WPX ENERGY, INC., 10-Q filed on 5/2/2013
Quarterly Report
Document and Entity Information
3 Months Ended
Mar. 31, 2013
Apr. 30, 2013
Document Documentand Entity Information [Abstract]
 
 
Document Type
10-Q 
 
Amendment Flag
false 
 
Document Period End Date
Mar. 31, 2013 
 
Document Fiscal Year Focus
2013 
 
Document Fiscal Period Focus
Q1 
 
Trading Symbol
WPX 
 
Entity Registrant Name
WPX ENERGY, INC. 
 
Entity Central Index Key
0001518832 
 
Current Fiscal Year End Date
--12-31 
 
Entity Filer Category
Large Accelerated Filer 
 
Entity Common Stock, Shares Outstanding
 
200,228,607 
Consolidated Balance Sheet (Unaudited) (USD $)
In Millions, unless otherwise specified
Mar. 31, 2013
Dec. 31, 2012
Current assets:
 
 
Cash and cash equivalents
$ 112 
$ 153 
Accounts receivable, net of allowance of $10 at March 31, 2013 and $11 at December 31, 2012
411 
443 
Deferred income taxes
33 
17 
Gross Derivative Assets, Current
20 
58 
Inventories
54 
66 
Other
50 
35 
Total current assets
680 
772 
Investments
148 
145 
Properties and equipment (successful efforts method of accounting)
13,613 
13,339 
Less—accumulated depreciation, depletion and amortization
(5,162)
(4,923)
Properties and equipment, net
8,451 
8,416 
Gross Derivative Assets, Noncurrent
Other noncurrent assets
121 
121 
Total assets
9,404 
9,456 
Current liabilities:
 
 
Accounts payable
521 
509 
Accrued and other current liabilities
145 
203 
Deferred income taxes
Total current liabilities
751 
726 
Deferred income taxes
1,347 
1,401 
Long-term debt
1,589 
1,508 
Gross Derivative Liabilities, Noncurrent
Gross Derivative Liabilities, Current
85 
14 
Asset retirement obligations
323 
316 
Other noncurrent liabilities
137 
133 
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; 200.3 million shares issued at March 31, 2013 and 199.3 million shares issued at December 31, 2012)
Additional paid-in-capital
5,489 
5,487 
Accumulated deficit
(339)
(223)
Accumulated other comprehensive income (loss)
(1)
Total stockholders’ equity
5,151 
5,268 
Noncontrolling interests in consolidated subsidiaries
106 
103 
Total equity
5,257 
5,371 
Total liabilities and equity
$ 9,404 
$ 9,456 
Consolidated Balance Sheet (Unaudited) (Parenthetical) (USD $)
In Millions, except Share data, unless otherwise specified
Mar. 31, 2013
Dec. 31, 2012
Statement of Financial Position [Abstract]
 
 
Allowance for doubtful accounts
$ 10 
$ 11 
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
200,300,000 
199,300,000 
Consolidated Statement of Operations (Unaudited) (USD $)
In Millions, except Per Share data, unless otherwise specified
3 Months Ended
Mar. 31, 2013
Mar. 31, 2012
Product revenues:
 
 
Natural gas sales
$ 267 
$ 357 
Oil and condensate sales
54 
93 
Natural gas liquid sales
139 
106 
Total product revenues
460 
556 
Gas management
261 
337 
Net gain (loss) on derivatives not designated as hedges (Note 10)
(94)
14 
Other
Total revenues
631 
910 
Costs and expenses:
 
 
Lease and facility operating
75 
67 
Gathering, processing and transportation
107 
135 
Taxes other than income
35 
30 
Gas management, including charges for unutilized pipeline capacity
243 
355 
Exploration
19 
19 
Depreciation, depletion and amortization
231 
228 
Impairment of costs of acquired unproved reserves (Note 4)
52 1
General and administrative
72 
68 
Other—net
Total costs and expenses
789 
959 
Operating income (loss)
(158)
(49)
Interest expense
(26)
(26)
Interest capitalized
Investment income and other
10 
Income (loss) from continuing operations before income taxes
(176)
(63)
Provision (benefit) for income taxes
(63)
(25)
Income (loss) from continuing operations
(113)
(38)
Income (loss) from discontinued operations
(2)
Net income (loss)
(113)
(40)
Less: Net income attributable to noncontrolling interests
Net income (loss) attributable to WPX Energy
$ (116)
$ (43)
Basic and diluted earnings (loss) per common share (Note 3):
 
 
Income (loss) from continuing operations (in dollars per share)
$ (0.58)
$ (0.21)
Income (loss) from discontinued operations (in dollars per share)
$ 0.00 
$ (0.01)
Net income (loss) (in dollars per share)
$ (0.58)
$ (0.22)
Weighted-average shares
199.9 
198.1 
[1] Due to significant declines in forward natural gas prices during the first quarter 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.
Consolidated Statement of Comprehensive Income (Loss) (Unaudited) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2013
Mar. 31, 2012
Statement of Other Comprehensive Income [Abstract]
 
 
Net income (loss) attributable to WPX Energy
$ (116)
$ (43)
Other comprehensive income (loss):
 
 
Change in fair value of cash flow hedges, net of tax (a)
1
65 1
Net reclassifications into earnings of net cash flow hedge realized gains, net of tax (b)
(3)2
(67)2
Other comprehensive income (loss), net of tax
(3)
(2)
Comprehensive income (loss) attributable to WPX Energy
$ (119)
$ (45)
Consolidated Statement of Comprehensive Income (Loss) (Parenthetical) (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2013
Mar. 31, 2012
Statement of Other Comprehensive Income [Abstract]
 
