10-K/A 1 d329924d10ka.htm AMENDMENT NO. 1 TO FORM 10-K Amendment No. 1 to Form 10-K
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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 10-K/A

(Amendment No. 1)

 

 

 

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2011

or

 

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                      to                     

Commission File No. 1-35322

 

 

WPX Energy, Inc.

(Exact name of registrant as specified in its charter)

 

 

 

Delaware   45-1836028

(State or other jurisdiction of

incorporation or organization)

 

(I.R.S. Employer

Identification No.)

One Williams Center, Tulsa, Oklahoma   74172-0172
(Address of principal executive offices)   (Zip Code)

(800) 945-5426

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

 

Title of Each Class

 

Name of Each Exchange on Which Registered

Common Stock, par value $0.01 per share   The New York Stock Exchange, Inc.

Securities registered pursuant to Section 12(g) of the Act:

None

 

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  ¨    No  x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ¨    No  x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  ¨    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ¨    No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  x

As of June 30, 2011, the registrant’s common stock was not publicly traded. The number of shares of the registrant’s common stock outstanding at April 16, 2012, was 198,714,249.

 

 

DOCUMENTS INCORPORATED BY REFERENCE: None.

 

 

 


Table of Contents

TABLE OF CONTENTS

 

EXPLANATORY NOTE

     1   

PART II

     2   

ITEM 8:

  Financial Statements and Supplementary Data      2   

PART III

     67   

ITEM 10:

  Directors, Executive Officers and Corporate Governance      67   

ITEM 11:

  Executive Compensation      79   

ITEM 12:

  Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters      110   

ITEM 13:

  Certain Relationships and Related Transactions, and Director Independence      112   

ITEM 14:

  Principal Accountant Fees and Services      113   

PART IV

     115   

ITEM 15:

  Exhibits and Financial Statement Schedules      115   

SIGNATURES

     116   

 

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Unless the context requires otherwise, references in this report to “WPX,” “we,” “us,” “our” and the “Company” refer to WPX Energy, Inc. and its subsidiaries.

EXPLANATORY NOTE

This Amendment No. 1 amends our Annual Report on Form 10-K for the fiscal year ended December 31, 2011, which was originally filed with the Securities and Exchange Commission, or SEC, on February 28, 2012. We are filing this Amendment to include the information required by Items 10, 11, 12, 13 and 14 of Part III of Form 10-K because we will not file a definitive proxy statement containing this information with the SEC within 120 days after the end of our fiscal year ended December 31, 2011. We are also filing this Amendment for the purpose of making a clerical correction to the date of the report of Ernst & Young LLP, our independent registered public accounting firm, contained in Item 8 of our original Form 10-K. Note 19 of the Notes to Consolidated Financial Statements has been added to include certain information subsequent to the date of the report of Ernst & Young LLP. Except as expressly noted in this Amendment, this Amendment does not reflect events occurring after the original filing of our Form 10-K or modify or update in any way any of the other disclosures, including the audited financial statements, contained in our Form 10-K. Accordingly, this Amendment should be read in conjunction with our Form 10-K and other SEC filings.

 

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PART II

 

Item 8. Financial Statements and Supplementary Data

Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders of WPX Energy, Inc.

We have audited the accompanying consolidated balance sheet of WPX Energy, Inc. as of December 31, 2011 and 2010, and the related consolidated statements of operations, changes in equity, and cash flows for each of the three years in the period ended December 31, 2011. Our audit also included the financial statement schedule listed in the Index at Item 15.(a). These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of WPX Energy, Inc. at December 31, 2011 and 2010, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2011, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

/s/ Ernst & Young LLP

Tulsa, Oklahoma

February 28, 2012

 

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WPX Energy, Inc.

Consolidated Statement of Operations

 

     Years Ended December 31,  
     2011     2010     2009  
     (Millions, except per share amounts)  

Revenues:

      

Product revenues, including sales to Williams:

      

Natural gas sales

   $ 1,795      $ 1,812      $ 1,929   

Natural gas liquid sales

     408        285        139   

Oil and condensate sales

     315        128        97   
  

 

 

   

 

 

   

 

 

 

Total product revenues, including sales to Williams

     2,518        2,225        2,165   

Gas management, including sales to Williams

     1,428        1,742        1,456   

Hedge ineffectiveness and mark to market gains and losses

     29        27        18   

Other

     13        40        42   
  

 

 

   

 

 

   

 

 

 

Total revenues

     3,988        4,034        3,681   

Costs and expenses:

      

Lease and facility operating, including expenses with Williams

     295        286        263   

Gathering, processing and transportation, including expenses with Williams

     499        326        273   

Taxes other than income

     140        125        93   

Gas management, including charges for unutilized pipeline capacity

     1,473        1,771        1,495   

Exploration

     134        73        54   

Depreciation, depletion and amortization

     949        875        887   

Impairment of producing properties and costs of acquired unproved reserves

     547        678        15   

Goodwill impairment

     —          1,003        —     

General and administrative, including expenses with Williams

     285        253        251   

Other—net

     1        (19     33   
  

 

 

   

 

 

   

 

 

 

Total costs and expenses

     4,323        5,371        3,364   
  

 

 

   

 

 

   

 

 

 

Operating income (loss)

     (335     (1,337     317   

Interest expense, including expenses with Williams

     (117     (124     (100

Interest capitalized

     9        16        18   

Investment income and other

     26        21        8   
  

 

 

   

 

 

   

 

 

 

Income (loss) from continuing operations before income taxes

     (417     (1,424     243   

Provision (benefit) for income taxes

     (145     (149     96   
  

 

 

   

 

 

   

 

 

 

Income (loss) from continuing operations

     (272     (1,275     147   

Loss from discontinued operations

     (20     (8     (7
  

 

 

   

 

 

   

 

 

 

Net income (loss)

     (292     (1,283     140   

Less: Net income attributable to noncontrolling interests

     10        8        6   
  

 

 

   

 

 

   

 

 

 

Net income (loss) attributable to WPX Energy

   $ (302   $ (1,291   $ 134   
  

 

 

   

 

 

   

 

 

 

Amounts attributable to WPX Energy, Inc.:

      

Basic and diluted earnings (loss) per common share (see Note 6):

      

Income (loss) from continuing operations

   $ (1.43   $ (6.51   $ 0.71   

Loss from discontinued operations

     (0.10     (0.04     (0.03
  

 

 

   

 

 

   

 

 

 

Net income (loss)

   $ (1.53   $ (6.55   $ 0.68   
  

 

 

   

 

 

   

 

 

 

Weighted-average shares (millions)

     197.1        197.1        197.1   

See accompanying notes.

 

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WPX Energy, Inc.

Consolidated Balance Sheet

 

     December 31,  
     2011      2010  
     (Millions)  

Assets

     

Current assets:

     

Cash and cash equivalents

   $ 526       $ 37   

Accounts receivable:

     

Trade, net of allowance for doubtful accounts of $13 and $16 as of December 31, 2011 and 2010, respectively

     447         362   

Williams

     62         60   

Derivative assets

     506         400   

Inventories

     74         77   

Other

     59         22   
  

 

 

    

 

 

 

Total current assets

     1,674         958   

Investments

     125         105   

Properties and equipment, net (successful efforts method of accounting)

     8,476         8,449   

Derivative assets

     10         173   

Other noncurrent assets

     147         161   
  

 

 

    

 

 

 

Total assets

   $ 10,432       $ 9,846   
  

 

 

    

 

 

 

Liabilities and Equity

     

Current liabilities:

     

Accounts payable:

     

Trade

     643         451   

Williams

     59         64   

Accrued and other current liabilities

     186         158   

Deferred income taxes

     116         87   

Notes payable to Williams

     —           2,261   

Derivative liabilities

     152         146   
  

 

 

    

 

 

 

Total current liabilities

     1,156         3,167   

Deferred income taxes

     1,556         1,645   

Long-term debt

     1,503         —     

Derivative liabilities

     7         143   

Asset retirement obligations

     296         282   

Other noncurrent liabilities

     155         125   

Contingent liabilities and commitments (Note 12)

     

Equity:

     

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; 197 million shares issued at December 31, 2011)

     2         —     

Additional paid-in-capital

     5,457         —     

Williams’ net investment

     —           4,244   

Accumulated other comprehensive income

     219         168   
  

 

 

    

 

 

 

Total stockholders’ equity

     5,678         4,412   

Noncontrolling interests in consolidated subsidiaries

     81         72   
  

 

 

    

 

 

 

Total equity

     5,759         4,484   
  

 

 

    

 

 

 

Total liabilities and equity

   $ 10,432       $ 9,846   
  

 

 

    

 

 

 

See accompanying notes.

 

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WPX Energy, Inc.

Consolidated Statement of Changes in Equity

 

    WPX Energy, Inc., Stockholders     Noncontrolling
Interest**
    Total  
    Common
Stock
    Capital in
Excess of
Par Value
    Williams’
Net

Investment
    Accumulated
Other
Comprehensive

Income (Loss)*
    Total
Stockholders’

Equity
     
    (Dollars in millions)  

Balance at December 31, 2008

  $ —        $ —        $ 5,136      $ 298      $ 5,434      $ 59      $ 5,493   

Comprehensive income:

             

Net income

    —          —          134        —          134        6        140   

Other comprehensive income:

             

Change in fair value of cash flow hedges (net of $97 of income tax)

    —          —          —          169        169        —          169   

Net reclassifications into earnings of net cash flow hedge gains(net of $226 income tax provision)

    —          —          —          (395     (395     —          (395
             

 

 

 

Total other comprehensive income

                (226
             

 

 

 

Total comprehensive income

                (86
             

 

 

 

Net transfers with Williams

    —          —          (16     —          (16     —          (16

Dividends to noncontrolling interests

    —          —          —          —          —          (1     (1
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance at December 31, 2009

    —          —          5,254        72        5,326        64        5,390   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Comprehensive income:

             

Net income

    —          —          (1,291     —          (1,291     8        (1,283

Other comprehensive income:

             

Change in fair value of net cash flow hedges (net of $184 of income tax)

    —          —          —          321        321        —          321   

Net reclassifications into earnings of cash flow hedge gain (net of $129 income tax provision)

    —          —          —          (225     (225     —          (225
             

 

 

 

Total other comprehensive loss

                96   
             

 

 

 

Total comprehensive loss

                (1,187
             

 

 

 

Cash proceeds in excess of historical book value related to assets sold to a Williams’ affiliate

    —          —          244        —          244        —          244   

Net transfers with Williams

        37        —          37        —          37   

Dividends to noncontrolling interests

    —          —          —          —          —          —          —     
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance at December 31, 2010

    —          —          4,244        168        4,412        72        4,484   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Comprehensive income:

             

Net loss

        (302     —          (302     10        (292

Other comprehensive income:

             

Change in fair value of net cash flow hedges (net of $151 of income tax)

    —          —          —          262        262        —          262   

Net reclassifications into earnings of cash flow hedge gains (net of $120 income tax provision)

    —          —          —          (211     (211     —          (211
             

 

 

 

Total other comprehensive income

                51   
             

 

 

 

Total comprehensive loss

                (241
             

 

 

 

Contribution of Notes Payable to Williams
(Note 4)

    —          —          2,420        —          2,420        —          2,420   

Allocation of alternative minimum tax credit (see Note 11)

    —          —          98        —          98        —          98   

Net transfers with Williams

    —          —          (25     —          (25     —          (25

Distribution to Williams a portion of note proceeds

    —          —          (981     —          (981     —          (981

Recapitalization upon contribution by Williams

    2        5,452        (5,454     —          —          —          —     

Dividends to noncontrolling interests

    —          —          —          —          —          (1     (1

Stock based compensation, net of tax benefit

    —          5        —          —          5        —          5   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance at December 31, 2011

  $ 2      $ 5,457      $ —        $ 219      $ 5,678      $ 81      $ 5,759   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

* Accumulated other comprehensive income (loss) is comprised primarily of unrealized gains relating to natural gas hedges totaling $221 million (net of $128 million for income taxes), $169 million (net of $97 million for income taxes) and $74 million (net of $42 million for income taxes) as of December 31, 2011, 2010 and 2009, respectively.
** Represents the 31 percent interest in Apco Oil and Gas International Inc. owned by others.

See accompanying notes.

 

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WPX Energy, Inc.

Consolidated Statement of Cash Flows

 

     Years Ended December 31,  
     2011     2010     2009  
     (Millions)  

Operating Activities

      

Net income (loss)

   $ (292   $ (1,283   $ 140   

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

      

Depreciation, depletion and amortization

     951        882        894   

Deferred income tax provision (benefit)

     (176     (166     108   

Provision for impairment of goodwill and properties and equipment (including certain exploration expenses)

     694        1,734        38   

Provision for loss on cost-based investment

     —          —          11   

Amortization of stock-based awards

     5        —          —     

(Gain) loss on sales of other assets

     (1     (22     1   

Cash provided (used) by operating assets and liabilities:

      

Accounts receivable and payable—Williams

     (10     21        (72

Accounts receivable—trade

     (90     7        103   

Other current assets

     (11     19        (17

Inventories

     3        (16     24   

Margin deposits and customer margin deposit payable

     (18     (1     4   

Accounts payable—trade

     131        (54     (17

Accrued and other current liabilities

     10        (62     (109

Changes in current and noncurrent derivative assets and liabilities

     8        (45     38   

Other, including changes in other noncurrent assets and liabilities

     2        42        35   
  

 

 

   

 

 

   

 

 

 

Net cash provided by operating activities

     1,206        1,056        1,181   
  

 

 

   

 

 

   

 

 

 

Investing Activities

      

Capital expenditures*

     (1,572     (1,856     (1,434

Purchase of business

     —          (949     —     

Proceeds from sales of assets

     15        493        —     

Purchases of investments

     (12     (7     (1

Other

     13        (18     —     
  

 

 

   

 

 

   

 

 

 

Net cash used in investing activities

     (1,556     (2,337     (1,435
  

 

 

   

 

 

   

 

 

 

Financing Activities

      

Proceeds from long term debt

     1,502        —          —     

Payments for debt issuance costs

     (30     —          —     

Net increase in notes payable to Williams

     159        1,045        270   

Net changes in Williams’ net investment, including a $981 distribution in 2011

     (777     241        (16

Other

     (15     (2     2   
  

 

 

   

 

 

   

 

 

 

Net cash provided by financing activities

     839        1,284        256   
  

 

 

   

 

 

   

 

 

 

Net increase in cash and cash equivalents

     489        3        2   

Cash and cash equivalents at beginning of period

     37        34        32   
  

 

 

   

 

 

   

 

 

 

Cash and cash equivalents at end of period

   $ 526      $ 37      $ 34   
  

 

 

   

 

 

   

 

 

 

 

*  Increase to properties and equipment

   $ (1,641   $ (1,891   $ (1,291

Changes in related accounts payable

     69        35        (143
  

 

 

   

 

 

   

 

 

 

Capital expenditures

   $ (1,572   $ (1,856   $ (1,434
  

 

 

   

 

 

   

 

 

 

See accompanying notes.

 

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WPX Energy, Inc.

