##### Table of Contents





As filed with the Securities
    and Exchange Commission on July 18,
    2011
 
 Registration No. 333-173808
    UNITED STATES SECURITIES AND
    EXCHANGE COMMISSION
 Washington, D.C.
    20549
    
  Amendment No. 2
    to
 
 Form S-1
 REGISTRATION
    STATEMENT
 UNDER
 THE SECURITIES ACT OF
    1933
     WPX Energy, Inc.
 (Exact name of registrant as
    specified in its charter)
      Delaware

1311

45-1836028(State or other jurisdiction
    of
    Incorporation or organization)

(Primary Standard Industrial
    Classification Code Number)

(I.R.S. Employer
    Identification Number)  One Williams Center
 Tulsa, Oklahoma
    74172-0172
 (918) 573-2000
 (Address, including zip code,
    and telephone number, including area code, of registrants
    principal executive offices)
  James J.
    Bender, Esq.
 General Counsel and Corporate
    Secretary
 One Williams Center,
    Suite 4900
 Tulsa, Oklahoma
    74172-0172
 (918) 573-2000
 (Name, address, including zip
    code, and telephone number, including area code, of agent for
    service)
      Copies
    to:
  Richard M. Russo
    Robyn E. Zolman
    Gibson, Dunn & Crutcher LLP
    1801 California Street, Suite 4200
    Denver, CO 80202

J. Michael Chambers
    Ryan J. Maierson
    Latham & Watkins LLP
    717 Texas Avenue, 16th floor
    Houston, TX 77002   Approximate date of commencement of proposed sale to the
    public:
  o
  o
  o
  o
    Large accelerated
    filer o

Accelerated
    filer o

Non-accelerated
    filer þ(Do not check if a smaller
    reporting company)

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




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##### Table of Contents



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


Subject
    to Completion, dated July 18, 2011
 
  PROSPECTUS
   Shares
 WPX
    Energy, Inc.
 Class A
    Common Stock
   This is the initial
    public offering of Class A common stock of WPX Energy, Inc.
    We are
    offering           shares
    of our Class A common stock. No public market currently
    exists for our Class A common stock.
  Following this
    offering, we will have two classes of authorized common stock,
    Class A common stock and Class B common stock. All of
    our shares of Class B common stock will be held by The
    Williams Companies, Inc. (Williams). The rights of
    holders of shares of Class A common stock and Class B
    common stock will be identical, except with respect to voting
    and conversion rights. Each share of Class A common stock
    will be entitled to one vote per share. Each share of
    Class B common stock will be entitled to ten votes per
    share and will be convertible at any time at the election of
    Williams into one share of Class A common stock. Our
    Class B common stock will automatically convert into shares
    of Class A common stock in certain circumstances.
 
  We have applied to
    list our Class A common stock on the New York Stock
    Exchange under the symbol WPX.
 
  We anticipate that
    the initial public offering price will be between
    $      and
    $      per share.
  Investing in
    our Class A common stock involves risks. See Risk
    Factors beginning on page 17 of this
    prospectus .
  Per
    Share


TotalPrice to the public

$



$Underwriting discounts and commissions

$



$Proceeds to us (before expenses)

$



$  
  We have granted the
    underwriters a
    30-day
    option to purchase up to an
    additional           shares
    of Class A common stock on the same terms and conditions
    set forth above if the underwriters sell more
    than      shares of Class A
    common stock in this offering. Any shares of Class A common
    stock issued pursuant to this option will not increase the total
    number of shares of common stock outstanding after this
    offering, but rather the number of shares of Class B common
    stock owned by Williams will be reduced share for share by the
    number of shares of Class A common stock issued pursuant to
    such option, thus reducing Williams ownership interest in
    us. We will distribute the net proceeds from the sale of shares
    of Class A common stock pursuant to this option to Williams
    as part of our restructuring transactions described herein.
    Williams is deemed to be an underwriter with respect to any
    shares of Class A common stock issued pursuant to this
    option.
 
  Neither the
    Securities and Exchange Commission nor any state securities
    commission has approved or disapproved of these securities or
    passed on the adequacy or accuracy of this prospectus. Any
    representation to the contrary is a criminal offense.
  Barclays Capital, on
    behalf of the underwriters, expects to deliver the shares on or
    about          ,
    2011.
  
 Joint
    Book-Running Managers
 
 
  Barclays
    Capital
    Citi
    J.P. Morgan
    BofA Merrill Lynch 
   
  Senior
    Co-Managers
 
 
  Deutsche Bank
    Securities
    Goldman, Sachs
    & Co.
    Morgan
    Stanley
    Wells Fargo
    Securities 
   
  Co-Managers
 
 
  Credit
    Suisse
    RBC Capital Markets
    Scotia Capital 
 
 UBS Investment Bank
    Howard Weil Incorporated 
  Prospectus
    dated          ,
    2011




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##### Table of Contents








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##### 



TABLE OF
    CONTENTS
   
 
 PageCERTAIN DEFINITIONS


iiiPROSPECTUS SUMMARY


1RISK FACTORS


17FORWARD-LOOKING STATEMENTS


43USE OF PROCEEDS


45DIVIDEND POLICY


46CAPITALIZATION


47DILUTION


48SELECTED HISTORICAL COMBINED FINANCIAL
    DATA


49MANAGEMENTS DISCUSSION AND ANALYSIS OF
    FINANCIAL CONDITION AND RESULTS OF OPERATIONS


51BUSINESS


74MANAGEMENT


104EXECUTIVE COMPENSATION


107PRINCIPAL STOCKHOLDER


139ARRANGEMENTS BETWEEN WILLIAMS AND OUR
    COMPANY


140OTHER RELATED PARTY TRANSACTIONS


147DESCRIPTION OF OUR CONCURRENT FINANCING
    TRANSACTIONS


150DESCRIPTION OF CAPITAL STOCK


151SHARES ELIGIBLE FOR FUTURE SALE


158CERTAIN U.S. FEDERAL INCOME TAX
    CONSIDERATIONS


160UNDERWRITING


164LEGAL MATTERS


172EXPERTS


172WHERE YOU CAN FIND MORE INFORMATION


172INDEX TO FINANCIAL STATEMENTS


F-1EX-2.1EX-3.1EX-3.2EX-5.1EX-10.1EX-10.2EX-10.3EX-10.4EX-10.5EX-10.7EX-10.8EX-10.9EX-23.2EX-23.3EX-23.4EX-23.5  
       You should rely only on the information contained in this
    document or any free writing prospectus prepared by or on behalf
    of us. We have not authorized anyone to provide you with
    information that is different. This document may only be used
    where it is legal to sell these securities. The information in
    this document may only be accurate on the date of this
    document.
      Dealer
    Prospectus Delivery Obligation
  Until          ,
    2011 (the 25th day after the date of this prospectus), all
    dealers that effect transactions in our common shares, whether
    or not participating in this offering, may be required to
    deliver a prospectus. This is in addition to the dealers
    obligation to deliver a prospectus when acting as an underwriter
    and with respect to unsold allotments or subscriptions.
  Industry
    and Market Data
  We obtained the market and competitive position data used
    throughout this prospectus from our own research, surveys or
    studies conducted by third parties and industry or general
    publications. Industry publications and surveys generally state
    that they have obtained information from sources believed to be
    reliable, but do not guarantee the accuracy and completeness of
    such information. While we believe that each of these studies
    and publications is reliable and have no reason to believe they
    are inaccurate or incomplete, neither we nor the underwriters
    have independently verified such data and neither we nor the
    underwriters make any representation as to the accuracy of such
    information. Similarly, we believe our internal research is
    reliable but it has not been verified by any independent
    sources.
 ii




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CERTAIN
    DEFINITIONS    Bakken Shale
  Barrel
  BBtu
  BBtu/d
  Bcfe
  Bcf/d
  Boe
  Boe/d
  British Thermal Unit or BTU
  FERC
  Fractionation
  LOE
  Mbbls
  Mboe/d
  Mcf
  Mcfe
  MMbbls
  MMboe
  MMBtu
  MMBtu/d
  MMcf
  MMcf/d
  MMcfe
  MMcfe/d
  NGLs
 iii




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PROSPECTUS
    SUMMARY  This summary highlights certain information contained
    elsewhere in this prospectus. This summary is not complete and
    does not contain all of the information that you should consider
    before investing in our Class A common stock. You should
    read this entire prospectus carefully, including the risks
    discussed under Risk Factors and the financial
    statements and notes thereto included elsewhere in this
    prospectus. Some of the statements in this summary constitute
    forward-looking statements. See Forward-Looking
    Statements.
  Except
    where the context otherwise requires or where otherwise
    indicated, (1) all references to Williams refer
    to The Williams Companies, Inc., our parent company, and its
    subsidiaries, other than us, and (2) all references to
    WPX Energy, WPX, the
    Company, we, us and
    our refer to WPX Energy, Inc. and its
    subsidiaries.
  Overview
   
   
    
 Estimated Net


May 2011





2011 Budget EstimateProved Reserves


Average Daily








Drilling% Proved


Net Production








Capital(2)


PV-10(3)Basin/Shale

Bcfe


Developed


(MMcfe/d)(1)


Net Acreage


Gross Wells


(Millions)


(Millions)Piceance Basin


2,927



53
%


714



211,000



376


$
575


$
2,707Bakken Shale(4)


136



11
%


38



89,420



41



260



399Marcellus Shale


28



71
%


8



99,301



62



170



29Powder River Basin


348



75
%


220



425,550



411



70



317San Juan Basin


554



79
%


135



120,998



51



40



477Apco(5)


190



60
%


58



404,304



37



30



358Other(6)


290



72
%


89



327,390



94



85



257Total


4,473



59
%


1,262



1,677,963



1,072


$
1,230


$
4,544  
   
  (1)
    
    Represents average daily net production of our continuing
    operations for the month of May 2011. 
  (2)
    
    Based on the midpoint of our estimated capital spending range.(3)
    
    PV-10 is a
    non-GAAP financial measure and generally differs from
    Standardized Measure of Discounted Future Net Cash Flows
    (Standardized Measure), the most directly comparable
    GAAP financial measure, because it does not include the effects
    of income taxes on future net revenues. Neither
    PV-10 nor
    Standardized Measure represents an estimate of the fair market
    value of our oil and natural gas assets. We and others in the
    industry use
    PV-10 as a
    measure to compare the relative size and value of proved
    reserves held by companies without regard to the specific tax
    characteristics of such entities. For a
 1




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definition of
    PV-10 and a
    reconciliation of
    PV-10 to
    Standardized Measure, see Summary Combined
    Historical Operating and Reserve
    DataNon-GAAP Financial Measures and
    Reconciliations below.(4)
    
    Our estimated net proved reserves in the Bakken Shale have not
    been audited by independent reserve engineers. 
  (5)
    
    Represents approximately 69 percent of each metric (which
    corresponds to our ownership interest in Apco) except Percent
    Proved Developed, Gross Wells and Drilling Capital. 
 
  (6)
    
    Other includes Barnett Shale, Arkoma and Green River Basins and
    miscellaneous smaller properties. May 2011 average daily net
    production excludes Arkoma production of approximately nine
    MMcfe/d as our Arkoma Basin operations were classified as held
    for sale and reported as discontinued operations as of
    March 31, 2011. 
    Bakken
    Shale and Marcellus Shale Acquisitions
 
   
  Bakken
    Shale
    Boe/d.
  Marcellus
    Shale
 2




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##### Table of Contents



Our
    Business Strategy
    
    Efficiently Allocate Capital for Optimal Portfolio
    Returns.  We expect to allocate capital to the
    most profitable opportunities in our portfolio based on
    commodity price cycles and other market conditions, enabling us
    to continue to grow our reserves and production in a manner that
    maximizes our return on investment. In determining which
    drilling opportunities to pursue, we target a minimum after-tax
    internal rate of return on each operated well we drill of
    15 percent. While we have a significant portfolio of
    drilling opportunities that we believe meet or exceed our return
    targets even in challenging commodity price environments, we are
    disciplined in our approach to capital spending and will adjust
    our drilling capital expenditures based on our level of expected
    cash flows, access to capital and overall liquidity position.
    For example, in 2009 we demonstrated our capital discipline by
    reducing drilling expenditures in response to prevailing
    commodity prices and their impact on these factors. 
  
    Continue Our Cost-Efficient Development
    Approach.  We focus on developing properties where
    we can apply development practices that result in cost
    efficiencies. We manage costs by focusing on establishing large
    scale, contiguous acreage blocks where we can operate a majority
    of the properties. We believe this strategy allows us to better
    achieve economies of scale and apply continuous technological
    improvements in our operations. We intend to replicate these
    cost-efficient approaches in our recently acquired growth
    positions in the Bakken Shale and the Marcellus Shale. 
 
  
    Pursue Strategic Acquisitions with Significant Resource
    Potential.  We have a history of acquiring
    undeveloped properties that meet our disciplined return
    requirements and other acquisition criteria to expand upon our
    existing positions as well as acquiring undeveloped acreage in
    new geographic areas that offer significant resource potential.
    This is illustrated by our recent acquisitions in the Bakken
    Shale and the Marcellus Shale. We seek to continue expansion of
    current acreage positions and opportunistically acquire acreage
    positions in new areas where we feel we can establish
    significant scale and replicate our cost-efficient development
    approach. 
 
  
    Target a More Balanced Commodity Mix in Our Production
    Profile.  With our Bakken Shale acquisition in
    December 2010 and our liquids-rich Piceance Basin assets, we
    have a significant drilling inventory of oil- and liquids-rich
    opportunities that we intend to develop rapidly in order to
    achieve a more balanced commodity mix in our production. We
    refer to the Piceance Basin as liquids-rich because
    our proved reserves in that basin consist of wet, as
    opposed to dry, gas and have a significant liquids
    component. Our current estimated proved reserves of NGLs and
    condensate in the Piceance Basin are 95 MMbbl and
    3 MMbbl, respectively. We will continue to pursue other
    oil- and liquids-rich organic development and acquisition
    opportunities that meet our investment returns and strategic
    criteria. 
 
  
    Maintain Substantial Financial Liquidity and Manage Commodity
    Price Sensitivity.  We plan to conservatively
    manage our balance sheet and maintain substantial liquidity
    through a mix of cash on hand and availability under our credit
    facility. In addition, we have engaged and will continue to
    engage in commodity hedging activities to maintain a degree of
    cash flow stability. Typically, we target hedging approximately
    50 percent of expected revenue from domestic production
    during a current calendar year in order to strike an appropriate
    balance of commodity price upside with cash flow protection,
    although we may vary from this level based on our perceptions of
    market risk. At May 31, 2011, our estimated domestic
    natural gas production revenues were 65 percent hedged for
    2011 and 44 percent hedged for 2012. Estimated domestic oil
    production revenues were 49 percent hedged for 2011 and
    49 percent hedged for 2012 as of the same date.
 3




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Our
    Competitive Strengths
   
  
    A Leading Piceance Basin Cost Structure.We
    have a large position in the lower cost valley area of the
    Piceance Basin, which we believe provides us economies
    associated with lower elevation drilling and large contiguous
    operations, allowing us to continuously drive down operating
    costs and increase efficiencies. The existing substantial
    midstream infrastructure in the Piceance Basin contributes to
    our cost-efficient structure and provides take-away capacity for
    our natural gas and NGLs. Because of this cost-efficient
    structure in the Piceance Basin, we have the ability to generate
    returns that we believe are in excess of those typically
    associated with Rockies producers. 
  
    Attractive Asset Base Across a Number of High Growth
    Areas.  In addition to our large scale Piceance
    Basin properties, our assets include emerging, high growth
    opportunities such as our Bakken Shale and Marcellus Shale
    positions. Based on our subsurface geological and engineering
    analysis of available well data, we believe our Bakken Shale and
    Marcellus Shale positions are located in core areas of these
    plays, which have associated historic drilling results that we
    believe offer highly attractive economic returns. 
  
    Extensive Drilling Inventory.  As of
    December 31, 2010, we have identified approximately 2,900
    proved undeveloped drilling locations. We have budgeted drilling
    approximately 500 gross operated wells during 2011. We have
    established significant scale in each of our core areas of
    operation that support multi-year development plans and allow us
    to optimally leverage our cost-efficient development approach.
    Our drilling inventory provides opportunities across diverse
    geographic markets and products including natural gas, oil and
    NGLs. 
  
    Significant Operating Flexibility.  In the
    Piceance Basin, Bakken Shale and Marcellus Shale, our three
    primary basins, we operate substantially all of our production.
    We expect approximately 91 percent of our projected 2011
    domestic drilling capital will be spent on projects we operate.
    We believe acting as operator on our properties allows us to
    better control costs and capital expenditures, manage
    efficiencies, optimize development pace, ensure safety and
    environmental stewardship and, ultimately, maximize our return
    on investment. As operator, we are also able to leverage our
    experience and expertise across all basins and transfer
    technology advances between them as applicable. In addition,
    substantially all of our Piceance Basin properties are held by
    producing wells, which allows us to adjust our level of drilling
    activity in response to changing market conditions.
    Significant Financial Flexibility.  Our capital
    structure is intended to provide a high degree of financial
    flexibility to grow our asset base, both through organic
    projects and opportunistic acquisitions. Immediately following
    the completion of this offering, we expect to have
    $2.0 billion of liquidity, comprised of availability under
    our $1.5 billion credit facility and approximately
    $500 million of cash on hand. We believe our pro forma
    level of debt to proved reserves is low relative to a majority
    of other publicly traded, independent oil and gas producers. 
  