 
Unrealized gain (loss) on derivatives, tax
 
$ 37 
Unrealized gains recognized for hedge transactions
 
15 
Reclassification adjustment on derivatives included in net income, tax
39 
Net gain (loss) reclassified from accumulated other comprehensive income (loss) into income (effective portion) (a)
$ 5 
$ 106 
Consolidated Statement of Changes in Equity (Unaudited) (USD $)
In Millions, unless otherwise specified
Total
Common Stock
Additional Paid-In- Capital
Accumulated Deficit
Accumulated Other Comprehensive Income (Loss)
Total Stockholders’ Equity
Noncontrolling Interests in Consolidated Subsidiaries
December 31, 2012 at Dec. 31, 2012
$ 5,371 
$ 2 
$ 5,487 
$ (223)
$ 2 
$ 5,268 
$ 103 1
Comprehensive income (loss):
 
 
 
 
 
 
 
Net income (loss)
(113)
 
 
(116)
 
(116)
1
Other comprehensive loss
(3)
 
 
 
(3)
(3)
 
Comprehensive income (loss)
(116)
 
 
 
 
 
 
Stock based compensation
 
 
 
 
March 31, 2013 at Mar. 31, 2013
$ 5,257 
$ 2 
$ 5,489 
$ (339)
$ (1)
$ 5,151 
$ 106 1
Consolidated Statement of Changes in Equity (Parenthetical)
Mar. 31, 2013
Dec. 31, 2012
Statement of Stockholders' Equity [Abstract]
 
 
Noncontrolling interest, ownership percentage by noncontrolling owners
31.00% 
31.00% 
Consolidated Statement of Cash Flows (USD $)
In Millions, unless otherwise specified
3 Months Ended
Mar. 31, 2013
Mar. 31, 2012
Operating Activities
 
 
Net income (loss)
$ (113)
$ (40)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
Depreciation, depletion and amortization
231 
235 
Deferred income tax provision (benefit)
(68)
(37)
Provision for impairment of properties and equipment (including certain exploration expenses)
14 
64 
Amortization of stock-based awards
Cash provided (used) by operating assets and liabilities:
 
 
Accounts receivable
33 
96 
Inventories
12 
11 
Margin deposits and customer margin deposit payable
(11)
(7)
Other current assets
(9)
(9)
Accounts payable
(80)
Accrued and other current liabilities
(63)
17 
Changes in current and noncurrent derivative assets and liabilities
103 
Other, including changes in other noncurrent assets and liabilities
(5)
Net cash provided by operating activities
143 
252 
Investing Activities
 
 
Capital expenditures
(271)1
(428)1
Deposit received from buyer of Barnett Shale and Arkoma assets
31 
Purchases of investments
(2)
Other
Net cash used in investing activities
(271)
(395)
Financing Activities
 
 
Proceeds from common stock
Proceeds from long-term debt
Borrowings on credit facility
80 
Other
(28)
Net cash provided by (used in) financing activities
87 
(21)
Net increase (decrease) in cash and cash equivalents
(41)
(164)
Cash and cash equivalents at beginning of period
153 
526 
Cash and cash equivalents at end of period
112 
362 
Increase to properties and equipment
(277)
(369)
Changes in related accounts payable
$ 6 
$ (59)
General, Description of Business and Basis of Presentation
General, Description of Business and Basis of Presentation
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 for the year ended December 31, 2012 in the Company's Annual Report on Form 10-K. 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 March 31, 2013, results of operations for the three months ended March 31, 2013 and 2012, changes in equity for the three months ended March 31, 2013 and cash flows for the three months ended March 31, 2013 and 2012.
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, oil and natural gas liquids ("NGL") development and production and gas management activities located in Colorado, New Mexico, North Dakota, Pennsylvania 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, Appalachian and Green River 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” is at times referred to in the first person as “we”, “us” or “our”.
Basis of Presentation
 
Discontinued operations
During the second quarter of 2012, we completed the sale of our holdings in the Barnett Shale and the Arkoma Basin. The results of operations of the Barnett Shale and Arkoma Basin operations are reported as discontinued operations (see Note 2).
Unless indicated otherwise, the information in the Notes to Consolidated Financial Statements relates to continuing operations.
Recently Issued Accounting Standards
In February 2013, the Financial Accounting Standards Board ("FASB") issued Accounting Standard Update ("ASU") 2013-04, Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation Is Fixed at the Reporting Date ("ASU 2013-04"). The amendments in ASU 2013-04 provide guidance for the recognition, measurement, and disclosure of obligations resulting from joint and several liability arrangements from which the total amount of the obligation within the scope of this guidance is fixed at the reporting date. ASU 2013-04 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013. The Company is currently evaluating the impact of ASU 2013-04, but we do not anticipate a material impact to the Company's financial position, results of operations or cash flows as a result of applying this ASU.
Recently Adopted Provisions of U.S. GAAP
In accordance with U.S. GAAP, the following provisions, which had no material impact on the Company's financial position, results of operations or cash flows, were effective as of January 1, 2013:
The requirement to provide disclosures related to offsetting assets and liabilities, specifically as it relates to offsetting disclosures, wherein an entity must now make separate disclosures regarding the gross assets and liabilities, the offsetting amounts and the net assets and liabilities (see Note 10).
The requirement to present significant amounts reclassified out of Accumulated Other Comprehensive Income (Loss) ("AOCI") by the respective line items in the results of operations. See Note 10 and the Consolidated Statements of Comprehensive Income (Loss).
Discontinued Operations
Discontinued Operations
Discontinued Operations
Summarized Results of Discontinued Operations
 