Notes to Consolidated Financial Statements

Note 1. Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies

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 development, production and gas management activities located in the Rocky Mountain (primarily Colorado, New Mexico and Wyoming), Mid-Continent (Texas) and Appalachian regions of the United States. We specialize in natural gas production from tight-sands and shale formations and coal bed methane reserves in the Piceance, San Juan, Powder River, Green River, Fort Worth and Appalachian Basins. During 2010, we acquired a company with a significant acreage position in the Williston Basin (Bakken Shale) in North Dakota, which is primarily comprised of crude oil. 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 primarily in Argentina.

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.

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. In July 2011, Williams contributed to the Company its investment in certain subsidiaries related to its domestic exploration and production business, including its wholly-owned subsidiaries WPX Energy Holdings, LLC (formerly Williams Production Holdings, LLC) and WPX Energy Production, LLC (formerly Williams Production Company, LLC), as well as all ongoing operations of WPX Energy Marketing, LLC (formerly Williams Gas Marketing, Inc.). Additionally, Williams contributed and transferred to the Company its investment in certain subsidiaries related to its international exploration and production business, including its 69 percent ownership interest in Apco in October 2011. We refer to the collective contributions described herein as the “Contribution”.

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 pro rata distribution on December 31, 2011 of WPX common stock to Williams’ stockholders of record as of the close of business on December 14, 2011, the spin-off record date. Each Williams’ stockholder received one share of WPX common stock for every three shares of Williams common stock held by such stockholder on the record date. See Note 4 for further discussion of agreements entered at the time of the spin-off, including a separation and distribution agreement, a transition services agreement, an employee matters agreement and a tax sharing agreement, among others.

Basis of Presentation

These financial statements are prepared on a consolidated basis. Prior to the Contribution, 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 Contribution to WPX.

 

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Notes to Consolidated Financial Statements—(continued)

 

Management believes the assumptions underlying the financial statements are reasonable. However, the financial statements included herein may not necessarily reflect the Company’s results of operations, financial position and cash flows in the future or what its results of operations, financial position and cash flows would have been had the Company been a stand-alone company during the periods presented. Because a direct ownership relationship did not exist prior to the Contribution among the various entities that comprise the Company, Williams’ net investment in the Company, excluding notes payable to Williams, has been shown as Williams’ net investment within stockholder’s equity in the consolidated financial statements. In connection with the Contribution, we have reflected the amounts previously presented as owner’s net investment in excess of the par value of our common stock as additional paid-in capital. Transactions with Williams’ other operating businesses, which generally settle monthly, are shown as accounts receivable—Williams or accounts payable—Williams (see Note 4). Other transactions between the Company and Williams which are not part of the notes payable to Williams have been identified in the Consolidated Statement of Equity as net transfers with Williams (see Note 4).

Discontinued operations

During the first quarter 2011, we initiated a formal process to pursue the divestiture of our holdings in the Arkoma Basin. As these assets are currently held for sale, are expected to be eliminated from our ongoing operations, and we do not expect to have any significant continuing involvement, we have reported the results of operations and financial position of the Arkoma operations as discontinued operations.

Additionally, the accompanying consolidated financial statements and notes include the results of operations of Williams’ former power business most of which was disposed in 2007 as discontinued operations. See Note 12 for a discussion of contingencies related to this discontinued power business.

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

Summary of Significant Accounting Policies

Principles of consolidation

The consolidated financial statements include the accounts of our wholly and majority-owned subsidiaries and investments. Companies in which we own 20 percent to 50 percent of the voting common stock, or otherwise exercise significant influence over operating and financial policies of the company, are accounted for under the equity method. All material intercompany transactions have been eliminated.

Use of estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.

Significant estimates and assumptions which impact these financials include:

 

   

Impairment assessments of long-lived assets and goodwill;

 

   

Valuations of derivatives;

 

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Notes to Consolidated Financial Statements—(continued)

 

   

Hedge accounting correlations and probability;

 

   

Estimation of oil and natural gas reserves;

 

   

Assessments of litigation-related contingencies.

These estimates are discussed further throughout these notes.

Cash and cash equivalents

Our cash and cash equivalents balance includes amounts primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government. These have maturity dates of three months or less when acquired.

Restricted cash

Restricted cash of our Domestic segment primarily consists of approximately $19 million in both 2011 and 2010 related to escrow accounts established as part of the settlement agreement with certain California utilities and is included in other noncurrent assets. Included in the separation and distribution agreement with Williams are indemnifications requiring us to pay to Williams any net asset (or receive any net liability) that result upon ultimate resolution of these matters. See Note 12. Additionally, our International segment holds approximately $8 million of restricted cash in 2011 associated with various letters of credit that is also classified in other noncurrent assets.

Accounts receivable

Accounts receivable are carried on a gross basis, with no discounting, less the allowance for doubtful accounts. We estimate the allowance for doubtful accounts based on existing economic conditions, the financial conditions of the customers and the amount and age of past due accounts. Receivables are considered past due if full payment is not received by the contractual due date. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted. A portion of our receivables are from joint interest owners of properties we operate. Thus, we may have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings.

Inventories

All inventories are stated at the lower of cost or market. Our inventories consist of tubular goods and production equipment for future transfer to wells of $40 million in 2011 and $46 million in 2010. Additionally, we have natural gas in storage of $34 million in 2011 and $31 million in 2010 primarily related to our gas management activities. Inventory is recorded and relieved using the weighted average cost method except for production equipment which is on the specific identification method. We recognized lower of cost or market writedowns on natural gas in storage of $10 million in 2011, $2 million in 2010 and $7 million in 2009.

Properties and equipment

Oil and gas exploration and production activities are accounted for under the successful efforts method. Costs incurred in connection with the drilling and equipping of exploratory wells are capitalized as incurred. If proved reserves are not found, such costs are charged to exploration expense. Other exploration costs, including geological and geophysical costs and lease rentals are charged to expense as incurred. All costs related to development wells, including related production equipment and lease acquisition costs, are capitalized when incurred whether productive or nonproductive.

 

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Notes to Consolidated Financial Statements—(continued)

 

Unproved properties include lease acquisition costs and costs of acquired unproved reserves. Individually significant lease acquisition costs are assessed annually, or as conditions warrant, for impairment considering our future drilling plans, the remaining lease term and recent drilling results. Lease acquisition costs that are not individually significant are aggregated by prospect or geographically, and the portion of such costs estimated to be nonproductive prior to lease expiration is amortized over the average holding period. The estimate of what could be nonproductive is based on our historical experience or other information, including current drilling plans and existing geological data. Impairment and amortization of lease acquisition costs are included in exploration expense in the Consolidated Statement of Operations. A majority of the costs of acquired unproved reserves are associated with areas to which we or other producers have identified significant proved developed producing reserves. Generally, economic recovery of unproved reserves in such areas is not yet supported by actual production or conclusive formation tests, but may be confirmed by our continuing development program. Ultimate recovery of unproved reserves in areas with established production generally has greater probability than in areas with limited or no prior drilling activity. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and gas properties. We refer to unproved lease acquisition costs and costs of acquired unproved reserves as unproved properties.

Other capitalized costs

Costs related to the construction or acquisition of field gathering, processing and certain other facilities are recorded at cost. Ordinary maintenance and repair costs are expensed as incurred.

Depreciation, depletion and amortization

Capitalized exploratory and developmental drilling costs, including lease and well equipment and intangible development costs are depreciated and amortized using the units-of-production method based on estimated proved developed oil and gas reserves on a field basis or concession basis for our international properties. International concession reserve estimates are limited to production quantities estimated through the life of the concession. Depletion of producing leasehold costs is based on the units-of-production method using estimated total proved oil and gas reserves on a field basis. In arriving at rates under the units-of-production methodology, the quantities of proved oil and gas reserves are established based on estimates made by our geologists and engineers.

Costs related to gathering, processing and certain other facilities are depreciated on the straight-line method over the estimated useful lives.

Gains or losses from the ordinary sale or retirement of properties and equipment are recorded in other—net included in operating income (loss).

Impairment of long-lived assets

We evaluate our long-lived assets for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such assets may not be recoverable. When an indicator of impairment has occurred, we compare our management’s estimate of undiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether an impairment has occurred. If an impairment of the carrying value has occurred, we determine the amount of the impairment recognized in the financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value.

 

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Notes to Consolidated Financial Statements—(continued)

 

Proved properties, including developed and undeveloped, are assessed for impairment using estimated future undiscounted cash flows on a field basis. If the undiscounted cash flows are less than the book value of the assets, then a subsequent analysis is performed using discounted cash flows.

Costs of acquired unproved reserves are assessed for impairment using estimated fair value determined through the use of future discounted cash flows on a field basis and considering market participants’ future drilling plans.

Judgments and assumptions are inherent in our management’s estimate of undiscounted future cash flows and an asset’s fair value. Additionally, judgment is used to determine the probability of sale with respect to assets considered for disposal. These judgments and assumptions include such matters as the estimation of oil and gas reserve quantities, risks associated with the different categories of oil and gas reserves, the timing of development and production, expected future commodity prices, capital expenditures, production costs and appropriate discount rates.

Contingent liabilities

Owing to the nature of our business, we are routinely subject to various lawsuits, claims and other proceedings. We recognize a liability in our consolidated financial statements when we determine that it is probable that a loss has been incurred and the amount can be reasonably estimated. If we determine that a loss is probable but lack information on which to reasonably estimate a loss, if any, or if we determine that a loss is only reasonably possible, we do not recognize a liability. We disclose the nature of loss contingencies that are potentially material but for which no liability has been recognized.

Asset retirement obligations

We record an asset and a liability upon incurrence equal to the present value of each expected future asset retirement obligation (ARO). These estimates include, as a component of future expected costs, an estimate of the price that a third party would demand, and could expect to receive, for bearing the uncertainties inherent in the obligations, sometimes referred to as a market risk premium. The ARO asset is depreciated in a manner consistent with the depreciation of the underlying physical asset. We measure changes in the liability due to passage of time by applying an interest method of allocation. This amount is recognized as an increase in the carrying amount of the liability and as a corresponding accretion expense in lease and facility operating expense included in costs and expenses.

Goodwill

As a result of significant declines in forward natural gas prices during 2010, we performed an interim impairment assessment of our goodwill related to our domestic production reporting unit. As a result of that assessment, we recorded an impairment of goodwill of approximately $1 billion and no longer have any goodwill recorded on the consolidated balance sheet related to our domestic operations (see Note 16).

Judgments and assumptions are inherent in our management’s estimate of future cash flows used to determine the estimate of the reporting unit’s fair value.

Cash flows from revolving credit facilities

Proceeds and payments related to any borrowings under our credit facilities are reflected in the financing activities of the Consolidated Statement of Cash Flows on a gross basis.

Derivative instruments and hedging activities

We utilize derivatives to manage our commodity price risk. These instruments consist primarily of futures contracts, swap agreements, option contracts, and forward contracts involving short- and long-term purchases and sales of a physical energy commodity.

We report the fair value of derivatives, except for those for which the normal purchases and normal sales exception has been elected, on the Consolidated Balance Sheet in derivative assets and derivative liabilities as

 

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Notes to Consolidated Financial Statements—(continued)

 

either current or noncurrent. We determine the current and noncurrent classification based on the timing of expected future cash flows of individual trades. We report these amounts on a gross basis. Additionally, we report cash collateral receivables and payables with our counterparties on a gross basis.

The accounting for the changes in fair value of a commodity derivative can be summarized as follows:

 

Derivative Treatment

  

Accounting Method

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

We may elect the normal purchases and normal sales exception for certain short- and long-term purchases and sales of a physical energy commodity. Under accrual accounting, any change in the fair value of these derivatives is not reflected on the balance sheet after the initial election of the exception.

For many of our existing commodity derivatives, we have also designated a hedging relationship. For a derivative to qualify for designation in a hedging relationship, it must meet specific criteria and we must maintain appropriate documentation. We establish hedging relationships pursuant to our risk management policies. We evaluate the hedging relationships at the inception of the hedge and on an ongoing basis to determine whether the hedging relationship is, and is expected to remain, highly effective in achieving offsetting changes in fair value or cash flows attributable to the underlying risk being hedged. We also regularly assess whether the hedged forecasted transaction is probable of occurring. If a derivative ceases to be or is no longer expected to be highly effective, or if we believe the likelihood of occurrence of the hedged forecasted transaction is no longer probable, hedge accounting is discontinued prospectively, and future changes in the fair value of the derivative are recognized currently in revenues or costs and operating expenses dependent upon the underlying hedge transaction.

For commodity derivatives designated as a cash flow hedge, the effective portion of the change in fair value of the derivative is reported in accumulated other comprehensive income (loss) (AOCI) and reclassified into earnings in the period in which the hedged item affects earnings. Any ineffective portion of the derivative’s change in fair value is recognized currently in revenues. Gains or losses deferred in AOCI associated with terminated derivatives, derivatives that cease to be highly effective hedges, derivatives for which the forecasted transaction is reasonably possible but no longer probable of occurring, and cash flow hedges that have been otherwise discontinued remain in AOCI until the hedged item affects earnings. If it becomes probable that the forecasted transaction designated as the hedged item in a cash flow hedge will not occur, any gain or loss deferred in AOCI is recognized in revenues at that time. The change in likelihood is a judgmental decision that includes qualitative assessments made by management.

Certain gains and losses on derivative instruments included in the Consolidated Statement of Operations are netted together to a single net gain or loss, while other gains and losses are reported on a gross basis. Gains and losses recorded on a net basis include:

 

   

Unrealized gains and losses on all derivatives that are not designated as hedges and for which we have not elected the normal purchases and normal sales exception;

 

   

The ineffective portion of unrealized gains and losses on derivatives that are designated as cash flow hedges;

 

   

Realized gains and losses on all derivatives that settle financially;

 

   

Realized gains and losses on derivatives held for trading purposes; and

 

   

Realized gains and losses on derivatives entered into as a pre-contemplated buy/sell arrangement.

 

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Notes to Consolidated Financial Statements—(continued)

 

Realized gains and losses on derivatives that require physical delivery, as well as natural gas derivatives which are not held for trading purposes nor were entered into as a pre-contemplated buy/sell arrangement, are recorded on a gross basis. In reaching our conclusions on this presentation, we considered whether we act as principal in the transaction; whether we have the risks and rewards of ownership, including credit risk; and whether we have latitude in establishing prices.

Product revenues

Revenues for sales of natural gas, natural gas liquids, and oil and condensate are recognized when the product is sold and delivered. Revenues from the production of natural gas in properties for which we have an interest with other producers are recognized based on the actual volumes sold during the period. Any differences between volumes sold and entitlement volumes, based on our net working interest, that are determined to be nonrecoverable through remaining production are recognized as accounts receivable or accounts payable, as appropriate. Our cumulative net natural gas imbalance position based on market prices as of December 31, 2011 and 2010 was insignificant. Additionally, natural gas revenues include hedge gains realized on production sold of $327 million in 2011, $333 million in 2010 and $615 million in 2009.