    Management Team with Broad Unconventional Resource
    Experience.  Our management and operating team has
    significant experience acquiring, operating and developing
    natural gas and oil reserves from tight-sands and shale
    formations. Our Chief Executive Officer and his direct reports
    have in excess of 238 collective years of experience running
    large scale drilling programs and drilling vertical and
    horizontal wells requiring complex well design and completion
    methods. Our team has demonstrated the ability to manage large
    scale operations and apply current technological successes to
    new development opportunities. We have deployed members of our
    successful Piceance Basin, Powder River Basin and Barnett Shale
    teams to the Bakken Shale and Marcellus Shale teams to help
    replicate our cost-efficient model and to apply our highly
    specialized technical expertise in the development of those
    resources. 
  Our
    Relationship with Williams
 4




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lock-up
 5




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
    Focused management attention.  Our separation
    from Williams will allow us to focus managerial attention solely
    on our business, resulting in stream-lined decision making, more
    efficient deployment of resources and increased operational
    flexibility.
    Direct access to the debt and equity capital
    markets.  As a separate public company, we will
    have direct access to the capital markets, thereby enabling us
    to optimize our capital structure to meet the specific needs of
    our business.
    Enhancing our market recognition with
    investors.  We believe our simpler corporate
    structure with a single business segment will allow us to fit
    more purely into an exploration and production investor sector
    and attract pure play investors.
    Improving our ability to pursue
    acquisitions.  As a stand alone exploration and
    production company, we will be better positioned to use our
    equity securities as capital in pursuing merger and acquisition
    activities. However, we will be subject to certain requirements,
    such as (1) prior to the spin-off to Williams shareholders
    of its retained shares in us, Williams must satisfy certain 80%
    ownership thresholds and (2) after the spin-off, we must avoid a
    50% or greater change in our ownership in transactions related
    to the spin-off. Both of these limitations are necessary in
    order to maintain the tax-free treatment of our separation from
    Williams. See Risk FactorsRisks Related to our
    Relationship with WilliamsOur agreements with Williams may
    limit our ability to obtain additional financing or make
    acquisitions, and Risk FactorsRisks Related to
    our Relationship with WilliamsOur tax sharing agreement
    with Williams may limit our ability to take certain actions and
    may require us to indemnify Williams for significant tax
    liabilities.  Our
    Restructuring
   
  
    Williams will contribute and transfer to us the assets and
    liabilities associated with our business and will contribute to
    our capital all intercompany debt associated with our business; 
  
    we will effect a recapitalization whereby the outstanding shares
    of our common stock, all of which are owned by Williams, will be
    reclassified into     shares of
    Class B common stock in exchange for all of the assets (net
    of the liabilities assumed and the cash we distribute to
    Williams) contributed to us by Williams, and a new Class A
    common stock will be authorized; and
    we will amend and restate our certificate of incorporation and
    bylaws.    Concurrent
    Financing Transactions
    Risk
    Factors
    
    Our business requires significant capital expenditures and we
    may be unable to obtain needed capital or financing on
    satisfactory terms.
    Failure to replace reserves may negatively affect our business.
    Exploration and development drilling may not result in
    commercially productive reserves.
 6




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
    Estimating reserves and future net revenues involves
    uncertainties. Decreases in natural gas and oil prices, or
    negative revisions to reserve estimates or assumptions as to
    future natural gas and oil prices may lead to decreased
    earnings, losses or impairment of natural gas and oil assets.
    Prices for natural gas, oil and NGLs are volatile, and this
    volatility could adversely affect our financial results, cash
    flows, access to capital and ability to maintain our existing
    business.
    Our business depends on access to natural gas, oil and NGL
    transportation systems and facilities.
    Our risk management and measurement systems and hedging
    activities might not be effective and could increase the
    volatility of our results.
    Our operations are subject to operational hazards and unforeseen
    interruptions for which they may not be adequately insured.
    Our operations are subject to governmental laws and regulations
    relating to the protection of the environment, including with
    respect to hydraulic fracturing, which may expose us to
    significant costs and liabilities and could exceed current
    expectations.
    Certain of our properties, including our operations in the
    Bakken Shale, are located on Native American tribal lands and
    are subject to various federal and tribal approvals and
    regulations, which may increase our costs and delay or prevent
    our efforts to conduct planned operations.
    Our acquisition attempts may not be successful or may result in
    completed acquisitions that do not perform as anticipated.
    Our historical and pro forma combined financial information may
    not be representative of the results we would have achieved as a
    stand-alone public company and may not be a reliable indicator
    of our future results.
    As long as we are controlled by Williams, your ability to
    influence the outcome of matters requiring stockholder approval
    will be limited.  Principal
    Executive Offices
  918-573-2000.
 7




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The
    Offering
  Issuer
    
    WPX Energy, Inc.Class A common stock offered
    
    shares.Common stock outstanding after this offering:Class A common stock
    
    shares,
    or           shares
    if the underwriters exercise their option to purchase additional
    Class A common shares in full.Class B common stock
    
    shares,
    or           shares
    if the underwriters exercise their option to purchase additional
    Class A common shares in full. 
  Total common stock
    
    shares.
    Any shares of Class A common stock issued pursuant to the
    underwriters option to purchase additional Class A
    common shares will not increase the total number of shares of
    common stock outstanding after this offering, but rather the
    number of shares of Class B common stock owned by Williams
    will be reduced share for share by the number of shares of
    Class A common stock issued pursuant to such option.
    Williams is deemed to be an underwriter with respect to any
    shares of Class A common stock issued pursuant to such
    option. 
  Common stock to be held by Williams after this offering:Class A common stock
    
    None.Class B common stock
    
    shares,
    or           shares
    if the underwriters exercise their option to purchase additional
    Class A common shares in full.Common stock voting rights:Class A common stock
    
    One vote per share on all matters to be voted on by
    stockholders, representing in aggregate
    approximately          
    percent of the combined voting power of our outstanding common
    stock,
    or          
    percent if the underwriters exercise their option to purchase
    additional Class A common shares in full.Class B common stock
    
    Ten votes per share on all matters to be voted on by
    stockholders, representing in aggregate
    approximately          
    percent of the combined voting power of our outstanding common
    stock,
    or          
    percent if the underwriters exercise their option to purchase
    additional Class A common shares in full.Use of proceeds
    
    We estimate that our net proceeds from the sale of shares of
    Class A common stock in this offering, after deducting
    estimated underwriting discounts and commissions and estimated
    offering expenses, will be approximately
    $      million
    ($      million if the
    underwriters exercise their option to purchase additional
    Class A common shares in full), assuming the shares are
    offered at $      per share of
    Class A common stock, which is the midpoint of the
    estimated offering price range set forth on the cover page of
    this prospectus. We expect to retain approximately
    $500 million of the net proceeds from this offering. At
    current commodity prices, we expect as much as 50 percent of
    these proceeds could be used for capital expenditures for
    drilling and facilities projects, with the remainder available
    to provide additional liquidity and for acquisition, exploration
    and general corporate purposes. As part of our restructuring
    transactions, the remainder of the net proceeds of this
 8




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offering will be distributed to Williams. Williams is deemed to
    be an underwriter with respect to any shares of Class A
    common stock issued pursuant to the underwriters option to
    purchase additional Class A common shares. See Use of
    Proceeds. 
  Dividend policy
    
    We do not anticipate paying any dividends on our common stock in
    the foreseeable future. See Dividend Policy. 
  Exchange Listing
    
    We have applied to have our shares of Class A common stock
    listed on the NYSE under the symbol WPX. 
    
    gives effect to our restructuring transactions;
    assumes no exercise by the underwriters of their option to
    purchase additional Class A common shares; and
    excludes shares of Class A common stock reserved for
    issuance, if any, under equity incentive plans.
 9




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Summary
    Combined Historical and Unaudited Pro Forma Combined Financial
    Data
      
    the completion of our restructuring transactions, including the
    forgiveness or contribution to our capital of the unsecured
    notes payable to Williams;
    the receipt of approximately $705 million from the sale of
    shares of Class A common stock offered by us at an assumed
    initial public offering price of $     
    per share, which is the midpoint of the estimated offering price
    range set forth on the cover page of this prospectus, after
    deducting estimated underwriting discounts and commissions and
    estimated offering expenses payable by us;
    the receipt of approximately $1.5 billion from our expected
    offering of the Notes, after deducting the discounts of the
    initial purchasers of the Notes and the expenses payable by us
    in connection with such offering; and
    the distribution of approximately $1.7 billion to Williams
    from the combined net proceeds from this offering and the
    expected offering of the Notes in connection with our
    restructuring transactions.
 10




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##### Table of Contents



Pro Forma Three


Pro FormaMonths Ended


Year Ended


Historical Three Months


Historical Year EndedMarch 31,


December 31,


Ended March 31,


December 31,2011


2010


2011


2010


2010


2009


2008(Millions)Statement of Operations Data:Revenues, including affiliate(1)

$
984


$
4,034


$
984


$
1,164


$
4,034


$
3,681


$
6,184Costs and expenses:Lease and facility operating, including affiliate


70



286



70



66



286



263



272Gathering, processing and transportation, including affiliate


115



326



115



72



326



273



229Taxes other than income


31



125



31



40



125



93



254Gas management (including charges for unutilized pipeline
    capacity)


417



1,771



417



558



1,771



1,495



3,248Exploration


13



73



13



8



73



54



37Depreciation, depletion and amortization


216



875



216



216



875



887



738Impairment of producing properties and costs of acquired
    unproved reserves






678











678



15



Goodwill impairment






1,003











1,003







General and administrative, including affiliate


70



253



70



61



253



251



247Gain on sale of contractual right to international production
    payment


























(148
)Othernet


3



(19
)


3







(19
)


33



6Total costs and expenses


935



5,371



935



1,021



5,371



3,364



4,883Operating income (loss)


49



(1,337
)


49



143



(1,337
)


317



1,301Interest expense, including affiliate


(27
)


(103
)


(49
)


(25
)


(124
)


(100
)


(74
)Interest capitalized


4



16



4



4



16



18



20Investment income and other


6



21



6



5



21



8



22Income (loss) before income taxes


32



(1,403
)


10



127



(1,424
)


243



1,269Provision (benefit) for income taxes


11



(142
)


3



44



(150
)


94



452Income (loss) from continuing operations(2)


21



(1,261
)


7



83



(1,274
)


149



817Loss from discontinued operations(3)


(8
)


(8
)


(8
)






(8
)


(7
)


(87
)Net income (loss)

$
13


$
(1,269
)


(1
)


83



(1,282
)


142



730Less: Net income attributable to noncontrolling interests










2



2



8



6



8Net income (loss) attributable to WPX Energy









$
(3
)

$
81


$
(1,290
)

$
136


$
722    (1)
    
    Includes gas management revenues of $408 million and
    $556 million for the three months ended March 31, 2011
    and 2010, respectively and $1,742 million,
    $1,456 million and $3,241 million for the year ended
    December 31, 2010, 2009 and 2008, respectively. These
    revenues were offset by the gas management expenses
 11




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##### Table of Contents



shown in the table above. See Managements Discussion
    and Analysis of Financial Condition and Results of
    OperationsResults of Operations.(2)
    
    Loss from continuing operations in 2010 includes
    $1.7 billion of impairment charges related to goodwill,
    producing properties in the Barnett Shale and costs of acquired
    unproved reserves in the Piceance Basin. Income from continuing
    operations in 2008 includes a $148 million gain related to
    the sale of a right to an international production payment. See
    Notes 6 and 14 of Notes to Combined Financial Statements
    for further discussion of asset sales, impairments and other
    accruals in 2010, 2009 and 2008.(3)
    
    Loss from discontinued operations includes our Arkoma operations
    which were classified as held for sale in the first quarter of
    2011 and activities associated with Williams former power
    business that was substantially disposed of in 2007. The loss in
    2008 includes a $148 million pre-tax impairment of the
    Arkoma producing properties.  Pro Forma


Historical


HistoricalAt March 31,


At March 31,


At December 31,2011


2011


2010


2009(Millions)Balance Sheet Data:Cash and cash equivalents

$
540


$
40


$
37


$
34Properties and equipment, net


8,503



8,503



8,449



7,662Total assets


10,291



9,764



9,846



10,553Unsecured notes payable to Williamscurrent






2,364



2,261



1,216Senior unsecured notes


1,500











Total equity


5,785



4,440



4,500



5,405Total liabilities and equity


10,291



9,764



9,846



10,553   Pro FormaThree Months


Pro FormaEnded


Year Ended


Historical Three MonthsMarch 31,


December 31,


Ended March 31,


Historical Year Ended December 31,2011


2010


2011


2010


2010


2009


2008(Millions)Other Financial Data:Net cash provided by operating activities









$
240


$
329


$
1,056


$
1,181


$
2,009Net cash used in investing activities










(342
)


(286
)


(2,337
)


(1,435
)


(2,252
)Net cash provided (used) by financing activities










105



(39
)


1,284



256



225Adjusted EBITDAX(1)

$
288


$
1,329



288



376



1,329



1,299



1,970Capital expenditures










(319
)


(284
)


(1,856
)


(1,434
)


(2,467
)     (1)
    
    Adjusted EBITDAX is a non-GAAP financial measure. For a
    definition of Adjusted EBITDAX and a reconciliation of Adjusted
    EBITDAX to our net income (loss), see Summary
    Combined Historical Operating and Reserve
    DataNon-GAAP Financial Measures and
    Reconciliations below.
 12




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##### Table of Contents



Summary
    Combined Historical Operating and Reserve Data
    At December 31,2010


2009Estimated Proved Reserves(1)Natural Gas (Bcf)(2)


4,214



4,316Oil (MMbbls)


43



23Total (Bcfe)


4,473



4,452PV-10 (in
    millions)

$
4,544


$
2,620Standardized Measure of Discounted Future Net Cash Flows (in
    millions)(3)

$
3,080


$
1,923    
  (1)
    
    Includes approximately 69 percent of Apcos reserves, which
    corresponds to our ownership interest in Apco. Our estimated
    proved reserves for domestic properties,
    PV-10 and
    Standardized Measure were derived using an average price of
    $3.36 per Mcf of natural gas and $48.63 per barrel of oil during
    2009 and $4.31 per Mcf of natural gas and $68.89 per barrel of
    oil during 2010. Our prices were calculated using the
    12-month
    average,
    first-of-the-month
    price for the applicable indices for each basin as adjusted for
    locational price differentials. The
    12-month
    average beginning of the month price for Apco properties was
    $1.93 per MMbtu of natural gas and $43.62 per barrel of oil for
    2009 and $1.63 per MMbtu of natural gas and $52.11 per barrel of
    oil for 2010. 
  (2)
    
    Net wellhead natural gas reserves at December 31, 2010 and
    2009 included approximately 99 MMbbls and 69 MMbbls,
    respectively, of NGLs to be extracted downstream at processing
    plants. The gas volume shrink associated with this processing is
    approximately 216 Bcf and 164 Bcf, respectively, or
    approximately 4.8 percent and 3.7 percent, respectively, of
    our total proved reserves volumes.(3)
    
    Standardized Measure represents the present value of estimated
    future cash inflows from proved natural gas and oil reserves,
    less future development and production costs and income tax
    expenses, discounted at ten percent per annum to reflect timing
    of future cash flows and using the same pricing assumptions as
    were used to calculate
    PV-10.
    Standardized Measure differs from
    PV-10
    because Standardized Measure includes the effect of future
    income taxes. For a reconciliation of the non-GAAP financial
    measure of
    PV-10 to
    Standardized Measure, the most directly comparable GAAP
    financial measure, see Non-GAAP Financial
    Measures and Reconciliations below.
 13




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##### Table of Contents



Year Ended December 31,2010


2009


2008Production Data:Natural Gas (MMcf)U.S.Piceance Basin


245,895



254,617



237,675Other(1)


158,040



167,678



153,206Argentina(2)


7,304



7,728



6,392Total


411,239



430,023



397,273Oil (MBbls)U.S.


859



803



731Argentina(2)


2,035



1,998



1,991Total


2,894



2,801



2,722Combined Equivalent Volumes (MMcfe)(2)


428,603



446,829



413,605Combined Equivalent Volumes (MBoe)


71,434



74,472



68,394Average Daily Combined Equivalent Volumes (MMcfe/d)U.S.Piceance Basin


674



698



649Other(1)


447



472



431Argentina(2)


53



54



50Total


1,174



1,224



1,130     (1)
    
    Excludes production from our Arkoma Basin operations which were
    classified as held for sale and reported as discontinued
    operations as of March 31, 2011 and comprised less than one
    percent of our total production.(2)
    
    Includes approximately 69 percent of Apcos production
    (which corresponds to our ownership interest in Apco) and other
    minor directly held interests.    Year Ended December 31,2010


2009


2008Realized average price per unit(1):Natural gas, without hedges (per Mcf)(2)

$
4.33


$
3.41


$
6.94Impact of hedges (per Mcf)(2)


0.82



1.45



0.10Natural gas, with hedges (per Mcf)(2)

$
5.15


$
4.86


$
7.04Oil, without hedges (per Bbl)

$
66.17


$
44.92


$
84.63Impact of hedges (per Bbl)










Oil, with hedges (per Bbl)

$
66.17


$
44.92


$
84.63Price per Boe, without hedges(3)

$
26.44


$
20.71


$
42.14Price per Boe, with hedges(3)

$
31.32


$
29.36


$
42.66Price per Mcfe, without hedges(3)

$
4.41


$
3.45


$
7.02Price per Mcfe, with hedges(3)

$
5.22


$
4.89


$
7.11
 14




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##### Table of Contents



(1)
    
    Excludes our Arkoma Basin operations, which were classified as
    held for sale and reported as discontinued operations as of
    March 31, 2011 and comprised less than one percent of our
    total revenues.(2)
    
    Includes NGLs.(3)
    
    Realized average prices reflect realized market prices, net of
    fuel and shrink.  Year Ended December 31,2010


2009


2008Expenses per Mcfe(1):Operating expenses:Lifting costs and workovers

$
0.46


$
0.39


$
0.45Facilities operating expense


0.14



0.14



0.15Other operating and maintenance


0.05



0.05



0.04Total LOE

$
0.65


$
0.58


$
0.64Gathering, processing and transportation charges


0.80



0.64



0.58Taxes other than income


0.27



0.19



0.61Production cost

$
1.72


$
1.41


$
1.83General and administrative

$
0.60


$
0.57


$
0.61Depreciation, depletion and amortization

$
2.10


$
2.04


$
1.83     (1)
    
    Excludes our Arkoma Basin operations, which were classified as
    held for sale and reported as discontinued operations as of
    March 31, 2011.  Non-GAAP Financial
    Measures and Reconciliations
  Adjusted
    EBITDAX
 15




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##### Table of Contents



Pro Forma Three


Pro Forma


HistoricalMonths Ended


Year Ended


Three Months


HistoricalMarch 31,


December 31,


Ended March 31,


Year Ended December 31,2011


2010


2011


2010


2010


2009


2008(Millions)Adjusted EBITDAX Reconciliation to Net Income (Loss):Net income (loss)

$
13


$
(1,269
)

$
(1
)

$
83


$
(1,282
)

$
142


$
730Interest expense


27



103



49



25



124



100



74Provision (benefit) for income taxes


11



(142
)


3



44



(150
)


94



452Depreciation, depletion and amortization


216



875



216



216



875



887



738Exploration expenses


13



73



13



8



73



54



37EBITDAX


280



(360
)


280



376



(360
)


1,277



2,031Gain on sale of contractual right to international production
    payment


























(148
)Impairments of goodwill, producing properties and cost of
    acquired unproved reserves






1,681











1,681



15



Loss from discontinued operations


8



8



8







8



7



87Adjusted EBITDAX

$
288


$
1,329


$
288


$
376


$
1,329


$
1,299


$
1,970   PV-10
  PV-10 PV-10 PV-10 PV-10
  PV-10
  At December 31,2010


2009(Millions)Standardized Measure of Discounted Future Net Cash Flows

$
3,080


$
1,923Present value of future income tax discounted at 10%


1,464



697PV-10

$
4,544


$
2,620
 16




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##### Table of Contents



RISK
    FACTORS  Investing in our Class A common stock involves
    substantial risk. You should carefully consider the following
    risk factors and the other information in this prospectus before
    investing in our Class A common stock. If any of the
    following risks actually occur, our business, financial
    condition, cash flows and results of operations could suffer
    materially and adversely. In that case, the trading price of our
    Class A common stock could decline, and you might lose all
    or part of your investment.
  Risks
    Related to Our Business
  Our
    business requires significant capital expenditures and we may be
    unable to obtain needed capital or financing on satisfactory
    terms.
    Failure
    to replace reserves may negatively affect our
    business.
    Exploration
    and development drilling may not result in commercially
    productive reserves.
    
    Increases in the cost of, or shortages or delays in the
    availability of, drilling rigs and equipment, supplies, skilled
    labor, capital or transportation;
    Equipment failures or accidents;
    Adverse weather conditions, such as blizzards;
    Title and lease related problems;
    Limitations in the market for natural gas and oil;
    Unexpected drilling conditions or problems;
    Pressure or irregularities in geological formations; 17




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##### Table of Contents




    Regulations and regulatory approvals;
    Changes or anticipated changes in energy prices; or
    Compliance with environmental and other governmental
    requirements.    If
    natural gas and oil prices decrease, we may be required to take
    write-downs of the carrying values of our natural gas and oil
    properties.
    Estimating
    reserves and future net revenues involves uncertainties.
    Decreases in natural gas and oil prices, or negative revisions
    to reserve estimates or assumptions as to future natural gas and
    oil prices may lead to decreased earnings, losses or impairment
    of natural gas and oil assets.
          The
    development of our proved undeveloped reserves may take longer
    and may require higher levels of capital expenditures than we
    currently anticipate.
   18




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##### Table of Contents



PV-10
  The
    present value of future net revenues from our proved reserves
    will not necessarily be the same as the value we ultimately
    realize of our estimated natural gas and oil reserves.
  12-month first-day-of-the-month
  
    actual prices we receive for natural gas and oil;
    actual cost of development and production expenditures;
    the amount and timing of actual production; and
    changes in governmental regulations or taxation.    Certain
    of our domestic undeveloped leasehold assets are subject to
    leases that will expire over the next several years unless
    production is established on units containing the
    acreage.
    Prices
    for natural gas, oil and NGLs are volatile, and this volatility
    could adversely affect our financial results, cash flows, access
    to capital and ability to maintain our existing
    business.
      