 
Three months
ended March 31,
 
 
2012
 
 
(Millions)
Revenues
 
$
20

Loss from discontinued operations
 
$
(2
)
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 March 31,
 
2013
 
2012
 
(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
$
(116
)
 
$
(41
)
Basic weighted-average shares
199.9

 
198.1

Diluted weighted-average shares
199.9

 
198.1

Earnings (loss) per common share from continuing operations:
 
 
 
Basic
$
(0.58
)
 
$
(0.21
)
Diluted
$
(0.58
)
 
$
(0.21
)

For the three months ended March 31, 2013 and 2012, 1.9 million and 2.5 million, respectively, weighted-average nonvested restricted stock units and awards and 0.8 million and 1.3 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 March 31, 2013 and 2012 but have been excluded from the computation of weighted-average stock options due to the option exercise price exceeding the first quarter weighted-average market price of our common shares.
 
March 31,
 
2013
 
2012
Options excluded (millions)
1.8

 
0.8

Weighted-average exercise price of options excluded
$
17.50

 
$
19.32

Exercise price range of options excluded
$15.67 - $20.97
 
$18.16 - $20.97
First quarter weighted-average market price
$
15.27

 
$
17.67

Impairments and Exploration Expense
Impairments and Exploration Expense
Impairments and Exploration Expense
Impairment of cost of acquired unproved reserves
As a result of declines in forward natural gas prices during the first quarter 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-quarter 2012. Accordingly, we recorded a $52 million impairment of capitalized costs of acquired unproved reserves primarily in the Powder River Basin. 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 Expense
 
Three months
ended March 31,
 
2013
 
2012
 
(Millions)
Geologic and geophysical costs
$
5

 
$
7

Dry hole costs
1

 
1

Unproved leasehold property impairment, amortization and expiration
13

 
11

Total exploration expense
$
19

 
$
19

Inventories
Inventories
Inventories 
 
March 31,
2013
 
December 31,
2012
 
(Millions)
Natural gas in underground storage
$
7

 
$
24

Material, supplies and other
47

 
42

 
$
54

 
$
66


During the first quarter of 2013, we sold most of our natural gas in storage and terminated two of three storage capacity agreements.
Debt and Banking Arrangements
Debt and Banking Arrangements
Debt and Banking Arrangements
As of the indicated dates, our debt consisted of the following:
 
March 31,
2013
 
December 31,
2012
 
(Millions)
5.250% Senior Notes due 2017
$
400

 
$
400

6.000% Senior Notes due 2022
1,100

 
1,100

Credit facility agreement
80

 

Apco
8

 
8

Other
1

 

 
$
1,589

 
$
1,508


We have a $1.5 billion five-year senior unsecured revolving credit facility agreement (the “Credit Facility Agreement”) that expires in 2016. 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. As of March 31, 2013, there was $80 million borrowed under the Credit Facility Agreement, with a variable interest rate of 2.08 percent. Subsequent to March 31, 2013, we have borrowed an additional $100 million under the Credit Facility Agreement.

Letters of Credit
WPX has also 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 March 31, 2013, a total of $311 million in letters of credit have been issued.
Provision (Benefit) for Income Taxes
Provision (Benefit) for Income Taxes
Provision (Benefit) for Income Taxes
The provision (benefit) for income taxes from continuing operations includes: 
 
Three months
ended March 31,
 
2013
 
2012
 
(Millions)
Current:
 
 
 
Federal
$
1

 
$
10

State

 

Foreign
4

 
3

 
5

 
13

Deferred:
 
 
 
Federal
(62
)
 
(35
)
State
(6
)
 
(3
)
Foreign

 

 
(68
)
 
(38
)
Total provision (benefit)
$
(63
)
 
$
(25
)

The effective income tax rate of the total benefit for the three months ended March 31, 2013, is greater than the federal statutory rate due primarily to state income taxes, partially offset by taxes on foreign operations.
The effective income tax rate of the total provision for the three months ended March 31, 2012, is greater than the federal statutory rate due primarily to state income taxes and an adjustment to the minimum tax credit that was allocated to us by The Williams Companies, Inc. ("Williams") as part of the spin-off, partially offset by taxes on foreign operations.
As of March 31, 2013, the amount of unrecognized tax benefits is not material. 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
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 related to 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. Plaintiffs have claimed damages of approximately $20 million plus interest. However, we believe our royalty calculations have been properly determined in accordance with the appropriate contractual arrangements and Colorado law.
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.
In February 2013, a potential class of royalty owners filed suit in Campbell County District Court, Wyoming, alleging violations of the Wyoming Royalty Payment Act by failing to properly and timely pay and report royalty and overriding royalty. Plaintiffs seek monetary damages, interest and penalties, and declaratory and injunctive relief. The case has been removed to Federal Court. At this time, we do not have a sufficient basis to calculate an estimated range of exposure related to this claim.
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 and, independent of the issuance of additional guidance, ONRR has recently asked producers to attempt to evaluate the deductibility of these fees directly with the midstream companies that transport and process gas. 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 April 2006 through March 2013, our deductions used in the calculation of the royalty payments in states other than New Mexico associated with conventional gas production total approximately $107 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 and 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 March 31, 2013, 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 March 31, 2013 and December 31, 2012, the Company had accrued approximately $18 million 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
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. The carrying amounts reported in the Consolidated Balance Sheets for cash and cash equivalents and restricted cash approximate fair value due to the nature of the instrument and/or the short-term maturity of these instruments. 
 