Gas management revenues and expenses

Revenues for sales related to gas management activities are recognized when the product is sold and physically delivered. Our gas management activities to date include purchases and subsequent sales to WPZ for fuel and shrink gas (see Note 4). Additionally, gas management activities include the managing of various natural gas related contracts such as transportation, storage and related hedges. The Company also sells natural gas purchased from working interest owners in operated wells and other area third party producers. The revenues and expenses related to these marketing activities are reported on a gross basis as part of gas management revenues and costs and expenses.

Charges for unutilized transportation capacity included in gas management expenses were $37 million in 2011, $48 million in 2010 and $21 million in 2009.

Capitalization of interest

We capitalize interest during construction on projects with construction periods of at least three months or a total estimated project cost in excess of $1 million. The interest rate used until June 30, 2011 was the rate charged to us by Williams through June 30, 2011, at which time our intercompany note with Williams was forgiven (see Note 4). We did not capitalize interest for the period from July 1, 2011 to mid November 2011. During November 2011, we began using the weighted average rate of our long-term notes payable which were issued in November 2011 (see Note 10).

Income taxes

Through the effective date of the spin-off, the Company’s domestic operations were included in the consolidated and combined federal and state income tax returns for Williams, except for certain separate state filings. The income tax provision has been calculated on a separate return basis for the Company and its consolidated subsidiaries, except for certain adjustments, such as alternative minimum tax calculated at the consolidated level by Williams, for which the ultimate expected benefit to the Company could not be determined until the date of deconsolidation. This allocation methodology results in the recognition of deferred assets and liabilities for the differences between the financial statement carrying amounts and their respective tax basis, except to the extent of deferred taxes on income considered to be permanently reinvested in foreign jurisdictions. Deferred tax assets and liabilities are measured using enacted tax rates for the years in which those temporary differences are expected to be recovered or settled.

 

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Notes to Consolidated Financial Statements—(continued)

 

Effective with the spin-off, certain state and federal tax attributes (primarily alternative minimum tax credits) have been allocated between Williams and the Company. Although the final allocation of these tax attributes cannot be determined until the consolidated tax returns for tax year 2011 are complete, which is expected in the third quarter of 2012, an estimate of the tax attributes allocated to the Company has been recorded in the 2011 financial statements as part of the Contribution.

Employee stock-based compensation

Until spin-off, certain employees providing direct service to us participated in Williams’ common-stock-based awards plans. The plans provided for Williams common-stock-based awards to both employees and Williams’ non-management directors. The plans permitted the granting of various types of awards including, but not limited to, stock options and restricted stock units. Awards were granted for no consideration other than prior and future services or based on certain financial performance targets.

Until spin-off, Williams charged us for compensation expense related to stock-based compensation awards granted to our direct employees. Stock based compensation was also a component of allocated amounts charged to us by Williams for general and administrative personnel providing services on our behalf.

In preparation for the spin-off, Williams’ Compensation Committee determined that all outstanding Williams equity-based compensation awards, whether vested or unvested, other than outstanding options issued prior to January 1, 2006 (Pre-2006 Options) would convert into awards with respect to shares of common stock of the company that continues to employ the holder following the spin-off. The Pre-2006 Options were converted into options covering both Williams and WPX common stock. The number of shares underlying each award and, with respect to options, the per share exercise price of each such award has been adjusted to maintain, on a post-spin-off basis, the pre-spin-off intrinsic value of such awards.

Stock options are valued at the date of award, which does not precede the approval date, and compensation cost is recognized on a straight-line basis, net of estimated forfeitures, over the requisite service period. The purchase price per share for stock options may not be less than the market price of the underlying stock on the date of grant. Stock options generally become exercisable over a three-year period from the date of grant and can be subject to accelerated vesting if certain future stock prices or specific financial performance targets are achieved. Stock options generally expire ten years after the grant.

Restricted stock units are generally valued at market value on the grant date and generally vest over three years. Restricted stock unit compensation cost, net of estimated forfeitures, is generally recognized over the vesting period on a straight-line basis.

Foreign exchange

Translation gains and losses that arise from exchange rate fluctuations applicable to transactions denominated in a currency other than the United States dollar are included in the results of operations as incurred.

Earnings (loss) per common share

Basic earnings (loss) per common share is based on the sum of the weighted-average number of common shares outstanding and vested restricted stock units. Diluted earnings (loss) per common share includes any dilutive effect of stock options and nonvested restricted stock units, unless otherwise noted. The impact of our stock issuance has been given effect to all periods presented. (see Note 6).

 

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Notes to Consolidated Financial Statements—(continued)

 

Accounting Standards Issued But Not Yet Adopted

In June 2011, the FASB issued Accounting Standards Update No. 2011-5, “Comprehensive Income (Topic 220) Presentation of Comprehensive Income” (ASU 2011-5). ASU 2011-5 requires presentation of net income and other comprehensive income either in a single continuous statement or in two separate, but consecutive, statements. ASU 2011-5 requires separate presentation in both net income and other comprehensive income of reclassification adjustments for items that are reclassified from other comprehensive income to net income. The new guidance does not change the items reported in other comprehensive income, nor affect how earnings per share is calculated and presented. We currently report net income in the Consolidated Statement of Operations and reports other comprehensive income in the Consolidated Statement of Equity. In December 2011, The FASB issued Accounting Standards Update No. 2011-12, “Comprehensive Income (Topic 220) Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05” (ASU 2011-12). ASU 2011-12 defers the effective date for only the presentation requirements related to reclassifications in ASU 2011-5. During this deferral period, ASU 2011-12 states that we should continue to report reclassifications out of accumulated other comprehensive income consistent with the presentation requirements in effect before ASU 2011-05. All other requirements in ASU 2011-05 are not affected by ASU 2011-12, including the requirement to report comprehensive income either in a single continuous financial statement or in two separate but consecutive financial statements. Both ASU’s are effective beginning the first quarter of 2012, with retrospective application to prior periods. We will apply the new guidance for both ASUs beginning in 2012.

Note 2. Restatement of Prior Periods

We have determined that we did not appropriately provide for deferred federal income taxes on the outside basis differences of a foreign equity investee for the years ended December 31, 2010 and 2009. As a result, our provision (benefit) for income taxes was understated and our net income from continuing operations was overstated by $1 million and $2 million for the years ended December 31, 2010 and 2009, respectively, our deferred income tax liability was understated by $16 million at December 31, 2010 and our net equity was overstated by $16 million, $15 million and $13 million at December 31, 2010, 2009 and 2008, respectively. This restatement also adjusted downward our earnings per share attributable to WPX Energy, Inc. by $.01 in each of the years ended December 31, 2010 and 2009. Based on guidance set forth in Staff Accounting Bulletin No. 99, “Materiality” and in Staff Accounting Bulletin No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements,” (“SAB 108”), we have determined that these amounts are immaterial to each of the periods affected and, therefore, we are not required to amend our previously filed financial statements. We have adjusted our previously reported results for the years ended December 31, 2010 and 2009 for these amounts.

Note 3. Discontinued Operations

Summarized Results of Discontinued Operations

 

     2011     2010     2009  
     (Millions)  

Revenues

   $ 13      $ 16      $ 17   
  

 

 

   

 

 

   

 

 

 

Loss from discontinued operations before impairments, gain on sale and income taxes

   $ (3   $ (13   $ (11

Impairments

     (29     —          —     

Benefit for income taxes

     12        5        4   
  

 

 

   

 

 

   

 

 

 

Loss from discontinued operations

   $ (20   $ (8   $ (7
  

 

 

   

 

 

   

 

 

 

 

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WPX Energy, Inc.

Notes to Consolidated Financial Statements—(continued)

 

Impairments in 2011 reflect write-downs to estimates of fair value less costs to sell the assets of our Arkoma Basin operations that were classified as held for sale as of December 31, 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.

The assets of our discontinued operations are significantly less than one percent of our total assets as of December 31, 2011 and 2010 and are reported in other assets and other noncurrent assets, respectively on our Consolidated Balance Sheet. Liabilities of our discontinued operations are insignificant for these periods.

Note 4. Transactions with Williams

During the fourth quarter of 2011, the Contribution and recapitalization of the Company was completed, whereby common stock held by Williams converted into approximately 197 million shares of WPX common stock. We also entered into agreements with Williams in connection with our separation from Williams. These agreements include:

 

   

A Separation and Distribution agreement for, among other things, the separation from Williams and the distribution of WPX common stock, the distribution of a portion of the net proceeds from the debt financing as well as agreements between us and Williams, including those relating to indemnification;

 

   

A tax sharing agreement, providing for, among other things, the allocation between Williams and WPX of federal, state, local and foreign tax liabilities for periods prior to the distribution and in some instances for periods after the distribution;

 

   

An employee matters agreement discussed below; and

 

   

A transition services agreement discussed below.

Personnel and related services

As previously discussed, our domestic operations were contributed to WPX Energy, Inc. on July 1, 2011. On June 30, 2011, certain entities that were contributed to us on July 1, 2011 withdrew from the Williams’ benefit plans and terminated their personnel services agreements with Williams’ payroll companies. Simultaneously, two new administrative service entities owned and controlled by Williams executed new personnel services agreements with the payroll companies and joined the Williams plans as participants. The effect of these transactions is that none of the companies contributed to WPX Energy in June 2011 had any employees. Through December 30, 2011, these service entities employed all personnel that provided services to the Company and remained owned and controlled by Williams.

In connection with the spin-off, we entered into an Employee Matters Agreement with Williams that set forth our agreements with Williams as to certain employment, compensation and benefits matters. The Employee Matters Agreement provides for the allocation and treatment of assets and liabilities arising out of employee compensation and benefit programs in which our employees participated prior to January 1, 2012. In connection with the spin-off, we provided benefit plans and arrangements in which our employees will participate going forward. Generally, other than with respect to equity compensation (discussed below), from and after January 1, 2012, we will sponsor and maintain employee compensation and benefit programs relating to all employees who transferred to us from Williams in connection with the spinoff through the contribution of two newly established service entities that employees of Williams were moved to prior to the spinoff. The Employee Matters Agreement provides that Williams will remain solely responsible for all liabilities under The Williams Companies Pension Plan, The Williams Companies Retirement Restoration Plan and The Williams Companies Investment Plus Plan. No assets and/or liabilities under any of those plans will be transferred to us or our benefit plans and our employees ceased active participation in those plans as of January 1, 2012. At December 31, 2011,

 

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Notes to Consolidated Financial Statements—(continued)

 

certain paid time off accruals approximating $13 million were transferred from Williams to us and are reflected in accrued liabilities. Additionally, while we have been charged for these costs, Williams remains responsible for any bonus amounts to be paid to our employees for the 2011 year which are currently estimated to be $19 million.

All outstanding Williams equity awards (other than stock options granted prior to January 1, 2006) held by our employees as of the spin-off were converted into WPX equity awards, issued pursuant to a plan that we established. See Note 14. In addition, outstanding Williams stock options that were granted prior to January 1, 2006 and held by our employees and Williams’ other employees as of the date of the spin-off were converted into options to acquire both WPX common stock and Williams common stock, in the same proportion as the number of shares of WPX common stock that each holder of Williams common stock received in the spin-off. The conversion maintained the same intrinsic value as the applicable Williams equity award as of the date of the conversion.

Until the spin-off, Williams charged us for the payroll and benefit costs associated with operations employees (referred to as direct employees) and carried the obligations for many employee-related benefits in its financial statements, including the liabilities related to employee retirement and medical plans. Our share of those costs was charged to us through affiliate billings and reflected in lease and facility operating and general and administrative within costs and expenses in the accompanying Consolidated Statement of Operations.

In addition, Williams charged us for certain employees of Williams who provide general and administrative services on our behalf (referred to as indirect employees). These charges were either directly identifiable or allocated to our operations. Direct charges included goods and services provided by Williams at our request. Allocated general corporate costs were based on our relative usage of the service or on a three-factor formula, which considers revenues; properties and equipment; and payroll. Our share of direct general and administrative expenses and our share of allocated general corporate expenses was reflected in general and administrative expense in the accompanying Consolidated Statement of Operations. In management’s estimation, the allocation methodologies used are reasonable and result in a reasonable allocation to us of our costs of doing business incurred by Williams.

We have entered into a transition services agreement with Williams under which Williams will provide to us, upon our request and on an interim basis, various corporate support services subsequent to the spin-off. These services consist generally of the services that have been provided to us on an intercompany basis prior to the spin-off. These services relate to;

 

   

treasury services;

 

   

finance and accounting;

 

   

tax;

 

   

internal audit;

 

   

investor relations;

 

   

payroll and human resource administration;

 

   

information technology;

 

   

legal and government affairs;

 

   

insurance and claims administration;

 

   

records management;

 

   

real estate and facilities management;

 

   

sourcing and procurement; and

 

   

mail, print and other office services.

 

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Notes to Consolidated Financial Statements—(continued)

 

Pursuant to the transition services agreement, Williams will provide certain services for up to one year after the spin-off. Williams will provide the services and we will pay Williams’ costs, including Williams’ direct and indirect administrative and overhead charges allocated in accordance with Williams’ regular and consistent accounting practices. The transition services agreement may be terminated by either us or Williams upon 60 days notice after the spin-off. In addition, Williams may immediately terminate any of the services it provides under the transition services agreement if it determines that the provision of such services involves certain conflicts of interest between Williams and us or would cause Williams to violate applicable law.

Other arrangements with Williams or its affiliates

We also have operating activities with WPZ and another Williams subsidiary. Our revenues include revenues from the following types of transactions:

 

   

Sales of natural gas liquids (NGLs) related to our production to WPZ at market prices at the time of sale and included within our oil and gas sales revenues; and

 

   

Sales to WPZ and another Williams subsidiary of natural gas procured by WPX Energy Marketing for those companies’ fuel and shrink replacement at market prices at the time of sale and included in our gas management revenues.

Our costs and operating expenses include the following services provided by WPZ:

 

   

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

 

   

Pipeline transportation for both our oil and gas sales and gas management activities which includes commitments totaling $401 million (see Note 12 for capacity commitments with affiliates).

In addition, through an agency agreement, we manage the jurisdictional merchant gas sales for Transcontinental Gas Pipe Line Company LLC (Transco), an indirect, wholly owned subsidiary of WPZ. We are authorized to make gas sales on Transco’s behalf in order to manage its gas purchase obligations. We receive all margins associated with jurisdictional merchant gas sales business and, as Transco’s agent, assume all market and credit risk associated with such sales. Gas sales and purchases related to our management of these jurisdictional merchant gas sales are included in gas management revenues and expenses, respectively, in the Consolidated Statement of Operations and the margins we realized related to these activities totaled less than $1 million in each of the years ended December 31, 2011, 2010 and 2009. We have signed an agreement with Williams under which these contracts will be assigned to them in the near term.