    Worldwide and domestic supplies of and demand for natural gas,
    oil and NGLs;
    Turmoil in the Middle East and other producing regions;
    The activities of the Organization of Petroleum Exporting
    Countries;
    Terrorist attacks on production or transportation assets; 19




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##### Table of Contents




    Weather conditions;
    The level of consumer demand;
    Variations in local market conditions (basis differential);
    The price and availability of other types of fuels;
    The availability of pipeline capacity;
    Supply disruptions, including plant outages and transportation
    disruptions;
    The price and quantity of foreign imports of natural gas and oil;
    Domestic and foreign governmental regulations and taxes;
    Volatility in the natural gas and oil markets;
    The overall economic environment;
    The credit of participants in the markets where products are
    bought and sold; and
    The adoption of regulations or legislation relating to climate
    change.  Our
    business depends on access to natural gas, oil and NGL
    transportation systems and facilities.
      We may
    have excess capacity under our firm transportation contracts, or
    the terms of certain of those contracts may be less favorable
    than those we could obtain currently.
    We have
    limited control over activities on properties we do not operate,
    which could reduce our production and revenues.
   20




---



##### Table of Contents



We might
    not be able to successfully manage the risks associated with
    selling and marketing products in the wholesale energy
    markets.
    Our risk
    management and measurement systems and hedging activities might
    not be effective and could increase the volatility of our
    results.
        The
    adoption and implementation of new statutory and regulatory
    requirements for derivative transactions could have an adverse
    impact on our ability to hedge risks associated with our
    business and increase the working capital requirements to
    conduct these activities.
   21




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##### Table of Contents



We are
    exposed to the credit risk of our customers and counterparties,
    and our credit risk management may not be adequate to protect
    against such risk.
  and/or and/or
  We face
    competition in acquiring new properties, marketing natural gas
    and oil and securing equipment and trained personnel in the
    natural gas and oil industry.
    Our
    operations are subject to operational hazards and unforeseen
    interruptions for which they may not be adequately
    insured.
    
    Hurricanes, tornadoes, floods, extreme weather conditions and
    other natural disasters;
    Aging infrastructure and mechanical problems;
    Damages to pipelines, pipeline blockages or other pipeline
    interruptions;
    Uncontrolled releases of natural gas (including sour gas), oil,
    NGLs, brine or industrial chemicals;
    Operator error;
    Pollution and environmental risks;
    Fires, explosions and blowouts;
    Risks related to truck and rail loading and unloading; and
    Terrorist attacks or threatened attacks on our facilities or
    those of other energy companies.   22




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##### Table of Contents



We do not
    insure against all potential losses and could be seriously
    harmed by unexpected liabilities or by the inability of our
    insurers to satisfy our claims.
      sub-limited.
    Potential
    changes in accounting standards might cause us to revise our
    financial results and disclosures in the future, which might
    change the way analysts measure our business or financial
    performance.
    Our
    investments and projects located outside of the United States
    expose us to risks related to the laws of other countries, and
    the taxes, economic conditions, fluctuations in currency rates,
    political conditions and policies of foreign governments. These
    risks might delay or reduce our realization of value from our
    international projects.
  and/or
 23




---



##### Table of Contents



Our
    operating results might fluctuate on a seasonal and quarterly
    basis.
    Our debt
    agreements impose restrictions on us that may limit our access
    to credit and adversely affect our ability to operate our
    business.
       24




---



##### Table of Contents



Difficult
    conditions in the global capital markets, the credit markets and
    the economy in general could negatively affect our business and
    results of operations
    We are
    subject to risks associated with climate change.
    and/or
      Our
    operations are subject to governmental laws and regulations
    relating to the protection of the environment, which may expose
    us to significant costs and liabilities and could exceed current
    expectations.
   25




---



##### Table of Contents




    Clean Air Act (CAA) and analogous state laws, which
    impose obligations related to air emissions;
    Clean Water Act (CWA), and analogous state laws,
    which regulate discharge of wastewaters and storm water from
    some our facilities into state and federal waters, including
    wetlands;
    Comprehensive Environmental Response, Compensation, and
    Liability Act (CERCLA), and analogous state laws,
    which regulate the cleanup of hazardous substances that may have
    been released at properties currently or previously owned or
    operated by us or locations to which we have sent wastes for
    disposal;
    Resource Conservation and Recovery Act (RCRA), and
    analogous state laws, which impose requirements for the handling
    and discharge of solid and hazardous waste from our facilities;
    National Environmental Policy Act (NEPA), which
    requires federal agencies to study likely environment impacts of
    a proposed federal action before it is approved, such as
    drilling on federal lands;
    Safe Drinking Water Act (SDWA), which restricts the
    disposal, treatment or release of water produced or used during
    oil and gas development;
    Endangered Species Act (ESA), and analogous state
    laws, which seek to ensure that activities do not jeopardize
    endangered or threatened animals, fish and plant species, nor
    destroy or modify the critical habitat of such species; and
    Oil Pollution Act (OPA) of 1990, which requires oil
    storage facilities and vessels to submit to the federal
    government plans detailing how they will respond to large
    discharges, requires updates to technology and equipment,
    regulation of above ground storage tanks and sets forth
    liability for spills by responsible parties.       26




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##### Table of Contents



Legislation
    and regulatory initiatives relating to hydraulic fracturing
    could result in increased costs and additional operating
    restrictions or delays.
   27




---



##### Table of Contents



Our
    ability to produce gas could be impaired if we are unable to
    acquire adequate supplies of water for our drilling and
    completion operations or are unable to dispose of the water we
    use at a reasonable cost and within applicable environmental
    rules.
    Legal and
    regulatory proceedings and investigations relating to the energy
    industry, and the complex government regulations to which our
    businesses are subject, have adversely affected our business and
    may continue to do so. The operation of our businesses might
    also be adversely affected by changes in regulations or in their
    interpretation or implementation, or the introduction of new
    laws, regulations or permitting requirements applicable to our
    businesses or our customers.
     28




---



##### Table of Contents



Certain
    of our properties, including our operations in the Bakken Shale,
    are located on Native American tribal lands and are subject to
    various federal and tribal approvals and regulations, which may
    increase our costs and delay or prevent our efforts to conduct
    planned operations.
    Tax laws
    and regulations may change over time, including the elimination
    of federal income tax deductions currently available with
    respect to oil and gas exploration and development.
        Our
    acquisition attempts may not be successful or may result in
    completed acquisitions that do not perform as
    anticipated.
    
    some of the acquired businesses or properties may not produce
    revenues, reserves, earnings or cash flow at anticipated levels
    or could have environmental, permitting or other problems for
    which contractual protections prove inadequate;
    we may assume liabilities that were not disclosed to us or that
    exceed our estimates; 29




---



##### Table of Contents




    properties we acquire may be subject to burdens on title that we
    were not aware of at the time of acquisition or that interfere
    with our ability to hold the property for production;
    we may be unable to integrate acquired businesses successfully
    and realize anticipated economic, operational and other benefits
    in a timely manner, which could result in substantial costs and
    delays or other operational, technical or financial problems;
    acquisitions could disrupt our ongoing business, distract
    management, divert resources and make it difficult to maintain
    our current business standards, controls and procedures; and
    we may issue additional equity or debt securities related to
    future acquisitions.  Substantial
    acquisitions or other transactions could require significant
    external capital and could change our risk and property
    profile.
    Failure
    of our service providers or disruptions to our outsourcing
    relationships might negatively impact our ability to conduct our
    business.
        Our
    assets and operations can be adversely affected by weather and
    other natural phenomena.
     30




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##### Table of Contents



Acts of
    terrorism could have a material adverse effect on our financial
    condition, results of operations and cash flows.
    We have
    identified two material weaknesses in our internal controls over
    financial reporting. Our failure to achieve and maintain
    effective internal controls could have a material adverse effect
    on our business in the future, on the price of our Class A
    common stock and our access to the capital markets.
      Risks
    Related to Our Relationship with Williams
  We may
    not realize the potential benefits from our separation from
    Williams.
    
    allowing our management to focus its efforts on our business and
    strategic priorities;
    enhancing our market recognition with investors;
    providing us with direct access to the debt and equity capital
    markets;
    improving our ability to pursue acquisitions through the use of
    shares of our common stock as consideration; and
    enabling us to allocate our capital more efficiently.   31




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##### Table of Contents



Our
    historical and pro forma combined financial information may not
    be representative of the results we would have achieved as a
    stand-alone public company and may not be a reliable indicator
    of our future results.
    Following
    this offering, we will continue to depend on Williams to provide
    us with certain services for our business; the services that
    Williams will provide to us following the separation may not be
    sufficient to meet our needs, and we may have difficulty finding
    replacement services or be required to pay increased costs to
    replace these services after our agreements with Williams
    expire.
   32




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##### Table of Contents



Your
    investment in our Class A common stock may be adversely
    affected if Williams does not spin-off the common stock owned by
    Williams.
    Our share
    price may decline because of Williams ability to sell
    shares of our common stock.
    lock-up
  180-day 180-day 180-day
 33




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##### Table of Contents



As long
    as we are controlled by Williams, your ability to influence the
    outcome of matters requiring stockholder approval will be
    limited.
    
    the composition of our board of directors and, through our board
    of directors, decision-making with respect to our business
    direction and policies, including the appointment and removal of
    our officers;
    any determinations with respect to acquisitions of businesses,
    mergers, or other business combinations;
    our acquisition or disposition of assets;
    our capital structure;
    changes to the agreements relating to our separation from
    Williams;
    our payment or non-payment of dividends on our common
    stock; and
    determinations with respect to our tax returns.  lock-up lock-up
  We may
    have potential business conflicts of interest with Williams
    regarding our past and ongoing relationships, and because of
    Williams controlling ownership in us, the resolution of
    these conflicts may not be favorable to us.
    
    labor, tax, employee benefit, indemnification and other matters
    arising under agreements with Williams;
    employee recruiting and retention;
    sales or distributions by Williams of all or any portion of its
    ownership interest in us, which could be to one of our
    competitors; and
    business opportunities that may be attractive to both Williams
    and us. 34




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##### Table of Contents



Pursuant
    to the terms of our amended and restated certificate of
    incorporation, Williams is not required to offer corporate
    opportunities to us, and certain of our directors and officers
    are permitted to offer certain corporate opportunities to
    Williams before us.
    
    Williams is free to compete with us in any activity or line of
    business;
    we do not have any interest or expectancy in any business
    opportunity, transaction, or other matter in which Williams
    engages or seeks to engage merely because we engage in the same
    or similar lines of business;
    to the fullest extent permitted by law, Williams will have no
    duty to communicate its knowledge of, or offer, any potential
    business opportunity, transaction, or other matter to us, and
    Williams is free to pursue or acquire such business opportunity,
    transaction, or other matter for itself or direct the business
    opportunity, transaction, or other matter to its
    affiliates; and
    if any director or officer of Williams who is also one of our
    officers or directors becomes aware of a potential business
    opportunity, transaction, or other matter (other than one
    expressly offered to that director or officer in writing solely
    in his or her capacity as our director or officer), that
    director or officer will have no duty to communicate or offer
    that business opportunity to us, and will be permitted to
    communicate or offer that business opportunity to Williams (or
    its affiliates) and that director or officer will not, to the
    fullest extent permitted by law, be deemed to have
    (1) breached or acted in a manner inconsistent with or
    opposed to his or her fiduciary or other duties to us regarding
    the business opportunity or (2) acted in bad faith or in a
    manner inconsistent with the best interests of our company or
    our stockholders.  and/or and/or
  Our
    agreements with Williams require us to assume the past, present,
    and future liabilities related to our business and may be less
    favorable to us than if they had been negotiated with
    unaffiliated third parties.
   35




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##### Table of Contents



Our
    agreements with Williams may limit our ability to obtain
    additional financing or make acquisitions.
     
  
    acquire any businesses or assets with an aggregate value of more
    than $50 million for all such acquisitions; 
 
  
    dispose of any assets with an aggregate value of more than
    $50 million for all such dispositions; and 
 
  
    acquire any equity or debt securities of any other person with
    an aggregate value of more than $50 million for all such
    acquisitions. 
    Our tax
    sharing agreement with Williams may limit our ability to take
    certain actions and may require us to indemnify Williams for
    significant tax liabilities.
 
   
 36




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##### Table of Contents



tax-related
  We will
    not have complete control over our tax decisions and could be
    liable for income taxes owed by Williams.
      If,
    following the completion of the spin-off of our stock to
    Williams stockholders, there is a determination that the
    spin-off is taxable for U.S. federal income tax purposes because
    the facts, assumptions, representations, or undertakings
    underlying the IRS private letter ruling or tax opinion are
    incorrect or for any other reason, then Williams and its
    stockholders could incur significant income tax liabilities, and
    we could incur significant liabilities.   37




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##### Table of Contents



and/or
  Third
    parties may seek to hold us responsible for liabilities of
    Williams that we did not assume in our agreements.    Our prior
    and continuing relationship with Williams exposes us to risks
    attributable to businesses of Williams.    Our
    directors and executive officers who own shares of common stock
    of Williams, who hold options to acquire common stock of
    Williams or other Williams equity-based awards, or who hold
    positions with Williams, may have actual or potential conflicts
    of interest.  and/or
 
   
  We will
    be a controlled company within the meaning of the
    NYSE rules and, as a result, will qualify for, and intend to
    rely on, exemptions from certain corporate governance
    requirements that provide protection to stockholders of other
    companies.   38




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##### Table of Contents




    a majority of our board of directors consists of independent
    directors;
    we have a nominating and governance committee that is composed
    entirely of independent directors, with a written charter
    addressing the committees purpose and responsibilities;
    we have a compensation committee that is composed entirely of
    independent directors, with a written charter addressing the
    committees purpose and responsibilities; and
    we conduct an annual performance evaluation of the nominating
    and governance committee and compensation committee.    Risks
    Related to this Offering
  No market
    currently exists for our Class A common stock. We cannot
    assure you that an active trading market will develop for our
    Class A common stock.    If our
    Class A stock price fluctuates after this offering, you
    could lose a significant part of your investment.    
    the failure of securities analysts to cover our Class A
    common stock after this offering or changes in financial
    estimates by analysts;
    the inability to meet the financial estimates of analysts who
    follow our Class A common stock;
    strategic actions by us or our competitors;
    announcements by us or our competitors of significant contracts,
    acquisitions, joint marketing relationships, joint ventures or
    capital commitments;
    variations in our quarterly operating results and those of our
    competitors;
    general economic and stock market conditions;
    risks related to our business and our industry, including those
    discussed above;
    changes in conditions or trends in our industry, markets or
    customers;
    terrorist acts;
    future sales of our Class A common stock or other
    securities; and
    investor perceptions of the investment opportunity associated
    with our Class A common stock relative to other investment
    alternatives.   39




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##### Table of Contents



Future
    sales, or the perception of future sales, of our common stock
    may depress the price of our Class A common
    stock.      lock-up lock-up lock-up
    We will
    not receive any benefit and accordingly you will suffer
    increased dilution if the underwriters exercise their option to
    purchase additional Class A common shares. 
   
  Our costs
    may increase as a result of operating as a public company, and
    our management will be required to devote substantial time to
    complying with public company regulations.     40




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##### Table of Contents



Failure
    to achieve and maintain effective internal controls in
    accordance with Section 404 of 
    Sarbanes-Oxley could have a material adverse effect on our
    business and stock price.    If
    securities or industry analysts do not publish research or
    reports about our business, if they adversely change their
    recommendations regarding our stock or if our operating results
    do not meet their expectations, our stock price could
    decline.    Investors
    purchasing Class A common stock in this offering will incur
    substantial and immediate dilution.   41




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##### Table of Contents



We do not
    anticipate paying any dividends on our common stock in the
    foreseeable future. As a result, you will need to sell your
    shares of common stock to receive any income or realize a return
    on your investment.    Provisions
    of Delaware law, our charter documents and our stockholder
    rights plan may delay or prevent an acquisition of us that
    stockholders may consider favorable or may prevent efforts by
    our stockholders to change our directors or our management,
    which could decrease the value of your shares.    
    restrictions on business combinations for a three-year period
    with a stockholder who becomes the beneficial owner of more than
    15% of our common stock;
    restrictions on the ability of our stockholders to remove
    directors;
    supermajority voting requirements for stockholders to amend our
    organizational documents; and
    a classified board of directors.   42




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##### Table of Contents



FORWARD-LOOKING
    STATEMENTS    forward-looking
  
    Amounts and nature of future capital expenditures;
    Expansion and growth of our business and operations;
    Financial condition and liquidity;
    Business strategy;
    Estimates of proved gas and oil reserves;
    Reserve potential;
    Development drilling potential;
    Cash flow from operations or results of operations;
    Seasonality of our business; and
    Natural gas, crude oil and NGLs prices and demand.    
    Availability of supplies (including the uncertainties inherent
    in assessing, estimating, acquiring and developing future
    natural gas and oil reserves), market demand, volatility of
    prices and the availability and cost of capital;
    Inflation, interest rates, fluctuation in foreign exchange and
    general economic conditions (including future disruptions and
    volatility in the global credit markets and the impact of these
    events on our customers and suppliers);
    The strength and financial resources of our competitors;
    Development of alternative energy sources;
    The impact of operational and development hazards;
    Costs of, changes in, or the results of laws, government
    regulations (including climate change legislation
    and/or
    potential additional regulation of drilling and completion of
    wells), environmental liabilities, litigation and rate
    proceedings;
    Changes in maintenance and construction costs;
    Changes in the current geopolitical situation;
    Our exposure to the credit risk of our customers;
    Risks related to strategy and financing, including restrictions
    stemming from our debt agreements, future changes in our credit
    ratings and the availability and cost of credit; 43




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##### Table of Contents




    Risks associated with future weather conditions;
    Acts of terrorism; and
    Other factors described in Managements Discussion
    and Analysis of Financial Condition and Results of
    Operations and Business.       44




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##### Table of Contents



USE OF
    PROCEEDS   
       
   
 
 
  
 Sources of Funds




Uses of FundsEstimated net proceeds from the sale
    of           shares
    of Class A common stock in this offering(1)

$
705


Retention of approximately $500 million of the estimated net
    proceeds from the sale of shares of Class A common stock in this
    offering

$
500Distribution of the remaining estimated net proceeds from the
    sale of             shares of Class A common stock in this
    offering to Williams(1)


205Estimated net proceeds from the issuance of the Notes(2)


1,480


Distribution of the estimated net proceeds from the issuance of
    the Notes to Williams(2)


1,480Total

$
2,185




$
2,185  
   
  (1)
    
    Assumes that the shares are offered at
    $      per share of Class A common
    stock, which is the midpoint of the estimated offering price
    range set forth on the cover page of this prospectus. 
 
  (2)
    
    After deducting estimated initial purchasers discounts.
    Assumes the Notes are issued at par. 
 45




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##### Table of Contents



DIVIDEND
    POLICY   46




---



##### Table of Contents



CAPITALIZATION    
    the completion of our restructuring transactions, including the
    forgiveness or contribution to our capital of the unsecured
    notes payable to Williams;
    the receipt of approximately $705 million from the sale of
    shares of Class A common stock offered by us at an assumed
    initial public offering price of $     
    per share, which is the midpoint of the estimated offering price
    range set forth on the cover page of this prospectus, after
    deducting estimated underwriting discounts and commissions and
    estimated offering expenses payable by us; and
    the receipt of approximately $1.5 billion from our expected
    offering of the Notes, after deducting the discounts of the
    initial purchasers of the Notes and the expenses payable by us
    in connection with such offering;
    the distribution of approximately $1.7 billion to Williams
    from the combined net proceeds from this offering and the
    expected offering of the Notes in connection with our
    restructuring transactions.    
 At March 31, 2011Historical


Pro Forma(Millions)Cash and cash equivalents(1)

$
40



540Debt:Senior unsecured credit facility(2)






Unsecured notes payable to Williamscurrent


2,364



Senior unsecured notes






1,500Total debt


2,364



1,500Equity:Owners net investment


4,258



Class A common stock, $     par
    value per
    share,           shares
    authorized
    and           shares
    outstanding


Class B common stock, $     par
    value per
    share,           shares
    authorized
    and           shares
    outstanding


Additional paid-in capital






5,603Noncontrolling interests


74



74Accumulated other comprehensive income


108



108Total equity


4,440



5,785Total capitalization

$
6,804



7,285  
   
  (1)
    
    The pro forma cash and cash equivalents balance does not reflect
    approximately $20 million in cash that Williams will
    provide to us in connection with certain information technology
    transition costs we expect to incur following the completion of
    this offering. See Managements Discussion and
    Analysis of Financial Condition and Results of
    OperationsManagements Discussion and Analysis of
    Financial Condition and LiquidityLiquidity. 
 