March 31, 2013
 
December 31, 2012
 
Level 1
 
Level 2
 
Level 3
 
Total
 
Level 1
 
Level 2
 
Level 3
 
Total
 
(Millions)
 
(Millions)
Energy derivative assets
$
8

 
$
15

 
$
1

 
$
24

 
$
20

 
$
38

 
$
2

 
$
60

Energy derivative liabilities
$
6

 
$
77

 
$
2

 
$
85

 
$
11

 
$
1

 
$
3

 
$
15

Long-term debt (a)
$

 
$
1,660

 
$

 
$
1,660

 
$

 
$
1,617

 
$

 
$
1,617

__________
(a)
The carrying value of long-term debt, excluding capital leases, was $1,588 million and $1,508 million as of March 31, 2013 and December 31, 2012, respectively.
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. These are carried at fair value on the Consolidated Balance Sheets.
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 natural gas swaps entered into, we granted natural gas swaptions to the swap counterparties in exchange for receiving premium hedged prices on the natural gas 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. Also categorized as Level 2 is the fair value of our debt, which is determined on market rates and the prices of similar securities with similar terms and credit ratings. Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2.
Our energy derivatives portfolio is largely comprised of exchange-traded products or like products and the tenure of our derivatives portfolio is relatively short with more than 99 percent of the net fair value of our derivatives portfolio expiring at the end of 2014. 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 March 31, 2013, consist primarily of natural gas index transactions that are used to manage our physical requirements.
 
Reclassifications of fair value between Level 1, Level 2 and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. No significant transfers between Level 1 and Level 2 occurred during the periods ended March 31, 2013 and 2012.
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 March 31,
 
2013
 
2012
 
(Millions)
Beginning balance
$
(1
)
 
$
1

Realized and unrealized gains (losses):
 
 
 
Included in income (loss) from continuing operations

 
1

Purchases, issuances, and settlements

 
(3
)
Transfers out of Level 3

 

Ending balance
$
(1
)
 
$
(1
)
Unrealized gains included in income (loss) from continuing operations relating to instruments still held at March 31
$

 
$
(1
)

Realized and unrealized gains (losses) included in income (loss) from continuing operations for the above periods are reported in revenues in our Consolidated Statements 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 three months
ended March 31,
 
 
2013
 
2012
 
 
(Millions)
 
Impairments:
 
 
 
 
Costs of acquired unproved reserves (see Note 4)
$

 
$
52

(a) 
 __________
(a)
Due to significant declines in forward natural gas prices during the first quarter 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.
Derivatives and Concentration of Credit Risk
Derivatives and Concentration of Credit Risk
Derivatives and Concentration of Credit Risk
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. Through December 2011, we elected to designate the majority of our applicable derivative instruments as cash flow hedges. Beginning in 2012, we began entering into commodity derivative contracts that will continue to serve as economic hedges but will not be designated as cash flow hedges for accounting purposes as we have elected not to utilize this method of accounting on new derivatives instruments. Remaining commodity derivatives recorded at December 31, 2011 that were designated as cash flow hedges were fully realized by the end of the first quarter of 2013.
We produce, buy and sell natural gas, crude oil and natural gas liquids 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, crude oil and natural gas liquids. We have also entered into basis swap agreements to reduce the locational price risk associated with our producing basins. Our financial option contracts are either purchased options, a combination of options that comprise a net purchased option or a zero- cost collar or swaptions.
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 economically hedge the expected cash flows generated by those agreements.
The following table sets forth the derivative volumes that are economic hedges of production volumes as well as the table depicts the notional amounts of the net long (short) positions which do not represent economic hedges of our production, both which are included in our commodity derivatives portfolio as of March 31, 2013.

  Derivatives related to production
Commodity
 
Period
 
Contract Type(a)
 
Location
 
Notional Volume (b)
 
Weighted Average
Price(c)
Crude Oil
 
Apr-Dec 2013
 
Fixed Price Swaps
 
WTI
 
(8,665
)
 
$
100.64

Crude Oil
 
Apr-Dec 2013
 
Fixed Price Swaps
 
LLS
 
(335
)
 
$
109.40

Natural Gas
 
Apr-Dec 2013
 
Fixed Price Swaps
 
Henry Hub
 
(470
)
 
$
3.59

Natural Gas
 
Apr-Dec 2013
 
Basis Swaps
 
Northeast
 
(111
)
 
$
0.21

Natural Gas
 
Apr-Dec 2013
 
Basis Swaps
 
Mid-Con
 
(33
)
 
$
(0.17
)
Natural Gas
 
Apr-Dec 2013
 
Basis Swaps
 
Rockies
 
(20
)
 
$
(0.15
)
Crude Oil
 
2014
 
Fixed Price Swaps
 
WTI
 
(1,500
)
 
$
95.00

Natural Gas
 
2014
 
Fixed Price Swaps
 
Henry Hub
 
(40
)
 
$
4.35

Natural Gas
 
2014
 
Swaptions
 
Henry Hub
 
(40
)
 
$
4.35

 
Derivatives primarily related to storage and transportation
Commodity
 
Period
 
Contract Type(d)
 
Location(e)
 
Notional Volume (b)
 
Weighted Average
Price(f)
Natural Gas
 
Apr-Dec 2013
 
Fixed Price Swaps
 
Multiple
 
(1
)
 
Natural Gas
 
Apr-Dec 2013
 
Basis Swaps
 
Multiple
 
(20
)
 
Natural Gas
 
Apr-Dec 2013
 
Index
 
Multiple
 
(87
)
 
Natural Gas
 
2014
 
Fixed Price Swaps
 
Multiple
 
(5
)
 
