (Parenthetical) (USD $)
In Millions, unless otherwise specified
9 Months Ended
Sep. 30, 2012
Sep. 30, 2011
Increase to properties and equipment
$ (1,073)
$ (1,095)
Changes in related accounts payable
(92)
Capital expenditures
$ (1,165)
$ (1,088)
General, Description of Business and Basis of Presentation
General, Description of Business and Basis of Presentation

Note 1. General, Description of Business and Basis of Presentation

General

The accompanying interim consolidated financial statements do not include all the notes included in our annual financial statements and, therefore, should be read in conjunction with the consolidated financial statements and notes thereto in Exhibit 99.1 of our Form 8-K dated May 15, 2012. The accompanying interim consolidated financial statements include all normal recurring adjustments that, in the opinion of management, are necessary to present fairly our financial position at September 30, 2012, results of operations for the three and nine months ended September 30, 2012 and 2011, changes in equity for the nine months ended September 30, 2012 and cash flows for the nine months ended September 30, 2012 and 2011.

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 consolidated financial statements and accompanying notes. Actual results could differ from those estimates.

Description of Business

Operations of our company are located in the United States and South America and are organized into domestic and international reportable segments.

Domestic includes natural gas, natural gas liquids and oil development and production and gas management activities located in Colorado, New Mexico, North Dakota (Bakken Shale), Pennsylvania (Marcellus Shale) and Wyoming in the United States. We specialize in development and production from tight-sands and shale formations and coal bed methane reserves in the Piceance, San Juan, Powder River, Williston (Bakken Shale), Green River and Appalachian (Marcellus Shale) Basins. Associated with our commodity production are sales and marketing activities that include the management of various commodity contracts such as transportation, storage and related derivatives coupled with the sale of our commodity volumes.

International primarily consists of our ownership in Apco Oil and Gas International Inc. (“Apco”, NASDAQ listed: APAGF), an oil and gas exploration and production company with concessions in Argentina and Colombia.

The consolidated businesses represented herein as WPX Energy, Inc., also referred to herein as “WPX” or the “Company”, previously comprised substantially all of the exploration and production reportable segment of The Williams Companies, Inc. In these notes, WPX Energy, Inc. is at times referred to in the first person as “WPX”, “we”, “us” or “our”. The Williams Companies, Inc. and its affiliates, including Williams Partners L.P. (“WPZ”) are at times referred to collectively as “Williams”.

Separation from Williams

On February 16, 2011, Williams announced that its board of directors had approved pursuing a plan to separate Williams’ businesses into two stand-alone, publicly traded companies. As a result, WPX Energy, Inc. was formed to effect the separation. On November 30, 2011, the Board of Directors of Williams approved the spin-off of the Company. The spin-off was completed by way of a distribution on December 31, 2011.

Basis of Presentation

These financial statements are prepared on a consolidated basis. Prior to the separation from Williams, the financial statements were 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 entities contributed to us.

 

Discontinued operations

During the second quarter of 2012, we completed the sale of our holdings in the Barnett Shale and the Arkoma Basin. Beginning in the first quarter of 2012, we reported the results of operations and financial position of the Barnett Shale operations as discontinued operations for all periods presented. The results of operations and financial position of the Arkoma operations were already reported as discontinued operations beginning in 2011 as we initiated a formal process to pursue the divestiture of those operations in the first quarter of 2011 (See Note 2).

Unless indicated otherwise, the information in the Notes to Consolidated Financial Statements relates to continuing operations.

Discontinued Operations
Discontinued Operations

Note 2. Discontinued Operations

Summarized Results of Discontinued Operations

During the first quarter of 2012, our management signed an agreement to divest its holdings in the Barnett Shale and the Arkoma Basin for $306 million, subject to closing adjustments. The buyer provided $31 million in cash as a deposit at the signing of the agreement. During the second quarter of 2012, the transaction closed and we received an additional $270 million before closing and transaction costs. Activity in the third quarter of 2012 represents estimates associated with the post closing settlement expected in the fourth quarter of 2012. The Barnett Shale properties included approximately 27,000 net acres, interests in 320 wells and 91 miles of pipeline. The Arkoma properties included approximately 66,000 net acres, interests in 525 wells and 115 miles of pipeline.

 

     Three months
ended

September 30,
    Nine months
ended
September 30,
 
     2012     2011     2012     2011  
     (Millions)  

Revenues

   $ (1   $ 30      $ 25      $ 93   
  

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) from discontinued operations before impairments, gain on sale and income taxes

   $ (1   $ —        $ (2   $ (5

Impairments

     —          (5     —          (16

Gain on sale

     4        —          39        —     

(Provision) benefit for income taxes

     (1     2        (14     8   
  

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) from discontinued operations

   $ 2      $ (3   $ 23      $ (13
  

 

 

   

 

 

   

 

 

   

 

 

 

Impairments in 2011 reflect write-downs to estimates of fair value less costs to sell the assets of the Arkoma Basin operations that were classified as held for sale as of September 30, 2011. This nonrecurring fair value measurement, which falls within Level 3 of the fair value hierarchy, utilized a probability-weighted discounted cash flow analysis that was based on internal cash flow models.

Earnings (Loss) Per Common Share from Continuing Operations
Earnings (Loss) Per Common Share from Continuing Operations

Note 3. Earnings (Loss) Per Common Share from Continuing Operations

 

     Three months
ended
September 30,
     Nine months
ended
September 30,
 
     2012     2011      2012     2011  
     (Millions, except per-share amounts)  

Income (loss) from continuing operations attributable to WPX Energy, Inc. available to common stockholders for basic and diluted earnings (loss) per common share

   $ (66   $ 17       $ (140   $ 49   
  

 

 

   

 

 

    

 

 

   

 

 

 

Basic weighted-average shares

     199.1        197.1         198.7        197.1   
  

 

 

   

 

 

    

 

 

   

 

 

 

Diluted weighted-average shares

     199.1        197.1         198.7        197.1   
  

 

 

   

 

 

    

 

 

   

 

 

 

Earnings (loss) per common share from continuing operations:

         

Basic

   $ (0.33   $ 0.09       $ (0.70   $ 0.25   
  

 

 

   

 

 

    

 

 

   

 

 

 

Diluted

   $ (0.33   $ 0.09       $ (0.70   $ 0.25   
  

 

 

   

 

 

    

 

 

   

 

 

 

On December 31, 2011, 197.1 million shares of our common stock were distributed to Williams’ shareholders in conjunction with our spin-off. For comparative purposes, and to provide a more meaningful calculation for weighted average shares, we have assumed this amount of common stock to be outstanding as of the beginning of each period presented for 2011 in the calculation of basic and diluted weighted average shares.

For the three and nine months ended September 30, 2012, 1.7 million and 1.8 million, respectively, weighted-average nonvested restricted stock units and 0.9 million and 1.1 million, respectively, weighted-average stock options have been excluded from the computation of diluted earnings per common share as their inclusion would be antidilutive due to our loss from continuing operations attributable to WPX Energy, Inc.

The table below includes information related to stock options that were outstanding at September 30, 2012 but have been excluded from the computation of weighted-average stock options due to the option exercise price exceeding the third quarter weighted-average market price of our common shares.

 

     September 30, 2012  

Options excluded (millions)

     1.8   

Weighted-average exercise price of options excluded

   $ 17.50   

Exercise price range of options excluded

   $ 15.67 - $20.97  

Third quarter weighted-average market price

   $ 15.56   
Impairments and Exploration Expenses
Impairments and Exploration Expenses

Note 4. Impairments and Exploration Expenses

Impairment of cost of acquired unproved reserves

As a result of declines in forward natural gas prices during the first half of 2012 as compared to forward natural gas prices as of December 31, 2011, we performed impairment assessments of our capitalized cost of acquired unproved reserves during first and second quarter 2012. Accordingly, we recorded $52 million and $65 million in impairments of capitalized costs of acquired unproved reserves primarily in the Powder River Basin in the first and second quarters, respectively. Our impairment analyses included an assessment of discounted future cash flows, which considered information obtained from drilling, other activities and natural gas reserve quantities (See Note 9).