  (2)
    
    Our Credit Facility provides for borrowings of up to
    $1.5 billion, all of which is expected to be available to
    us upon the effectiveness of that facility. Our future borrowing
    capacity may be reduced by letters of credit issued under the
    Credit Facility. See Description of our Concurrent
    Financing TransactionsCredit Facility. 
 47




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##### Table of Contents



DILUTION      Assumed initial public offering price per share





$Pro forma net tangible book value per share as of March 31,
    2011 after giving effect to our restructuring transactions but
    before giving effect to this offering

$Change in pro forma net tangible book value per share
    attributable to new investors purchasing shares in this offering

$Less: Pro forma net tangible book value per share after giving
    effect to this offering





$Dilution in pro forma net tangible book value per share to new
    investors





$       Percentage








AverageShares Acquired


of Voting


Total Consideration


Price PerNumber


Percent


Rights


Amount


Percent


ShareWilliams







%



%

$




0
%

$
New investors in this offering














750



100Total






100
%


100
%

$
750



100
%

$     
    the number of shares of Class A common stock held by new
    investors will increase
    to          ,
    or approximately     % of our total
    outstanding common stock and
    approximately     % of the total voting
    power of our common stock; and
    the number of shares of our Class B common stock held by
    Williams will be reduced
    to          ,
    or approximately     % of our total
    outstanding common stock and
    approximately     % of the total voting
    power of our common stock. 48




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##### Table of Contents



SELECTED
    HISTORICAL COMBINED FINANCIAL DATA        Three Months Ended March 31,


Year Ended December 31,2011


2010


2010


2009


2008


2007


2006(Millions)Statement of operations data:Revenues

$
984


$
1,164


$
4,034


$
3,681


$
6,184


$
4,479


$
4,627Income (loss) from continuing operations(1)


7



83



(1,274
)


149



817



192



104Income (loss) from discontinued operations(2)


(8
)






(8
)


(7
)


(87
)


146



6Net income (loss)


(1
)


83



(1,282
)


142



730



338



110Less: Net income attributable to noncontrolling interests


2



2



8



6



8



11



12Net income (loss) attributable to WPX Energy

$
(3
)

$
81


$
(1,290
)

$
136


$
722


$
327


$
98   As ofMarch 31,


As of December 31,2011


2010


2009


2008


2007


2006Balance sheet dataNotes payable to Williams  current

$
2,364


$
2,261


$
1,216


$
925


$
656


$
Notes receivable from Williams






















64Third party debt






















34Total assets


9,764



9,846



10,553



11,624



10,571



11,223Total equity


4,440



4,500



5,405



5,506



4,356



4,376     (1)
    
    Loss from continuing operations in 2010 includes
    $1.7 billion of impairment charges related to goodwill,
    producing properties in the Barnett Shale and costs of acquired
    unproved reserves in the Piceance Basin. Income from continuing
    operations in 2008 includes a $148 million gain related to
    the sale of a right to an international production payment. See
    Notes 6 and 14 of Notes to Combined Financial Statements
    for further discussion of asset sales, impairments and other
    accruals in 2010, 2009 and 2008.(2)
    
    Income (loss) from discontinued operations includes our Arkoma
    operations which were classified as held for sale as of
    March 31, 2011 and Williams former power business
    that was substantially disposed of in 2007. The activity in 2010
    and 2009 primarily relates to the Arkoma operations and the
    remaining indemnity and 49




---



##### Table of Contents



other obligations related to the former power business. Activity
    in 2008 reflects a $148 million pre-tax impairment charge
    related to the producing properties in the Arkoma Basin.
    Activity in 2007 and 2006 primarily reflects the operations of
    the power business and 2007 includes a pre-tax gain of
    $429 million associated with the reclassification of
    deferred net hedge gains from accumulated other comprehensive
    income (loss) to earnings based on the determination that the
    hedged forecasted transactions were probable of not occurring
    due to the sale of Williams power business. This gain is
    partially offset by a pre-tax unrealized
    mark-to-market
    loss of $23 million, a $37 million loss from
    operations and $111 million of pre-tax impairments
    primarily related to the carrying value of certain derivative
    contracts. 50




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##### Table of Contents



MANAGEMENTS
    DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
    OPERATIONS   
      Basis of
    Presentation
 
   
   51




---



##### Table of Contents



Corporate Services.
  Employee Benefits and Incentives.
   
  Interest Expense.
 
      Overview
    of the three months ended March 31, 2011 and 2010
   52




---



##### Table of Contents



For the Three Months Ended March 31,2011


2010


% ChangeAverage daily domestic production (MMcfe/d)


1,155



1,091



+6
%Average daily total production (MMcfe/d)


1,210



1,145



+6
%Domestic production realized average price ($/Mcfe)(1)

$
5.28


$
5.77



-8
%Capital expenditures and acquisitions ($ millions)

$
319


$
284



12
%Domestic oil and gas revenues ($ millions)

$
549


$
567



(3
)%Revenues ($ millions)

$
984


$
1,164



(15
)%Operating income ($ millions)

$
49


$
143



(66
)%     (1)
    
    Realized average prices include market prices, net of fuel and
    shrink and hedge gains and losses. The realized hedge gain per
    Mcfe was $0.73 and $0.29 for the first three months of 2011 and
    2010, respectively.  Overview
    of 2010
        cost-of-service
   53




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##### Table of Contents



Years Ended December 31,2010


2009


% ChangeAverage daily domestic production
    (MMcfe/d)


1,121



1,170



(4)
%Average daily total production
    (MMcfe/d)


1,174



1,224



(4)
%Domestic production realized average price ($/Mcfe)(1)

$
5.22


$
4.89



7
%Capital expenditures and acquisitions ($ millions)

$
2,805


$
1,434



96
%Domestic oil and gas revenues ($ millions)

$
2,136


$
2,090



2
%Revenues ($ millions)

$
4,034


$
3,681



10
%Operating income (loss) ($ millions)

$
(1,337
)

$
317



NM     (1)
    
    Realized average prices include market prices, net of fuel and
    shrink and hedge gains and losses. The realized hedge gain per
    Mcfe was $0.81 and $1.44 for 2010 and 2009, respectively.      Outlook
    for 2011
     
   
    
    Continuing to invest in and grow our production and reserves; 54




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##### Table of Contents




    Retaining the flexibility to make adjustments to our planned
    levels of capital and investment expenditures in response to
    changes in economic conditions or business opportunities;
    Continuing to diversify our commodity portfolio through the
    development of our Bakken Shale oil play position and
    liquids-rich basins with high concentrations of NGLs;
    Maintaining our industry leadership position in relationship to
    costs; and
    Continuing to maintain an active hedging program around our
    commodity price risks.    
    Lower than anticipated energy commodity prices;
    Lower than expected levels of cash flow from operations;
    Unavailability of capital;
    Higher capital costs of developing unconventional shale
    properties;
    Counterparty credit and performance risk;
    Decreased drilling success;
    General economic, financial markets or industry downturn;
    Changes in the political and regulatory environments; and
    Increase in the cost of, or shortages or delays in the
    availability of, drilling rigs and equipment, supplies, skilled
    labor or transportation.    Commodity
    Price Risk Management
    2011 Natural GasWeighted AveragePrice ($/MMBtu)Volume


Floor-Ceiling(BBtu/d)


for CollarsCollar agreements  Rockies


45


$5.30 - $7.10Collar agreements  San Juan


90


$5.27 - $7.06Collar agreements  Mid-Continent


80


$5.10 - $7.00Collar agreements  Southern California


30


$5.83 - $7.56Collar agreements  Appalachia


30


$6.50 - $8.14Fixed price at basin swaps


375


$5.19   2011 Crude OilVolume


Weighted Average(Bbls/d)


Price ($/Bbl)WTI Crude Oil fixed-price


3,917


$
96.01  55




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##### Table of Contents



Natural GasThree Months Ended March 31,2011

2010Weighted




WeightedAverage Price




Average Price($/MMBtu)




($/MMBtu)Volume


Floor-Ceiling

Volume


Floor-Ceiling(BBtu/d)


for Collars

(BBtu/d)


for CollarsCollar agreements   Rockies


45


$5.30 - $7.10


100


$6.53 -$8.94Collar agreements   San Juan


90


$5.27 - $7.06


240


$5.72 - $7.77Collar agreements   Mid-Continent


80


$5.10 - $7.00


105


$5.37 - $7.41Collar agreements   Southern California


30


$5.83 - $7.56


45


$4.80 - $6.43Collar agreements   Appalachia


30


$6.50 - $8.14


20


$5.54 - $6.81NYMEX and basis fixed-price swaps


344


$5.24


120


$4.42   Crude OilThree Months Ended March 31,2011


2010Weighted





WeightedVolume


Average Price


Volume


Average Price(Bbls/d)


($/Bbl)


(Bbls/d)


($/Bbl)WTI Crude Oil fixed-price


1,475



94.84







     2010

2009

2008Weighted Average




Weighted Average




Weighted AveragePrice ($/MMBtu)




Price ($/MMBtu)




Price ($/MMBtu)Volume


Floor-Ceiling

Volume


Floor-Ceiling

Volume


Floor-Ceiling(BBtu/d)


for Collars

(BBtu/d)


for Collars

(BBtu/d)


for CollarsCollar agreements  Rockies


100


$6.53 - $8.94


150


$6.11 - $9.04


170


$6.16 - $9.14Collar agreements  San Juan


233


$5.75 - $7.82


245


$6.58 - $9.62


202


$6.35 - $8.96Collar agreements  Mid-Continent


105


$5.37 - $7.41


95


$7.08 - $9.73


63


$7.02 - $9.72Collar agreements  Southern California


45


$4.80 -$6.43











Collar agreements  Other


28


$5.63 - $6.87











NYMEX and basis fixed-price swaps


120


$4.40


106


$3.67


70


$3.97    56




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##### Table of Contents



Results
    of Operations
  Three
    Month-Over-Three
    Month Results of Operations
    HistoricalThree Months EndedMarch 31,2011





2010(Millions)% changefrom 2010Revenues:Oil and gas sales, including affiliate

$
572



(3
)%

$
587Gas management, including affiliate


408



(27
)%


556Hedge ineffectiveness and
    mark-to-market
    gains


2



(78
)%


9Other


2



(83
)%


12Total revenues

$
984






$
1,164Costs and expenses:Lease and facility operating, including affiliate


70



6
%


66Gathering, processing and transportation, including affiliate


115



60
%


72Taxes other than income


31



(23
)%


40Gas management (including charges for unutilized pipeline
    capacity)


417



(25
)%


558Exploration


13



63
%


8Depreciation, depletion and amortization


216







216General and administrative, including affiliate


70



15
%


61Other  net


3



NM



Total costs and expenses

$
935






$
1,021Operating income

$
49






$
143Interest expense, including affiliate


(49
)


96
%


(25
)Interest capitalized


4







4Investment income and other


6



20
%


5Income before income taxes

$
10






$
127Provision (benefit) for income taxes


3



(93
)%


44Income from continuing operations

$
7






$
83Loss from discontinued operations


(8
)


NM



Net income (loss)

$
(1
)





$
83Less: Net income attributable to noncontrolling interests


2







2Net income (loss) attributable to WPX Energy

$
(3
)





$
81         
    $15 million lower oil and gas sales revenues, comprised of
    a decrease of $50 million associated with an
    eight percent decrease in realized average prices including
    the effect of hedges, partially offset by an increase of
    $33 million associated with a six percent increase in
    production volumes sold. Oil and gas 57




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##### Table of Contents



sales in 2011 and 2010 include approximately $97 million
    and $70 million, respectively, related to natural gas
    liquids and approximately $34 million and $11 million,
    respectively, related to oil and condensate. The increase in NGL
    revenues is primarily due to higher volumes in our Piceance
    Basin related to Williams Partners Willow Creek facility.
    The increase in crude and condensate is primarily related to our
    Bakken properties which were acquired in the fourth quarter of
    2010;  
    $148 million decrease in gas management revenues primarily
    due to a 19 percent decrease in average prices on physical
    natural gas sales and 9 percent lower natural gas sales
    volumes. We experienced a similar decrease of $141 million
    in related costs and expenses; and
    $10 million decrease in other revenues primarily related to
    gathering revenues associated with the gathering and processing
    assets in Colorados Piceance Basin that we sold to
    Williams Partners in the fourth quarter of 2010.    
    $9 million lower taxes other than income, including
    severance and ad valorem, primarily due to lower average
    commodity prices (excluding the impact of hedges). Our domestic
    production taxes averaged $0.27 per Mcfe in the first quarter of
    2011 and $0.37 per Mcfe in the first quarter of 2010. The
    decrease in the per unit amount is primarily the result of lower
    average domestic commodity prices; and
    $141 million decrease in gas management expenses, primarily
    due to an 18 percent decrease in average prices on physical
    natural gas purchases and a nine percent decrease in
    natural gas purchase volumes. These gas purchases were made in
    connection with our gas purchase activities for Williams
    Partners and certain working interest owners share of
    production and to manage our transportation and storage
    activities. The sales associated with our marketing of this gas
    are included in gas management revenues. Also included in gas
    management expenses are $10 million in the first quarter of
    2011 and $13 million in the first quarter of 2010 for
    unutilized pipeline capacity.    
    $4 million higher lease and facility operating expenses
    which reflects higher expenses associated with increased
    workover, water management and maintenance activity, offset by
    the absence in 2011 of $11 million in expenses associated
    with the previously owned gathering and processing assets. 
  
    $43 million higher gathering, processing, and
    transportation expenses primarily as a result of fees paid to
    Williams Partners in 2011 for gathering and processing
    associated with certain gathering and processing assets in the
    Piceance Basin that we sold to Williams Partners in the fourth
    quarter of 2010 and an increase in natural gas liquids volumes
    processed at Williams Partners Willow Creek plant. Our
    domestic gathering, processing and transportation expenses
    averaged $1.11 per Mcfe in the first quarter of 2011 and $0.73
    per Mcfe in the first quarter of 2010. In the first quarter of
    2011, gathering, processing and transportation expenses were
    $34 million ($0.33/Mcfe) higher due to fees paid to
    Williams Partners pursuant to the gathering and processing
    agreement associated with the assets we sold to Williams
    Partners in the fourth quarter of 2010. During the first quarter
    of 2010, operating costs included $21 million ($0.20/Mcfe)
    associated with these assets (primarily reflected in lease and
    facility operating costs ($11 million) and depreciation,
    depletion and amortization ($6 million)). These costs are
    no longer directly incurred as operating costs (but rather as
    gathering, processing and transportation expenses) as we no
    longer own or operate these assets. 
  
    $5 million higher exploration expenses primarily due to an
    increase in impairment, amortization and expiration of unproved
    leasehold costs; and
    $9 million higher general and administrative expenses
    primarily due to higher wages, salary and benefits costs as a
    result of an increase in the number of employees.   58




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##### Table of Contents



Year-Over-Year
    Results of Operations
    HistoricalYear Ended December 31,2010





2009





2008(Millions)% Change





% Changefrom 2009





from 2008Revenues:Oil and gas sales, including affiliate

$
2,225



3
%

$
2,168



(25
%)

$
2,882Gas management, including affiliate


1,742



20
%


1,456



(55
%)


3,241Hedge ineffectiveness and
    mark-to-market
    gains and losses


27



50
%


18



(38
%)


29Other


40



3
%


39



22
%


32Total revenues

$
4,034






$
3,681






$
6,184Costs and expenses:Lease and facility operating, including affiliate

$
286



9
%

$
263



(3
%)

$
272Gathering, processing and transportation, including affiliate


326



19
%


273



19
%


229Taxes other than income


125



34
%


93



(63
%)


254Gas management (including charges for unutilized pipeline
    capacity)


1,771



18
%


1,495



(54
%)


3,248Exploration


73



35
%


54



46
%


37Depreciation, depletion and amortization


875



(1
%)


887



20
%


738Impairment of producing properties and costs of acquired
    unproved reserves


678



NM



15



NM



Goodwill impairment


1,003



NM







NM



General and administrative, including affiliate


253



1
%


251



2
%


247Gain on sale of contractual right to international production
    payment






NM







NM



(148
)Other  net


(19
)


NM



33



NM



6Total costs and expenses

$
5,371






$
3,364






$
4,883Operating income (loss)

$
(1,337
)





$
317






$
1,301Interest expense, including affiliate


(124
)


24
%


(100
)


35
%


(74
)Interest capitalized


16



(11
%)


18



(10
%)


20Investment income and other


21



163
%


8



(64
%)


22Income (loss) before income taxes

$
(1,424
)





$
243






$
1,269Provision (benefit) for income taxes


(150
)


NM



94



(79
%)


452Income (loss) from continuing operations

$
(1,274
)





$
149






$
817Loss from discontinued operations


(8
)






(7
)






(87
)Net income (loss)

$
(1,282
)





$
142






$
730Less: Net income attributable to noncontrolling interests


8



33
%


6



(25
%)


8Net income (loss) attributable to WPX Energy

$
(1,290
)





$
136






$
722      59




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##### Table of Contents



2010 vs.
    2009
    
    $57 million higher oil and gas sales revenues from an
    increase of $134 million resulting from a
    seven percent increase in domestic realized average prices
    including the effect of hedges, partially offset by a decrease
    of $88 million associated with a four percent decrease in
    domestic production volumes sold. Oil and gas revenues in 2010
    and 2009 include approximately $282 million and
    $136 million, respectively, related to NGLs and
    approximately $57 million and $38 million,
    respectively, related to condensate; and
    $286 million higher gas management revenues primarily from
    a 21 percent increase in average prices on domestic
    physical natural gas sales associated with our transportation
    and storage contracts. There is a similar increase of
    $276 million in related costs and expenses.    
    $23 million higher lease and facility operating expenses
    due to increased activity and generally higher industry costs.
    Our average domestic lease and facility operating expenses are
    $0.65 per Mcfe in 2010 and $0.58 per Mcfe in 2009. The increase
    in the per unit amount results primarily from an increase in
    costs incurred to maintain individual well production rates and
    higher industry costs;
    $53 million higher gathering, processing and transportation
    expenses, primarily as a result of processing fees charged by
    Williams Partners at its Willow Creek plant for extracting NGLs
    from a portion of our Piceance Basin gas production. Our
    domestic gathering, processing and transportation expenses
    averaged $0.80 per Mcfe in 2010 and $0.64 per Mcfe in 2009. The
    increase in the per unit amount is primarily a result of the
    Willow Creek plant going into service in August 2009 resulting
    in a partial year of processing. This processing provides us
    additional NGL recovery, the revenues for which are included in
    oil and gas sales in the Combined Statement of Operations;
    $32 million higher taxes other than income, including
    severance and ad valorem, primarily due to higher average
    commodity prices (excluding the impact of hedges). Our domestic
    production taxes averaged $0.27 per Mcfe in 2010 and $0.19 per
    Mcfe in 2009. The increase in the per unit amount is primarily
    the result of higher average domestic commodity prices;
    $276 million increase in gas management expenses, primarily
    due to a 18 percent increase in average prices on domestic
    physical natural gas purchases. These gas purchases were made in
    connection with our gas purchase activities for Williams
    Partners and certain working interest owners share of
    production, and to manage our transportation and storage
    activities. The sales associated with our marketing of this gas
    are included in gas management revenues. Also included in gas
    management expenses are $48 million in 2010 and
    $21 million in 2009 for unutilized pipeline capacity;
    $19 million higher exploration expense primarily due to an
    increase in impairment, amortization and expiration of unproved
    leasehold costs; and
    $1,681 million impairments of property and goodwill in 2010
    as previously discussed. In 2009, $15 million of
    impairments were recorded in the Barnett Shale.    
    $12 million lower depreciation, depletion and amortization
    expenses primarily due to lower domestic production
    volumes; and
    Other  net includes $32 million of expenses in
    2009 related to penalties from the early release of drilling
    rigs.   60