During fourth-quarter 2010, the Company sold certain gathering and processing assets in Colorado’s Piceance Basin (the Piceance Sale) with a net book value of $458 million to WPZ, an entity under the common control of Williams, in exchange for $702 million in cash and 1.8 million WPZ limited partner units. As the Company and WPZ were under common control at that time, no gain was recognized on this transaction in the Consolidated Statement of Operations. Accordingly, the $244 million difference between the cash consideration received and the historical net book value of the assets has been reflected in the Consolidated Statement of Equity for the year ended December 31, 2010. Since the WPZ units received in this transaction by the Company were intended to be (and were, as described below) distributed through a dividend to Williams, these units (as well as the tax effects associated with these units of $42 million) have been presented net within equity and are included in net transfers with Williams in 2010. Further, as a result of the limitations on the Company’s ability to sell these units and the subsequent dividend to Williams, no gains on the value of the common units during the holding period have been recognized in the Consolidated Statement of Operations. In conjunction with the Piceance Sale, we entered into long-term contracts with WPZ for gathering and processing of our natural gas production in the area. Due to the continuation of significant direct cash flows related to these assets, historical operating results of these assets have been presented in the Consolidated Statement of Operations as continuing operations for periods prior to the sale. In

 

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WPX Energy, Inc.

Notes to Consolidated Financial Statements—(continued)

 

March 2011, the 1.8 million WPZ units and related tax basis were distributed via dividend to Williams.

We have managed a transportation capacity contract for WPZ. To the extent the transportation is not fully utilized or does not recover full-rate demand expense, WPZ reimburses us for these transportation costs. These reimbursements to us totaled approximately $11 million, $10 million and $9 million for the years ended December 31, 2011, 2010 and 2009, respectively, and are included in gas management revenues. We have signed an agreement with WPZ under which these contracts will be assigned to them in the near term.

WPZ periodically entered into derivative contracts with us to hedge their forecasted NGL sales and natural gas purchases. We entered into offsetting derivative contracts with third parties at equivalent pricing and volumes. These contracts are included in derivative assets and liabilities on the Consolidated Balance Sheet at December 31, 2010. No contracts existed at December 31, 2011.

Prior to December 1, 2011 we participated in Williams centralized approach to cash management and the financing of its businesses. Daily cash activity from our domestic operations was transferred to or from Williams on a regular basis and was recorded as increases or decreases in the balance due under unsecured promissory notes we had in place with Williams through June 30, 2011, at which time the notes were cancelled by Williams. The amount due to Williams at the time of cancellation was $2.4 billion and is reflected as an increase in owner’s net investment. Through fourth-quarter 2011, an additional $162 million was cancelled and reflected as an increase in owner’s net investment. The notes reflected interest based on Williams’ weighted average cost of debt and such interest was added monthly to the note principle. The interest rate for the notes payable to Williams was 8.08%, 8.08% and 8.01% at June 30, 2011, December 31, 2010 and 2009, respectively.

Under Williams’ cash-management system, certain cash accounts reflected negative balances to the extent checks written had not been presented for payment. These negative amounts represented obligations and were reclassified to accounts payable-affiliate. Accounts payable-affiliate includes approximately $38 million of these negative balances at December 31, 2010. On December 1, 2011, we initiated our own cash management system as we began self-funding our operations. To the extent that certain cash accounts reflect negative balances, that obligation is reflected within our external accounts payable.

On August 25, 2011, we entered into a 10.5 year lease for our present headquarters office with Williams Headquarters Building Company, a direct subsidiary of Williams. We estimate the annual rent payable by us under the lease to be approximately $4 million per year.

Below is a summary of the transactions with Williams or its affiliates discussed above:

 

     2011      2010      2009  
     (Millions)  

Product revenues—sales of NGLs to WPZ

   $ 258       $ 277       $ 116   

Gas management revenues—sales of natural gas for fuel and shrink to WPZ and another Williams subsidiary

     586         509         431   

Lease and facility operating expenses from Williams-direct employee salary and benefit costs

     21         23         23   

Gathering, processing and transportation expense from services with WPZ:

        

Gathering and processing

     298         163         72   

Transportation

     44         25         28   

General and administrative from Williams:

        

Direct employee salary and benefit costs

     111         102         100   

Charges for general and administrative services

     62         58         60   

Allocated general corporate costs

     62         64         63   

Other

     16         12         13   

Interest expense on notes payable to Williams

     96         119         92   

 

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WPX Energy, Inc.

Notes to Consolidated Financial Statements—(continued)

 

In addition, the current amount due to or from affiliates consists of normal course receivables and payables resulting from the sale of products to and cost of gathering services provided by WPZ. Below is a summary of these payables and receivables and other assets and liabilities with Williams and its affiliates:

 

     December 31,  
         2011              2010      
     (Millions)  

Current:

     

Accounts receivable:

     

Due from WPZ and another Williams subsidiary

   $ 62       $ 60   
  

 

 

    

 

 

 

Other noncurrent assets—Due from Williams

   $ 11       $ —     
  

 

 

    

 

 

 

Accounts payable:

     

Due to WPZ

   $ 35       $ 12   

Due to Williams for cash overdraft

     —           38   

Due to Williams for accrued payroll and benefits

     10         14   

Due to Williams for administrative expenses

     14         —     
  

 

 

    

 

 

 
   $ 59       $ 64   
  

 

 

    

 

 

 

Noncurrent liability to Williams

   $ 48       $ —     
  

 

 

    

 

 

 

Note 5. Investment Income and Other

Investment income

 

     Years Ended December 31,  
         2011              2010              2009      
     (Millions)  

Equity earnings

   $ 24       $ 20       $ 18   

Impairment of cost-based investment

     —           —           (11

Other

     2         1         1   
  

 

 

    

 

 

    

 

 

 

Total investment income and other

   $ 26       $ 21       $ 8   
  

 

 

    

 

 

    

 

 

 

Impairment of cost-based investment in 2009 reflects an $11 million full impairment of our 4 percent interest in a Venezuelan corporation that owns and operates oil and gas activities in Venezuela.

Investments

 

     December 31,  
         2011              2010      
     (Millions)  

Petrolera Entre Lomas S.A.—40.8%

   $ 90       $ 82   

Other

     35         23   
  

 

 

    

 

 

 
   $ 125       $ 105   
  

 

 

    

 

 

 

Petrolera Entre Lomas S.A. operates several development concessions in South America. Other is comprised of investments in miscellaneous gas gathering interests in the United States.

Dividends and distributions received from companies accounted for by the equity method were $17 million in 2011, $19 million in 2010 and $9 million in 2009.

 

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WPX Energy, Inc.

Notes to Consolidated Financial Statements—(continued)

 

Note 6. Earnings (Loss) Per Common Share from Continuing Operations

 

     Years Ended December 31,  
     2011     2010     2009  
     (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

   $ (282   $ (1,283   $ 141   
  

 

 

   

 

 

   

 

 

 

Basic weighted-average shares

     197.1        197.1        197.1   
  

 

 

   

 

 

   

 

 

 

Diluted weighted-average shares

     197.1        197.1        197.1   
  

 

 

   

 

 

   

 

 

 

Earnings (loss) per common share from continuing operations:

      

Basic

   $ (1.43   $ (6.51   $ 0.71   
  

 

 

   

 

 

   

 

 

 

Diluted

   $ (1.43   $ (6.51   $ 0.71   
  

 

 

   

 

 

   

 

 

 

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 in the calculation of basic weighted average shares.

For 2011 approximately 2.9 million weighted-average nonvested restricted stock units and 1.2 million weighted-average stock options have been excluded from the computation of diluted earnings per common share as their inclusion would be antidilutive to our loss from continuing operations attributable to WPX Energy, Inc. For 2010 and 2009 these amounts are not given retrospective effect to the calculation.

Note 7. Asset Sales, Impairments, Exploration Expenses and Other Accruals

The following table presents a summary of significant gains or losses reflected in impairment of producing properties and costs of acquired unproved reserves, goodwill impairment and other—net within costs and expenses. These significant adjustments are associated with our domestic operations.

 

     Years Ended December 31,  
         2011             2010             2009      
     (Millions)  

Goodwill impairment

   $ —        $ 1,003      $ —     

Impairment of producing properties and costs of acquired unproved reserves *

     547        678        15   

Penalties from early release of drilling rigs included in other (income) expense—net

     —          —          32   

(Gain) loss on sales of other assets

     (1     (22     1   

 

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

 

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WPX Energy, Inc.

Notes to Consolidated Financial Statements—(continued)

 

As part of our assessment for impairments primarily resulting from declining forward natural gas prices during the fourth quarter 2011, we recorded a $276 million impairment of proved producing oil and gas properties in the Powder River basin and a $180 million impairment in Barnett Shale (see Note 16). Additionally, we recorded a $91 million impairment of our capitalized cost of acquired unproved reserves in the Powder River.

As a result of significant declines in forward natural gas prices during 2010, we performed an impairment assessment of our capitalized costs related to goodwill and domestic producing properties. As a result of these assessments, we recorded an impairment of goodwill, as noted above, and impairments of our capitalized costs of certain natural gas producing properties in the Barnett Shale of $503 million and capitalized costs of certain acquired unproved reserves in the Piceance Highlands acquired in 2008 of $175 million (see Note 16).

We recorded a $15 million impairment in 2009 related to costs of acquired unproved reserves resulting from a 2008 acquisition in the Fort Worth basin (see Note 16).

Our impairment analyses included an assessment of undiscounted (except for the costs of acquired unproved reserves) and discounted future cash flows, which considered information obtained from drilling, other activities and natural gas reserve quantities.

In July 2010, we sold a portion of gathering and processing facilities in the Piceance basin to a third party for cash proceeds of $30 million resulting in a gain of $12 million. The remaining portion of the facilities was part of the Piceance Sale (see Note 4). Also in 2010, we exchanged undeveloped leasehold acreage in different areas with a third party resulting in a $7 million gain.

The following presents a summary of exploration expenses:

 

     Years Ended December 31,  
         2011              2010              2009      
     (Millions)  

Geologic and geophysical costs

   $ 18       $ 22       $ 33   

Dry hole costs

     13         17         11   

Unproved leasehold property impairment, amortization and expiration

     103         34         10   
  

 

 

    

 

 

    

 

 

 

Total exploration expense

   $ 134       $ 73       $ 54   
  

 

 

    

 

 

    

 

 

 

Dry hole costs in 2011 include an $11 million dry hole expense in connection with a Marcellus Shale well in Columbia County, Pennsylvania, while 2010 and 2009 reflect dry hole expense associated primarily with wells in the Paradox basin.

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 acreage in Pennsylvania.

 

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WPX Energy, Inc.

Notes to Consolidated Financial Statements—(continued)

 

Note 8. Properties and Equipment

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

 

     Estimated
Useful
Life  (a)
(Years)
  December 31,  
       2011     2010  
         (Millions)  

Proved properties

   (b)   $ 9,985      $ 9,822   

Unproved properties

   (c)     1,555        1,893   

Gathering, processing and other facilities

   15-25     181        119   

Construction in progress

   (c)     692        603   

Other

   3-25     99        127   
    

 

 

   

 

 

 

Total properties and equipment, at cost

       12,512        12,564   

Accumulated depreciation, depletion and amortization

       (4,036     (4,115
    

 

 

   

 

 

 

Properties and equipment—net

     $ 8,476      $ 8,449   
    

 

 

   

 

 

 

 

(a) Estimated useful lives are presented as of December 31, 2011.
(b) Proved properties are depreciated, depleted and amortized using the units-of-production method (see Note 1).
(c) Unproved properties and construction in progress are not yet subject to depreciation and depletion.

Unproved properties consist primarily of non-producing leasehold in the Williston Basin (Bakken Shale) and the Appalachian Basin (Marcellus Shale) and acquired unproved reserves in the Powder River and Piceance Basins.

On December 21, 2010, we closed the acquisition of 100 percent of the equity of Dakota-3 E&P Company LLC for $949 million, including closing adjustments. This company held approximately 85,800 net acres on the Fort Berthold Indian Reservation in the Williston Basin of North Dakota. Approximately 85% of the acreage was undeveloped. Approximately $400 million of the purchase price was recorded as proved properties, $542 million as unproved properties within properties and equipment and $5 million of prepaid drilling costs (no significant working capital was acquired). Revenues and earnings for the acquired company were nominal and thus insignificant to us for the years ended December 31, 2010 and 2009.

As discussed in Note 4 in 2010, the Company sold certain gathering and processing assets in Colorado’s Piceance Basin with a net book value of $458 million to WPZ.

In May 2010, we entered into a purchase agreement consisting primarily of non-producing leasehold acreage in the Appalachian Basin and a 5 percent overriding royalty interest associated with the acreage position for $599 million.

Construction in progress includes $113 million in 2011 and $142 million in 2010 related to wells located in Powder River. In order to produce gas from the coal seams, an extended period of dewatering is required prior to natural gas production.

In 2009, we adopted Accounting Standards Update No. 2010-03, which aligned oil and gas reserve estimation and disclosure requirements to those in the Securities and Exchange Commission’s final rule related thereto. Accordingly, our fourth quarter 2009 depreciation, depletion and amortization expense was approximately $17 million more than had it been computed under the prior requirements.

 

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WPX Energy, Inc.

Notes to Consolidated Financial Statements—(continued)

 

Asset Retirement Obligations

Our asset retirement obligations relate to producing wells, gas gathering well connections and related facilities. At the end of the useful life of each respective asset, we are legally obligated to plug producing wells and remove any related surface equipment and to cap gathering well connections at the wellhead and remove any related facility surface equipment.

A rollforward of our asset retirement obligation for the years ended 2011 and 2010 is presented below.

 

     2011     2010  
     (Millions)  

Balance, January 1

   $ 285      $ 242   

Liabilities incurred during the period

     23        43   

Liabilities settled during the period

     (2     (2

Liabilities associated with assets sold

     —          (22

Estimate revisions

     (24     3   

Accretion expense *

     20        21   
  

 

 

   

 

 

 

Balance, December 31

   $ 302      $ 285   
  

 

 

   

 

 

 

Amount reflected as current

   $ 6      $ 3   
  

 

 

   

 

 

 

 

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

Estimate revisions in 2011 are primarily associated with changes in anticipated well lives and plug and abandonment costs.

Note 9. Accrued and other current liabilities

Accrued and other current liabilities

 

     December 31,  
     2011      2010  
     (Millions)  

Taxes other than income taxes

   $ 79       $ 76   

Customer margin deposits

     7         25   

Accrued interest

     13         1   

Compensation and benefit related accruals

     13         —     

Other, including other loss contingencies

     74         56   
  

 

 

    

 

 

 
   $ 186       $ 158   
  

 

 

    

 

 

 

Prior to the spin-off, employee compensation and benefit accruals were obligations of Williams with the expense related to compensation allocated to us through affiliate charges.

 

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WPX Energy, Inc.

Notes to Consolidated Financial Statements—(continued)

 

Note 10. Debt and Banking Arrangements

In connection with our separation from Williams, we issued $1.5 billion face value Senior Notes as follows:

 

     December 31,  
     2011      2010  
     (Millions)  

5.250% Senior Notes due 2017

   $ 400       $ —     

6.000% Senior Notes due 2022

     1,100         —     

Other

     3         —     
  

 

 

    

 

 

 
   $ 1,503       $ —     
  

 

 

    

 

 

 

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 connection with the Contribution.