Natural Gas
 
2014
 
Basis Swaps
 
Multiple
 
6

 
Natural Gas
 
2014
 
Index
 
Multiple
 
(20
)
 
Natural Gas
 
2015
 
Basis Swaps
 
Multiple
 
(6
)
 
Natural Gas
 
2015
 
Index
 
Multiple
 
(3
)
 
Natural Gas
 
2016
 
Index
 
Multiple
 
2

 
Natural Gas
 
2017
 
Index
 
Multiple
 
2

 
__________
(a)
Derivatives related to WPX crude oil production are business day average swaps and the derivatives related to natural gas production are fixed price swaps, basis swaps and swaptions.
(b)
Natural gas volumes are reported in BBtu/day and crude oil volumes are reported in Bbl/day.
(c)
The weighted average price for natural gas is reported in $/MMBtu and the crude oil price is reported in $/Bbl.
(d)
WPX Marketing enters into exchange traded fixed price and basis swaps, over the counter fixed price and basis swaps, physical fixed price transactions and transactions with an index component.
(e)
WPX Marketing transacts at multiple locations primarily around our core assets to maximize the economic value of our transportation, storage and asset management agreements.
(f)
The weighted average price is not reported since the notional volumes represent a net position comprised of buys and sells with positive and negative transaction prices.

 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 Sheets 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.
 
March 31, 2013
 
December 31, 2012
 
Assets
 
Liabilities
 
Assets
 
Liabilities
 
(Millions)
Derivatives related to production designated as hedging instruments
$

 
$

 
$
5

 
$

Not designated as hedging instruments:
 
 
 
 
 
 
 
Derivatives related to production not designated as hedging instruments
15

 
77

 
33

 

Legacy natural gas contracts from former power business
2

 
1

 
2

 
2

All other
7

 
7

 
20

 
13

Total derivatives not designated as hedging instruments
24

 
85

 
55

 
15

Total derivatives
$
24

 
$
85

 
$
60

 
$
15


 
The following table presents pre-tax gains and losses for our energy commodity derivatives designated as cash flow hedges, as recognized in AOCI or revenues.
 
Three months
ended March 31,
 
 
 
2013
 
2012
 
Classification
 
(Millions)
 
 
Net gain recognized in other comprehensive income (loss) (effective portion)
$

 
$
102

 
AOCI
Net gain (loss) reclassified from accumulated other comprehensive income (loss) into income (effective portion) (a)
$
5

 
$
106

 
Revenues
Loss recognized in income (ineffective portion)
$

 
$
(1
)
 
Revenues
__________
(a)
Gains reclassified from accumulated other comprehensive income (loss) primarily represent realized gains on derivatives designated as hedges of our production and are 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 March 31,
 
2013
 
2012
 
(Millions)
Unrealized loss
$
(103
)
 
$
(1
)
Realized gain
9

 
15

Net gain (loss)
$
(94
)
 
$
14


The cash flow impact of our unrealized loss on derivative activities is presented in the Consolidated Statements of Cash Flows as changes in current and noncurrent derivative assets and liabilities.

Offsetting of derivative assets and liabilities
The following table presents our gross and net derivative assets and liabilities.
 
Gross Amount Presented on Balance Sheet
 
Netting Adjustments (a)
 
Cash Collateral Posted(Received)
 
Net Amount
March 31, 2013
(Millions)
Derivative assets with right of offset or master netting agreements
$
24

 
$
(18
)
 
$

 
$
6

Derivative liabilities with right of offset or master netting agreements
$
(85
)
 
$
18

 
$

 
$
(67
)
 
 
 
 
 
 
 
 
December 31, 2012
 
 
 
 
 
 
 
Derivative assets with right of offset or master netting agreements
$
60

 
$
(10
)
 
$
(2
)
 
$
48

Derivative liabilities with right of offset or master netting agreements
$
(15
)
 
$
10

 
$

 
$
(5
)
__________
(a)
With all of our financial trading counterparties, we have agreements in place that allow for the financial right of offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements. Additionally, we have negotiated master netting agreements with some of our counterparties. These master netting agreements allow multiple entities that have multiple underlying agreements the ability to net derivative assets and derivative liabilities at settlement or in the event of a default or a termination under one or more of the underlying contracts.

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 March 31, 2013, we had a net $67 million derivative liability position (reflecting master netting arrangements in place with certain counterparties), which includes a reduction of $1 million to our liability balance for our own nonperformance risk. The additional collateral that we would have been required to post, assuming our credit thresholds were eliminated and a call for adequate assurance under the credit risk provisions in our derivative contracts was triggered, was $68 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 Statements of Operations for 2012. As of March 31, 2013, no derivatives were designated as cash flow hedges.
Concentration of Credit Risk
Cash equivalents
Our cash equivalents are primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government.

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 2013, 2012 and 2011, we did not incur any significant losses due to counterparty bankruptcy filings. 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 gross and net credit exposure from our derivative contracts as of March 31, 2013, is summarized as follows:
Counterparty Type
Gross Investment
Grade  (a)
 
Gross Total
 
Net Investment
Grade  (a)
 
Net Total
 
(Millions)
Energy marketers and traders
$
1

 
$
1

 
$

 
$
1

Financial institutions
23

 
23

 
5

 
5

 
$
24

 
24

 
$
5

 
6

Credit reserves
 
 

 
 
 

Credit exposure from derivatives
 
 
$
24

 
 
 
$
6

 
__________
(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 two largest net counterparty positions represent approximately 81 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 March 31, 2013, we did not hold any collateral support either in the form of cash or letters of credit, related to our other derivative positions.
Segment Disclosures
Segment Disclosures
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 Statements of Operations.
 