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##### Table of Contents



2009 vs.
    2008
    
    $714 million lower oil and gas sales revenues primarily
    from a $947 million decrease resulting from a
    31 percent decrease in domestic realized average prices,
    partially offset by an increase of $226 million associated
    with an eight percent increase in domestic production volumes
    sold. Oil and gas revenues in 2009 and 2008 include
    approximately $136 million and $89 million,
    respectively, related to NGLs and approximately $38 million
    and $62 million, respectively, related to condensate. While
    NGL volumes were significantly higher than the prior year, NGL
    prices were significantly lower;
    $1,785 million lower gas management revenues primarily from
    a 56 percent decrease in average prices on domestic
    physical natural gas sales associated with our transportation
    and storage contracts. There is a similar decrease of
    $1,753 million in related costs and expenses; and
    $11 million lower hedge ineffectiveness and
    mark-to-market
    gains and losses primarily due to the absence of a
    $10 million favorable impact in 2008 for the initial
    consideration of our own nonperformance risk in estimating the
    fair value of our derivative liabilities.    
    $161 million lower taxes other than income, including
    severance and ad valorem, primarily due to 51 percent lower
    average commodity prices (excluding the impact of hedges),
    partially offset by higher production volumes sold. The lower
    operating taxes include a net decrease of $39 million
    reflecting a $34 million charge in 2008 and $5 million
    of favorable revisions in 2009 relating to Wyoming severance and
    ad valorem taxes. Our domestic production taxes averaged $0.19
    per Mcfe in 2009 and $0.61 per Mcfe in 2008. The decrease in the
    per unit amount is primarily the result of lower average
    commodity prices;
    $1,753 million decrease in gas management expenses,
    primarily due to a 55 percent decrease in domestic average
    prices on physical natural gas purchases, slightly offset by a
    2 percent increase in natural gas purchase volumes. This
    decrease is primarily related to the natural gas purchases
    associated with our previously discussed transportation and
    storage contracts and is more than offset by a decrease in
    revenues. Gas management expenses in 2009 and 2008 include
    $21 million and $8 million, respectively, related to
    charges for unutilized pipeline capacity. Gas management
    expenses in 2009 and 2008 also include $7 million and
    $35 million, respectively, related to lower of cost or
    market charges to the carrying value of natural gas inventories
    in storage; and    
    $44 million higher gathering, processing and transportation
    expense primarily due to higher production volumes and the
    processing fees for NGLs at Williams Partners Willow Creek
    plant, which began processing in August 2009. Our domestic
    gathering, processing and transportation expenses averaged $0.64
    per Mcfe in 2009 and $0.58 per Mcfe in 2008. The increase in the
    per unit amount is primarily a result of the initiation of
    processing at the Willow Creek plant in 2009 as previously
    discussed; and
    $17 million higher exploration expense primarily due to an
    increase in geologic and geophysical services.
    $149 million higher depreciation, depletion and
    amortization expense primarily due to higher capitalized
    drilling costs from prior years and higher production volumes
    compared to the prior year. Also, we recorded an additional
    $17 million of depreciation, depletion and amortization in
    the fourth 61




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##### Table of Contents



quarter of 2009 primarily due to new SEC reserves reporting
    rules. Our proved reserves decreased primarily due to the new
    SEC reserves reporting rules and the related price impact;  
    The absence in 2009 of a $148 million gain recorded in 2008
    from the sale of our contractual right to a production payment
    in Peru;
    $32 million of expense in 2009 related to penalties from
    the early release of drilling rigs as previously
    discussed; and
    $15 million of impairment expense in 2009 related to costs
    of acquired unproved reserves from our 2008 acquisition in the
    Barnett Shale. This impairment was based on our assessment of
    estimated future discounted cash flows and additional
    information obtained from drilling and other activities in 2009.      Managements
    Discussion and Analysis of Financial Condition and
    Liquidity
  Overview
      
    As of March 31, 2011, Williams maintained liquidity through
    cash, cash equivalents and available credit capacity under
    credit facilities. Additionally, at that date we had an
    unsecured credit agreement that served to reduce our margin
    requirements related to our hedging activities. See additional
    discussion in the following Liquidity section.
    Our credit exposure to derivative counterparties is partially
    mitigated by master netting agreements and collateral support.
    Apcos liquidity requirements have historically been
    provided by its cash flows from operations.  Outlook
   62




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##### Table of Contents




    Our capital expenditures are estimated to be between
    $1.3 billion and $1.6 billion, and are generally
    considered to be largely discretionary; and
    Apcos liquidity requirements will continue to be provided
    from its cash flows from operations and available liquidity
    under its credit facility.    
    Sustained reductions in energy commodity prices from the range
    of current expectations;
    Lower than expected levels of cash flow from operations; and
    Higher than expected collateral obligations that may be
    required, including those required under new commercial
    agreements.  Liquidity
         
   
 63




---



##### Table of Contents



Sources
    (Uses) of Cash
  Three
    Months-Over-Three
    Months
    Three MonthsEnded March 31,2011


2010(Millions)Net cash provided (used) by:Operating activities

$
240


$
329Investing activities


(342
)


(286
)Financing activities


105



(39
)Increase in cash and cash equivalents

$
3


$
4   Operating
    activities
    Investing
    activities
    Financing
    activities
    Year-Over-Year
    Years Ended December 31,2010


2009


2008(Millions)Net cash provided (used) by:Operating activities

$
1,056


$
1,181


$
2,009Investing activities


(2,337
)


(1,435
)


(2,252
)Financing activities


1,284



256



225Increase (decrease) in cash and cash equivalents

$
3


$
2


$
(18
)   Operating
    activities
     64




---



##### Table of Contents



Investing
    activities
      2010
  
    Expenditures for drilling and completion were approximately
    $950 million.
    Our acquisition in July 2010 of properties in the Marcellus
    Shale for $599 million (see Overview of
    2010).
    Our acquisition in December 2010 of oil and gas properties in
    the Bakken Shale for $949 million (see Overview
    of 2010).
    The sale in November 2010 of certain gathering and processing
    assets in the Piceance Basin to Williams Partners for
    $702 million in cash and approximately 1.8 million
    Williams Partners common units, which units were subsequently
    distributed to Williams.  2009
  
    Expenditures for drilling and completion were approximately
    $1.0 billion.
    A $253 million payment for the purchase of additional
    properties in the Piceance Basin.  2008
  
    Expenditures for drilling and completion were approximately
    $1.65 billion.
    Acquisitions of certain interests in the Piceance Basin for
    $285 million. A third party subsequently exercised its
    contractual option to purchase a 49 percent interest in a
    portion of the acquired assets for $71 million.
    Our sale of a contractual right to a production payment in Peru
    for $148 million.  Financing
    activities
    Off-Balance
    Sheet Financing Arrangements
   65




---



##### Table of Contents



Contractual
    Obligations
    April 1 -December 31,


2012 -


2014 -2011


2013


2015


Thereafter


Total(Millions)Operating leases and associated service commitmentsDrilling rig commitments(1)

$
75


$
83


$
43


$



$
201Other


6



7



5



16



34Transportation and storage commitments


152



402



347



634



1,535Natural gas purchase commitments(2)


141



417



388



922



1,868Oil and gas activities(3)


110



269



128



216



723Other long-term liabilities, including current portion:Physical and financial derivatives(4)(5)


459



1,100



909



3,666



6,134Total

$
943


$
2,278


$
1,820


$
5,454


$
10,495     (1)
    
    Includes materials and services obligations associated with our
    drilling rig contracts.(2)
    
    Purchase commitments are at market prices and the purchased
    natural gas can be sold at market prices. The obligations are
    based on market information as of March 31, 2011 and
    contracts are assumed to remain outstanding for their full
    contractual duration. Because market information changes daily
    and is subject to volatility, significant changes to the values
    in this category may occur.(3)
    
    Includes gathering, processing and other oil and gas related
    services commitments. Excluded are liabilities associated with
    asset retirement obligations, which total $296 million as
    of March 31, 2011. The ultimate settlement and timing can
    not be precisely determined in advance; however we estimate that
    less than 10% of this liability will be settled in the next five
    years.(4)
    
    Includes $5.3 billion of physical natural gas derivatives
    related to purchases at market prices. The natural gas expected
    to be purchased under these contracts can be sold at market
    prices, largely offsetting this obligation. The obligations for
    physical and financial derivatives are based on market
    information as of March 31, 2011, and assume contracts
    remain outstanding for their full contractual duration. Because
    market information changes daily and is subject to volatility,
    significant changes to the values in this category may occur.(5)
    
    Expected offsetting cash inflows of $2.4 billion at
    March 31, 2011, resulting from product sales or net
    positive settlements, are not reflected in these amounts. In
    addition, product sales may require additional purchase
    obligations to fulfill sales obligations that are not reflected
    in these amounts.  Effects
    of Inflation
    Environmental
   66




---



##### Table of Contents



eight-hour eight-hour eight-hour
      one-hour
    Quantitative
    and Qualitative Disclosures About Market Risk
  Interest
    Rate Risk
   67




---



##### Table of Contents



Commodity
    Price Risk
    value-at-risk one-day value-at-risk one-day value-at-risk one-day one-day
    Value-at-risk
  Trading
    Nontrading
      value-at-risk
 68




---



##### Table of Contents



Critical
    Accounting Estimates
      Impairments
    of Goodwill and Long-Lived Assets
  year-to-date
    step-up
     69




---



##### Table of Contents



Accounting
    for Derivative Instruments and Hedging Activities
    
    qualifying for and electing cash flow hedge accounting, which
    recognizes changes in the fair value of the derivative in other
    comprehensive income (to the extent the hedge is effective)
    until the hedged item is recognized in earnings;
    qualifying for and electing accrual accounting under the normal
    purchases and normal sales exception; or
    applying
    mark-to-market
    accounting, which recognizes changes in the fair value of the
    derivative in earnings.  mark-to-market
   70




---



##### Table of Contents



Combined Statement of Operations

Combined Balance SheetAccounting Method

Drivers

Impact

Drivers

ImpactAccrual Accounting

Realizations

Less Volatility

None

No ImpactCash Flow Hedge
    Accounting

Realizations &
    Ineffectiveness

Less Volatility

Fair Value Changes

More VolatilityMark-to-Market
    Accounting

Fair Value Changes

More Volatility

Fair Value Changes

More Volatility       Successful
    Efforts Method of Accounting for Oil and Gas Exploration and
    Production Activities
    
    An increase (decrease) in estimated proved oil and gas reserves
    can reduce (increase) our
    unit-of-production
    depreciation, depletion and amortization rates; and
    Changes in oil and gas reserves and forward market prices both
    impact projected future cash flows from our oil and gas
    properties. This, in turn, can impact our periodic impairment
    analyses.   71




---



##### Table of Contents



Contingent
    Liabilities
    Valuation
    of Deferred Tax Assets and Liabilities
     72




---



##### Table of Contents



Fair
    Value Measurements
             73




---



##### Table of Contents



BUSINESS  Overview
   
   
    
 Estimated Net


May 2011





2011 Budget EstimateProved Reserves


Average Daily








Drilling% Proved


Net Production


Net


Gross


Capital(2)


PV-10(3)Basin/Shale

Bcfe


Developed


(MMcfe/d)(1)


Acreage


Wells


(Millions)


(Millions)Piceance Basin


2,927



53
%


714



211,000



376


$
575


$
2,707Bakken Shale(4)


136



11
%


38



89,420



41



260



399Marcellus Shale


28



71
%


8



99,301



62



170



29Powder River Basin


348



75
%


220



425,550



411



70



317San Juan Basin


554



79
%


135



120,998



51



40



477Apco(5)


190



60
%


58



404,304



37



30



358Other(6)


290



72
%


89



327,390



94



85



257Total


4,473



59
%


1,262



1,677,963



1,072


$
1,230


$
4,544  
   
  (1)
    
    Represents average daily net production of our continuing
    operations for the month of May 2011. 
  (2)
    
    Based on the midpoint of our estimated capital spending range.(3)
    
    PV-10 is a
    non-GAAP financial measure and generally differs from
    Standardized Measure, the most directly comparable GAAP
    financial measure, because it does not include the effects of
    income taxes on future net revenues. Neither
    PV-10 nor
    Standardized Measure represents an estimate of the fair market
    value of our oil and natural gas assets. We and others in the
    industry use
    PV-10 as a
    measure to compare the relative size and value of proved
    reserves held by companies without regard to the specific tax
    characteristics of such entities. For a definition of
    PV-10 and a
    reconciliation of
    PV-10 to
    Standardized Measure, see Prospectus SummarySummary
    Combined Historical Operating and Reserve
    DataNon-GAAP Financial Measures and
    Reconciliations.(4)
    
    Our estimated net proved reserves in the Bakken Shale have not
    been audited by independent reserve engineers. 
  (5)
    
    Represents approximately 69 percent of each metric (which
    corresponds to our ownership interest in Apco) except Percent
    Proved Developed, Gross Wells and Drilling Capital. 
 74




---



##### Table of Contents



(6)
    
    Other includes Barnett Shale, Arkoma and Green River Basins and
    miscellaneous smaller properties. May 2011 average daily net
    production excludes Arkoma production of approximately nine
    MMcfe/d as our Arkoma Basin operations were classified as held
    for sale and reported as discontinued operations as of
    March 31, 2011. 
  2011
    Capital Expenditures Budget
    
    approximately $1.23 billion for development
    drilling; and
    approximately $0.22 billion for facilities, infrastructure,
    and land/acquisitions.    Our
    Business Strategy
    
    Efficiently Allocate Capital for Optimal Portfolio
    Returns.  We expect to allocate capital to the
    most profitable opportunities in our portfolio based on
    commodity price cycles and other market conditions, enabling us
    to continue to grow our reserves and production in a manner that
    maximizes our return on investment. In determining which
    drilling opportunities to pursue, we target a minimum after-tax
    internal rate of return on each operated well we drill of
    15 percent. While we have a significant portfolio of
    drilling opportunities that we believe meet or exceed our return
    targets even in challenging commodity price environments, we are
    disciplined in our approach to capital spending and will adjust
    our drilling capital expenditures based on our level of expected
    cash flows, access to capital and overall liquidity position.
    For example, in 2009 we demonstrated our capital discipline by
    reducing drilling expenditures in response to prevailing
    commodity prices and their impact on these factors. 
  
    Continue Our Cost-Efficient Development
    Approach.  We focus on developing properties where
    we can apply development practices that result in
    cost-efficiencies. We manage costs by focusing on establishing
    large scale, contiguous acreage blocks where we can operate a
    majority of the properties. We believe this strategy allows us
    to better achieve economies of scale and apply continuous
    technological improvements in our operations. We intend to
    replicate these cost-efficient approaches in our recently
    acquired growth positions in the Bakken Shale and the Marcellus
    Shale. 
  
    Pursue Strategic Acquisitions with Significant Resource
    Potential.  We have a history of acquiring
    undeveloped properties that meet our disciplined return
    requirements and other acquisition criteria to 75




---



##### Table of Contents



expand upon our existing positions as well as acquiring
    undeveloped acreage in new geographic areas that offer
    significant resource potential. This is illustrated by our
    recent acquisitions in the Bakken Shale and the Marcellus Shale.
    We seek to continue expansion of current acreage positions and
    opportunistically acquire acreage positions in new areas where
    we feel we can establish significant scale and replicate our
    cost-efficient development approach. 
 
  
    Target a More Balanced Commodity Mix in Our Production
    Profile.  With our Bakken Shale acquisition in
    December 2010 and our liquids-rich Piceance Basin assets, we
    have a significant drilling inventory of oil- and liquids-rich
    opportunities that we intend to develop rapidly in order to
    achieve a more balanced commodity mix in our production. We
    refer to the Piceance Basin as liquids-rich because
    our proved reserves in that basin consist of wet, as
    opposed to dry, gas and have a significant liquids
    component. Our current estimated proved reserves of NGLs and
    condensate in the Piceance Basin are 95 MMbbl and
    3 MMbbl, respectively. We will continue to pursue other
    oil- and liquids-rich organic development and acquisition
    opportunities that meet our investment returns and strategic
    criteria. 
 
  
    Maintain Substantial Financial Liquidity and Manage Commodity
    Price Sensitivity.  We plan to conservatively
    manage our balance sheet and maintain substantial liquidity
    through a mix of cash on hand and availability under our Credit
    Facility. In addition, we have engaged and will continue to
    engage in commodity hedging activities to maintain a degree of
    cash flow stability. Typically, we target hedging approximately
    50 percent of expected revenue from domestic production
    during a current calendar year in order to strike an appropriate
    balance of commodity price upside with cash flow protection,
    although we may vary from this level based on our perceptions of
    market risk. At May 31, 2011, our estimated domestic
    natural gas production revenues were 65 percent hedged for
    2011 and 44 percent hedged for 2012. Estimated domestic oil
    production revenues were 49 percent hedged for 2011 and
    49 percent hedged for 2012 as of the same date. 
  Our
    Competitive Strengths
   
  
    A Leading Piceance Basin Cost Structure.  We
    have a large position in the lower cost valley area of the
    Piceance Basin, which we believe provides us economies
    associated with lower elevation drilling and large contiguous
    operations, allowing us to continuously drive down operating
    costs and increase efficiencies. The existing substantial
    midstream infrastructure in the Piceance Basin contributes to
    our cost-efficient structure and provides take-away capacity for
    our natural gas and NGLs. Because of this cost-efficient
    structure in the Piceance Basin, we have the ability to generate
    returns that we believe are in excess of those typically
    associated with Rockies producers. 
  
    Attractive Asset Base Across a Number of High Growth
    Areas.  In addition to our large scale Piceance
    Basin properties, our assets include emerging, high growth
    opportunities such as our Bakken Shale and Marcellus Shale
    positions. Based on our subsurface geological and engineering
    analysis of available well data, we believe our Bakken Shale and
    Marcellus Shale positions are located in core areas of these
    plays, which have associated historic drilling results that we
    believe offer highly attractive economic returns. 
  
    Extensive Drilling Inventory.  As of
    December 31, 2010, we have identified approximately
    2,900 proved undeveloped drilling locations. We have
    budgeted drilling approximately 500 gross operated wells
    during 2011. We have established significant scale in each of
    our core areas of operation that support multi-year development
    plans and allow us to optimally leverage our
    cost-efficient
    development approach. Our drilling inventory provides
    opportunities across diverse geographic markets and products
    including natural gas, oil and NGLs. 
  
    Significant Operating Flexibility.  In the
    Piceance Basin, Bakken Shale and Marcellus Shale, our three
    primary basins, we operate substantially all of our production.
    We expect approximately 91 percent of our projected 2011
    domestic drilling capital will be spent on projects we operate.
    We believe acting as operator on our properties allows us to
    better control costs and capital expenditures, 76




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##### Table of Contents



manage efficiencies, optimize development pace, ensure safety
    and environmental stewardship and, ultimately, maximize our
    return on investment. As operator, we are also able to leverage
    our experience and expertise across all basins and transfer
    technology advances between them as applicable. In addition,
    substantially all of our Piceance Basin properties are held by
    producing wells, which allows us to adjust our level of drilling
    activity in response to changing market conditions.  
    Significant Financial Flexibility.  Our capital
    structure is intended to provide a high degree of financial
    flexibility to grow our asset base, both through organic
    projects and opportunistic acquisitions. Immediately following
    the completion of this offering, we expect to have
    $2.0 billion of liquidity, comprised of availability under
    our $1.5 billion Credit Facility and approximately
    $500 million of cash on hand. We believe our pro forma
    level of debt to proved reserves is low relative to a majority
    of other publicly traded, independent oil and gas producers. 
  