Optional Redemption. We have the option, prior to maturity, in the case of the 2017 notes, and prior to October 15, 2021 (which is the date that is three months prior to the maturity date of the 2022 notes), in the case of the 2022 notes, to redeem all or a portion of the Notes of the applicable series at any time at a redemption price equal to the greater of (i) 100% of their principal amount and (ii) the discounted present value of 100% of their principal amount and remaining scheduled interest payments, in either case plus accrued and unpaid interest to the redemption date. We also have the option at any time on or after October 15, 2021, to redeem the 2022 notes, in whole or in part, at a redemption price equal to 100% of their principal amount, plus accrued and unpaid interest thereon to the redemption date.

Change of Control. If we experience a change of control (as defined in the indenture governing the Notes) accompanied by a rating decline with respect to a series of Notes, we must offer to repurchase the Notes of such series at 101% of their principal amount, plus accrued and unpaid interest.

Covenants. The terms of the indenture restrict our ability and the ability of our subsidiaries to incur additional indebtedness secured by liens and to effect a consolidation, merger or sale of substantially all our assets. The indenture also requires us to file with the trustee and the SEC certain documents and reports within certain time limits set forth in the indenture. However, these limitations and requirements will be subject to a number of important qualifications and exceptions. The indenture does not require the maintenance of any financial ratios or specified levels of net worth or liquidity.

Events of Default. Each of the following is an “Event of Default” under the indenture with respect to the Notes of any series:

(1) a default in the payment of interest on the Notes when due that continues for 30 days;

(2) a default in the payment of the principal of or any premium, if any, on the Notes when due at their stated maturity, upon redemption, or otherwise;

(3) failure by us to duly observe or perform any other of the covenants or agreements (other than those described in clause (1) or (2) above) in the indenture, which failure continues for a period of 60 days, or, in the case of the reporting covenant under the indenture, which failure continues for a period of 90 days, after

 

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WPX Energy, Inc.

Notes to Consolidated Financial Statements—(continued)

 

the date on which written notice of such failure has been given to us by the trustee; provided, however, that if such failure is not capable of cure within such 60-day or 90-day period, as the case may be, such 60-day or 90-day period, as the case may be, will be automatically extended by an additional 60 days so long as (i) such failure is subject to cure and (ii) we are using commercially reasonable efforts to cure such failure; and

(4) certain events of bankruptcy, insolvency or reorganization described in the indenture.

Registration Rights Agreement. As part of the new issuance, we entered into a registration rights agreement whereby we agree to offer to exchange the notes for a new issue of substantially identical notes registered under the Securities Act of 1933, as amended, within 180 days from closing and to use commercially reasonable efforts to cause the registration statement to be declared effective within 270 days after closing and to consummate the exchange offer within 30 business days after such effective date. We are required to provide a shelf registration statement to cover resales of the notes under certain circumstances. If we fail to fulfill these obligations, additional interest will accrue on the affected securities until we have successfully registered the securities.

Credit Facility Agreement

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. Borrowings may be used for working capital, acquisitions, capital expenditures and other general corporate purposes. At December 31, 2011 there was no outstanding balance under the Credit Facility Agreement.

The Credit Facility Agreement became effective on November 1, 2011. Also, on November 1, 2011 we terminated our existing unsecured credit agreement which had served to reduce margin requirements and transaction fees related to hedging activities. All outstanding hedges under the terminated agreement were transferred to new agreements with various financial institutions that also participate in the new credit facility. We nor the participating financial institutions are required to provide collateral support related to hedging activities under the new agreements.

Interest on borrowings under the Credit Facility Agreement will be payable at rates per annum equal to, at the option of WPX Energy: (1) a fluctuating base rate equal to the Alternate Base Rate plus the Applicable Rate, or (2) a periodic fixed rate equal to LIBOR plus the Applicable Rate. The Alternate Base Rate will be the highest of (i) the federal funds rate plus 0.5 percent, (ii) the Prime Rate, and (iii) one-month LIBOR plus 1.0 percent. The Applicable Rate changes depending on which interest rate WPX selects and WPX’s credit rating. Additionally, WPX Energy will be required to pay a commitment fee based on the unused portion of the commitments under the Credit Facility Agreement.

Under the Credit Facility Agreement, prior to the occurrence of the Investment Grade Date (as defined below), we will be required to maintain a ratio of net present value of projected future cash flows from proved reserves to Consolidated Indebtedness (each as defined in the Credit Facility Agreement) of at least 1.50 to 1.00. Net present value is determined as of the end of each fiscal year and reflects the present value, discounted at 9 percent, of projected future cash flows of domestic proved oil and gas reserves (such cash flows adjusted to reflect the impact of hedges, our lenders’ commodity price forecasts, and, if necessary, including only a portion of our reserves that are not proved developed producing reserves). Additionally, the ratio of debt to capitalization (defined as net worth plus debt) will not be permitted to be greater than 60%. Beginning December 31, 2011, each of the above ratios will be tested at the end of each fiscal quarter. We were in compliance with our debt covenant ratios as of December 31, 2011. Investment Grade Date means the first date on which our long-

 

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WPX Energy, Inc.

Notes to Consolidated Financial Statements—(continued)

 

term senior unsecured debt ratings are BBB- or better by S&P or Baa3 or better by Moody’s (without negative outlook or negative watch), provided that the other of the two ratings is at least BB+ by S&P or Ba1 by Moody’s.

The Credit Facility Agreement contains customary representations and warranties and affirmative, negative and financial covenants which were made only for the purposes of the Credit Facility Agreement and as of the specific date (or dates) set forth therein, and may be subject to certain limitations as agreed upon by the contracting parties. The covenants limit, among other things, the ability of our subsidiaries to incur indebtedness, make investments, loans or advances and enter into certain hedging agreements; our ability to merge or consolidate with any person or sell all or substantially all of our assets to any person, enter into certain affiliate transactions, make certain distributions during the continuation of an event of default and allow material changes in the nature of our business. In addition, the representations, warranties and covenants contained in the Credit Facility Agreement may be subject to standards of materiality applicable to the contracting parties that differ from those applicable to investors.

The Credit Facility Agreement includes customary events of default, including events of default relating to non-payment of principal, interest or fees, inaccuracy of representations and warranties in any material respect when made or when deemed made, violation of covenants, cross payment-defaults, cross acceleration, bankruptcy and insolvency events, certain unsatisfied judgments and a change of control. If an event of default with respect to us occurs under the Credit Facility Agreement, the lenders will be able to terminate the commitments and accelerate the maturity of any loans outstanding under the Credit Facility Agreement at the time, in addition to the exercise of other rights and remedies available.

Letters of Credit

In addition to the Notes and Credit Facility Agreement, WPX has executed 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 December 31, 2011 a total of $292 million in letters of credit have been issued.

Other

Apco executed a loan agreement with a financial institution for a $10 million bank line of credit. Borrowings under this facility are unsecured and bear interest at six-month LIBOR plus three percent per annum plus a one percent arrangement fee per borrowing and a commitment fee for the unused portion of the loan amount. The funds can be borrowed during a one-year period ending in March 2012, and principal amounts will be repaid in semi-annual installments from each borrowing date after a two and a half year grace period. 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. As of December 31, 2011, we have borrowed $2 million under this banking agreement. Aggregate minimum maturities of this long-term debt are $1 million each for 2013 and 2014.

Note 11. Income Taxes

Through the effective date of the spin-off, the Company’s domestic operations were included in the consolidated and combined federal and state income tax returns for Williams, except for certain separate state filings. The income tax provision has been calculated on a separate return basis for the Company and its consolidated subsidiaries, except for certain adjustments, such as alternative minimum tax calculated at the consolidated level by Williams, for which the ultimate expected impact to the Company could not be determined until the date of deconsolidation.

 

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WPX Energy, Inc.

Notes to Consolidated Financial Statements—(continued)

 

Effective with the spin-off, Williams and the Company entered into a tax sharing agreement which governs the respective rights, responsibilities and obligations of each company, for tax periods prior to the spin-off, with respect to the payment of taxes, filing of tax returns, reimbursements of taxes, control of audits and other tax proceedings, liability for taxes that may be triggered as a result of the spin-off and other matters regarding taxes.

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

 

     Years Ended December 31,  
     2011     2010     2009  
     (Millions)  

Provision (benefit):

      

Current:

      

Federal

   $ 5      $ 7      $ (17

State

     4        1        (1

Foreign

     10        11        9   
  

 

 

   

 

 

   

 

 

 
     19        19        (9
  

 

 

   

 

 

   

 

 

 

Deferred:

      

Federal

     (161     (158     99   

State

     (3     (10     6   
  

 

 

   

 

 

   

 

 

 
     (164     (168     105   
  

 

 

   

 

 

   

 

 

 

Total provision (benefit)

   $ (145   $ (149   $ 96   
  

 

 

   

 

 

   

 

 

 

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

 

     Years Ended December 31,  
     2011     2010     2009  
     (Millions)  

Provision (benefit) at statutory rate

   $ (146   $ (498   $ 85   

Increases (decreases) in taxes resulting from:

      

State income taxes (net of federal benefit)

     (8     (6     3   

Effective state income tax rate change (net of federal benefit)

     9        —          —     

Foreign operations—net

     —          4        6   

Goodwill impairment

     —          351        —     

Other—net

     —          —          2   
  

 

 

   

 

 

   

 

 

 

Provision (benefit) for income taxes

   $ (145   $ (149   $ 96   
  

 

 

   

 

 

   

 

 

 

Income (loss) from continuing operations before income taxes includes $40 million, $36 million and $21 million of foreign income in 2011, 2010 and 2009, respectively.

 

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WPX Energy, Inc.

Notes to Consolidated Financial Statements—(continued)

 

Significant components of deferred tax liabilities and deferred tax assets are as follows:

 

     December 31,  
     2011      2010  
     (Millions)  

Deferred tax liabilities:

     

Properties and equipment

   $ 1,779       $ 1,739   

Derivatives, net

     137         110   
  

 

 

    

 

 

 

Total deferred tax liabilities

     1,916         1,849   
  

 

 

    

 

 

 

Deferred tax assets:

     

Accrued liabilities and other

     146         117   

Alternative minimum tax credits (a)

     98         —     

Loss carry-overs

     16         22   
  

 

 

    

 

 

 

Total deferred tax assets

     260         139   

Less: valuation allowance

     16         22   
  

 

 

    

 

 

 

Total net deferred tax assets

     244         117   
  

 

 

    

 

 

 

Net deferred tax liabilities

   $ 1,672       $ 1,732   
  

 

 

    

 

 

 

 

(a) In connection with the spin-off from Williams effective December 31, 2011, alternative minimum tax credits were able to be estimated and allocated between Williams and the Company. This resulted in the allocation to the Company of $98 million with a corresponding increase to additional paid-in capital. Any subsequent adjustments of the alternative minimum tax credit allocation with Williams will be recorded in the provision for the period in which the change occurs.

As of December 31, 2011, the Company has approximately $290 million of state net operating loss carryovers of which approximately 75 percent expire after 2020.

The valuation allowance at December 31, 2011 and 2010 serves to reduce the recognized tax assets associated with state losses, net of federal benefit, to an amount that will more likely than not be realized by the Company. There have been no significant effects on the income tax provision associated with changes in the valuation allowance for the years ended December 31, 2011 and 2010.

Undistributed earnings of certain consolidated foreign subsidiaries excluding amounts related to foreign equity investments at December 31, 2011, totaled approximately $66 million. No provision for deferred U.S. income taxes has been made for these subsidiaries because we intend to permanently reinvest such earnings in foreign operations.

The payments and receipts for domestic income taxes were made to or received from Williams in accordance with Williams’ intercompany tax allocation procedure. Cash payments for domestic income taxes (net of receipts) were $10 million, $5 million and ($13) million in 2011, 2010 and 2009, respectively. Additionally, payments made directly to international taxing authorities were $10 million, $8 million and $4 million in 2011, 2010 and 2009, respectively.

The Company’s policy is to recognize related interest and penalties as a component of income tax expense. The amounts accrued for interest and penalties are insignificant.

Pursuant to our tax sharing agreement with Williams, we will remain responsible for the tax from audit adjustments related to our business for periods prior to the spin-off. During the first quarter of 2011, Williams

 

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WPX Energy, Inc.

Notes to Consolidated Financial Statements—(continued)

 

finalized settlements with the IRS for 1997 through 2008. The statute of limitations for most states expires one year after expiration of the IRS statute. Income tax returns for our foreign operations, primarily in Argentina, are open to audit for the 2004 to 2011 tax years.

As of December 31, 2011, 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.

Note 12. Contingent Liabilities and Commitments

Royalty litigation

In September 2006, royalty interest owners in Garfield County, Colorado, filed a class action suit in District Court, Garfield County, Colorado, alleging we improperly calculated oil and gas royalty payments, failed to account for 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 2012. 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 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 and payments and future reporting. This matter has been removed to the United States District Court for New Mexico. 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.

 

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WPX Energy, Inc.

Notes to Consolidated Financial Statements—(continued)

 

Other producers have been in litigation with a federal regulatory agency and 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 have monitored 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 January 2004 through December 2011, our deductions used in the calculation of the royalty payments in states other than New Mexico associated with conventional gas production total approximately $72 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 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 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.

 

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WPX Energy, Inc.

Notes to Consolidated Financial Statements—(continued)

 

Although the State Settlement and Utilities Settlement resolved a significant portion of the refund issues among the settling parties, we continue to have potential refund exposure to nonsettling parties, including various California end users that did not participate in the Utilities Settlement. We are currently in settlement negotiations with certain California utilities aimed at eliminating or substantially reducing this exposure. If successful, and subject to a final “true-up” mechanism, the settlement agreement would also resolve our collection of accrued interest from counterparties as well as our payment of accrued interest on refund amounts. Thus, as currently contemplated by the parties, the settlement agreement would resolve most, if not all, of our legal issues arising from the 2000-2001 California Energy Crisis. With respect to these matters, amounts accrued are not material to our financial position.

Certain other issues also remain open at the FERC and for other nonsettling parties.

Reporting of natural gas-related information to trade publications

Civil suits based on allegations of manipulating published gas price indices have been brought against us and others, 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. However, it is reasonably possible that the ultimate resolution of these items could result in future charges that may be material to our results of operations.

Other Indemnifications

Pursuant to various purchase and sale agreements relating to divested businesses and assets, we have indemnified certain purchasers against liabilities that they may incur with respect to the businesses and assets acquired from us. The indemnities provided to the purchasers are customary in sale transactions and are contingent upon the purchasers incurring liabilities that are not otherwise recoverable from third parties. The indemnities generally relate to breach of warranties, tax, historic litigation, personal injury, environmental matters, right of way and other representations that we have provided.

At December 31, 2011, 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.

 

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WPX Energy, Inc.

Notes to Consolidated Financial Statements—(continued)

 

Summary

As of December 31, 2011 and December 31, 2010, the Company had accrued approximately $23 million and $21 million, respectively, for loss contingencies associated with royalty litigation, reporting of natural gas information to trade publications and other contingencies. 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.