 

Exploration Expenses

 

     Three months
ended

September 30,
     Nine months
ended
September 30,
 
     2012      2011      2012      2011  
     (Millions)  

Geologic and geophysical costs

   $ 5       $ 1       $ 17       $ 4   

Dry hole costs

     2         11         3         13   

Unproved leasehold property impairment, amortization and expiration

     15         62         40         83   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total exploration expense

   $ 22       $ 74       $ 60       $ 100   
  

 

 

    

 

 

    

 

 

    

 

 

 

Dry hole costs in 2011 reflect an $11 million dry hole expense in connection with a Marcellus Shale well in Columbia County, Pennsylvania.

Unproved leasehold impairment, amortization and expiration in 2011 includes a $50 million write-off of leasehold costs associated with certain portions of our Columbia County, Pennsylvania acreage that we did not plan to develop.

Inventories
Inventories

Note 5. Inventories

 

     September 30,
2012
     December 31,
2011
 
     (Millions)  

Natural gas in underground storage

   $ 24       $ 34   

Material, supplies and other

     47         39   
  

 

 

    

 

 

 
   $ 71       $ 73   
  

 

 

    

 

 

 

During the first quarter of 2012, we recognized a lower of cost or market adjustment to natural gas in underground storage of approximately $11 million. This adjustment is reflected in gas management expense on the Consolidated Statement of Operations for the nine months ended September 30, 2012.

Debt and Banking Arrangements
Debt and Banking Arrangements

Note 6. Debt and Banking Arrangements

In November 2011, we issued $1.5 billion in face value Senior Notes. The Notes were issued under an indenture between us and The Bank of New York Mellon Trust Company, N.A., as trustee. The net proceeds from the offering of the Notes were approximately $1.481 billion after deducting the initial purchasers’ discounts and our offering expenses. We retained $500 million of the net proceeds from the issuance of the Notes and distributed the remainder of the net proceeds from the issuance of the Notes, approximately $981 million, to Williams.

In June 2012, we completed an exchange offer whereby we exchanged our privately-placed Notes for like principal amounts of registered 5.250% Senior Notes due 2017 and 6.000% Senior Notes due 2022. The exchange offer fulfilled our obligations under the registration rights agreement that we entered into as part of the November 2011 issuance.

During 2011, we entered into a new $1.5 billion five-year senior unsecured revolving credit facility agreement (the “Credit Facility Agreement”). Under the terms of the Credit Facility Agreement and subject to certain requirements, we 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. At September 30, 2012, there were no amounts outstanding under the Credit Facility Agreement.

 

Letters of Credit

In addition to the Notes and Credit Facility Agreement, WPX has entered into three bilateral, uncommitted letter of credit (“LC”) agreements. These LC agreements provide WPX the ability to meet various contractual requirements and incorporate terms similar to those found in the Credit Facility Agreement. At September 30, 2012, a total of $259 million in letters of credit have been issued.

Other

Apco has a loan agreement with a financial institution for a $10 million bank line of credit. The funds could be borrowed during a one year period which ended March 2012. As of September 30, 2012, Apco has $8 million outstanding under this banking agreement. Principal amounts will be repaid in installments through 2016. This debt agreement contains covenants that restrict or limit, among other things, our ability to create liens supporting indebtedness, purchase or sell assets outside the ordinary course of business and incur additional debt.

Provision (Benefit) for Income Taxes
Provision (Benefit) for Income Taxes

Note 7. Provision (Benefit) for Income Taxes

The provision (benefit) for income taxes from continuing operations includes:

 

     Three months
ended
September 30,
    Nine months
ended
September 30,
 
     2012     2011     2012     2011  
     (Millions)  

Current:

        

Federal

   $ 3      $ (10   $ 22      $ 21   

State

     —          (1     —          2   

Foreign

     4        3        12        8   
  

 

 

   

 

 

   

 

 

   

 

 

 
     7        (8     34        31   

Deferred:

        

Federal

     (30     17        (96     —     

State

     (5     1        (9     (1

Foreign

     —          —          —          —     
  

 

 

   

 

 

   

 

 

   

 

 

 
     (35     18        (105     (1
  

 

 

   

 

 

   

 

 

   

 

 

 

Total provision (benefit)

   $ (28   $ 10      $ (71   $ 30   
  

 

 

   

 

 

   

 

 

   

 

 

 

The effective income tax rate of the total benefit for the three months ended September 30, 2012, is less than the federal statutory rate due primarily to taxes on foreign operations and a reduction of the minimum tax credit that was allocated to us by Williams as part of the spin-off, partially offset by state income taxes.

The effective income tax rate of the total provision for the three months ended September 30, 2011, is greater than the federal statutory rate due primarily to taxes on foreign operations, partially offset by state income taxes.

The effective income tax rate of the total benefit for the nine months ended September 30, 2012, approximates the federal statutory rate due primarily to state income taxes offset by taxes on foreign operations and a reduction of the minimum tax credit that was allocated to us by Williams as part of the spin-off.

The effective income tax rate of the total provision for the nine months ended September 30, 2011, approximates the federal statutory rate due primarily to state income taxes, partially offset by taxes on foreign operations.

As of September 30, 2012, the amount of unrecognized tax benefits is insignificant. 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.

Contingent Liabilities
Contingent Liabilities

Note 8. Contingent Liabilities

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 proceeds 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 for certification, resolved claims relating to past calculation of royalty and overriding royalty payments, established certain rules to govern future royalty and overriding royalty payments, resolved claims related to past withholding for ad valorem tax payments, established a procedure for refunds of any such excess withholding in the future, and reserved two claims for court resolution. We have prevailed at the trial court and all levels of appeal on the first reserved claim regarding whether we are allowed to deduct mainline pipeline transportation costs pursuant to certain lease agreements. The remaining claim is 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 entitled to deduct a proportionate share of transportation costs in calculating royalty payments. We anticipate litigating the second reserved claim in 2013. 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.

In October 2011, a potential class of royalty interest owners in New Mexico and Colorado filed a complaint against us in the County of Rio Arriba, New Mexico. The complaint alleges failure to pay royalty on hydrocarbons including drip condensate, fraud and misstatement of the value of gas and affiliated sales, breach of duty to market hydrocarbons, violation of the New Mexico Oil and Gas Proceeds Payment Act, bad faith breach of contract and unjust enrichment. Plaintiffs seek monetary damages and a declaratory judgment enjoining activities relating to production, payments and future reporting. This matter has been removed to the United States District Court for New Mexico. In August 2012, a second potential class action was filed against us in the United States District Court for the District of New Mexico by mineral interest owners in New Mexico and Colorado. Plaintiffs claim breach of contract, breach of the covenant of good faith and fair dealing, breach of implied duty to market both in Colorado and New Mexico, violation of the New Mexico Oil and Gas Proceeds Payment Act and seek declaratory judgment, accounting and injunction. At this time, we believe that our royalty calculations have been properly determined in accordance with the appropriate contractual arrangements and applicable laws. We do not have sufficient information to calculate an estimated range of exposure related to these claims.

Other producers have been pursuing administrative appeals with a federal regulatory agency and have been in discussions with 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 those matters, we are monitoring them to evaluate whether their resolution might have the potential for unfavorable impact on our results of operations. Certain outstanding issues in those matters could be material to us. 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 though such guidelines are expected in the future. However, the timing of any such guidance is uncertain. 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. Interpretive guidelines on the applicability of certain deductions in the calculation of federal royalties are extremely complex and may vary based upon the ONRR’s assessment of the configuration of processing, treating and transportation operations supporting each federal lease. 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. From October 2005 through September 2012, our deductions used in the calculation of the royalty payments in states other than New Mexico associated with conventional gas production total approximately $100 million.