    Management Team with Broad Unconventional Resource
    Experience.  Our management and operating team has
    significant experience acquiring, operating and developing
    natural gas and oil reserves from tight-sands and shale
    formations. Our Chief Executive Officer and his direct reports
    have in excess of 238 collective years of experience running
    large scale drilling programs and drilling vertical and
    horizontal wells requiring complex well design and completion
    methods. Our team has demonstrated the ability to manage large
    scale operations and apply current technological successes to
    new development opportunities. We have deployed members of our
    successful Piceance Basin, Powder River Basin and Barnett Shale
    teams to the Bakken Shale and Marcellus Shale teams to help
    replicate our cost-efficient model and to apply our highly
    specialized technical expertise in the development of those
    resources. 
  Our
    Recent Acquisition History
    Bakken
    Shale
  
    In December 2010, we acquired Dakota-3 E&P Company LLC, a
    company that holds approximately 85,800 net acres on the
    Fort Berthold Indian Reservation in the Williston Basin,
    with then-current net oil production of 3,300 barrels per
    day from 24 existing wells, for $949 million.  Marcellus
    Shale
  
    In July 2010, we acquired 42,000 net acres of largely
    undeveloped properties primarily located in Susquehanna County
    in northeastern Pennsylvania for $599 million.
    During 2010, we also acquired additional unproved leasehold
    acreage positions in the Marcellus Shale for a total of
    $164 million.
    In June 2009, we initiated our strategy of securing acreage in
    the Marcellus Shale with our participation and exploration
    agreement to develop natural gas wells with Rex Energy
    Corporation. We acquired a 50 percent interest in
    44,000 net acres in Pennsylvanias Westmoreland,
    Clearfield and Centre Counties for $33 million in a
    drill to earn structure.  Piceance
    Basin
  
    In September 2009, we completed a bolt-on acquisition of
    21,800 net acres in the Piceance Basin, east of our
    existing properties, for $253 million. The asset included
    then current production of 24 MMcfe/d from 28 wells,
    related gas and water gathering facilities, 94 approved drilling
    permits and more than 800 drillable locations at
    10-acre
    spacing. In December 2009, we increased our working interest in
    these properties through an additional $22 million
    acquisition. 77




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##### Table of Contents




    In May 2008, we acquired 24,000 net acres in the Piceance
    Basin for $285 million. The acreage covered by the
    agreement was contiguous to our existing position in the Ryan
    Gulch area of the Piceance Basin Highlands in Rio Blanco County.
    A third party subsequently exercised its contractual option to
    purchase a 49 percent interest in a portion of the acquired
    assets for $71 million.  Recent
    Sales & Dispositions
  
    In November 2010, we sold certain of our gathering and
    processing assets in Colorados Piceance Basin to Williams
    Partners for $702 million in cash and approximately
    1.8 million Williams Partners common units, which units
    were subsequently distributed to Williams. These assets include
    the Parachute Plant Complex, three other treating facilities
    with a combined processing capacity of 1.2 Bcf/d, and a
    gathering system with approximately 150 miles of pipeline.
    There are more than 3,300 wells connected to the gathering
    system, which includes pipelines ranging up to
    30-inch
    trunk lines. As part of this sale, we agreed to continue to use
    this gathering system for our production in this area for the
    life of our leases. See Other Related Party
    TransactionsAgreements Related to the Piceance
    Disposition.  
    In January 2008, we sold a contractual right to a production
    payment on certain future hydrocarbon production in Peru for
    $148 million. As a result of the contract termination, we
    have no further interests associated with this crude oil
    concession, which we had obtained through our acquisition of
    Barrett Resources Corporation in 2001.  Significant
    Properties
    Piceance
    Basin
   
   
  
    211,000 total net acres, including 108,165 undeveloped net acres;
    2,927 Bcfe of estimated net proved reserves;
    3,587 net producing wells; and 
  
    1,567 undrilled proved drilling locations. 
 
   
   78




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##### Table of Contents



fit-for-purpose state-of-the
  Bakken
    Shale
   
   
  
    89,420 total net acres, including 75,937 undeveloped net acres;
    23 MMboe of estimated net proved reserves; and
    13 net producing wells. 
   
     79




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##### Table of Contents



Marcellus
    Shale
   
   
  
    99,301 total net acres, including 98,387 undeveloped net acres;
    28 Bcfe of estimated net proved reserves; and
    Six net producing wells. 80




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##### Table of Contents



Powder
    River Basin
   
   
  
    425,550 total net acres, including 175,371 undeveloped net acres;
    348 Bcfe of estimated net proved reserves; and
    2,884 net producing wells.        San Juan
    Basin
   81




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##### Table of Contents



non-unit
 
   
  
    120,998 total net acres, including 1,576 undeveloped net acres;
    554 Bcfe of estimated net proved reserves; and
    880 net producing wells.      Apco
 
   
  
    586,288 total net acres, including 556,661 undeveloped net acres;
    45.9 MMboe of estimated net proved reserves; and
    322 net producing wells.      Neuquén Basin. 25-year
   82




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##### Table of Contents



25-year
  Austral Basin Properties.
  Northwest Basin Properties.
  San Jorge Basin Properties.
  Other
    Properties
   
   
  
    327,390 total net acres, including 245,497 undeveloped net acres;
    290 Bcfe of estimated net proved reserves; and
    532 net producing wells. 
   
   83




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##### Table of Contents



Reserves
    and Production Information
    Oil and
    Gas Reserves
      December 31,2010


2009


2008(Bcfe)(1)Proved developed reserves


2,498



2,387



2,456Proved undeveloped reserves


1,774



1,868



1,883Total proved reserves


4,272



4,255



4,339     (1)
    
    Gas equivalents are calculated using a ratio of six thousand
    cubic feet of natural gas to one barrel of oil.  Estimated NetProved ReservesBasin / Shale

December 31, 2010(Bcfe)Piceance Basin


2,927Bakken Shale


136Marcellus Shale


28Powder River Basin


348San Juan Basin


554Other(1)


279Total(2)


4,272     (1)
    
    Other includes Barnett Shale, Arkoma and Green River Basins and
    miscellaneous smaller properties.(2)
    
    Of our total 4,272 Bcfe of net proved reserves as of
    December 31, 2010, three percent are oil.   
  12-month first-of-the-month
 
 84




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Reserves
    estimation process
          well-by-well
      85




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##### Table of Contents



Proved
    undeveloped reserves
        Oil and
    Gas Properties and Production, Production Prices and Production
    Costs
    Year Ended December 31,2010


2009


2008Production Data:Natural Gas (MMcf)U.S.Piceance Basin


245,895



254,617



237,675Other(1)


158,040



167,678



153,206Argentina(2)


7,304



7,728



6,392Total


411,239



430,023



397,273Oil (MBbls)U.S.


859



803



731Argentina(2)


2,035



1,998



1,991Total


2,894



2,801



2,722Combined Equivalent Volumes (MMcfe)(2)


428,603



446,829



413,605Combined Equivalent Volumes (MBoe)


71,434



74,472



68,394Average Daily Combined Equivalent Volumes (MMcfe/d)U.S.Piceance Basin


674



698



649Other(1)


447



472



431Argentina(2)


53



54



50Total


1,174



1,224



1,130  86




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##### Table of Contents



(1)
    
    Excludes production from our Arkoma Basin operations which were
    classified as held for sale and reported as discontinued
    operations as of March 31, 2011 and comprised less than one
    percent of our total production.(2)
    
    Includes approximately 69 percent of Apcos production
    (which corresponds to our ownership interest in Apco) and other
    minor directly held interests.    Year Ended December 31,2010


2009


2008Realized average price per unit(1):Natural gas, without hedges (per Mcf)(2)

$
4.33


$
3.41


$
6.94Impact of hedges (per Mcf)(2)


0.82



1.45



0.10Natural gas, with hedges (per Mcf)(2)

$
5.15


$
4.86


$
7.04Oil, without hedges (per Bbl)

$
66.17


$
44.92


$
84.63Impact of hedges (per Bbl)










Oil, with hedges (per Bbl)

$
66.17


$
44.92


$
84.63Price per Boe, without hedges(3)

$
26.44


$
20.71


$
42.14Price per Boe, with hedges(3)

$
31.32


$
29.36


$
42.66Price per Mcfe, without hedges(3)

$
4.41


$
3.45


$
7.02Price per Mcfe, with hedges(3)

$
5.22


$
4.89


$
7.11     (1)
    
    Excludes our Arkoma Basin operations, which were classified as
    held for sale and reported as discontinued operations as of
    March 31, 2011 and comprised less than one percent of our
    total revenues.(2)
    
    Includes NGLs.(3)
    
    Realized average prices reflect realized market prices, net of
    fuel and shrink.  Year Ended December 31,2010


2009


2008Expenses per Mcfe(1):Operating expenses:Lifting costs and workovers

$
0.46


$
0.39


$
0.45Facilities operating expense


0.14



0.14



0.15Other operating and maintenance


0.05



0.05



0.04Total LOE

$
0.65


$
0.58


$
0.64Gathering, processing and transportation charges


0.80



0.64



0.58Taxes other than income


0.27



0.19



0.61Production cost

$
1.72


$
1.41


$
1.83General and administrative

$
0.60


$
0.57


$
0.61Depreciation, depletion and amortization

$
2.10


$
2.04


$
1.83     (1)
    
    Excludes our Arkoma Basin operations, which were classified as
    held for sale and reported as discontinued operations as of
    March 31, 2011. 87




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##### Table of Contents



Productive
    Oil and Gas Wells
    Gas Wells


Gas Wells


Oil Wells


Oil Wells(Gross)


(Net)


(Gross)


(Net)Piceance Basin


3,923



3,587







Bakken Shale










19



13Marcellus Shale


14



6







Powder River Basin


6,404



2,884







San Juan Basin


3,267



881







Other(1)


1,626



532







Total


15,234



7,890



19



13     *
    
    We use the term gross to refer to all wells or
    acreage in which we have at least a partial working interest and
    net to refer to our ownership represented by that
    working interest.(1)
    
    Other includes Barnett Shale, Arkoma and Green River Basins and
    miscellaneous smaller properties. Our Arkoma Basin operations
    were classified as held for sale and reported as discontinued
    operations as of March 31, 2011 and comprised less than one
    percent of our assets.    Developed
    and Undeveloped Acreage
    Developed


Undeveloped


TotalGross Acres


Net Acres


Gross Acres


Net Acres


Gross Acres


Net AcresPiceance Basin


133,428



102,835



157,017



108,165



290,445



211,000Bakken Shale


16,178



13,483



114,245



75,937



130,423



89,420Marcellus Shale


1,828



914



108,023



98,387



109,851



99,301Powder River Basin


551,113



250,179



399,869



175,371



950,982



425,550San Juan Basin


237,587



119,422



2,100



1,576



239,687



120,998Other(1)


149,414



81,731



326,778



241,254



476,191



322,986Total


1,089,548



568,565



1,108,032



700,690



2,197,580



1,269,255     (1)
    
    Other includes Barnett Shale, Arkoma and Green River Basins,
    other Williston Basin acreage and miscellaneous smaller
    properties. Our Arkoma Basin operations were classified as held
    for sale and reported as discontinued operations as of
    March 31, 2011 and comprised less than one percent of our
    assets. 88




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Drilling
    and Exploratory Activities
      2010


2009


2008Gross Wells



Net Wells



Gross Wells



Net Wells



Gross Wells



Net WellsPiceance Basin


398



360



349



303



687



624Bakken Shale


0



0



n/a



n/a



n/a



n/aMarcellus Shale


8



3



8



4



n/a



n/aPowder River Basin


531



242



233



95



702



324San Juan Basin


43



15



77



39



95



37Other


177



38



208



45



298



65Productive, development


1,157



658



875



486



1,782



1,050Productive, exploration


0



0



3



1



4



2Total Productive


1,157



658



878



487



1,786



1,052Dry, development


5



3



2



0



1



0Dry, exploration


0



0



2



1



0



0Total Drilled


1,162



661



882



488



1,787



1,052     (1)
    
    Other includes Barnett Shale, Arkoma and Green River Basins and
    miscellaneous smaller properties.    Present
    Activities
 
   
  Scheduled
    Lease Expirations
  Domestic.
  2011


2012


2013


2014 +


TotalPiceance Basin


22,456



4,279



5,828



2,950



35,513Bakken Shale


280



17,048



57,715



3,868



78,911Marcellus Shale


984



2,288



46,310



61,706



111,288Powder River Basin


3,155



8,677



16,649



1,081



29,562San Juan Basin


0



0



0



0



0Other


50,778



11,957



8,559



81,015



152,309Total (Gross Acres)


77,653



44,249



135,061



150,620



407,583   89




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##### Table of Contents



2011


2012


2013


2014 +


TotalPiceance Basin


20,597



2,226



2,411



2,878



28,112Bakken Shale


196



16,639



55,429



3,611



75,875Marcellus Shale


905



1,764



32,181



51,067



85,917Powder River Basin


1,290



2,800



8,236



547



12,873San Juan Basin


0



0



0



0



0Other


24,737



9,745



7,346



80,789



122,617Total (Net Acres)


47,725



33,174



105,603



138,892



325,394   International.
  Gas
    Management
    Delivery
    Commitments
    Purchase
    Commitments
  12-year
 90




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Hedging
    Activity
    Customers
    Title to
    Properties
    Seasonality
    Competition
      Environmental
    Matters and Regulation
   91




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##### Table of Contents



clean-up clean-up
        Hazardous Substances and Wastes.
  clean-up
 92




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##### Table of Contents



Waste Discharges.
    Air Emissions.
  Oil Pollution Act.
 93




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##### Table of Contents



National Environmental Policy Act.
  Endangered Species Act.
  Worker Safety.
  Safe Drinking Water Act.
  Hydraulic Fracturing.
 
   
 94




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##### Table of Contents




    Prior to perforating the production casing and hydraulic
    fracturing operations, the casing is pressure tested. 
 
  
    Before the fracturing operation commences, all surface equipment
    is pressure tested, which includes the wellhead and all
    pressurized lines and connections leading from the pumping
    equipment to the wellhead. During the pumping phases of the
    hydraulic fracturing treatment, specialized equipment is
    utilized to monitor and record surface pressures, pumping rates,
    volumes and chemical concentrations to ensure the treatment is
    proceeding as designed and the wellbore integrity is sound.
    Should any problem be detected during the hydraulic fracturing
    treatment, the operation is shut down until the problem is
    evaluated, reported and remediated. 
 
  
    As a means to protect against the negative impacts of any
    potential surface release of fluids associated with the
    hydraulic fracturing operation, special precautions are taken to
    ensure proper containment and storage of fluids. For example,
    any earthen pits containing non-fresh water must be lined with a
    synthetic impervious liner. These pits are tested regularly, and
    in certain sensitive areas have additional leak detection
    systems in place. At least two feet of freeboard, or available
    capacity, must be present in the pit at all times. In addition,
    earthen berms are constructed around any storage tanks, any
    fluid handling equipment, and in some cases around the perimeter
    of the location to contain any fluid releases. These berms are
    considered to be a secondary form of containment and
    serve as an added measure for the protection of groundwater. 
 
  
    We conduct baseline water monitoring in many of the basins in
    which we use hydraulic fracturing: 
 
  
    In Colorado, baseline water monitoring may be required by the
    Colorado Oil and Gas Conservation Commission (COGCC)
    or BLM as a condition of approval for the drilling permit, but
    otherwise it is not a requirement. The industry is currently
    working with the COGCC in preparing a voluntary baseline water
    monitoring program by basin. The Company has committed to this
    program that will likely go into effect later in 2011. 
 
  
    In the Barnett Shale, and with landowner approval, we perform
    water monitoring of fresh water wells within an agreed upon
    distance on a voluntary basis, even though not required by state
    regulation. 
 
  
    In Pennsylvania, we perform baseline water monitoring pursuant
    to Pennsylvania Department of Environmental Protection
    requirements. 
 
  
    There are currently no regulatory requirements to conduct
    baseline water monitoring in the Bakken Shale or the
    San Juan Basin. We plan to begin voluntarily conducting
    water monitoring in the Bakken Shale. The majority of our assets
    in the San Juan Basin are on federal lands, and there are
    few cases where water wells are within one to two miles of our
    wells, which is outside the range that we would typically sample. 
   95




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##### Table of Contents




    Improper cementing work. This can create conditions in
    which hydraulic fracturing fluids and other natural occurring
    substances can migrate into the surrounding geological
    formation. Production casing cementing tops and cement bond
    effectiveness are evaluated using either a temperature log or an
    acoustical cement bond log prior to any completion operations.
    If the cement bond or cement top is determined to be inadequate
    for zone isolation, remedial cementing operations are performed
    to fill any voids and re-establish integrity. As part of this
    remedial operation, the casing is again pressure tested before
    fracturing operations are initiated. 
 
  
    Initial casing integrity failure. The casing is pressure
    tested prior to commencing completion operations. If the test
    fails due to a compromise in the casing, the applicable oil and
    gas regulatory body will be notified and a remediation procedure
    will be written, approved, and completed before any further
    operations are conducted. In addition, casing pressures are
    monitored throughout the fracturing treatment and any indication
    of failure will result in an immediate shutdown of the operation. 
 
  
    Well failure or casing integrity failure during
    production. Loss of wellbore integrity can occur over time
    even if the well was correctly constructed due to downhole
    operating environments causing corrosion and stress. During
    production, the bradenhead, casing, and tubing pressures are
    monitored and a casing failure can be identified and evaluated.
    Remediation could include placing additional cement behind
    casing, installing a casing patch, or plugging and abandoning
    the well, if necessary. 
 
  
    Fluid leakoff during the fracturing process.
    Fluid leakoff can occur during hydraulic fracturing operations
    whereby some of the hydraulic fracturing fluid flows through the
    artificially created fractures into the micropore or pore spaces
    within the formation, existing natural factures in the
    formation, or small fractures opened into the formation by the
    pressure in the induced fracture. Fluid leakoff is accounted for
    in the volume design of nearly every fracturing job and
    pump-in tests are often conducted prior to
    fracturing jobs to estimate the extent of fluid leakoff. In
    certain situations, a very fine grain sand is added in the
    initial part of the treatment to seal-off any small fractures of
    micropore spaces and mitigate fluid leak-off. 
 
   
 
 
 
   
 96




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97




---



##### Table of Contents



Global Warming and Climate Change. and/or
     98




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##### Table of Contents



Foreign Operations.
  Other
    Regulation of the Oil and Gas Industry
        Drilling
    and Production
    
    the location of wells;
    the method of drilling and casing wells; 99




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##### Table of Contents




    the timing of construction or drilling activities including
    seasonal wildlife closures;
    the employment of tribal members or use of tribal owned service
    businesses;
    the rates of production or allowables;
    the surface use and restoration of properties upon which wells
    are drilled;
    the plugging and abandoning of wells; and
    the notice to surface owners and other third parties.      Natural
    Gas Sales and Transportation
     100




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##### Table of Contents



point-of-sale
  Oil Sales
    and Transportation
        Operation
    on Native American Reservations
       101




---



##### Table of Contents



Employees
    Offices
    Legal
    Proceedings
  Royalty
    litigation
    California
    energy crisis
     102




---



##### Table of Contents



true-up 2000-2001
      Reporting
    of natural gas-related information to trade
    publications
       103




---



##### Table of Contents



MANAGEMENT  Directors
    and Executive Officers
    
 Name

Age

PositionAlan S. Armstrong


49


Chairman of the BoardRalph A. Hill


51


Chief Executive OfficerDonald R. Chappel


59


Chief Financial OfficerTed T. Timmermans


54


Chief Accounting OfficerJames J. Bender


54


General Counsel and Corporate SecretaryRobyn L. Ewing


55


Chief Administrative OfficerRodney J. Sailor


52


Treasurer and Deputy Chief Financial Officer  
  Alan S. Armstrong.
    Ralph A. Hill.
  Donald R. Chappel.
 104




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##### Table of Contents



Ted T. Timmermans.
  James J. Bender.
  Robyn L. Ewing.
  Rodney J. Sailor.
  Board
    Composition
    Status as
    a Controlled Company
     105




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##### Table of Contents



Board
    Committees
  Audit
    committee
          Other
    Committees
    and/or
  Compensation
    Committee Interlocks and Insider Participation
    Code of
    Ethics
   106




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##### Table of Contents



EXECUTIVE
    COMPENSATION  Compensation
    Discussion and Analysis
    and/or
      Objective
    of Williams Compensation Programs
  ® ® 1 ®
  Looking forward
  Williams
    2010 Pay Philosophy
      1 ® ®
 107




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##### Table of Contents



Long-term


Annual CashWilliams Pay Principles

Incentives


Incentives


Base Pay


BenefitsPay should reinforce business objectives and values


ü



ü



üA significant portion of an NEOs total pay should be
    variable based on performance


ü



üIncentive pay should balance long-term, intermediate and
    short-term performance


ü



üIncentives should align interest of NEOs with stockholders


ü



üPay opportunity should be competitive


ü



ü



ü



üA portion of pay should be provided to compensate for the core
    activities required for performing in the role










ü



üPay should foster a culture of collaboration with shared focus
    and commitment to Williams


ü



ü   Looking Forward
  Williams
    2010 Compensation Summary
    Williams
    2010 Pay Decisions
    2008-2010 2007-2009 2008-2010.
   108




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##### Table of Contents



®
    Williams
    Plan Design Decisions
      Mr. Malcolm


Other NEOsPerformance-Based RSUs


50
%


35
%Stock Options


50
%


30
%Time-Based RSUs


0
%


35
%   ® ®
  Mitigating
    Risk
    Williams
    Compensation Recommendation and Decision Process
  Role of
    Williams Management
   109




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##### Table of Contents



Role of
    Williams CEO
    ® ®
  Role of
    the Other NEOs
    Role of
    Williams Compensation Committee
      
    Evaluations of the Williams CEO completed by the board members
    and the executive officers (excluding the Williams CEO);
    The Williams CEOs written assessment of
    his/her own
    performance compared with the stated goals; and
    EVA®

    performance of the Company relative to established targets as
    well as the financial and safety metrics presented as a
    supplement to
    EVA®

    performance.    Role of
    the Independent Compensation Consultant
     110




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##### Table of Contents



2010
    Williams Comparator Group
  How
    Williams Uses its Comparator Group
    Composition
    of the Williams Comparator Group
    Characteristics
    of Williams Comparator Group
    Composition
    of Our Comparator Group
    Williams 2010


OurComparator


ComparatorCompany


CompanyCompany Name

Group


GroupAnadarko Petroleum Corp.