 
Domestic
 
International
 
Total
 
 
 
(Millions)
 
 
Three months ended March 31, 2013
 
 
 
 
 
Total revenues
$
595

 
$
36

 
$
631

Costs and expenses:
 
 
 
 
 
Lease and facility operating
$
67

 
$
8

 
$
75

Gathering, processing and transportation
106

 
1

 
107

Taxes other than income
29

 
6

 
35

Gas management, including charges for unutilized pipeline capacity
243

 

 
243

Exploration
18

 
1

 
19

Depreciation, depletion and amortization
224

 
7

 
231

General and administrative
69

 
3

 
72

Other—net
6

 
1

 
7

Total costs and expenses
$
762

 
$
27

 
$
789

Operating income (loss)
$
(167
)
 
$
9

 
$
(158
)
Interest expense
(26
)
 

 
(26
)
Interest capitalized
1

 

 
1

Investment income and other
2

 
5

 
7

Income (loss) from continuing operations before income taxes
$
(190
)
 
$
14

 
$
(176
)
Three months ended March 31, 2012
 
 
 
 
 
Total revenues
$
879

 
$
31

 
$
910

Costs and expenses:
 
 
 
 
 
Lease and facility operating
$
61

 
$
6

 
$
67

Gathering, processing and transportation
135

 

 
135

Taxes other than income
25

 
5

 
30

Gas management, including charges for unutilized pipeline capacity
355

 

 
355

Exploration
14

 
5

 
19

Depreciation, depletion and amortization
222

 
6

 
228

Impairment of costs of acquired unproved reserves (Note 4)
52

 

 
52

General and administrative
65

 
3

 
68

Other—net
5

 

 
5

Total costs and expenses
$
934

 
$
25

 
$
959

Operating income (loss)
$
(55
)
 
$
6

 
$
(49
)
Interest expense
(26
)
 

 
(26
)
Interest capitalized
2

 

 
2

Investment income and other
2

 
8

 
10

Income (loss) from continuing operations before income taxes
$
(77
)
 
$
14

 
$
(63
)
Total assets
 
 
 
 
 
Total assets as of March 31, 2013
$
9,048

 
$
356

 
$
9,404

Total assets as of December 31, 2012
$
9,113

 
$
343

 
$
9,456

General, Description of Business and Basis of Presentation (Policies)
Discontinued operations
During the second quarter of 2012, we completed the sale of our holdings in the Barnett Shale and the Arkoma Basin. The results of operations of the Barnett Shale and Arkoma Basin operations are reported as discontinued operations (see Note 2).
Recently Issued Accounting Standards
In February 2013, the Financial Accounting Standards Board ("FASB") issued Accounting Standard Update ("ASU") 2013-04, Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation Is Fixed at the Reporting Date ("ASU 2013-04"). The amendments in ASU 2013-04 provide guidance for the recognition, measurement, and disclosure of obligations resulting from joint and several liability arrangements from which the total amount of the obligation within the scope of this guidance is fixed at the reporting date. ASU 2013-04 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013. The Company is currently evaluating the impact of ASU 2013-04, but we do not anticipate a material impact to the Company's financial position, results of operations or cash flows as a result of applying this ASU.
Recently Adopted Provisions of U.S. GAAP
In accordance with U.S. GAAP, the following provisions, which had no material impact on the Company's financial position, results of operations or cash flows, were effective as of January 1, 2013:
The requirement to provide disclosures related to offsetting assets and liabilities, specifically as it relates to offsetting disclosures, wherein an entity must now make separate disclosures regarding the gross assets and liabilities, the offsetting amounts and the net assets and liabilities (see Note 10).
The requirement to present significant amounts reclassified out of Accumulated Other Comprehensive Income (Loss) ("AOCI") by the respective line items in the results of operations. See Note 10 and the Consolidated Statements of Comprehensive Income (Loss).
Discontinued Operations (Tables)
Summarized Results of Discontinued Operations
Summarized Results of Discontinued Operations
 
 
Three months
ended March 31,
 
 
2012
 
 
(Millions)
Revenues
 
$
20

Loss from discontinued operations
 
$
(2
)
Earnings (Loss) Per Common Share from Continuing Operations (Tables)
Earnings (Loss) Per Common Share from Continuing Operations
 
Three months
ended March 31,
 
2013
 
2012
 
(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
$
(116
)
 
$
(41
)
Basic weighted-average shares
199.9

 
198.1

Diluted weighted-average shares
199.9

 
198.1

Earnings (loss) per common share from continuing operations:
 
 
 
Basic
$
(0.58
)
 
$
(0.21
)
Diluted
$
(0.58
)
 
$
(0.21
)
The table below includes information related to stock options that were outstanding at March 31, 2013 and 2012 but have been excluded from the computation of weighted-average stock options due to the option exercise price exceeding the first quarter weighted-average market price of our common shares.
 