The New Mexico State Land Office Commissioner has filed suit against us in Santa Fe County alleging that we have underpaid royalties due per the oil and gas leases with the State of New Mexico. In August 2011, the parties agreed to stay this matter pending the New Mexico Supreme Court’s resolution of a similar matter involving a different producer. At this time, we do not have a sufficient basis to calculate an estimated range of exposure related to this claim.

Environmental matters

The Environmental Protection Agency (“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, one hour nitrogen dioxide emission limits, and hydraulic fracturing and water standards. 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

In connection with the Separation and Distribution Agreement, Williams is obligated to indemnify and hold us harmless from any losses arising out of liabilities assumed by us, and we are obligated to pay Williams any net proceeds realized from, the pending or threatened litigation described below relating to the 2000-2001 California energy crisis and the reporting of certain natural gas-related information to trade publications.

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 Federal Energy Regulatory Commission (“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 currently have a settlement agreement in principle with certain California utilities aimed at eliminating and substantially reducing this exposure. Once finalized, the settlement agreement will 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 will 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, seeking unspecified amounts 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. When a final order is entered against the one remaining defendant, the Colorado plaintiffs may appeal the order.

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. The plaintiffs have appealed to the United States Court of Appeals for the Ninth Circuit. Because of the uncertainty around 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.

Other 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 September 30, 2012, we have not received a claim against any of these indemnities and thus have no basis from which to estimate any reasonably possible loss. Further, 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 connection with the separation from Williams, we have agreed to indemnify and hold Williams harmless from any losses resulting from the operation of our business or arising out of liabilities assumed by us. Similarly, Williams has agreed to indemnify and hold us harmless from any losses resulting from the operation of its business or arising out of liabilities assumed by it.

Summary

As of September 30, 2012 and December 31, 2011, the Company had accrued approximately $18 million and $23 million, respectively, for loss contingencies associated with royalty litigation, reporting of natural gas information to trade publications and other contingencies. In certain circumstances, we may be eligible for insurance recoveries, or reimbursement from others. Any such recoveries or reimbursements will be recognized only when realizable.

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.

Fair Value Measurements
Fair Value Measurements

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. For the fair value disclosures of financial instruments, see Note 10.

 

     September 30, 2012      December 31, 2011  
     Level 1      Level 2      Level 3      Total      Level 1      Level 2      Level 3      Total  
     (Millions)      (Millions)  

Energy derivative assets

   $ 22       $ 143       $ 3       $ 168       $ 55       $ 454       $ 7       $ 516   

Energy derivative liabilities

   $ 14       $ 26       $ 3       $ 43       $ 41       $ 112       $ 6       $ 159   

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, options and swaptions.

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 or as swaptions and are financially settled. All of our financial options are valued using an industry standard Black-Scholes option pricing model. In connection with several crude oil swaps entered into, we granted crude oil swaptions to the swap counterparties in exchange for receiving premium hedged prices on the crude oil swaps. These swaptions grant the counterparty the option to enter into future swaps with us. 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.

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 98 percent of the net fair value of our derivatives portfolio expiring in the next 15 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 September 30, 2012, 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 transfers between Level 1 and Level 2 occurred during the periods ended September 30, 2012 and 2011. 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 and other assets classified as Level 3 in the fair value hierarchy.

Level 3 Fair Value Measurements Using Significant Unobservable Inputs

 

     Three months
ended
September 30,
    Nine months
ended
September 30,
 
     2012     2011     2012     2011  
     (Millions)  

Beginning balance

   $ —        $ 1      $ 1      $ 1   

Realized and unrealized gains (losses):

        

Included in income (loss) from continuing operations

     —          4        3        12   

Settlements

     —          (4     (4     (9

Transfers out of Level 3

     —          —          —          (3
  

 

 

   

 

 

   

 

 

   

 

 

 

Ending balance

   $ —        $ 1      $ —        $ 1   
  

 

 

   

 

 

   

 

 

   

 

 

 

Unrealized gains included in income (loss) from continuing operations relating to instruments still held at September 30

   $ (1   $ 1      $ —        $ 1   
  

 

 

   

 

 

   

 

 

   

 

 

 

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

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.

 

     Total losses for the nine months
ended September 30,
 
     2012     2011  
     (Millions)  

Impairments:

    

Costs of acquired unproved reserves (see Note 4)

   $ 117 (a)    $ —     
  

 

 

   

 

 

 

 

(a) Due to significant declines in forward natural gas and natural gas liquids prices during the first half of 2012, we assessed the carrying value of our natural gas costs of acquired unproved reserves for impairments. Most of the impairment charge is related to costs of acquired unproved reserves in the Powder River Basin. Our assessment utilized estimates of future discounted cash flows. Significant judgments and assumptions in these assessments include estimates of probable and possible reserve quantities, estimates of future natural gas prices using a forward NYMEX curve adjusted for locational basis differentials, future natural gas liquids prices, expectation for market participant drilling plans, expected capital costs and an after-tax discount rate of 13 percent and 15 percent for probable and possible reserves, respectively.
Financial Instruments, Derivatives, Guarantees and Concentration of Credit Risk
Financial Instruments, Derivatives, Guarantees and Concentration of Credit Risk

Note 10. Financial Instruments, Derivatives, Guarantees and Concentration of Credit Risk

We use the following methods and assumptions for financial instruments that require fair value disclosure.

Cash and cash equivalents and restricted cash: The carrying amounts reported in the Consolidated 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 Consolidated Balance Sheet approximate fair value given the short-term status of the instruments.

Long-term debt: The fair value of our debt is determined on market rates and the prices of similar securities with similar terms and credit ratings and is categorized as Level 2 in the fair value hierarchy.

Energy derivatives: Energy derivatives include futures, forwards, swaps, options and swaptions. These are carried at fair value in the Consolidated Balance Sheet. See Note 9 for a discussion of valuation of energy derivatives.

Carrying amounts and fair values of our financial instruments were as follows:

 

     September 30, 2012     December 31, 2011  

Asset (Liability)

   Carrying
Amount
    Fair
Value
    Carrying
Amount
    Fair
Value
 
     (Millions)  

Cash and cash equivalents

   $ 240      $ 240      $ 526      $ 526   

Restricted cash (current and noncurrent)

     29        29        29        29   

Other

     (2     (2     (7     (7

Long-term debt (a)

     1,508        1,615        1,502        1,523   

Net energy derivatives:

        

Energy commodity cash flow hedges

     88        88        347        347   

Other energy derivatives

     37        37        10        10   

 

(a) Excludes capital leases.

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, natural gas liquids 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. Through December 31, 2011, the majority of our derivatives were designated as cash flow hedges. For derivatives entered into after December 31, 2011, we have elected not to utilize hedge accounting.