XApache Corp.


XCabot Oil & Gas Corp.






XCenterpoint Energy Inc.


XChesapeake Energy Corp.


X



XCimarex Energy Corp.






XDevon Energy Corp.


X



XDominion Resources Inc.


XEl Paso Corp.


XEOG Resources Inc.


X



XEQT Corp.


XForest Oil Corp.






XHess Corp.


XMurphy Oil Corp.


X 111




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##### Table of Contents



Williams 2010


OurComparator


ComparatorCompany


CompanyCompany Name

Group


GroupNewfield Exploration Co.






XNiSource Inc.


XNoble Energy Inc.


X



XOneok Inc.


XPetrohawk Energy Corp.






XPioneer Natural Resources Co.






XPlains All American Pipeline


XQEP Resources Inc.






XQuestar Corp.


XRange Resources Corp.






XSandridge Energy Inc.






XSempra Energy


XSM Energy Co.






XSouthern Union Co.


XSouthwestern Energy Co.






XSpectra Energy Corp


XUltra Petroleum Corp.






XXTO Energy Inc. (acquired by ExxonMobilremoved)


X   Characteristics
    of Our Comparator Group
    Williams
    Pay Setting Process
       112




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##### Table of Contents



pay-for-performance
  2010 Target Pay Mix by NEOBase


Annual


Long-TermSalary


Incentive


Incentive


TotalMr. Malcolm


14
%


14
%


72
%


100
%Mr. Chappel


20
%


15
%


65
%


100
%Mr. Hill


19
%


13
%


68
%


100
%Mr. Bender


23
%


15
%


62
%


100
%Mrs. Ewing


22
%


14
%


64
%


100
%   Game Plan
    for Growth
    Invest
    in Growth
  
    Enhance Williams relationships with customers so that
    Williams continues to grow its competitive advantage and earn
    recognition for the reliable service and value that is essential
    to their success.
    Invest in Williams businesses in ways that grow
    EVA®,

    earnings and cash flows for Williams and Williams Partners; meet
    Williams customers needs; and enhance Williams
    competitive position.
    Pursue additional investment opportunities in new and emerging
    basins to capture significant, strategic, long-lived growth.
    Expand Williams intellectual, operational and leadership
    capacities so that Williams can successfully grow and develop
    high-performing employees and businesses.  Support
    Williams Growth
  
    Comply with applicable laws and regulations.
    Continuously improve Williams safety and environmental
    compliance performance in all of Williams operations.
    Assess and manage risks effectively; take appropriate,
    well-considered risks in order to create value. Exercise
    financial discipline so that Williams and Williams
    Partners financial condition is strong and credit ratings
    are investment-grade.  Deliver
    the Growth
  
    Achieve or exceed Williams
    EVA®,

    earnings and cash flow goals. Also achieve attractive growth in
    value for Williams and Williams Partners investors.
    Openly engage with communities, vendors and other stakeholders
    crucial to Williams success so that Williams grows the
    competitive advantage we enjoy as a preferred partner.
    Operate the business in a way that grows Williams
    reputation as a leader in environmental stewardship. 113




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##### Table of Contents




    Completed the transformation of Williams Partners to a large
    diversified master limited partnership with reliable access to
    capital markets. This was accomplished through:  
    Strategic asset drop-downs from Williams to Williams Partners;
    and
    The merger of Williams Partners and Williams Pipeline Partners
    L.P.  
    Completed significant asset acquisitions in the Marcellus Shale.
    All of Williams businesses have a strategic presence in
    the Marcellus Shale allowing Williams to leverage the strengths
    of each business unit;
    Invested $2.8 billion in drilling activity and acquisitions
    in Williams Exploration & Production business.
    This included $1.7 billion related to acquisitions in the
    Bakken and Marcellus Shale areas. The Bakken Shale transaction
    creates more diversification in Williams Exploration and
    Production business by expanding the long-term crude oil
    portfolio;
    Invested $1 billion in capital and investment expenditures
    in the midstream businesses and invested $473 million in
    capital expenditures in Williams gas pipelines business in
    2010;
    Expanded ownership of the Overland Pass Pipeline;
    Maintained Williams investment grade credit rating while
    achieving an upgrade of Williams Partners to an investment grade
    credit rating; and
    In addition to continuing to expand Williams natural gas
    businesses and drive stockholder value, Williams was recognized
    for its efforts to make Williams a great place to work for its
    employees;  
    The Houston Business Journal recognized Williams as a Best Place
    to Work in Houston among companies not based in Houston. This
    was the third year in a row Williams was recognized on the Best
    Place to Work in Houston list;
    Utah Business magazine named Williams as a finalist in its Best
    Companies to Work for program, where Williams was recognized as
    one of the four best medium-sized companies in Utah for the
    second year in a row;
    OKCBiz magazine recognized Williams on its Best Places to Work
    in Oklahoma list for the third year in a row; and
    Tulsa Business Journals Economic Development Impact Awards
    recognized Williams as a finalist for the Best Workplace for
    Young Professionals.  How
    Williams Determines the Amount for Each Type of Pay
    Long-Term
    Incentives
      
    the proportion of long-term incentives relative to base pay;
    the NEOs impact on Williams performance and ability
    to create value; 114




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##### Table of Contents




    long-term business objectives;
    awards made to NEOs in similar positions within Williams
    comparator group of companies
    the market demand for the NEOs particular skills and
    experience;
    the amount granted to other NEOs in comparable positions at
    Williams;
    the NEOs demonstrated performance over the past few
    years; and
    the NEOs leadership performance.      Drives operatingStockholder



and financial

RetentionEquity type and Performance Drivers

alignment

Stock ownership

performance

IncentivePerformance-Based RSUsAbsolute and Relative TSR

l

l

lStock OptionsStock Price Appreciation

l

l

lTime-Based RSUsStock Price Appreciation

l

l



l   2010
    Performance-Based RSUs
      
  2008
    Performance-Based RSUs
  2008-2010.
 115




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##### Table of Contents



EVA®

Payout Level as a % of Target(Millions)

(Attainment %)Threshold$191

(where incentives start to be earned)$299

100%$407

200%   Stock
    Option Awards
    Time-Based
    RSUs
    Grant
    Practices
      Looking Forward
  Annual
    Cash Incentives
  ® ®
  EVA®

=

Adjusted Net Operating
    Profits after Taxes
    (NOPAT)

Less

Adjusted Capital Charge (the amount 
    of capital invested by Williams 
    multiplied by the cost of capital)   ® ® ®
  
    Motivate and incent management to choose strategies and
    investments that maximize long-term stockholder value;
    Offer sufficient incentive compensation to motivate management
    to put forth extra effort, take prudent risks and make tough
    decisions to maximize stockholder value;
    Provide sufficient total compensation to retain
    management; and 116




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##### Table of Contents




    Limit the cost of compensation to levels that will maximize the
    wealth of current stockholders without compromising the other
    objectives.  The
    EVA®

    Calculation
  ® ® ® ®
  ® ®
  
    Gains, losses and impairments;
    Mark-to-market,
    commodity price collar and construction
    work-in-progress; and
    Other unusual items that could result in unearned windfalls or
    undue penalties to NEOs such as certain litigation matters and
    natural disasters.  ® ®
  ®
  Annual
    Cash IncentivesTarget
    Mr. Malcolm


100
%Mr. Chappel


75
%Other NEOs


65
%   Annual
    Cash IncentivesActual
  ® ®
  Base Pay received in 2010

X

Incentive Target %

X

EVA®

    Goal Attainment %  117




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##### Table of Contents



How
    Williams Sets the
    EVA®

    Goals
  ®
  
    Business and financial plans are submitted by the business units
    and consolidated by the corporate planning department.
    The business and financial plans are reviewed and analyzed by
    Williams chief executive officer, chief financial officer
    and other named executive officers.
    Using the plan guidance, Williams management establishes
    the
    EVA®

    goal and recommends it to the Committee.
    The Committee reviews, discusses and makes adjustments as
    necessary to managements recommendations and sets the goal
    at the beginning of each fiscal year.
    Thereafter, progress toward the goal is regularly monitored and
    reported to the Committee throughout the year.  2010
    EVA®

    Goal for the Annual Cash Incentive Program
  ® ® ® ® ®
  EVA®

Payout Level as a % of Target(Millions)

(Attainment %)Threshold($563)

(where incentives start to be earned)($347)

100%($131)

200%   ® ® ® ®
  ® ®
  Looking Forward
 118




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##### Table of Contents



Base
    Pay
    pay-for-performance
  INSPIRE A





OPTIMIZEMODEL THE

SHARED

CHAMPION

LEVERAGE

BUSINESSWAY

VISION

INNOVATION

TALENT

PERFORMANCECaring About People

Enterprise Perspective

Change Leadership

Building Effective Teams

Business AcumenIntegrity

Vision and Strategic Perspective

Entrepreneurial Spirit

Communication

Customer and Market FocusLoyalty and Commitment



Promoting Diversity and Creativity

Developing People Resources

Decision MakingWillingness to Take Risks

Empowering Others

Drive for ResultsManagerial Courage

Functional/Technical SkillsMotivating and Inspiring Others   Looking Forward
  Benefits
    
    Retirement Restoration Benefits.  All NEOs
    participate in Williams qualified retirement program on
    the same terms as other Williams employees. Williams
    offers a retirement restoration plan to NEOs to maintain a
    proportional level of pension benefits to officers as provided
    to other employees. The Code limits qualified pension benefits
    based on an annual compensation limit. For 2010, the limit was
    $245,000. Any reduction in an NEOs pension benefit in the
    tax-qualified pension plan due to this limit is made up for
    (subject to a cap) in the unfunded restoration retirement plan.
    Benefits for NEOs are calculated using the same benefit formula
    as that used to calculate benefits for all employees in the
    qualified pension plan. The value of pay in the form of stock
    option or other equity is not used in the formula to calculate
    benefits under the pension plan or restoration plan for NEOs,
    which is consistent with the treatment for all employees.
    Additionally, Williams does not provide a nonqualified benefit
    related to the qualified 401(k) defined contribution retirement
    plan.
    Financial Planning Allowance.  Williams offers
    financial planning to the NEOs to provide expertise on current
    tax laws with personal financial planning and preparations for
    contingencies such as death and disability. In addition, by
    working with a financial planner, executive officers gain a
    better understanding of and appreciation for the programs
    Williams provides, which helps to maximize the retention and
    engagement aspects of the dollars Williams spends on these
    programs. 119




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##### Table of Contents




    Home Security.  Williams paid 2010 home
    security system and monitoring fees for its former CEO,
    Mr. Malcolm.
    Personal Use of Williams Company
    Aircraft.  Williams provides limited personal use
    of Williams company aircraft at the Williams CEOs
    discretion. There was limited personal use of Williams
    company aircraft by the NEOs in 2010 and the details are
    provided in the footnote to the Summary Compensation Table.
    Event Center.  Williams has a suite and club
    seats at an event center that were purchased for business
    purposes. If it is not being used for business purposes,
    Williams makes them available to all employees, including the
    NEOs, as a form of reward and recognition.
    Executive Physicals.  The Committee approved
    physicals for the NEOs beginning in 2009. Executive officer
    physicals align with Williams wellness initiative as well
    as assist Williams in mitigating risk. These physicals reduce
    vacancy succession risk because they help to identify and
    prevent issues that would leave a role vacated unexpectedly.  Looking Forward
  Additional
    Components of Williams Executive Compensation
    Program
    Recoupment
    Policy
    Stock
    Ownership Guidelines
  All NEOs must hold an equity interest in
    Williams.
  Holding Requirement asa multiple of Base Pay


Time Frame forPosition

2010


2011


ComplianceMr. Malcolm


5



6



5 YearsOther NEOs


3



3



5 Years     Derivative
    Transactions
   120




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##### Table of Contents



Accounting
    and Tax Treatment
      Employment
    Agreements
    Termination
    and Severance Arrangements
    Rationale
    for Change in Control Agreements
    gross-up
 121




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##### Table of Contents



What does thebenefit provide to

What does theChange in Control

Williams and

benefit provide toBenefit

stockholders?

the NEO?Multiple of 3x base pay plus annual cash incentive at target

Encourages NEOs to remain engaged and stay focused on
    successfully closing the transaction.

Financial security for the NEO equivalent to three years of
    continued employment.Accelerated vesting of stock awards

An incentive to stay during and after a change in control. If
    there is risk of forfeiture, NEOs may be less inclined to stay
    or to support the transaction.

The NEOs are kept whole, if they have a separation from service
    following a change in control.Up to 18 months of medical or health coverage through COBRA

This is a minimal cost to Williams that creates a competitive
    benefit.

Access to health coverage.3x the previous years retirement restoration allocation

This is a minimal cost to Williams that creates a competitive
    benefit.

May allow those NEOs who are nearing retirement to receive a
    cash payment to make up for lost allocations due to a change in
    control.Reimbursement of legal fees to enforce benefit

Keeps NEOs focused on Williams and not concerned about whether
    the acquiring company will honor commitments after a change in
    control.

Security during a non-stable period of time.Outplacement assistance

Keeps NEOs focused on supporting the transaction and less
    concerned about trying to secure another position.

Assists NEOs in finding a comparable executive position.   Looking Forward
 122




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##### Table of Contents



Our
    Equity Plans Following this Offering
 
 
   
 
  2011
    Incentive Plan
 
 
   
 
   
 
  Administration.
 
 
  Limits on Awards.
 
 
  Stock Options.
 
 123




---



##### Table of Contents



Stock Appreciation Rights.
 
 
  Restricted Stock and Restricted Stock
    Units.
 
 
  Performance Units.
 
 
  Performance Shares.
 
 
  Other Stock-Based Awards.
 
 
  Non-Management Director Annual
    Grants. and/or
 
 
   
 
  Performance-Based Awards.
 
 124




---



##### Table of Contents



and/or and/or
 
 
  Payment and Deferral of Awards.
 
 
  Transfer Limitations on Awards.
 
 
  Amendment.
 
 125




---



##### Table of Contents



Change in Control.
 
 
  Employee
    Stock Purchase Plan
 
 
   
 
   
 
  Administration.
 
 
  Eligibility. and/or
 
 
  Offering Period.
 
 126




---



##### Table of Contents



Purchase of Stock; Limitations on Purchase of
    Stock.
 
 
  Purchase Price.
 
 
  Termination of Employment.
 
 
  Transferability.
 
 
  Amendment; Termination.
 
 127




---



##### Table of Contents



Executive
    Compensation and Other Information
  2010
    Summary Compensation Table
    Change inPensionValue andNonqualifiedNon-Equity


DeferredName and Principal










Stock


Option


Incentive Plan


Compensation


All OtherPosition(1)

Year


Salary(2)


Bonus


Awards(3)


Awards(4)


Compensation(5)


Earnings(6)


Compensation(7)


TotalSteven J. Malcolm


2010


$
1,100,000


$



$
2,936,283


$
1,902,806


$
1,276,378


$
744,426


$
43,805


$
8,003,698Former Chairman, President &


2009



1,142,308







2,116,863



2,846,407



1,903,360



1,399,796



71,100



9,479,835Chief Executive Officer


2008



1,094,231







2,906,309



2,789,127



2,000,000



1,201,514



56,134



10,047,315of WilliamsDonald R. Chappel


2010



610,154







1,436,882



407,743



559,052



225,539



16,320



3,255,690Chief Financial Officer


2009



623,077







1,242,734



618,783



765,047



383,380



16,320



3,649,341of Williams


2008



597,115







2,114,349



651,405



780,008



330,531



15,744



4,489,152Ralph A. Hill


2010



493,208







1,257,287



356,777



384,479



315,626



16,304



2,823,681Senior Vice President 


2009



503,654







1,056,319



525,969



566,473



427,867



37,786



3,118,068Exploration & Production of Williams


2008



480,962







1,606,867



495,071



579,633



363,151



30,371



3,556,055James J. Bender


2010



477,954







933,975



265,033



359,122



188,427



33,900



2,258,411Senior Vice President and General


2009



488,077







807,773



402,209



522,119



250,679



26,647



2,497,504Counsel of Williams


2008



466,538







1,271,209



390,840



533,132



216,799



30,323



2,908,842Robyn L. Ewing


2010



442,692







933,975



265,033



328,364



233,254



35,579



2,238,897Senior Vice President and Chief


2009



446,538







745,640



371,269



485,362



304,374



31,093



2,384,277Administrative Officer of


2008



370,198







299,757



118,485



435,072



248,784



30,096



1,502,392Williams     (1)
    
    Name and Principal Position.On January 3, 2011
    Mr. Malcolm retired as Chairman, President and Chief
    Executive Officer of Williams.(2)
    
    Salary. All NEOs did not receive a salary increase in
    2009. The increase in the reported 2009 salary was due to a
    payroll timing issue resulting in a 27th bi-weekly paycheck
    being issued in the calendar year.(3)
    
    Stock Awards.Awards were granted under the terms of
    Williams 2007 Incentive Plan and include time-based and
    performance-based RSUs. Amounts shown are the grant date fair
    value of awards computed in accordance with FASB ASC Topic 718.
    The assumptions used to value the stock awards can be found in
    Williams Annual Report on
    Form 10-K
    for the year-ended December 31, 2010.The potential maximum values of the performance-based RSUs,
    subject to changes in performance outcomes, are as follows:  2010 Performance-Based RSUMaximum potentialSteven J. Malcolm

$
5,872,566Donald R. Chappel


1,468,141Ralph A. Hill


1,284,639James J. Bender


954,294Robyn L. Ewing


954,294   (4)
    
    Option Awards.Awards are granted under the terms of
    Williams 2007 Incentive Plan and include non-qualified
    stock options. Amounts shown are the grant date fair value of
    awards computed in accordance with FASB ASC Topic 718. The
    assumptions used to value the option awards can be found in our
    Annual Report on
    Form 10-K
    for the year-ended December 31, 2010.(5)
    
    Non-Equity Incentive Plan. Under Williams AIP, the
    maximum annual incentive pool funding for NEOs is 250% of
    target. The reserve provision of the AIP was eliminated in 2009
    and the outstanding balances for the NEOs remained at risk over
    a three year performance period in which threshold performance
    levels must be attained in order for the balances to be paid and
    will be reduced if threshold is not met in accordance with
    previous plan provisions. Threshold performance was met in 2009
    and 2010 and a portion of the respective reserve balance was
    paid to each NEO each year. 128




---



##### Table of Contents



The annual cash incentive and reserve amounts paid in 2011 as it
    relates to 2010 performance are as follows:  Amount of


Total AIP plusReserve


AIP


Reserve


ReserveBalance


for 2010


Paid in 2011


for 2010Steven J. Malcolm

$
242,756


$
1,155,000


$
121,378


$
1,276,378Donald R. Chappel


60,103



529,000



30,052



559,052Ralph A. Hill


72,958



348,000



36,479



384,479James J. Bender


44,244



337,000



22,122



359,122Robyn L. Ewing


20,728



318,000



10,364



328,364   (6)
    
    Change in Pension Value and Nonqualified Deferred
    Compensation Earnings.The amount shown is the aggregate
    change from December 31, 2009 to December 31, 2010 in
    the actuarial present value of the accrued benefit under the
    qualified pension and supplemental plan sponsored by Williams.
    Please refer to the Pension Benefits table for
    further details of the present value of the accrued benefit. The
    underlying benefit programs have been consistent during the time
    period displayed. The primary reason for the fluctuation in the
    change in present value during this time is due to the use of
    updated discount rates and conversion rates.(7)
    