March 31,
 
2013
 
2012
Options excluded (millions)
1.8

 
0.8

Weighted-average exercise price of options excluded
$
17.50

 
$
19.32

Exercise price range of options excluded
$15.67 - $20.97
 
$18.16 - $20.97
First quarter weighted-average market price
$
15.27

 
$
17.67

Impairments and Exploration Expense (Tables)
Exploration Expenses
Exploration Expense
 
Three months
ended March 31,
 
2013
 
2012
 
(Millions)
Geologic and geophysical costs
$
5

 
$
7

Dry hole costs
1

 
1

Unproved leasehold property impairment, amortization and expiration
13

 
11

Total exploration expense
$
19

 
$
19

Inventories (Tables)
Inventories
Inventories 
 
March 31,
2013
 
December 31,
2012
 
(Millions)
Natural gas in underground storage
$
7

 
$
24

Material, supplies and other
47

 
42

 
$
54

 
$
66

Debt and Banking Arrangements (Tables)
Schedule of Long-term Debt Instruments
As of the indicated dates, our debt consisted of the following:
 
March 31,
2013
 
December 31,
2012
 
(Millions)
5.250% Senior Notes due 2017
$
400

 
$
400

6.000% Senior Notes due 2022
1,100

 
1,100

Credit facility agreement
80

 

Apco
8

 
8

Other
1

 

 
$
1,589

 
$
1,508

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 March 31,
 
2013
 
2012
 
(Millions)
Current:
 
 
 
Federal
$
1

 
$
10

State

 

Foreign
4

 
3

 
5

 
13

Deferred:
 
 
 
Federal
(62
)
 
(35
)
State
(6
)
 
(3
)
Foreign

 

 
(68
)
 
(38
)
Total provision (benefit)
$
(63
)
 
$
(25
)
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. The carrying amounts reported in the Consolidated Balance Sheets for cash and cash equivalents and restricted cash approximate fair value due to the nature of the instrument and/or the short-term maturity of these instruments. 
 
March 31, 2013
 
December 31, 2012
 
Level 1
 
Level 2
 
Level 3
 
Total
 
Level 1
 
Level 2
 
Level 3
 
Total
 
(Millions)
 
(Millions)
Energy derivative assets
$
8

 
$
15

 
$
1

 
$
24

 
$
20

 
$
38

 
$
2

 
$
60

Energy derivative liabilities
$
6

 
$
77

 
$
2

 
$
85

 
$
11

 
$
1

 
$
3

 
$
15

Long-term debt (a)
$

 
$
1,660

 
$

 
$
1,660

 
$

 
$
1,617

 
$

 
$
1,617

__________
(a)
The carrying value of long-term debt, excluding capital leases, was $1,588 million and $1,508 million as of March 31, 2013 and December 31, 2012, respectively.
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 March 31,
 
2013
 
2012
 
(Millions)
Beginning balance
$
(1
)
 
$
1

Realized and unrealized gains (losses):
 
 
 
Included in income (loss) from continuing operations

 
1

Purchases, issuances, and settlements

 
(3
)
Transfers out of Level 3

 

Ending balance
$
(1
)
 
$
(1
)
Unrealized gains included in income (loss) from continuing operations relating to instruments still held at March 31
$

 
$
(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 three months
ended March 31,
 
 
2013
 
2012
 
 
(Millions)
 
Impairments:
 
 
 
 
Costs of acquired unproved reserves (see Note 4)
$

 
$
52

(a) 
 __________
(a)
Due to significant declines in forward natural gas prices during the first quarter 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.

Derivatives and Concentration of Credit Risk (Tables)
Derivatives related to production
Commodity
 
Period
 
Contract Type(a)
 
Location
 
Notional Volume (b)
 
Weighted Average
Price(c)
Crude Oil
 
Apr-Dec 2013
 
Fixed Price Swaps
 
WTI
 
(8,665
)
 
$
100.64

Crude Oil
 
Apr-Dec 2013
 
Fixed Price Swaps
 
LLS
 
(335
)
 
$
109.40

Natural Gas
 
Apr-Dec 2013
 
Fixed Price Swaps
 
Henry Hub
 
(470
)
 
$
3.59

Natural Gas
 
Apr-Dec 2013
 
Basis Swaps
 
Northeast
 
(111
)
 
$
0.21

Natural Gas
 
Apr-Dec 2013
 
Basis Swaps
 
Mid-Con
 
(33
)
 
$
(0.17
)
Natural Gas
 
Apr-Dec 2013
 
Basis Swaps
 
Rockies
 
(20
)
 
$
(0.15
)
Crude Oil
 
2014
 
Fixed Price Swaps
 
WTI
 
(1,500
)
 
$
95.00

Natural Gas
 
2014
 
Fixed Price Swaps
 
Henry Hub
 
(40
)
 
$
4.35

Natural Gas
 
2014
 
Swaptions
 
Henry Hub
 
(40
)
 
$
4.35

 
Derivatives primarily related to storage and transportation
Commodity
 
Period
 
Contract Type(d)
 
Location(e)
 
Notional Volume (b)
 
Weighted Average
Price(f)
Natural Gas
 
Apr-Dec 2013
 
Fixed Price Swaps
 
Multiple
 
(1
)
 
Natural Gas
 
Apr-Dec 2013
 
Basis Swaps
 
Multiple
 
(20
)
 
Natural Gas
 
Apr-Dec 2013
 
Index
 
Multiple
 
(87
)
 
Natural Gas
 
2014
 
Fixed Price Swaps
 
Multiple
 
(5
)
 
Natural Gas
 
2014
 
Basis Swaps
 
Multiple
 
6

 
Natural Gas
 
2014
 
Index
 
Multiple
 
(20
)
 
Natural Gas
 
2015
 
Basis Swaps
 
Multiple
 
(6
)
 
Natural Gas
 
2015
 
Index
 
Multiple
 
(3
)
 
Natural Gas
 
2016
 
Index
 
Multiple
 
2

 
Natural Gas
 
2017
 
Index
 
Multiple
 
2

 
__________
(a)
Derivatives related to WPX crude oil production are business day average swaps and the derivatives related to natural gas production are fixed price swaps, basis swaps and swaptions.
(b)
Natural gas volumes are reported in BBtu/day and crude oil volumes are reported in Bbl/day.
(c)
The weighted average price for natural gas is reported in $/MMBtu and the crude oil price is reported in $/Bbl.
(d)
WPX Marketing enters into exchange traded fixed price and basis swaps, over the counter fixed price and basis swaps, physical fixed price transactions and transactions with an index component.
(e)
WPX Marketing transacts at multiple locations primarily around our core assets to maximize the economic value of our transportation, storage and asset management agreements.
(f)
The weighted average price is not reported since the notional volumes represent a net position comprised of buys and sells with positive and negative transaction prices.
 