We produce, buy and sell natural gas, natural gas liquids and crude oil at different locations throughout the United States. To reduce exposure to a decrease in revenues from fluctuations in commodity market prices, we enter into futures contracts, swap agreements and financial option contracts to mitigate the price risk on forecasted sales of natural gas, natural gas liquids and crude oil. We have also entered into basis swap agreements to reduce the locational price risk associated with our natural gas 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 purchased options, a combination of options that comprise a net purchased option or a zero-cost collar or swaptions. 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 cash flow hedges of production volumes as of September 30, 2012:

 

Commodity

   Period    Contract Type      Location    Notional Volume
(BBtu/day)
     Weighted Average
Price
($/MMBtu)
 

Natural Gas

   Oct – Dec 2012      Location Swaps       Rockies      135       $ 4.76   

Natural Gas

   Oct – Dec 2012      Location Swaps       San Juan      110       $ 4.94   

Natural Gas

   Oct – Dec 2012      Location Swaps       MidCon      65       $ 4.74   

Natural Gas

   Oct – Dec 2012      Location Swaps       SoCal      33       $ 5.14   

Natural Gas

   Oct – Dec 2012      Location Swaps       Northeast      138       $ 5.62   

Natural Gas

   2013      Location Swaps       Northeast      5       $ 6.48   

 

Commodity

   Period    Contract Type    Location    Notional Volume
(Bbls/day)
     Weighted Average
Price
($/Bbl)
 

Crude Oil

   Oct – Dec 2012    Business Day Avg Swaps    WTI      8,500       $ 98.20   

The following table sets forth the derivative volumes not designated as cash flow hedges but are economic hedges of production volumes as of September 30, 2012:

 

Commodity

   Period    Contract Type    Location    Notional Volume
(BBtu/day)
     Weighted Average
Price
($/MMBtu)
 

Natural Gas

   Oct – Dec 2012    Location Swaps    MidCon      23       $ 4.80   

 

Commodity

   Period    Contract Type    Location      Notional Volume
(Bbls/day)
     Weighted Average
Price
($/Bbl)
 

Crude Oil

   Oct – Dec 2012    Costless Collar      WTI         2,000       $ 85.00 - $106.30   

Crude Oil

   2013    Business Day Avg Swaps      WTI         9,000       $ 100.52   

Crude Oil

   2013    Swaption      WTI         2,250       $ 108.10   

 

Commodity

   Period    Contract Type    Location    Notional Volume
(Bbls/day)
     Weighted Average
Price
($Bbl)
 

Natural Gas Liquids

   Oct – Dec 2012    Swaps    Mont Belvieu      4,000       $ 50.74   

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. Derivatives for transportation and 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. 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 do not represent hedges of our production in our commodity derivatives portfolio as of September 30, 2012. Natural gas is presented in millions of British Thermal Units (“MMBtu”). All of the Central hub risk realizes by March 31, 2013 and 100% of the basis risk realizes by October 2015. The net index position includes contracts for the future sale of physical natural gas related to our production. These contracts result in minimal commodity price risk exposure and have a value of less than $1 million at September 30, 2012.

 

Derivative Notional Volumes

   Unit of
Measure
     Central Hub
Risk (a)
    Basis
Risk (b)
    Index
Risk (c)
 

Not Designated as Hedging Instruments

         

Risk Management

     MMBtu         (12,592,995     (11,742,995     (65,778,916

Other

     MMBtu           3,702,500     

 

(a) Includes physical and financial derivative transactions that settle against the Henry Hub price.
(b) Includes physical and 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.

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 Consolidated 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.

 

     September 30, 2012      December 31, 2011  
     Assets      Liabilities      Assets      Liabilities  
     (Millions)  

Designated as hedging instruments

   $ 90       $ 2       $ 360       $ 13   

Not designated as hedging instruments:

           

Economic hedges of production

     32         1         3         7   

Legacy natural gas contracts from former power business

     23         23         93         92   

All other

     23         17         60         47   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total derivatives not designated as hedging instruments

     78         41         156         146   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total derivatives

   $ 168       $ 43       $ 516       $ 159   
  

 

 

    

 

 

    

 

 

    

 

 

 

 

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.

 

     Three  months
ended
September 30,
     Nine months
ended
September  30,
      
     2012     2011      2012      2011      Classification
     (Millions)      (Millions)       

Net gain recognized in other comprehensive income (loss) (effective portion)

   $ (19   $ 212       $ 88       $ 270       AOCI

Net gain reclassified from accumulated other comprehensive income into income (effective portion) (a)

   $ 110      $ 77       $ 348       $ 219       Revenues

 

(a) Gains reclassified from accumulated other comprehensive income (loss) primarily represent realized gains associated with our production reflected in natural gas sales and oil and condensate 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 recognized in revenues for our energy commodity derivatives not designated as hedging instruments.

 

     Three months
ended
September 30,
     Nine months
ended
September  30,
 
     2012     2011      2012      2011  
     (Millions)      (Millions)  

Unrealized gain (loss)

   $ (31   $ 5       $ 28       $ (10

Realized gain (loss)

     9        7         35         30   
  

 

 

   

 

 

    

 

 

    

 

 

 

Net gain

   $ (22   $ 12       $ 63       $ 20   
  

 

 

   

 

 

    

 

 

    

 

 

 

The cash flow impact of our derivative activities is presented in the Consolidated 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, under certain events, 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 Investment Services. 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.

As of September 30, 2012, we had a net derivative liability position with certain counterparties of $10 million, which includes a liability credit reserve for our own nonperformance risk of less than $1 million. The 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 were triggered, was $9 million.

 

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. During the first quarter of 2012, approximately $15 million of unrealized gains were recognized into earnings in 2012 for hedge transactions where the underlying transactions were no longer probable of occurring due to the sale of our Barnett Shale properties. The $15 million gain is included in net gains (losses) on derivatives not designated as hedges on the Consolidated Statement of Operations for the nine months ended September 30, 2012, as are second quarter 2012 changes in forward mark to market value. As of September 30, 2012, we have hedged portions of future cash flows associated with anticipated energy commodity purchases and sales for up to six months. Based on recorded values at September 30, 2012, $56 million of net gains (net of income tax provision of $32 million) will be reclassified into earnings within the next nine months. These recorded values are based on market prices of the commodities as of September 30, 2012. 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.

We also enter into master netting agreements to mitigate counterparty performance and credit risk. During 2012 and 2011 we did not incur any significant losses due to counterparty bankruptcy filings.

The gross credit exposure from our derivative contracts as of September 30, 2012, is summarized as follows.

 

Counterparty Type

   Investment
Grade  (a)
     Total  
     (Millions)  

Gas and electric utilities and integrated oil and gas companies

   $ —         $ 1   

Energy marketers and traders

     66         76   

Financial institutions

     91         91   
  

 

 

    

 

 

 
   $ 157         168   
  

 

 

    

 

 

 

Credit reserves

        —     
     

 

 

 

Gross credit exposure from derivatives

      $ 168   
     

 

 

 

 

(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.

 

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 September 30, 2012, excluding collateral support discussed below, is summarized as follows.

 

Counterparty Type

   Investment
Grade  (a)
     Total  
     (Millions)  

Gas and electric utilities

   $ —         $ —     

Energy marketers and traders

     63         64   

Financial institutions

     71         71   
  

 

 

    

 

 

 
   $ 134         135   
  

 

 

    

 

 

 

Credit reserves

        —     
     

 

 

 

Net credit exposure from derivatives

      $ 135   
     

 

 

 

 

(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 twelve largest net counterparty positions represent approximately 99 percent of our net credit exposure from derivatives and are all with investment grade counterparties. Under our marginless hedging agreements with key banks, we nor the participating financial institutions are required to provide collateral support related to hedging activities.

At September 30, 2012, we held collateral support of $9 million, either in the form of cash or letters of credit, related to our other derivative positions.

Segment Disclosures
Segment Disclosures

Note 11. Segment Disclosures

Our reporting segments are domestic and international (See Note 1).

Our segment presentation is reflective of the parent-level focus by our chief operating decision-maker, considering the resource allocation and governance provisions. Domestic and international maintain separate capital and cash management structures. These factors, coupled with differences in the business environment associated with operating in different countries, serve to differentiate the management of this entity as a whole.

Performance Measurement

We evaluate performance based upon segment revenues and segment operating income (loss). There are no intersegment sales between domestic and international.