Commitments

As part of managing our commodity price risk, we utilize contracted pipeline capacity (including capacity on former affiliates’ systems, resulting in a total of $401 million for all years) to move our natural gas production and third party gas purchases to other locations in an attempt to obtain more favorable pricing differentials. Our commitments under these contracts as of December 31, 2011 are as follows:

 

     (Millions)  

2012

   $ 215   

2013

     211   

2014

     177   

2015

     167   

2016

     149   

Thereafter

     489   
  

 

 

 

Total

   $ 1,408   
  

 

 

 

We also have certain commitments to an equity investee and others, primarily for natural gas gathering and treating services and well completion services, which total $780 million over approximately seven years.

We hold a long-term obligation to deliver on a firm basis 200,000 MMBtu per day of natural gas to a buyer at the White River Hub (Greasewood-Meeker, Colorado), which is the major market hub exiting the Piceance Basin. This obligation expires in 2014.

In connection with a gathering agreement entered into by WPZ with a third party in December 2010, we concurrently agreed to buy up to 200,000 MMBtu per day of natural gas at Transco Station 515 (Marcellus Basin) at market prices from the same third party. Purchases under the 12-year contract are anticipated to begin in the first quarter of 2012. We expect to sell this natural gas in the open market and may utilize available transportation capacity to facilitate the sales.

 

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WPX Energy, Inc.

Notes to Consolidated Financial Statements—(continued)

 

Future minimum annual rentals under noncancelable operating leases as of December 31, 2011, are payable as follows:

 

     (Millions)  

2012

   $ 67   

2013

     76   

2014

     67   

2015

     32   

2016

     9   

Thereafter

     36   
  

 

 

 

Total

   $ 287   
  

 

 

 

Total rent expense, excluding month-to-month rentals, was $16 million, $13 million and $22 million in 2011, 2010 and 2009, respectively. Rent charges incurred for drilling rig rentals are capitalized under the successful efforts method of accounting.

Note 13. Employee Benefit Plans

Prior to spin-off

Through the spin-off date, certain benefit costs associated with direct employees who support our operations are determined based on a specific employee basis and were charged to us by Williams as described below. These pension and post retirement benefit costs included amounts associated with vested participants who are no longer employees. As described in Note 4 Williams also charged us for the allocated cost of certain indirect employees of Williams who provided general and administrative services on our behalf. Williams included an allocation of the benefit costs associated with these Williams employees based upon a Williams’ determined benefit rate, not necessarily specific to the employees providing general and administrative services on our behalf. As a result, the information described below is limited to amounts associated with the direct employees that supported our operations.

For the periods presented, we were not the plan sponsor for these plans. Accordingly, our Consolidated Balance Sheet does not reflect any assets or liabilities related to these plans.

Pension plans

Williams is the sponsor of noncontributory defined benefit pension plans that provides pension benefits for its eligible employees. Pension expense charged to us by Williams for 2011, 2010 and 2009 totaled $8 million, $7 million and $7 million, respectively.

Other postretirement benefits

Williams is the sponsor of subsidized retiree medical and life insurance benefit plans (other postretirement benefits) that provides benefits to certain eligible participants, generally including employees hired on or before December 31, 1991, and other miscellaneous defined participant groups. Other postretirement benefit expense charged to us by Williams for 2011, 2010, and 2009 totaled less than $1 million for each period.

Defined contribution plan

Williams also is the sponsor of a defined contribution plan that provides benefits to certain eligible participants and has charged us compensation expense of $4 million, $5 million and $5 million in 2011, 2010 and 2009, respectively, for Williams’ matching contributions to this plan.

 

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WPX Energy, Inc.

Notes to Consolidated Financial Statements—(continued)

 

Subsequent to spin-off

On January 1, 2012, several new plans became effective for us including a defined contribution plan. WPX matches dollar-for-dollar up to the first 6 percent of eligible pay per period. Employees also receive a non-matching annual employer contribution of equal to 8 percent of eligible pay if they are age 40 or older and 6 percent of eligible pay if they are under age 40.

Note 14. Stock-Based Compensation

Certain of our direct employees participated in The Williams Companies, Inc. 2007 Incentive Plan, which provides for Williams common-stock-based awards to both employees and Williams’ nonmanagement directors. The plan permits the granting of various types of awards including, but not limited to, stock options and restricted stock units. Awards may be granted for no consideration other than prior and future services or based on certain financial performance targets. Additionally, certain of our eligible direct employees participated in Williams’ Employee Stock Purchase Plan (ESPP). The ESPP enables eligible participants to purchase through payroll deductions a limited amount of Williams’ common stock at a discounted price.

Through the date of spin-off we were charged by Williams for stock-based compensation expense related to our direct employees. Williams also charges us for the allocated costs of certain indirect employees of Williams (including stock-based compensation) who provide general and administrative services on our behalf. However, information included in this note is limited to stock-based compensation associated with the direct employees (see Note 4 for total costs charged to us by Williams).

Williams’ Compensation Committee determined that all outstanding Williams stock-based compensation awards, whether vested or unvested, other than outstanding options issued prior to January 1, 2006 (the Pre-2006 Options), be converted into awards with respect to shares of common stock of the company that continues to employ the holder following the spin-off. The Pre-2006 Options (whether held by our employees or other Williams employees) converted into options for both Williams and WPX common stock following the spin-off, in the same ratio as is used in the distribution of WPX common stock to holders of Williams common stock. The number of shares underlying each such award (including the Pre-2006 Options) and, with respect to options (including the Pre-2006 Options), the per share exercise price of each award was adjusted to maintain, on a post-spin-off basis, the pre-spin-off intrinsic value of each award.

Total stock-based compensation expense included in general and administrative expense for the years ended December 31, 2011, 2010 and 2009 was $18 million, $14 million, and $13 million, respectively. Measured but unrecognized stock-based compensation expense at December 31, 2011 was $24 million. This amount is comprised of $2 million related to stock options and $22 million related to restricted stock units. These amounts are expected to be recognized over a weighted-average period of 1.8 years.

WPX Energy, Inc. 2011 Incentive Plan

Subsequent to the spin-off, we have an equity incentive plan and an employee stock purchase plan. The 2011 Incentive Plan authorizes the grant of nonqualified stock options, incentive stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance units and other stock-based awards. The number of shares of common stock authorized for issuance pursuant to all awards granted under the 2011 Incentive Plan is 11,000,000 shares. The 2011 Incentive Plan will be administered by either the full Board of Directors or a committee as designated by the Board of Directors. Our employees, officers and non-employee directors are eligible to receive awards under the 2011 Incentive Plan.

The employee stock purchase plan allows domestic employees the option to purchase WPX common stock at a 15 percent discount through after-tax payroll deductions. The purchase price of the stock is the lower of

 

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WPX Energy, Inc.

Notes to Consolidated Financial Statements—(continued)

 

either the first or last day of the biannual offering periods, followed with the 15 percent discount. The maximum number of shares that shall be made available under the purchase plan is 1,000,000, subject to adjustment for stock splits and similar events.

Employee stock-based awards

Stock options are valued at the date of award, which does not precede the approval date, and compensation cost is recognized on a straight-line basis, net of estimated forfeitures, over the requisite service period. The purchase price per share for stock options may not be less than the market price of the underlying stock on the date of grant.

Stock options generally become exercisable over a three-year period from the date of grant and generally expire ten years after the grant.

Restricted stock units are generally valued at fair value on the grant date and generally vest over three years. Restricted stock unit compensation cost, net of estimated forfeitures, is generally recognized over the vesting period on a straight-line basis.

Stock Options

The following summary reflects stock option activity and related information for the year ended December 31, 2011.

 

     WPX Plan      Direct employees participation in
Williams Plan
 

Stock Options

   Options      Weighted-
Average
Exercise
Price
     Aggregate
Intrinsic
Value
     Options     Weighted-
Average
Exercise
Price
     Aggregate
Intrinsic
Value
 
     (Millions)             (Millions)      (Millions)            (Millions)  

Outstanding at December 31, 2010

     —         $ —         $ —           1.6      $ 18.23       $ 13   
        

 

 

         

 

 

 

Granted

     —         $ —              .2      $ 29.73      

Exercised

     —         $ —              (.4   $ 13.52      

Expired

     —         $ —              (.1   $ 34.66      

Conversion of direct employee options

     2.0       $ 12.81            (1.3   $ 21.08      

Conversion of other options(1)

     2.2       $ 10.16            —        $ —        
  

 

 

    

 

 

       

 

 

   

 

 

    

Outstanding at December 31, 2011

     4.2       $ 11.41       $ 29         —        $ —        
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

    

Exercisable at December 31, 2011

     3.0       $ 10.92       $ 22         —          —        
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

    

 

(1) Includes approximately 962 thousand shares held by Williams employees at a weighted average price of $7.07 per share.

The total intrinsic value of options exercised during the years ended December 31, 2011, 2010, and 2009 was $7 million, $2 million, and $0.2 million, respectively.

 

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WPX Energy, Inc.

Notes to Consolidated Financial Statements—(continued)

 

The following summary provides additional information about stock options that are outstanding and exercisable at December 31, 2011.

 

     WPX Plan  
     Stock Options Outstanding      Stock Options Exercisable  

Range of Exercise Prices

   Options      Weighted-
Average
Exercise
Price
     Weighted-
Average
Remaining
Contractual
Life
     Options      Weighted-
Average
Exercise
Price
     Weighted-
Average
Remaining
Contractual
Life
 
     (Millions)             (Years)      (Millions)             (Years)  

$  1.26 to $6.02

     1.4       $ 5.19         4.6         1.2       $ 5.00         4.1   

$  6.49 to $11.75

     1.1       $ 11.21         5.7         0.7       $ 10.93         4.4   

$12.00 to $15.67

     0.7       $ 14.41         4.8         0.7       $ 14.41         4.8   

$16.46 to $20.97

     1.0       $ 18.17         7.8         0.4       $ 20.23         6.2   
  

 

 

          

 

 

       

Total

     4.2       $ 11.41         5.7         3.0       $ 10.92         4.6   
  

 

 

          

 

 

       

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

 

     WPX Plan     Williams Plan  
     2011     2011     2010     2009  

Weighted-average or grant date fair value of options granted

   $ —        $ 7.71      $ 7.02      $ 5.60   
  

 

 

   

 

 

   

 

 

   

 

 

 

Weighted-average conversion date fair value options granted

   $ 8.48         
  

 

 

       

Weighted-average assumptions:

        

Dividend yield

         3.6     2.6     1.6

Volatility

     45     34.6     39.0     60.8

Risk-free interest rate

     0.377     2.84     3.0     2.3

Expected life (years)

     2.8        6.5        6.5        6.5   

For the WPX Plan the weighted average fair value is a component of the intrinsic value calculation at spin-off and is not necessarily indicative of the fair value of future WPX grants. The expected volatility yield is based on the historical volatility of comparable peer group stocks. The risk free rate interest rate is based on the U.S. Treasury Constant Maturity rates as of the modification date. The expected life of the options is based over the remaining option term.

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

 

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WPX Energy, Inc.

Notes to Consolidated Financial Statements—(continued)

 

Nonvested Restricted Stock Units

The following summary reflects nonvested restricted stock unit activity and related information for the year ended December 31, 2011.

 

    WPX Plan     Direct employees
participation in
Williams Plan
 

Restricted Stock Units

  Shares     Weighted-
Average
Fair Value*
    Shares     Weighted-
Average
Fair Value*
 
    (Millions)           (Millions)        

Nonvested at December 31, 2010

    —        $ —          1.8      $ 16.93   

Granted

    —        $ —          .5      $ 27.74   

Forfeited

    —        $ —          (.1   $ 18.20   

Cancelled

    —        $ —          (.1   $ 35.47   

Vested

    $ —          (.3   $ 32.75   

Conversion of direct employee restricted units

    3.3      $ 9.74        (1.8   $ 17.59   

Conversion of indirect employee restricted units

    1.3      $ 9.54        —          —     
 

 

 

   

 

 

   

 

 

   

 

 

 

Nonvested at December 31, 2011

    4.6      $ 9.69        —        $ —     
 

 

 

   

 

 

   

 

 

   

 

 

 

 

* Performance-based shares are primarily valued using a valuation pricing model. However, certain of these shares were valued using the end-of-period market price until certification that the performance objectives were completed or a value of zero once it was determined that it was unlikely that performance objectives would be met. All other shares are valued at the grant-date market price, less dividends projected to be paid over the vesting period.

Other restricted stock unit information

 

     Williams Plan  
     2011      2010      2009  

Weighted-average grant date fair value of Williams restricted stock units granted during the year, per share

   $ 27.74       $ 20.00       $ 9.71   
  

 

 

    

 

 

    

 

 

 

Total fair value of restricted stock units vested during the year ($’s in millions)

   $ 10       $ 9       $ 8   
  

 

 

    

 

 

    

 

 

 

Performance-based shares granted represent 13 percent of nonvested restricted stock units outstanding at December 31, 2011. These grants may be earned at the end of a three-year period based on actual performance against a performance target. Expense associated with these performance-based grants is recognized in periods after performance targets are established. Based on the extent to which certain financial targets are achieved, vested shares may range from zero percent to 200 percent of the original grant amount.

Note 15. Stockholders’ Equity

Common Stock

Each share of our common stock entitles its holder to one vote in the election of each director. No share of our common stock affords any cumulative voting rights. Holders of our common stock will be entitled to dividends in such amounts and at such times as our Board of Directors in its discretion may declare out of funds legally available for the payment of dividends. No dividends were declared or paid as of December 31, 2011. No shares of common stock are subject to redemption or have preemptive rights to purchase additional shares of our common stock or other securities.

 

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WPX Energy, Inc.

Notes to Consolidated Financial Statements—(continued)

 

Preferred Stock

Our amended and restated certificate of incorporation authorizes our Board of Directors to establish one or more series of preferred stock. Unless required by law or by any stock exchange on which our common stock is listed, the authorized shares of preferred stock will be available for issuance without further action. Rights and privileges associated with shares of preferred stock are subject to authorization by our Board of Directors and may differ from those of any and all other series at any time outstanding.

Note 16. Fair Value Measurements

Fair value is the amount received from the sale of an asset or the amount paid to transfer a liability in an orderly transaction between market participants (an exit price) at the measurement date. Fair value is a market-based measurement considered from the perspective of a market participant. We use market data or assumptions that we believe market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation. These inputs can be readily observable, market corroborated, or unobservable. We apply both market and income approaches for recurring fair value measurements using the best available information while utilizing valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.

The fair value hierarchy prioritizes the inputs used to measure fair value, giving the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). We classify fair value balances based on the observability of those inputs. The three levels of the fair value hierarchy are as follows:

 

   

Level 1—Quoted prices for identical assets or liabilities in active markets that we have the ability to access. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 measurements primarily consist of financial instruments that are exchange traded.

 

   

Level 2—Inputs are other than quoted prices in active markets included in Level 1, that are either directly or indirectly observable. These inputs are either directly observable in the marketplace or indirectly observable through corroboration with market data for substantially the full contractual term of the asset or liability being measured. Our Level 2 measurements primarily consist of over-the-counter (OTC) instruments such as forwards, swaps, and options. These options, which hedge future sales of production, are structured as costless collars and are financially settled. They are valued using an industry standard Black-Scholes option pricing model.