March 31, 2013
 
December 31, 2012
 
Assets
 
Liabilities
 
Assets
 
Liabilities
 
(Millions)
Derivatives related to production designated as hedging instruments
$

 
$

 
$
5

 
$

Not designated as hedging instruments:
 
 
 
 
 
 
 
Derivatives related to production not designated as hedging instruments
15

 
77

 
33

 

Legacy natural gas contracts from former power business
2

 
1

 
2

 
2

All other
7

 
7

 
20

 
13

Total derivatives not designated as hedging instruments
24

 
85

 
55

 
15

Total derivatives
$
24

 
$
85

 
$
60

 
$
15

The following table presents pre-tax gains and losses for our energy commodity derivatives designated as cash flow hedges, as recognized in AOCI or revenues.
 
Three months
ended March 31,
 
 
 
2013
 
2012
 
Classification
 
(Millions)
 
 
Net gain recognized in other comprehensive income (loss) (effective portion)
$

 
$
102

 
AOCI
Net gain (loss) reclassified from accumulated other comprehensive income (loss) into income (effective portion) (a)
$
5

 
$
106

 
Revenues
Loss recognized in income (ineffective portion)
$

 
$
(1
)
 
Revenues
__________
(a)
Gains reclassified from accumulated other comprehensive income (loss) primarily represent realized gains on derivatives designated as hedges of our production and are 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 March 31,
 
2013
 
2012
 
(Millions)
Unrealized loss
$
(103
)
 
$
(1
)
Realized gain
9

 
15

Net gain (loss)
$
(94
)
 
$
14

The following table presents our gross and net derivative assets and liabilities.
 
Gross Amount Presented on Balance Sheet
 
Netting Adjustments (a)
 
Cash Collateral Posted(Received)
 
Net Amount
March 31, 2013
(Millions)
Derivative assets with right of offset or master netting agreements
$
24

 
$
(18
)
 
$

 
$
6

Derivative liabilities with right of offset or master netting agreements
$
(85
)
 
$
18

 
$

 
$
(67
)
 
 
 
 
 
 
 
 
December 31, 2012
 
 
 
 
 
 
 
Derivative assets with right of offset or master netting agreements
$
60

 
$
(10
)
 
$
(2
)
 
$
48

Derivative liabilities with right of offset or master netting agreements
$
(15
)
 
$
10

 
$

 
$
(5
)
__________
(a)
With all of our financial trading counterparties, we have agreements in place that allow for the financial right of offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements. Additionally, we have negotiated master netting agreements with some of our counterparties. These master netting agreements allow multiple entities that have multiple underlying agreements the ability to net derivative assets and derivative liabilities at settlement or in the event of a default or a termination under one or more of the underlying contracts.
The gross and net credit exposure from our derivative contracts as of March 31, 2013, is summarized as follows:
Counterparty Type
Gross Investment
Grade  (a)
 
Gross Total
 
Net Investment
Grade  (a)
 
Net Total
 
(Millions)
Energy marketers and traders
$
1

 
$
1

 
$

 
$
1

Financial institutions
23

 
23

 
5

 
5

 
$
24

 
24

 
$
5

 
6

Credit reserves
 
 

 
 
 

Credit exposure from derivatives
 
 
$
24

 
 
 
$
6

 
__________
(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 Statements of Operations.
 
 
Domestic
 
International
 
Total
 
 
 
(Millions)
 
 
Three months ended March 31, 2013
 
 
 
 
 
Total revenues
$
595

 
$
36

 
$
631

Costs and expenses:
 
 
 
 
 
Lease and facility operating
$
67

 
$
8

 
$
75

Gathering, processing and transportation
106

 
1

 
107

Taxes other than income
29

 
6

 
35

Gas management, including charges for unutilized pipeline capacity
243

 

 
243

Exploration
18

 
1

 
19

Depreciation, depletion and amortization
224

 
7

 
231

General and administrative
69

 
3

 
72

Other—net
6

 
1

 
7

Total costs and expenses
$
762

 
$
27

 
$
789

Operating income (loss)
$
(167
)
 
$
9

 
$
(158
)
Interest expense
(26
)
 

 
(26
)
Interest capitalized
1

 

 
1

Investment income and other
2

 
5

 
7

Income (loss) from continuing operations before income taxes
$
(190
)
 
$
14

 
$
(176
)
Three months ended March 31, 2012
 
 
 
 
 
Total revenues
$
879

 
$
31

 
$
910

Costs and expenses:
 
 
 
 
 
Lease and facility operating
$
61

 
$
6

 
$
67

Gathering, processing and transportation
135

 

 
135

Taxes other than income
25

 
5

 
30

Gas management, including charges for unutilized pipeline capacity
355

 

 
355

Exploration
14

 
5

 
19

Depreciation, depletion and amortization
222

 
6

 
228

Impairment of costs of acquired unproved reserves (Note 4)
52

 

 
52

General and administrative
65

 
3

 
68