 

The following tables reflect the reconciliation of segment revenues and segment operating income (loss) to revenues and operating income (loss) as reported in the Consolidated Statement of Operations.

 

     Domestic     International      Total  
           (Millions)         

Three months ended September 30, 2012

       

Total revenues

   $ 642      $ 35       $ 677   
  

 

 

   

 

 

    

 

 

 

Costs and expenses:

       

Lease and facility operating

   $ 60      $ 8       $ 68   

Gathering, processing and transportation

     124        —           124   

Taxes other than income

     17        6         23   

Gas management, including charges for unutilized pipeline capacity

     200        —           200   

Exploration

     19        3         22   

Depreciation, depletion and amortization

     236        7         243   

General and administrative

     64        3         67   

Other—net

     4        1         5   
  

 

 

   

 

 

    

 

 

 

Total costs and expenses

   $ 724      $ 28       $ 752   
  

 

 

   

 

 

    

 

 

 

Operating income (loss)

   $ (82   $ 7       $ (75

Interest expense

     (25     —           (25

Interest capitalized

     2        —           2   

Investment income and other

     1        6         7   
  

 

 

   

 

 

    

 

 

 

Income (loss) from continuing operations before income taxes

   $ (104   $ 13       $ (91
  

 

 

   

 

 

    

 

 

 

Three months ended September 30, 2011

       

Total revenues

   $ 967      $ 28       $ 995   
  

 

 

   

 

 

    

 

 

 

Costs and expenses:

       

Lease and facility operating

   $ 63      $ 7       $ 70   

Gathering, processing and transportation

     130        —           130   

Taxes other than income

     26        6         32   

Gas management, including charges for unutilized pipeline capacity

     359        —           359   

Exploration

     74        —           74   

Depreciation, depletion and amortization

     233        6         239   

General and administrative

     67        3         70   

Other—net

     (2     1         (1
  

 

 

   

 

 

    

 

 

 

Total costs and expenses

   $ 950      $ 23       $ 973   
  

 

 

   

 

 

    

 

 

 

Operating income (loss)

   $ 17      $ 5       $ 22   

Investment income and other

     2        5         7   
  

 

 

   

 

 

    

 

 

 

Income (loss) from continuing operations before income taxes

   $ 19      $ 10       $ 29   
  

 

 

   

 

 

    

 

 

 

 

     Domestic     International     Total  
           (Millions)        

Nine months ended September 30, 2012

      
                    

Total revenues

   $ 2,262      $ 100      $ 2,362   
  

 

 

   

 

 

   

 

 

 

Costs and expenses:

      

Lease and facility operating

   $ 181      $ 21      $ 202   

Gathering, processing and transportation

     379        —          379   

Taxes other than income

     60        18        78   

Gas management, including charges for unutilized pipeline capacity

     749        —          749   

Exploration

     49        11        60   

Depreciation, depletion and amortization

     700        19        719   

Impairment of costs of acquired unproved reserves

     117        —          117   

General and administrative

     197        9        206   

Other—net

     9        (1     8   
  

 

 

   

 

 

   

 

 

 

Total costs and expenses

   $ 2,441      $ 77      $ 2,518   
  

 

 

   

 

 

   

 

 

 

Operating income (loss)

   $ (179   $ 23      $ (156

Interest expense

     (77     —          (77

Interest capitalized

     7        —          7   

Investment income and other

     3        22        25   
  

 

 

   

 

 

   

 

 

 

Income (loss) from continuing operations before income taxes

   $ (246   $ 45      $ (201
  

 

 

   

 

 

   

 

 

 

Nine months ended September 30, 2011

      

Total revenues

   $ 2,834      $ 78      $ 2,912   
  

 

 

   

 

 

   

 

 

 

Costs and expenses:

      

Lease and facility operating

   $ 176      $ 18      $ 194   

Gathering, processing and transportation

     363        —          363   

Taxes other than income

     90        15        105   

Gas management, including charges for unutilized pipeline capacity

     1,120        —          1,120   

Exploration

     98        2        100   

Depreciation, depletion and amortization

     654        16        670   

General and administrative

     192        8        200   

Other—net

     2        2        4   
  

 

 

   

 

 

   

 

 

 

Total costs and expenses

   $ 2,695      $ 61      $ 2,756   
  

 

 

   

 

 

   

 

 

 

Operating income (loss)

   $ 139      $ 17      $ 156   

Interest expense

     (97     —          (97

Interest capitalized

     8        —          8   

Investment income and other

     5        14        19   
  

 

 

   

 

 

   

 

 

 

Income (loss) from continuing operations before income taxes

   $ 55      $ 31      $ 86   
  

 

 

   

 

 

   

 

 

 

Total assets

      

Total assets as of September 30, 2012

   $ 9,247      $ 336      $ 9,583   
  

 

 

   

 

 

   

 

 

 

Total assets as of December 31, 2011

   $ 10,144      $ 288      $ 10,432   
  

 

 

   

 

 

   

 

 

 
General, Description of Business and Basis of Presentation (Policies)

Basis of Presentation

These financial statements are prepared on a consolidated basis. Prior to the separation from Williams, the financial statements were 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 entities contributed to us.

Discontinued operations

During the second quarter of 2012, we completed the sale of our holdings in the Barnett Shale and the Arkoma Basin. Beginning in the first quarter of 2012, we reported the results of operations and financial position of the Barnett Shale operations as discontinued operations for all periods presented. The results of operations and financial position of the Arkoma operations were already reported as discontinued operations beginning in 2011 as we initiated a formal process to pursue the divestiture of those operations in the first quarter of 2011 (See Note 2).

Discontinued Operations (Tables)
Summarized Results of Discontinued Operations

 

     Three months
ended

September 30,
    Nine months
ended
September 30,
 
     2012     2011     2012     2011  
     (Millions)  

Revenues

   $ (1   $ 30      $ 25      $ 93   
  

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) from discontinued operations before impairments, gain on sale and income taxes

   $ (1   $ —        $ (2   $ (5

Impairments

     —          (5     —          (16

Gain on sale

     4        —          39        —     

(Provision) benefit for income taxes

     (1     2        (14     8   
  

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) from discontinued operations

   $ 2      $ (3   $ 23      $ (13
  

 

 

   

 

 

   

 

 

   

 

 

 
Earnings (Loss) Per Common Share from Continuing Operations (Tables)

Note 3. Earnings (Loss) Per Common Share from Continuing Operations

 

     Three months
ended
September 30,
     Nine months
ended
September 30,
 
     2012     2011      2012     2011  
     (Millions, except per-share amounts)  

Income (loss) from continuing operations attributable to WPX Energy, Inc. available to common stockholders for basic and diluted earnings (loss) per common share

   $ (66   $ 17       $ (140   $ 49   
  

 

 

   

 

 

    

 

 

   

 

 

 

Basic weighted-average shares

     199.1        197.1         198.7        197.1   
  

 

 

   

 

 

    

 

 

   

 

 

 

Diluted weighted-average shares

     199.1        197.1         198.7        197.1   
  

 

 

   

 

 

    

 

 

   

 

 

 

Earnings (loss) per common share from continuing operations:

         

Basic

   $ (0.33   $ 0.09       $ (0.70   $ 0.25   
  

 

 

   

 

 

    

 

 

   

 

 

 

Diluted

   $ (0.33   $ 0.09       $ (0.70   $ 0.25   
  

 

 

   

 

 

    

 

 

   

 

 

 

The table below includes information related to stock options that were outstanding at September 30, 2012 but have been excluded from the computation of weighted-average stock options due to the option exercise price exceeding the third quarter weighted-average market price of our common shares.