 

   

Level 3—Inputs that are not observable for which there is little, if any, market activity for the asset or liability being measured. These inputs reflect management’s best estimate of the assumptions market participants would use in determining fair value. Our Level 3 measurements consist of instruments valued using industry standard pricing models and other valuation methods that utilize unobservable pricing inputs that are significant to the overall fair value.

In valuing certain contracts, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. For disclosure purposes, assets and liabilities are classified in their entirety in the fair value hierarchy level based on the lowest level of input that is significant to the overall fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels.

 

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WPX Energy, Inc.

Notes to Consolidated Financial Statements—(continued)

 

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.

 

     December 31, 2011      December 31, 2010  
     Level 1      Level 2      Level 3      Total      Level 1      Level 2      Level 3      Total  
            (Millions)                    (Millions)         

Energy derivative assets

   $ 55       $ 454       $ 7       $ 516       $ 97       $ 474       $ 2       $ 573   

Energy derivative liabilities

   $ 41       $ 112       $ 6       $ 159       $ 78       $ 210       $ 1       $ 289   

Energy derivatives include commodity based exchange-traded contracts and OTC contracts. Exchange-traded contracts include futures, swaps, and options. OTC contracts include forwards, swaps and options.

Many contracts have bid and ask prices that can be observed in the market. Our policy is to use a mid-market pricing (the mid-point price between bid and ask prices) convention to value individual positions and then adjust on a portfolio level to a point within the bid and ask range that represents our best estimate of fair value. For offsetting positions by location, the mid-market price is used to measure both the long and short positions.

The determination of fair value for our assets and liabilities also incorporates the time value of money and various credit risk factors which can include the credit standing of the counterparties involved, master netting arrangements, the impact of credit enhancements (such as cash collateral posted and letters of credit) and our nonperformance risk on our liabilities. The determination of the fair value of our liabilities does not consider noncash collateral credit enhancements.

Exchange-traded contracts include New York Mercantile Exchange and Intercontinental Exchange contracts and are valued based on quoted prices in these active markets and are classified within Level 1.

Forward, swap, and option contracts included in Level 2 are valued using an income approach including present value techniques and option pricing models. Option contracts, which hedge future sales of our production, are structured as costless collars and are financially settled. They are valued using an industry standard Black-Scholes option pricing model. Significant inputs into our Level 2 valuations include commodity prices, implied volatility by location, and interest rates, as well as considering executed transactions or broker quotes corroborated by other market data. These broker quotes are based on observable market prices at which transactions could currently be executed. In certain instances where these inputs are not observable for all periods, relationships of observable market data and historical observations are used as a means to estimate fair value. Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2.

Our energy derivatives portfolio is largely comprised of exchange-traded products or like products and the tenure of our derivatives portfolio is relatively short with more than 99 percent of the 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 December 31, 2011, consist primarily of natural gas index transactions that are used to manage our physical requirements.

 

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Notes to Consolidated Financial Statements—(continued)

 

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 years ended December 31, 2011 or 2010. During the period ended March 31, 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. In 2009, certain options which hedge future sales of production were transferred from Level 3 to Level 2. These options were originally included in Level 3 because a significant input to the model, implied volatility by location, was considered unobservable. Due to increased transparency, this input was considered observable, and we transferred these options to Level 2.

The following 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

 

     Years ended December 31,  
     2011
Net Energy
Derivatives
    2010
Net Energy
Derivatives
    2009
Net Energy
Derivatives
 
     (Millions)  

Beginning balance

   $ 1      $ 1      $ 506   

Realized and unrealized gains (losses):

      

Included in income (loss) from continuing operations

     15        1        476   

Included in other comprehensive income (loss)

     —          —          (329

Purchases, issuances, and settlements

     (12     (1     (479

Transfers out of Level 3

     (3     —          (173
  

 

 

   

 

 

   

 

 

 

Ending balance

   $ 1      $ 1      $ 1   
  

 

 

   

 

 

   

 

 

 

Unrealized gains included in income (loss) from continuing operations relating to instruments still held at December 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 Statement of Operations.

For the year ending December 31, 2011, the entire $12 million reduction to level 3 fair value measurements are settlements.

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 years ended December 31,
 
         2011             2010             2009      
     (Millions)  

Impairments:

      

Goodwill (see Note 7)

   $ —        $ 1,003 (b)    $ —     

Producing properties and costs of acquired unproved reserves (see Note 7)

     547 (a)      678 (c)      15 (d) 

Cost-based investment (see Note 5)

     —          —          11 (e) 
  

 

 

   

 

 

   

 

 

 
   $ 547      $ 1,681      $ 26   
  

 

 

   

 

 

   

 

 

 

 

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WPX Energy, Inc.

Notes to Consolidated Financial Statements—(continued)

 

 

(a) Due to significant declines in forward natural gas prices, we assessed the carrying value of our natural gas-producing properties and costs of acquired unproved reserves for impairments. Our assessment utilized estimates of future cash flows including potential disposition proceeds. Significant judgments and assumptions in these assessments include estimates of natural gas reserve quantities, estimates of future natural gas prices using a forward NYMEX curve adjusted for locational basis differentials, drilling plans, expected capital costs, and an applicable discount rate commensurate with risk of the underlying cash flow estimates. The annual assessment identified certain properties with a carrying value in excess of their calculated fair values. As a result, we recorded the following impairment charges. Fair value measured for these properties at December 31, 2011, was estimated to be approximately $798 million.

 

   

$276 million of impairment charge related to natural gas-producing properties in Powder River. Significant assumptions in valuing these properties included proved reserves quantities of more than 352 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $3.81 per Mcfe for natural gas (adjusted for locational differences), natural gas liquids and oil, and an after-tax discount rate of 11 percent.

 

   

$180 million of impairment charge related to natural gas-producing properties in the Barnett Shale. Significant assumptions in valuing these properties included proved reserves quantities of more than 235 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $4.24 per Mcfe for natural gas (adjusted for locational differences and contractual arrangements), natural gas liquids and oil, and an after-tax discount rate of 11 percent. Additionally, the weighted average price is net of deductions for gathering and processing.

 

   

$91 million of the impairment charge related to acquired unproved reserves in Powder River. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, expectation for market participant drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 13 percent and 15 percent for probable and possible reserves, respectively.

 

(b)

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

 

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Notes to Consolidated Financial Statements—(continued)

 

  implied fair value of the goodwill was zero. As a result of our analysis, we recognized a full $1 billion impairment charge related to this goodwill.
(c) As of September 30, 2010, we had a trigger event as a result of recent significant declines in forward natural gas prices and therefore, we assessed the carrying value of our natural gas-producing properties and costs of acquired unproved reserves for impairments. Our assessment utilized estimates of future cash flows. Significant judgments and assumptions in these assessments are similar to those used in the goodwill evaluation and include estimates of natural gas reserve quantities, estimates of future natural gas prices using a forward NYMEX curve adjusted for locational basis differentials, drilling plans, expected capital costs, and an applicable discount rate commensurate with risk of the underlying cash flow estimates. The assessment performed at September 30, 2010, identified certain properties with a carrying value in excess of their calculated fair values. As a result, we recorded a $678 million impairment charge in the third-quarter 2010 as further described below. Fair value measured for these properties at September 30, 2010, was estimated to be approximately $320 million.

 

   

$503 million of impairment charge related to natural gas-producing properties in the Barnett Shale. Significant assumptions in valuing these properties included proved reserves quantities of more than 227 billion cubic feet of gas equivalent, forward weighted average prices averaging approximately $4.67 per Mcfe for natural gas (adjusted for locational differences), natural gas liquids and oil, and an after-tax discount rate of 11 percent. Additionally, the weighted average price is net of deductions for gathering and processing.

 

   

$175 million of the impairment charge related to acquired unproved reserves in the Piceance Highlands acquired in 2008. Significant assumptions in valuing these unproved reserves included evaluation of probable and possible reserves quantities, drilling plans, forward natural gas (adjusted for locational differences) and natural gas liquids prices, and an after-tax discount rate of 13 percent.

 

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

Note 17. 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.

Energy derivatives: Energy derivatives include futures, forwards, swaps and options. These are carried at fair value in the Consolidated Balance Sheet. See Note 16 for a discussion of valuation of energy derivatives.

 

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WPX Energy, Inc.

Notes to Consolidated Financial Statements—(continued)

 

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

 

     December 31,  
     2011     2010  

Asset (Liability)

   Carrying
Amount
    Fair
Value
    Carrying
Amount
    Fair
Value
 
     (Millions)  

Cash and cash equivalents

   $ 526      $ 526      $ 37      $ 37   

Restricted cash (current and noncurrent)

     29        29        24        24   

Other

     (7     (7     (25     (25

Long-term debt (1)

     1,502        1,523        —          —     

Net energy derivatives:

        

Energy commodity cash flow hedges

     347        347        266        266   

Other energy derivatives

     10        10        18        18   

 

(1) Excludes capital leases.

For the year ended December 31, 2010 our note payable to Williams had a carrying amount of $2,261, which approximated fair value.

Energy Commodity Derivatives

Risk Management Activities

We are exposed to market risk from changes in energy commodity prices within our operations. We utilize derivatives to manage exposure to the variability in expected future cash flows from forecasted sales of natural gas and oil attributable to commodity price risk. Certain of these derivatives utilized for risk management purposes have been designated as cash flow hedges, while other derivatives have not been designated as cash flow hedges or do not qualify for hedge accounting despite hedging our future cash flows on an economic basis.

We produce, buy and sell natural gas and oil at different locations throughout the United States. To reduce exposure to a decrease in revenues from fluctuations in natural gas market prices, we enter into natural gas and oil futures contracts, swap agreements, and financial option contracts to mitigate the price risk on forecasted sales of natural gas and oil. We have also entered into basis swap agreements to reduce the locational price risk associated with our producing basins. Those agreements and contracts designated as cash flow hedges are expected to be highly effective in offsetting cash flows attributable to the hedged risk during the term of the hedge. However, ineffectiveness may be recognized primarily as a result of locational differences between the hedging derivative and the hedged item. Our financial option contracts are either purchased options or a combination of options that comprise a net purchased option or a zero-cost collar. 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.

 

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WPX Energy, Inc.

Notes to Consolidated Financial Statements—(continued)

 

The following table sets forth the derivative volumes designated as hedges of production volumes as of December 31, 2011:

 

Commodity

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

Natural Gas

     2012       Location Swaps    Rockies      49,410       $ 4.76   

Natural Gas

     2012       Location Swaps    San Juan      40,260       $ 4.94   

Natural Gas

     2012       Location Swaps    MidCon      32,025       $ 4.76   

Natural Gas

     2012       Location Swaps    SoCal      11,895       $ 5.14   

Natural Gas

     2012       Location Swaps    Northeast      52,460       $ 5.58   

Natural Gas

     2013       Location Swaps    Northeast      1,800       $ 6.48   

 

Commodity

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

Crude Oil

     2012       Business Day Avg Swaps    Midcon      2,624       $ 97.32   

We also enter into forward contracts to buy and sell natural gas to maximize the economic value of transportation agreements and storage capacity agreements. To reduce exposure to a decrease in margins from fluctuations in natural gas market prices, we may enter into futures contracts, swap agreements, and financial option contracts to mitigate the price risk associated with these contracts. 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 and affiliated entities. These legacy natural gas contracts include substantially offsetting positions and have had an insignificant net impact on earnings.

The following table depicts the notional amounts of the net long (short) positions which we did not designate as hedges of our production in our commodity derivatives portfolio as of December 31, 2011. Natural gas is presented in millions of British Thermal Units (MMBtu) and crude oil is presented in barrels. The volumes for options represent zero-cost collars and present one side of the short position. These 2012 options were executed to reduce exposure to a decrease in revenues from fluctuations in crude oil market prices. The floor and ceiling prices associated with these collars are $85 per barrel and $106.30 per barrel, respectively, and realize by December 2012. Despite being economic hedges, we did not designate these contracts in a hedge relationship for accounting purposes. All of the Central hub risk realizes by March 31, 2013 and 91% of the basis risk realizes by 2013. The net index position includes contracts for the future sale of physical natural gas related to our production. Offsetting these sales are contracts for the future production of physical natural gas related to WPZ’s natural gas shrink requirements. These contracts result in minimal commodity price risk exposure and have a value of less than $1 million at December 31, 2011.

 

Derivative Notional Volumes

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

Not Designated as Hedging Instruments

           

Risk Management

   MMBtu      (14,396,621     (15,570,621     (35,487,182  

Other

   MMBtu      (7,500     (7,102,500    

Risk Management (d)

   Barrels      (730,000         (732,000

 

(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;

 

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(c) includes physical derivative transactions at an unknown future price, including purchases of 81,679,958 MMBtu primarily on behalf of WPZ and sales of 117,167,110 MMBtu.
(d) includes financial derivatives entered into to hedge our crude oil exposure that were not designated in a hedging relationship at December 31, 2011.
(e) includes all fixed price options or combination of options that set a floor and/or ceiling for the transaction price of a commodity.

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.

 

     December 31,  
     2011      2010  
     Assets      Liabilities      Assets      Liabilities  
     (Millions)  

Designated as hedging instruments

   $ 360       $ 13       $ 288       $ 22   

Not designated as hedging instruments:

           

Legacy natural gas contracts from former power business

     93         92         186         187   

All other

     63         54         99         80   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total derivatives not designated as hedging instruments

     156         146         285         267   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total derivatives

   $ 516       $ 159       $ 573       $ 289   
  

 

 

    

 

 

    

 

 

    

 

 

 

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

 

     Years Ended
December 31,
      
         2011              2010          Classification
     (Millions)

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

   $ 413       $ 505       AOCI

Net gain reclassified from accumulated other comprehensive income (loss) into income (effective portion) (1)

   $ 331       $ 354       Revenues

Gain recognized in income (ineffective portion)

   $ —         $ 9       Revenues

 

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

There were no gains or losses recognized in income as a result of excluding amounts from the assessment of hedge effectiveness.

 

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WPX Energy, Inc.

Notes to Consolidated Financial Statements—(continued)

 

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

 

     Years Ended
December 31,
 
         2011              2010      
     (Millions)  

Gas management revenues

   $ 30       $ 47   

Gas management expenses

     —           28   
  

 

 

    

 

 

 

Net gain

   $ 30       $ 19   
  

 

 

    

 

 

 

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, in certain circumstances, to post additional collateral in support of our net derivative liability positions. These credit-risk-related provisions require us to post collateral in the form of cash or letters of credit when our net liability positions exceed an established credit threshold. The credit thresholds are typically based on our senior unsecured debt ratings from Standard and Poor’s and/or Moody’s Investors Service. Under these contracts, a credit ratings decline would lower our credit thresholds, thus requiring us to post additional collateral. We also have contracts that contain adequate assurance provisions giving the counterparty the right to request collateral in an amount that corresponds to the outstanding net liability. Additionally, we have an unsecured agreements with certain banks related to economic hedging activities. We are not required to provide collateral support for net derivative liability positions under these agreements.