 

     September 30, 2012  

Options excluded (millions)

     1.8   

Weighted-average exercise price of options excluded

   $ 17.50   

Exercise price range of options excluded

   $ 15.67 - $20.97  

Third quarter weighted-average market price

   $ 15.56   
Impairments and Exploration Expenses (Tables)
Exploration Expenses

 

Exploration Expenses

 

     Three months
ended

September 30,
     Nine months
ended
September 30,
 
     2012      2011      2012      2011  
     (Millions)  

Geologic and geophysical costs

   $ 5       $ 1       $ 17       $ 4   

Dry hole costs

     2         11         3         13   

Unproved leasehold property impairment, amortization and expiration

     15         62         40         83   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total exploration expense

   $ 22       $ 74       $ 60       $ 100   
  

 

 

    

 

 

    

 

 

    

 

 

 
Inventories (Tables)
Inventories

Inventories

 

     September 30,
2012
     December 31,
2011
 
     (Millions)  

Natural gas in underground storage

   $ 24       $ 34   

Material, supplies and other

     47         39   
  

 

 

    

 

 

 
   $ 71       $ 73   
  

 

 

    

 

 

 
Provision (Benefit) for Income Taxes (Tables)
Provision (Benefit) for Income Taxes from Continuing Operations

The provision (benefit) for income taxes from continuing operations includes:

 

     Three months
ended
September 30,
    Nine months
ended
September 30,
 
     2012     2011     2012     2011  
     (Millions)  

Current:

        

Federal

   $ 3      $ (10   $ 22      $ 21   

State

     —          (1     —          2   

Foreign

     4        3        12        8   
  

 

 

   

 

 

   

 

 

   

 

 

 
     7        (8     34        31   

Deferred:

        

Federal

     (30     17        (96     —     

State

     (5     1        (9     (1

Foreign

     —          —          —          —     
  

 

 

   

 

 

   

 

 

   

 

 

 
     (35     18        (105     (1
  

 

 

   

 

 

   

 

 

   

 

 

 

Total provision (benefit)

   $ (28   $ 10      $ (71   $ 30   
  

 

 

   

 

 

   

 

 

   

 

 

 
Fair Value Measurements (Tables)

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. For the fair value disclosures of financial instruments, see Note 10.

 

     September 30, 2012      December 31, 2011  
     Level 1      Level 2      Level 3      Total      Level 1      Level 2      Level 3      Total  
     (Millions)      (Millions)  

Energy derivative assets

   $ 22       $ 143       $ 3       $ 168       $ 55       $ 454       $ 7       $ 516   

Energy derivative liabilities

   $ 14       $ 26       $ 3       $ 43       $ 41       $ 112       $ 6       $ 159   

The following table presents 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

 

     Three months
ended
September 30,
    Nine months
ended
September 30,
 
     2012     2011     2012     2011  
     (Millions)  

Beginning balance

   $ —        $ 1      $ 1      $ 1   

Realized and unrealized gains (losses):

        

Included in income (loss) from continuing operations

     —          4        3        12   

Settlements

     —          (4     (4     (9

Transfers out of Level 3

     —          —          —          (3
  

 

 

   

 

 

   

 

 

   

 

 

 

Ending balance

   $ —        $ 1      $ —        $ 1   
  

 

 

   

 

 

   

 

 

   

 

 

 

Unrealized gains included in income (loss) from continuing operations relating to instruments still held at September 30

   $ (1   $ 1      $ —        $ 1   
  

 

 

   

 

 

   

 

 

   

 

 

 

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.

 

     Total losses for the nine months
ended September 30,
 
     2012     2011  
     (Millions)  

Impairments:

    

Costs of acquired unproved reserves (see Note 4)

   $ 117 (a)    $ —     
  

 

 

   

 

 

 

 

(a) Due to significant declines in forward natural gas and natural gas liquids prices during the first half of 2012, we assessed the carrying value of our natural gas costs of acquired unproved reserves for impairments. Most of the impairment charge is related to costs of acquired unproved reserves in the Powder River Basin. Our assessment utilized estimates of future discounted cash flows. Significant judgments and assumptions in these assessments include estimates of probable and possible reserve quantities, estimates of future natural gas prices using a forward NYMEX curve adjusted for locational basis differentials, future natural gas liquids prices, expectation for market participant drilling plans, expected capital costs and an after-tax discount rate of 13 percent and 15 percent for probable and possible reserves, respectively.
Financial Instruments, Derivatives, Guarantees and Concentration of Credit Risk (Tables)

Carrying amounts and fair values of our financial instruments were as follows:

 

     September 30, 2012     December 31, 2011  

Asset (Liability)

   Carrying
Amount
    Fair
Value
    Carrying
Amount
    Fair
Value
 
     (Millions)  

Cash and cash equivalents

   $ 240      $ 240      $ 526      $ 526   

Restricted cash (current and noncurrent)

     29        29        29        29   

Other

     (2     (2     (7     (7

Long-term debt (a)

     1,508        1,615        1,502        1,523   

Net energy derivatives:

        

Energy commodity cash flow hedges

     88        88        347        347   

Other energy derivatives

     37        37        10        10   

 

(a) Excludes capital leases.

The following table sets forth the derivative volumes designated as cash flow hedges of production volumes as of September 30, 2012:

 

Commodity

   Period    Contract Type      Location    Notional Volume
(BBtu/day)
     Weighted Average
Price
($/MMBtu)
 

Natural Gas

   Oct – Dec 2012      Location Swaps       Rockies      135       $ 4.76   

Natural Gas

   Oct – Dec 2012      Location Swaps       San Juan      110       $ 4.94   

Natural Gas

   Oct – Dec 2012      Location Swaps       MidCon      65       $ 4.74   

Natural Gas

   Oct – Dec 2012      Location Swaps       SoCal      33       $ 5.14   

Natural Gas

   Oct – Dec 2012      Location Swaps       Northeast      138       $ 5.62   

Natural Gas

   2013      Location Swaps       Northeast      5       $ 6.48   

 

Commodity

   Period    Contract Type    Location    Notional Volume
(Bbls/day)
     Weighted Average
Price
($/Bbl)
 

Crude Oil

   Oct – Dec 2012    Business Day Avg Swaps    WTI      8,500       $ 98.20   

The following table sets forth the derivative volumes not designated as cash flow hedges but are economic hedges of production volumes as of September 30, 2012:

 

Commodity

   Period    Contract Type    Location    Notional Volume
(BBtu/day)
     Weighted Average
Price
($/MMBtu)
 

Natural Gas

   Oct – Dec 2012    Location Swaps    MidCon      23       $ 4.80   

 

Commodity

   Period    Contract Type    Location      Notional Volume
(Bbls/day)
     Weighted Average
Price
($/Bbl)
 

Crude Oil

   Oct – Dec 2012    Costless Collar      WTI         2,000       $ 85.00 - $106.30   

Crude Oil

   2013    Business Day Avg Swaps      WTI         9,000       $ 100.52   

Crude Oil

   2013    Swaption      WTI         2,250       $ 108.10   

 

Commodity

   Period    Contract Type    Location    Notional Volume
(Bbls/day)
     Weighted Average
Price
($Bbl)
 

Natural Gas Liquids

   Oct – Dec 2012    Swaps    Mont Belvieu      4,000       $ 50.74   

The following table depicts the notional amounts of the net long (short) positions which do not represent hedges of our production in our commodity derivatives portfolio as of September 30, 2012. Natural gas is presented in millions of British Thermal Units (“MMBtu”). All of the Central hub risk realizes by March 31, 2013 and 100% of the basis risk realizes by October 2015. The net index position includes contracts for the future sale of physical natural gas related to our production. These contracts result in minimal commodity price risk exposure and have a value of less than $1 million at September 30, 2012.

 

Derivative Notional Volumes

   Unit of
Measure
     Central Hub
Risk (a)
    Basis
Risk (b)
    Index
Risk (c)
 

Not Designated as Hedging Instruments

         

Risk Management

     MMBtu         (12,592,995     (11,742,995     (65,778,916

Other

     MMBtu           3,702,500     

 

(a) Includes physical and financial derivative transactions that settle against the Henry Hub price.
(b) Includes physical and 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.

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.

 

     September 30, 2012      December 31, 2011  
     Assets      Liabilities      Assets      Liabilities  
     (Millions)  

Designated as hedging instruments

   $ 90       $ 2       $ 360       $ 13   

Not designated as hedging instruments:

           

Economic hedges of production

     32         1         3         7   

Legacy natural gas contracts from former power business

     23         23         93         92   

All other

     23         17         60         47   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total derivatives not designated as hedging instruments

     78         41         156         146   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total derivatives

   $ 168       $ 43       $ 516       $ 159   
  

 

 

    

 

 

    

 

 

    

 

 

 

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.

 

     Three  months
ended
September 30,
     Nine months
ended
September  30,
      
     2012     2011      2012      2011      Classification
     (Millions)      (Millions)       

Net gain recognized in other comprehensive income (loss) (effective portion)

   $ (19   $ 212       $ 88       $ 270       AOCI

Net gain reclassified from accumulated other comprehensive income into income (effective portion) (a)

   $ 110      $ 77       $ 348       $ 219       Revenues

 

(a) Gains reclassified from accumulated other comprehensive income (loss) primarily represent realized gains associated with our production reflected in natural gas sales and oil and condensate sales.

The following table presents pre-tax gains and losses recognized in revenues for our energy commodity derivatives not designated as hedging instruments.

 

     Three months
ended
September 30,
     Nine months
ended
September  30,
 
     2012     2011      2012      2011  
     (Millions)      (Millions)  

Unrealized gain (loss)

   $ (31   $ 5       $ 28       $ (10

Realized gain (loss)

     9        7         35         30   
  

 

 

   

 

 

    

 

 

    

 

 

 

Net gain

   $ (22   $ 12       $ 63       $ 20   
  

 

 

   

 

 

    

 

 

    

 

 

 

The gross credit exposure from our derivative contracts as of September 30, 2012, is summarized as follows.

 

Counterparty Type

   Investment
Grade  (a)
     Total  
     (Millions)  

Gas and electric utilities and integrated oil and gas companies

   $ —         $ 1   

Energy marketers and traders

     66         76   

Financial institutions

     91         91   
  

 

 

    

 

 

 
   $ 157         168   
  

 

 

    

 

 

 

Credit reserves

        —     
     

 

 

 

Gross credit exposure from derivatives

      $ 168   
     

 

 

 

 

(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.

The net credit exposure from our derivatives as of September 30, 2012, excluding collateral support discussed below, is summarized as follows.

 

Counterparty Type

   Investment
Grade  (a)
     Total  
     (Millions)  

Gas and electric utilities

   $ —         $ —     

Energy marketers and traders

     63         64   

Financial institutions

     71         71   
  

 

 

    

 

 

 
   $ 134         135   
  

 

 

    

 

 

 

Credit reserves

        —     
     

 

 

 

Net credit exposure from derivatives

      $ 135   
     

 

 

 

 

(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.
Segment Disclosures (Tables)
Reconciliation of Segment Revenues and Segment Operating Income (Loss)

The following tables reflect the reconciliation of segment revenues and segment operating income (loss) to revenues and operating income (loss) as reported in the Consolidated Statement of Operations.

 

     Domestic     International      Total  
           (Millions)         

Three months ended September 30, 2012

       

Total revenues

   $ 642      $ 35       $ 677   
  

 

 

   

 

 

    

 

 

 

Costs and expenses:

       

Lease and facility operating

   $ 60      $ 8       $ 68   

Gathering, processing and transportation

     124        —           124   

Taxes other than income

     17        6         23   

Gas management, including charges for unutilized pipeline capacity

     200        —           200   

Exploration

     19        3         22   

Depreciation, depletion and amortization

     236        7         243   

General and administrative

     64        3         67   

Other—net

     4        1         5   
  

 

 

   

 

 

    

 

 

 

Total costs and expenses

   $ 724      $ 28       $ 752   
  

 

 

   

 

 

    

 

 

 

Operating income (loss)

   $ (82   $ 7       $ (75

Interest expense

     (25     —           (25

Interest capitalized

     2        —           2   

Investment income and other

     1        6         7   
  

 

 

   

 

 

    

 

 

 

Income (loss) from continuing operations before income taxes

   $ (104   $ 13       $ (91
  

 

 

   

 

 

    

 

 

 

Three months ended September 30, 2011

       

Total revenues

   $ 967      $ 28       $ 995   
  

 

 

   

 

 

    

 

 

 

Costs and expenses:

       

Lease and facility operating

   $ 63      $ 7       $ 70   

Gathering, processing and transportation

     130        —           130   

Taxes other than income

     26        6         32   

Gas management, including charges for unutilized pipeline capacity

     359        —           359   

Exploration

     74        —           74   

Depreciation, depletion and amortization

     233        6         239   

General and administrative

     67        3         70   

Other—net

     (2     1         (1
  

 

 

   

 

 

    

 

 

 

Total costs and expenses

   $ 950      $ 23       $ 973   
  

 

 

   

 

 

    

 

 

 

Operating income (loss)

   $ 17      $ 5       $ 22   

Investment income and other

     2        5         7   
  

 

 

   

 

 

    

 

 

 

Income (loss) from continuing operations before income taxes

   $ 19      $ 10       $ 29   
  

 

 

   

 

 

    

 

 

 

 

     Domestic     International     Total  
           (Millions)        

Nine months ended September 30, 2012

      
                    

Total revenues

   $ 2,262      $ 100      $ 2,362   
  

 

 

   

 

 

   

 

 

 

Costs and expenses:

      

Lease and facility operating

   $ 181      $ 21      $ 202   

Gathering, processing and transportation

     379        —          379   

Taxes other than income

     60        18        78   

Gas management, including charges for unutilized pipeline capacity

     749        —          749   

Exploration

     49        11        60   

Depreciation, depletion and amortization

     700        19        719   

Impairment of costs of acquired unproved reserves

     117        —          117   

General and administrative

     197        9        206   

Other—net

     9        (1     8   
  

 

 

   

 

 

   

 

 

 

Total costs and expenses

   $ 2,441      $ 77      $ 2,518   
  

 

 

   

 

 

   

 

 

 

Operating income (loss)

   $ (179   $ 23      $ (156

Interest expense

     (77     —          (77

Interest capitalized

     7        —          7   

Investment income and other

     3        22        25   
  

 

 

   

 

 

   

 

 

 

Income (loss) from continuing operations before income taxes

   $ (246   $ 45      $ (201
  

 

 

   

 

 

   

 

 

 

Nine months ended September 30, 2011

      

Total revenues

   $ 2,834      $ 78      $ 2,912   
  

 

 

   

 

 

   

 

 

 

Costs and expenses:

      

Lease and facility operating

   $ 176      $ 18      $ 194   

Gathering, processing and transportation

     363        —          363   

Taxes other than income

     90        15        105   

Gas management, including charges for unutilized pipeline capacity

     1,120        —          1,120   

Exploration

     98        2        100   

Depreciation, depletion and amortization

     654        16        670   

General and administrative

     192        8        200   

Other—net

     2        2        4   
  

 

 

   

 

 

   

 

 

 

Total costs and expenses

   $ 2,695      $ 61      $ 2,756   
  

 

 

   

 

 

   

 

 

 

Operating income (loss)

   $ 139      $ 17      $ 156   

Interest expense

     (97     —          (97

Interest capitalized

     8        —          8   

Investment income and other

     5        14        19   
  

 

 

   

 

 

   

 

 

 