As of December 31, 2011, we had collateral totaling $18 million posted to derivative counterparties to support the aggregate fair value of our net $37 million derivative liability position (reflecting master netting arrangements in place with certain counterparties), which includes a reduction of less than $1 million to our liability balance for our own nonperformance risk. At December 31, 2010, we had collateral totaling $8 million posted to derivative counterparties, all of which was in the form of letters of credit, to support the aggregate fair value of our net derivative liability position (reflecting master netting arrangements in place with certain counterparties) of $36 million, which included a reduction of less than $1 million to our liability balance for 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 $19 million and $29 million at December 31, 2011 and December 31, 2010, respectively.

Cash flow hedges

Changes in the fair value of our cash flow hedges, to the extent effective, are deferred in AOCI and reclassified into earnings in the same period or periods in which the hedged forecasted purchases or sales affect earnings, or when it is probable that the hedged forecasted transaction will not occur by the end of the originally specified time period. As of December 31, 2011, we have hedged portions of future cash flows associated with anticipated energy commodity purchases and sales for up to two years. Based on recorded values at December 31, 2011, $219 million of net gains (net of income tax provision of $127 million) will be reclassified into earnings within the next year. These recorded values are based on market prices of the commodities as of December 31, 2011. Due to the volatile nature of commodity prices and changes in the creditworthiness of

 

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counterparties, actual gains or losses realized within the next year will likely differ from these values. These gains or losses are expected to substantially offset net losses or gains that will be realized in earnings from previous unfavorable or favorable market movements associated with underlying hedged transactions.

Concentration of Credit Risk

Cash equivalents

Our cash equivalents are primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government.

Accounts receivable

The following table summarizes concentration of receivables (other than as relates to Williams), net of allowances, by product or service as of December 31:

 

     2011      2010  
     (Millions)  

Receivables by product or service:

     

Sale of natural gas and related products and services

   $ 286       $ 272   

Joint interest owners

     150         83   

Other

     11         7   
  

 

 

    

 

 

 

Total

   $ 447       $ 362   
  

 

 

    

 

 

 

Natural gas customers include pipelines, distribution companies, producers, gas marketers and industrial users primarily located in the eastern and northwestern United States, Rocky Mountains and Gulf Coast. As a general policy, collateral is not required for receivables, but customers’ financial condition and credit worthiness are evaluated regularly.

Derivative assets and liabilities

We have a risk of loss from counterparties not performing pursuant to the terms of their contractual obligations. Counterparty performance can be influenced by changes in the economy and regulatory issues, 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 2011, 2010 and 2009, we did not incur any significant losses due to counterparty bankruptcy filings.

 

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WPX Energy, Inc.

Notes to Consolidated Financial Statements—(continued)

 

The gross credit exposure from our derivative contracts as of December 31, 2011, is summarized as follows.

 

Counterparty Type

   Investment
Grade*
     Total  
     (Millions)  

Gas and electric utilities and integrated oil and gas companies

   $ 2       $ 2   

Energy marketers and traders

     —           50   

Financial institutions

     410         464   
  

 

 

    

 

 

 
   $ 412         516   
  

 

 

    

 

 

 

Credit reserves

        —     
     

 

 

 

Gross credit exposure from derivatives

      $ 516   
     

 

 

 

We assess our credit exposure on a net basis to reflect master netting agreements in place with certain counterparties. We offset our credit exposure to each counterparty with amounts we owe the counterparty under derivative contracts. The net credit exposure from our derivatives as of December 31, 2011, excluding collateral support discussed below, is summarized as follows.

 

Counterparty Type

   Investment
Grade*
     Total  
     (Millions)  

Gas and electric utilities

   $ 2       $ 2   

Energy marketers and traders

     —           4   

Financial institutions

     374         388   
  

 

 

    

 

 

 
   $ 376         394   
  

 

 

    

 

 

 

Credit reserves

        —     
     

 

 

 

Net credit exposure from derivatives

      $ 394   
     

 

 

 

 

* We determine investment grade primarily using publicly available credit ratings. We include counterparties with a minimum Standard & Poor’s rating of BBB- or Moody’s Investors Service rating of Baa3 in investment grade.

Our seven largest net counterparty positions represent approximately 97 percent of our net credit exposure from derivatives and are all with investment grade counterparties. Included within this group are counterparty positions hedging our production of energy commodities, representing 88 percent of our net credit exposure from derivatives. Under our new marginless hedging agreements with key banks, we nor the participating financial institutions are required to provide collateral support related to hedging activities.

At December 31, 2011, we hold collateral support, which may include cash or letters of credit, of $2 million related to our other derivative positions.

 

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WPX Energy, Inc.

Notes to Consolidated Financial Statements—(continued)

 

Revenues

During 2011 and 2010, BP Energy Company, a domestic segment customer, accounted for 11% and 13% of our consolidated revenues, respectively. During 2009, there were no customers for which our sales exceeded 10 percent of our consolidated revenues. Management believes that the loss of any individual purchaser would not have a long-term material adverse impact on the financial position or results of operations of the Company.

Note 18. 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). The accounting policies of the segments are the same as those described in Note 1. There are no intersegment sales between Domestic and International. Costs historically allocated from Williams were not allocated by us to our International segment.

 

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WPX Energy, Inc.

Notes to Consolidated Financial Statements—(continued)

 

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. Long-lived assets are comprised of gross property, plant and equipment and long-term investments.

 

For the year ended December 31, 2011    Domestic     International      Total  
           (Millions)         

Total revenues

   $ 3,878      $ 110       $ 3,988   
  

 

 

   

 

 

    

 

 

 

Costs and expenses:

       

Lease and facility operating

   $ 268      $ 27       $ 295   

Gathering, processing and transportation

     499        —           499   

Taxes other than income

     119        21         140   

Gas management, including charges for unutilized pipeline capacity

     1,473        —           1,473   

Exploration

     131        3         134   

Depreciation, depletion and amortization

     927        22         949   

Impairment of producing properties and costs of acquired unproved reserves

     547        —           547   

General and administrative

     273        12         285   

Other—net

     (2     3         1   
  

 

 

   

 

 

    

 

 

 

Total costs and expenses

   $ 4,235      $ 88       $ 4,323   
  

 

 

   

 

 

    

 

 

 

Operating income (loss)

   $ (357   $ 22       $ (335

Interest expense, including affiliate

     (117     —           (117

Interest capitalized

     9        —           9   

Investment income and other

     6        20         26   
  

 

 

   

 

 

    

 

 

 

Income (loss) from continuing operation before income taxes

   $ (459   $ 42       $ (417
  

 

 

   

 

 

    

 

 

 

Other financial information:

       

Net capital expenditures

   $ 1,531      $ 41       $ 1,572   

Total assets

   $ 10,144      $ 288       $ 10,432   

Long-lived assets

   $ 12,284      $ 354       $ 12,638   

 

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WPX Energy, Inc.

Notes to Consolidated Financial Statements—(continued)

 

For the year ended December 31, 2010    Domestic     International      Total  
           (Millions)         

Total revenues

   $ 3,945      $ 89       $ 4,034   
  

 

 

   

 

 

    

 

 

 

Costs and expenses:

       

Lease and facility operating

   $ 267      $ 19       $ 286   

Gathering, processing and transportation

     326        —           326   

Taxes other than income

     109        16         125   

Gas management, including charges for unutilized pipeline capacity

     1,771        —           1,771   

Exploration

     67        6         73   

Depreciation, depletion and amortization

     858        17         875   

Impairment of producing properties and costs of acquired unproved reserves

     678        —           678   

Goodwill impairment

     1,003        —           1,003   

General and administrative

     244        9         253   

Other—net

     (19     —           (19
  

 

 

   

 

 

    

 

 

 

Total costs and expenses

   $ 5,304      $ 67       $ 5,371   
  

 

 

   

 

 

    

 

 

 

Operating income (loss)

   $ (1,359   $ 22       $ (1,337

Interest expense, including affiliate

     (124     —           (124

Interest capitalized

     16        —           16   

Investment income and other

     4        17         21   
  

 

 

   

 

 

    

 

 

 

Income (loss) from continuing operation before income taxes

   $ (1,463   $ 39       $ (1,424
  

 

 

   

 

 

    

 

 

 

Other financial information:

       

Net capital expenditures

   $ 1,821      $ 35       $ 1,856   

Total assets

   $ 9,590      $ 256       $ 9,846   

Long—lived assets

   $ 12,363      $ 306       $ 12,669   

 

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WPX Energy, Inc.

Notes to Consolidated Financial Statements—(continued)

 

For the year ended December 31, 2009    Domestic     International      Total  
           (Millions)         

Total revenues

   $ 3,603      $ 78       $ 3,681   
  

 

 

   

 

 

    

 

 

 

Costs and expenses:

       

Lease and facility operating

   $ 247      $ 16       $ 263   

Gathering, processing and transportation

     273        —           273   

Taxes other than income

     80        13         93   

Gas management, including charges for unutilized pipeline capacity

     1,495        —           1,495   

Exploration

     53        1         54   

Depreciation, depletion and amortization

     870        17         887   

Impairment of producing properties and costs of acquired unproved reserves

     15        —           15   

General and administrative

     242        9         251   

Other—net

     32        1         33   
  

 

 

   

 

 

    

 

 

 

Total costs and expenses

   $ 3,307      $ 57       $ 3,364   
  

 

 

   

 

 

    

 

 

 

Operating income

   $ 296      $ 21       $ 317   

Interest expense, including affiliate

     (100     —           (100

Interest capitalized

     18        —           18   

Investment income and other

     5        3         8   
  

 

 

   

 

 

    

 

 

 

Income from continuing operation before income taxes

   $ 219      $ 24       $ 243   
  

 

 

   

 

 

    

 

 

 

Other financial information:

       

Net capital expenditures

   $ 1,409      $ 25       $ 1,434   

Total assets

   $ 10,323      $ 230       $ 10,553   

Long—lived assets

   $ 11,014      $ 270       $ 11,284   

Note 19. Information Subsequent to Date of Independent Registered Public Accounting Firm Report

On April 2, 2012, we announced that we had entered into an agreement to sell certain assets for $306 million in the Barnett Shale located in north central Texas, as well as our interests in the Arkoma Basin in southeastern Oklahoma. These assets include interests in undeveloped acreage, producing wells, and pipelines. The properties represent less than five percent of our year-end 2011 proved domestic reserves and approximately five percent of total production. The transaction is subject to certain closing adjustments that will impact the total proceeds to be received.

 

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WPX Energy, Inc.

QUARTERLY FINANCIAL DATA

(Unaudited)

Summarized quarterly financial data are as follows:

 

     First
Quarter
    Second
Quarter
     Third
Quarter
    Fourth
Quarter
 
     (Millions, except per-share amounts)  

2011

  

Revenues

   $ 984     $ 990      $ 1,022     $ 992   

Operating costs and expenses

     862       841        928       859   

Income (loss) from continuing operations

     7        28        19       (326

Net income (loss)

     (1     28        16       (335

Amounts attributable to WPX Energy:

         

Net income (loss)

     (3     25        14       (338

Basic and diluted earnings (loss) per common share:

         

Income (loss) from continuing operations

     0.02        0.13        0.09       (1.67

2010

         

Revenues

   $ 1,164     $ 904      $ 1,006     $ 960  

Operating costs and expenses

     960       775        882       839  

Income (loss) from continuing operations

     83       32        (1,410     20   

Net income (loss)

     83       31        (1,411     14   

Amounts attributable to WPX Energy:

         

Net income (loss)

     81       29        (1,413     12   

Basic and diluted earnings (loss) per common share:

         

Income (loss) from continuing operations

     0.41       0.15        (7.17     0.09   

The sum of earnings per share for the four quarters may not equal the total earnings per share for the year due to rounding.

Net loss for fourth-quarter 2011 includes the following pre-tax items:

 

   

$547 million of impairments of producing properties and costs of acquired unproved reserves (see Note 7) and $13 million of impairments related to the Arkoma discontinued operations (see Note 3).

Net income for third-quarter 2011 includes the following pre-tax items:

 

   

$50 million write-off of leasehold costs associated with approximately 65 percent of our Columbia County, Pennsylvania acreage;

 

   

$11 million of dry hole costs associated with an exploratory Marcellus Shale well in Columbia County;

Net loss for third-quarter 2010 includes the following pre-tax items:

 

   

$1,003 million impairment of goodwill (see Note 7);

 

   

$678 million of impairments of certain producing properties and acquired unproved reserves (see Note 7);

 

   

$15 million of exploratory dry hole costs.

 

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WPX Energy, Inc.

Supplemental Oil and Gas Disclosures

(Unaudited)

We have significant oil and gas producing activities primarily in the Rocky Mountain, Northeast and Mid-continent areas of the United States. Additionally, we have international oil and gas producing activities, primarily in Argentina. The following information excludes our gas management activities.

With the exception of Capitalized Costs in 2011 and the Results of Operations for all years presented, the following information includes our Arkoma Basin operations which have been reported as discontinued operations in our consolidated financial statements. These operations represent less than one percent of our total domestic and international proved reserves for all periods presented.

Capitalized Costs

 

     As of December 31, 2010  
     Domestic     International     Consolidated
Total
    Entity’s share  of
international
equity method
investee
 

Proved Properties

   $ 9,854      $ 213      $ 10,067      $ 220   

Unproved properties

     2,094        3        2,097        —     
  

 

 

   

 

 

   

 

 

   

 

 

 
     11,948        216        12,164        220   

Accumulated depreciation, depletion and amortization and valuation provisions

     (3,867     (109     (3,976     (129
  

 

 

   

 

 

   

 

 

   

 

 

 

Net capitalized costs

   $ 8,081      $ 107      $ 8,188      $ 91   
  

 

 

   

 

 

   

 

 

   

 

 

 
     As of December 31, 2011  
     Domestic     International     Consolidated
Total
    Entity’s share of
international
equity method
investee
 

Proved Properties

   $ 10,116      $ 259      $ 10,375      $ 254   

Unproved properties

     1,686        3        1,689        —     
  

 

 

   

 

 

   

 

 

   

 

 

 
     11,802        262        12,064        254   

Accumulated depreciation, depletion and amortization and valuation provisions

     (3,696     (133     (3,829     (154
  

 

 

   

 

 

   

 

 

   

 

 

 

Net capitalized costs

   $ 8,106      $ 129      $ 8,235      $ 100   
  

 

 

   

 

 

   

 

 

   

 

 

 

 

   

Excluded from capitalized costs are equipment and facilities in support of oil and gas production of $349 million and $312 million, net, for 2011 and 2010, respectively.

 

   

Proved properties include capitalized costs for oil and gas leaseholds holding proved reserves, development wells including uncompleted development well costs and successful exploratory wells.

 

   

Unproved properties consist primarily of unproved leasehold costs and costs for acquired unproven reserves.

 

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WPX Energy, Inc.

Supplemental Oil and Gas Disclosures—(continued)

(Unaudited)

 

Cost Incurred

 

     Domestic      International      Entity’s share  of
international
equity method
investee
 
     (Millions)  

For the Year Ended December 31, 2009

        

Acquisition

   $ 305       $ 3 &nbs