Income (loss) from continuing operations before income taxes

   $ 55      $ 31      $ 86   
  

 

 

   

 

 

   

 

 

 

Total assets

      

Total assets as of September 30, 2012

   $ 9,247      $ 336      $ 9,583   
  

 

 

   

 

 

   

 

 

 

Total assets as of December 31, 2011

   $ 10,144      $ 288      $ 10,432   
  

 

 

   

 

 

   

 

 

 
Discontinued Operations - Additional Information (Detail) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Jun. 30, 2012
Mar. 31, 2012
Sales Price as per agreement to divest company holdings in the Barnett Shale and the Arkoma Basin
 
$ 306 
Deposit received from potential buyer of Barnett Shale and Arkoma assets
 
31 
Proceeds from Divestiture
$ 270 
 
Barnett Shale [Member]
 
 
Area in disposal group
 
27,000 
Interests in number of wells in disposal group
 
320 
Length of pipeline in disposal group
 
91 
Arkoma Basin [Member]
 
 
Area in disposal group
 
66,000 
Interests in number of wells in disposal group
 
525 
Length of pipeline in disposal group
 
115 
Summarized Results of Discontinued Operations (Detail) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2012
Sep. 30, 2011
Sep. 30, 2012
Sep. 30, 2011
Revenues
$ (1)
$ 30 
$ 25 
$ 93 
Income (loss) from discontinued operations before impairments, gain on sale and income taxes
(1)
 
(2)
(5)
Impairments
 
(5)
 
(16)
Gain on sale
 
39 
 
(Provision) benefit for income taxes
(1)
(14)
Income (loss) from discontinued operations
$ 2 
$ (3)
$ 23 
$ (13)
Earnings (Loss) Per Common Share from Continuing Operations (Detail) (USD $)
In Millions, except Per Share data, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2012
Sep. 30, 2011
Sep. 30, 2012
Sep. 30, 2011
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
 
 
 
 
Income (loss) from continuing operations attributable to WPX Energy, Inc. available to common stockholders for basic and diluted earnings (loss) per common share
$ (66)
$ 17 
$ (140)
$ 49 
Basic weighted-average shares
199.1 
197.1 
198.7 
197.1 
Diluted weighted-average shares
199.1 
197.1 
198.7 
197.1 
Earnings (loss) per common share from continuing operations:
 
 
 
 
Basic
$ (0.33)
$ 0.09 
$ (0.70)
$ 0.25 
Diluted
$ (0.33)
$ 0.09 
$ (0.70)
$ 0.25 
Earnings (Loss) Per Common Share from Continuing Operations - Additional information (Detail)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended 3 Months Ended 9 Months Ended
Dec. 31, 2011
Sep. 30, 2012
Restricted Stock Units [Member]
Sep. 30, 2012
Restricted Stock Units [Member]
Sep. 30, 2012
Stock Options [Member]
Sep. 30, 2012
Stock Options [Member]
Common stock distributed to William's shareholders in conjunction with spin-off
197.1 
 
 
 
 
Shares excluded from the computation of diluted earnings per common share
 
1.7 
1.9 
0.9 
1.1 
Schedule of Stock Options Outstanding Excluded from Computation of Weighted-Average Stock (Detail) (USD $)
In Millions, except Per Share data, unless otherwise specified
9 Months Ended
Sep. 30, 2012
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
 
Options excluded (millions)
1.8 
Weighted-average exercise price of options excluded
$ 17.50 
Exercise price range of options excluded, lower limit
$ 15.67 
Exercise price range of options excluded, upper limit
$ 20.97 
Third quarter weighted-average market price
$ 15.56 
Impairments and Exploration Expenses - Additional information (Detail) (USD $)
In Millions, unless otherwise specified
9 Months Ended 3 Months Ended
Sep. 30, 2012
Sep. 30, 2011
Marcellus Shale [Member]
Jun. 30, 2012
Powder River Basin [Member]
Mar. 31, 2012
Powder River Basin [Member]
Impairment of capitalized costs of acquired unproved reserves
$ 117 
 
$ 65 
$ 52 
Dry hole costs
 
11 
 
 
Write-off of leasehold costs
 
$ 50 
 
 
Exploration Expenses (Detail) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2012
Sep. 30, 2011
Sep. 30, 2012
Sep. 30, 2011
Geologic and geophysical costs
$ 5 
$ 1 
$ 17 
$ 4 
Dry hole costs
11 
13 
Unproved leasehold property impairment, amortization and expiration
15 
62 
40 
83 
Total exploration expense
$ 22 
$ 74 
$ 60 
$ 100 
Inventories (Detail) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2012
Dec. 31, 2011
Natural gas in underground storage
$ 24 
$ 34 
Material, supplies and other
47 
39 
Inventory, Total
$ 71 
$ 73 
Inventories - Additional Information (Detail) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2012
Adjustment to natural gas in underground storage
$ 11 
Debt and Banking Arrangements (Detail) (USD $)
12 Months Ended 12 Months Ended 1 Months Ended
Sep. 30, 2012
Dec. 31, 2011
Five-year senior unsecured revolving credit facility agreement [Member]
Sep. 30, 2012
Five-year senior unsecured revolving credit facility agreement [Member]
Mar. 31, 2012
Apco
Sep. 30, 2012
Apco
Jun. 30, 2012
Notes Payable Due 2017 [Member]
Jun. 30, 2012
Notes Payable Due 2022 [Member]
Nov. 30, 2011
Senior Notes [Member]
Face value of senior notes
 
 
 
 
 
 
 
$ 1,500,000,000 
Net proceeds from the offering of the notes
 
 
 
 
 
 
 
1,481,000,000 
Net proceeds retained
 
 
 
 
 
 
 
500,000,000 
Net proceeds distributed
 
 
 
 
 
 
 
981,000,000 
Interest rate of senior notes
 
 
 
 
 
5.25% 
6.00% 
 
Credit Facility Agreement
 
1,500,000,000 
 
 
10,000,000 
 
 
 
Increase in the commitments
 
300,000,000 
 
 
 
 
 
 
Line of credit facility, Outstanding amount
 
 
 
8,000,000 
 
 
 
Letters of credit issued
$ 259,000,000 
 
 
 
 
 
 
 
Period of borrowing the funds
 
 
 
1 year 
 
 
 
 
Provision (Benefit) for Income Taxes from Continuing Operations (Detail) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2012
Sep. 30, 2011
Sep. 30, 2012
Sep. 30, 2011
Current:
 
 
 
 
Federal
$ 3 
$ (10)
$ 22 
$ 21 
State
 
(1)
 
Foreign
12 
Total current
(8)
34 
31 
Deferred:
 
 
 
 
Federal
(30)
17 
(96)
 
State
(5)
(9)
(1)
Foreign
   
   
   
   
Total Deferred
(35)
18 
(105)
(1)
Total provision (benefit)
$ (28)
$ 10 
$ (71)
$ 30 
Contingent Liabilities - Additional Information (Detail) (USD $)
In Millions, unless otherwise specified
1 Months Ended 9 Months Ended
Sep. 30, 2006
Claim
Sep. 30, 2012
Dec. 31, 2011
Number of claims reserved for court resolution
 
 
Processing, treating and transportation costs used in the calculation of federal royalties
 
$ 100 
 
Loss contingencies associated with royalty litigation
 
$ 18 
$ 23 
Fair Value Measurements - Additional Information (Detail)
9 Months Ended
Sep. 30, 2012
Percentage of net fair value of derivatives portfolio expiring
98.00% 
Expiry of net fair value of derivatives portfolio
15 months 
Level 3 Fair Value Measurements Using Significant Unobservable Inputs (Detail) (USD $)
In Millions, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2012
Sep. 30, 2011
Sep. 30, 2012
Sep. 30, 2011
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]