    All Other Compensation.Amounts shown represent payments
    by Williams made on behalf of the NEOs and includes life
    insurance premium, a 401(k) matching contribution and
    perquisites (if applicable). Perquisites include financial
    planning services, mandated annual physical exam, home security
    monitoring for the CEO and personal use of Williams
    company aircraft. The incremental cost method was used to
    calculate the personal use of the Company aircraft. The
    incremental cost calculation includes such items as fuel,
    maintenance, weather and airport services, pilot meals, pilot
    overnight expenses, aircraft telephone and catering. The amounts
    of perquisites for Mr. Malcolm, Mr. Bender and
    Ms. Ewing are included because the aggregate amounts exceed
    $10,000.  CompanyAnnual





AircraftFinancial


Physical


Home


PersonalPlanning


Exam


Security


UsageSteven J. Malcolm

$
15,000


$
0


$
438


$
12,047James J. Bender


15,000



2,646



0



0Robyn L. Ewing


15,000



4,437



0



0  129




---



##### Table of Contents



2010
    Grants of Williams Plan Based Awards
    All OtherStock


All OtherAwards:


Option





GrantNumber


Awards


Exercise


Date Fairof Shares


Number of


or Base


Value ofEquity Future Payouts Under


Estimated Future Payouts Under


of Stock


Securities


Price of


Stock andGrant


Non-Equity Incentive Plan Awards(1)


Equity Incentive Plan Awards


or


Underlying


Option


OptionName

Date


Threshold


Target


Maximum


Threshold


Target(2)


Maximum


Units(3)


Options(4)


Awards


AwardsSteven J. Malcolm


2/23/2010


$
121,378


$
1,221,378


$
2,871,378



















271,055


$
21.22


$
1,902,8062/23/2010



















140,492



280,984















2,936,283Donald R. Chappel


2/23/2010



30,052



487,667



1,174,090



















58,083



21.22



407,7432/23/2010



















35,123



70,246















734,0712/23/2010



























35,123











702,811Ralph A. Hill


2/23/2010



36,479



357,064



837,941



















50,823



21.22



356,7772/23/2010



















30,733



61,466















642,3202/23/2010



























30,733











614,967James J. Bender


2/23/2010



22,122



332,792



798,797



















37,754



21.22



265,0332/23/2010



















22,830



45,660















477,1472/23/2010



























22,830











456,828Robyn L. Ewing


2/23/2010



10,364



298,114



729,739



















37,754



21.22



265,0332/23/2010



















22,830



45,660















477,1472/23/2010



























22,830











456,828     (1)
    
    Non-Equity Incentive Awards. Awards from Williams 2010 AIP
    are shown.  
    Threshold: Because one-half of the AIP reserve balance from
    prior years is payable in 2011 upon meeting threshold
    performance, one-half of the reserve balance is shown.
    Target: The amount shown is based upon an
    EVA®

    attainment of 100%, plus one-half of the existing AIP reserve
    balance.
    Maximum: The maximum amount the NEOs can receive is 250% of
    their AIP target, plus one-half of the AIP reserve balance.  (2)
    
    Represents performance-based RSUs granted under Williams
    2007 Incentive Plan. Performance-based RSUs can be earned over a
    three-year period only if the established performance target is
    met and the NEO is employed on the certification date, subject
    to certain exceptions such as the executives death or
    disability. These shares will be distributed no earlier than the
    third anniversary of the grant other than due to a termination
    upon a change in control. If performance plan goals are
    exceeded, the NEO can receive up to 200% of target. If plan
    goals are not met, the NEO can receive as little as 0% of target.(3)
    
    Represents time-based RSUs granted under Williams 2007
    Incentive Plan. Time-based units vest three years from the grant
    date of 2/23/2010 on 2/23/2013.(4)
    
    Represents stock options granted under Williams 2007
    Incentive Plan. Stock options granted in 2010 become exercisable
    in three equal annual installments beginning one year after the
    grant date. One-third of the options vested on 2/23/2011.
    Another one-third will vest on 2/23/2012, with the final
    one-third vesting on 2/23/2013. Once vested, stock options are
    exercisable for a period of 10 years from the grant date. 130




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##### Table of Contents



2010
    Outstanding Williams Equity Awards
    Option Award

Stock AwardsEquityEquity

IncentiveIncentive

Plan Award:Plan

Market orEquity











Awards:

PayoutIncentive











Number of

Value ofPlan









Market

Unearned

UnearnedAwards:







Number

Value of

Shares,

Shares,Number of

Number of

Number of







of Shares

Shares or

Units of

Units orSecurities

Securities

Securities







or Units

Units of

Stock or

OtherUnderlying

Underlying

Underlying







of Stock

Stock

Other

RightsUnexercised

Unexercised

Unexercised

Option





That

That

Rights

That HaveGrant

Options (#)

Options (#)

Unearned

Exercise

Expiration

Grant

Have Not

Have Not

That Have

NotName

Date(1)

Exercisable

Unexercisable

Options

Price

Date

Date

Vested

Vested

Not Vested

Vested(4)Steven J. Malcolm


2/23/2010







271,055






$
21.22



2/23/2020



2/23/2010(3
)






140,492


$
3,472,9622/23/2009



169,429



338,858







10.86



2/23/2019



2/23/2009(3
)






288,401



7,129,2732/25/2008



144,927



72,464







36.50



2/25/2018



2/25/2008(3
)






82,192



2,031,7862/26/2007



200,000











28.30



2/26/20173/3/2006



250,000











21.67



3/3/20162/25/2005



225,000











19.29



2/25/20152/5/2004



300,000











9.93



2/5/20142/11/2002



200,000











15.86



2/11/20129/19/2001



33,333











26.79



9/19/20114/2/2001



27,232











39.98



4/2/20111/18/2001



114,373











34.77



1/18/2011Donald R. Chappel


2/23/2010







58,083







21.22



2/23/2020



2/23/2010(2
)






35,123



868,2412/23/2009



36,832



73,665







10.86



2/23/2019



2/23/2010(3
)






35,123



868,2412/25/2008



33,848



16,924







36.50



2/25/2018



2/23/2009(2
)






73,145



1,808,1442/26/2007



48,450











28.30



2/26/2017



2/23/2009(3
)






73,145



1,808,1443/3/2006



41,921











21.67



3/3/2016



2/25/2008(2
)






19,911



492,2002/25/2005



55,000











19.29



2/25/2015



2/25/2008(3
)






39,822



984,4002/5/2004



75,000











9.93



2/5/20144/16/2003



175,000











5.10



4/16/2013Ralph A. Hill


2/23/2010







50,823







21.22



2/23/2020



2/23/2010(2
)






30,733



759,7202/23/2009



31,307



62,616







10.86



2/23/2019



2/23/2010(3
)






30,733



759,7202/25/2008



25,724



12,863







36.50



2/25/2018



2/23/2009(2
)






62,173



1,536,9172/26/2007



43,605











28.30



2/26/2017



2/23/2009(3
)






62,173



1,536,9173/3/2006



30,488











21.67



3/3/2016



2/25/2008(2
)






15,132



374,0632/25/2005



40,000











19.29



2/25/2015



2/25/2008(3
)






30,264



748,1261/18/2001



22,875











34.77



1/18/2011James J. Bender


2/23/2010







37,754







21.22



2/23/2020



2/23/2010(2
)






22,830



564,3582/23/2009



23,941



47,882







10.86



2/23/2019



2/23/2010(3
)






22,830



564,3582/25/2008



20,308



10,155







36.50



2/25/2018



2/23/2009(2
)






47,544



1,175,2882/26/2007



29,070











28.30



2/26/2017



2/23/2009(3
)






47,544



1,175,2883/3/2006



24,136











21.67



3/3/2016



2/25/2008(2
)






11,946



295,3052/25/2005



40,000











19.29



2/25/2015



2/25/2008(3
)






23,893



590,6352/5/2004



15,000











9.93



2/5/2014Robyn L. Ewing


2/23/2010







37,754







21.22



2/23/2020



2/23/2010(2
)






22,830



564,3582/23/2009



22,099



44,199







10.86



2/23/2019



2/23/2010(3
)






22,830



564,3582/25/2008



6,156



3,079







36.50



2/25/2018



2/23/2009(2
)






43,887



1,084,8872/26/2007



10,174











28.30



2/26/2017



2/23/2009(3
)






43,887



1,084,8873/3/2006



11,738











21.67



3/3/2016



2/25/2008(2
)






3,622



89,5362/25/2005



23,000











19.29



2/25/2015



2/25/2008(3
)






4,829



119,373     Stock
    Options
  (1)
    
    The following table reflects the vesting schedules for
    associated stock option grant dates for awards that had not been
    100% vested as of December 31, 2010.  131




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##### Table of Contents



Grant Date

Vesting Schedule

Vesting Dates2/23/2010

One-third vests each year for three years


2/23/2011, 2/23/2012, 2/23/20132/23/2009

One-third vests each year for three years


2/23/2010, 2/23/2011, 2/23/20122/25/2008

One-third vests each year for three years


2/25/2009, 2/25/2010, 2/25/2011   Stock
    Awards
  (2)
    
    The following table reflects the vesting dates for associated
    time-based restricted stock unit award grant dates.  Grant Date

Vesting Schedule

Vesting Dates2/23/2010

100% vests in three years


2/23/20132/23/2009

100% vests in three years


2/23/20122/25/2008

100% vests in three years


2/25/2011   (3)
    
    All performance-based RSUs are subject to attainment of
    performance targets established by the Committee. These awards
    will vest no earlier than the end of the performance period and
    therefore do not have a specific vesting date. The awards
    included on the table are outstanding as of December 31,
    2010.(4)
    
    Values are based on a closing stock price for Williams of $24.72
    on December 31, 2010.  2010
    Williams Option Exercises and Stock Vested
    Option Awards

Stock AwardsNumber of Shares



Number of SharesAcquired on

Value Realized

Acquired on

Value RealizedName

Exercise

on Exercise

Vesting

on VestingSteven J. Malcolm


475,000


$
10,096,083






$
Donald R. Chappel










19,069



410,746Ralph A. Hill










17,162



369,669James J. Bender










11,442



246,461Robyn L. Ewing










4,005



86,268     Retirement
    Plan
    Pension
    Plan
   132




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##### Table of Contents



Percentage of



Percent of Eligible Pay GreaterAge

Eligible Pay



than the Social Security Wage BaseLess than 30


4.5
%


+


from 1% to 1.2%30-39


6
%


+


2%40-49


8
%


+


3%50 or over


10
%


+


5%         Retirement
    Restoration Plan
    cost-of-living
   133




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##### Table of Contents



2010
    Williams Pension Benefits
    Number of



PaymentsYears Credited

Present Value of

During LastName

Plan Name

Services

Accrued Benefit(1)

Fiscal YearSteven J. Malcolm(2)(3)

Pension Plan


27


$
829,307



Retirement Restoration Plan


27



5,497,857



Donald R. Chappel(2)

Pension Plan


8



245,359



Retirement Restoration Plan


8



1,319,741



Ralph A. Hill(3)

Pension Plan


27



586,869



Retirement Restoration Plan


27



1,321,013



James J. Bender

Pension Plan


8



216,010



Retirement Restoration Plan


8



799,037



Robyn L. Ewing(2)

Pension Plan


30



598,781



Retirement Restoration Plan


30



723,095



     (1)
    
    The primary actuarial assumptions used to determine the present
    values include an annual interest credit to normal retirement
    age equal to 5% and a discount rate equal to 5.29% for the
    pension plan and discount rate equal to 5.1% for the retirement
    restoration plan.(2)
    
    Mr. Malcolm, Mr. Chappel and Ms. Ewing are the
    only NEOs eligible to retire as of December 31, 2010.(3)
    
    Williams pension plan includes a Rule of 55 benefit that
    is a transition benefit that was provided to all employees
    meeting the eligibility criteria at the time Williams
    pension plan was converted from a final average pay formula to a
    cash balance formula. To be eligible for the Rule of 55
    enhancement an employees age and years of service at the
    time of the cash balance conversion in 1998 must have totaled
    55. Mr. Malcolm and Mr. Hill are the only NEOs that
    met the eligibility criteria for the Rule of 55 transitional
    benefit.  Nonqualified
    Deferred Compensation
    Change in
    Control Agreements
      
    Within 10 business days after the termination date:  
    Accrued but unpaid base salary, accrued earned but unpaid cash
    incentive, accrued but unpaid paid time off and any other
    amounts or benefits due but not paid (lump sum payment); 134




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##### Table of Contents




    On the first business day following six months after the
    termination date:  
    Prorated annual bonus for the year of separation through the
    termination date (lump sum payment);
    A severance amount equal to three times
    his/her base
    salary for the NEO as of the termination date plus an annual
    bonus amount equal to
    his/her
    target percentage multiplied by
    his/her base
    salary in effect at the termination date as if performance goals
    were achieved at 100% (lump sum payment);
    An amount equal to three times for the total allocations made by
    Williams for the NEOs in the preceding calendar year under our
    retirement restoration plan (lump sum payment);
    An amount equal to the sum of the value of the unvested portion
    of the NEOs accounts or accrued benefits under
    Williams 401(k) plan that would have otherwise been
    forfeited (lump sum payment);  
    Continued participation in Williams medical benefit plans
    for so long as the NEO elects coverage or 18 months from
    the termination, whichever is less, in the same manner and at
    the same cost as similarly situated active employees;
    All restrictions on stock options held by the NEO will lapse,
    and the options will vest and become immediately exercisable;
    All restricted stock will vest and will be paid out only in
    accordance with the terms of the respective award agreements;
    Continued participation in Williams directors and
    officers liability insurance for six years or any longer
    known applicable statute of limitations period;
    Indemnification as set forth under Williams
    bylaws; and
    Outplacement benefits for six months at a cost not exceeding
    $25,000.  gross-up gross-up
        
    conviction of or a plea of nolo contendere to a felony or a
    crime involving fraud, dishonesty or moral turpitude;
    willful or reckless material misconduct in the performance of
    his/her
    duties that has an adverse effect on Williams or any of its
    subsidiaries or affiliates;
    willful or reckless violation or disregard of the code of
    business conduct of Williams or the policies of Williams or its
    subsidiaries; or
    habitual or gross neglect of
    his/her
    duties. 135




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##### Table of Contents




    Any person or group (other than an affiliate of Williams or an
    employee benefit plan sponsored by Williams or its affiliates)
    becomes a beneficial owner, as such term is defined under the
    Exchange Act, of 20% or more of the common stock of Williams or
    20% or more of the combined voting power of all securities
    entitled to vote generally in the election of directors of
    Williams (Voting Securities), unless such person
    owned both more than 75% of common stock and Voting Securities,
    directly or indirectly, in substantially the same proportion
    immediately before such acquisition;
    Williams directors as of a date of the agreement
    (Existing Directors) and directors approved after
    that date by at least two-thirds of the Existing Directors cease
    to constitute a majority of the directors of Williams;
    Consummation of any merger, reorganization, recapitalization
    consolidation or similar transaction (Reorganization
    Transaction), other than a Reorganization Transaction that
    results in the person who was the direct or indirect owner of
    outstanding common stock and Voting Securities of Williams prior
    to the transaction becoming, immediately after the transaction,
    the owner of at least 65% of the then outstanding common stock
    and Voting Securities representing 65% of the combined voting
    power of the then outstanding Voting Securities of the surviving
    corporation in substantially the same respective proportion as
    that persons ownership immediately before such
    Reorganization Transaction; or
    approval by the stockholders of Williams of the sale or other
    disposition of all or substantially all of the consolidated
    assets of Williams or the complete liquidation of Williams other
    than a transaction that would result in (i) a related party
    owning more than 50% of the assets that were owned by Williams
    immediately prior to the transaction or (ii) the persons
    who were the direct or indirect owners of outstanding Williams
    common stock and Voting Securities prior to the transaction
    continuing to own, directly or indirectly, 50% or more of the
    assets that were owned by Williams immediately prior to the
    transaction.    
    the NEO agrees in writing prior to an event that such an event
    will not be a change in control; or
    Williams board of directors determines that a liquidation,
    sale or other disposition approved by the stockholders, as
    described in the fourth bullet above, will not occur, except to
    the extent termination occurred prior to such determination.  his/her he/she
    
    the termination of an NEOs employment from Williams or an
    affiliate before a change in control for any reason; or 136




---



##### Table of Contents




    the termination of an NEOs employment by a successor
    (during the period beginning upon a change of control and
    continuing for two years or until the termination of the
    agreement, whichever happens first), if the NEO is employed in
    substantially the same position and the successor has assumed
    the Williams change in control agreement.    Termination
    Scenarios
    he/she his/her
  For





Death &


Not forName

Payment

Cause(1)


Retirement(2)


Disability(3)


Cause(4)


CIC(5)Malcolm, Steven J

AIP Reserve





$
242,756


$
242,756


$
242,756


$
242,756Stock options






5,645,264



5,645,264







5,645,264Stock awards






7,240,399



7,240,399



7,240,399



12,634,022Cash Severance


















6,600,000Outplacement


















25,000Health & Welfare


















18,170Retirement RestorationPlan


















2,207,808EnhancementTax Gross Up


















8,649,197Total





$
13,128,419


$
13,128,419


$
7,483,155


$
36,022,217Chappel, Donald R

AIP Reserve





$
60,103


$
60,103


$
60,103


$
60,103Stock options






1,224,287



1,224,287







1,224,287Stock awards






4,086,877



5,444,451



5,444,451



6,829,365Cash Severance


















3,213,000Outplacement


















25,000Health & Welfare


















26,699Retirement Restoration Plan














Enhancement


















646,557Tax Gross Up


















2,966,960Total





$
5,371,267


$
6,728,841


$
5,504,554


$
14,991,971 137




---



##### Table of Contents



For





Death &


Not forName

Payment

Cause(1)


Retirement(2)


Disability(3)


Cause(4)


CIC(5)Hill, Ralph A

AIP Reserve





$
72,958


$
72,958


$
72,958


$
72,958Stock options






1,045,738



1,045,738







1,045,738Stock awards






3,360,366



4,527,523



4,527,523



5,715,453Cash Severance


















2,448,765Outplacement


















25,000Health & Welfare


















26,346Retirement Restoration Plan














Enhancement


















636,018Tax Gross Up


















Total





$
4,479,062


$
5,646,219


$
4,600,481


$
9,970,278Bender, James J

AIP Reserve





$
44,244


$
44,244


$
44,244


$
44,244Stock options






795,784



795,784







795,784Stock awards






2,586,716



3,467,769



3,467,769



4,365,230Cash Severance


















2,373,030Outplacement


















25,000Health & Welfare


















26,346Retirement Restoration Plan














Enhancement


















423,896Tax Gross Up


















2,217,566Total





$
3,426,744


$
4,307,797


$
3,512,013


$
10,271,096Ewing, Robyn L

AIP Reserve





$
20,728


$
20,728


$
20,728


$
20,728Stock options






744,737



744,737







744,737Stock awards






1,836,807



2,671,273



2,671,273



3,507,393Cash Severance


















2,202,750Outplacement


















25,000Health & Welfare


















26,346Retirement Restoration Plan














Enhancement


















437,948Tax Gross Up


















1,861,484Total





$
2,602,272


$
3,436,738


$
2,692,001


$
8,826,386    (1)
    
    If an NEO is terminated for cause or leaves Williams
    voluntarily, no additional benefits will be received.(2)
    
    If an NEO retires from Williams, then all unvested stock options
    will fully accelerate. A pro-rated portion of the unvested time
    based RSUs will accelerate and a pro-rated portion of any
    performance-based RSUs will vest on the original vesting date if
    the Committee certifies that the performance measures were met.(3)
    
    If an NEO dies or becomes disabled, then all unvested stock
    options will fully accelerate. All unvested time-based RSUs will
    fully accelerate, and a pro-rated portion of any
    performance-based RSUs will vest if the Committee certifies that
    the performance measures were met.(4)
    
    For an NEO who is involuntarily terminated who receives
    severance or for an NEO whose job is outsourced with no
    comparable internal offer, all unvested time-based RSUs will
    fully accelerate and a pro-rated portion of any
    performance-based RSUs will vest if the Committee certifies that
    the performance measures were met. However all unvested stock
    options cancel.(5)
    
    See Change In Control Agreements above.   138




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##### Table of Contents



PRINCIPAL
    STOCKHOLDER    
    each person who is an executive officer;
    each person who is a director;
    all directors and executive officers as a group; and
    Williams, who, after completion of this offering will own 100%
    of the outstanding shares of our Class B common stock,
    which will represent (1)     % of all
    classes of our outstanding common stock
    (     % if the underwriters exercise
    their option to purchase additional Class A common shares
    in full) and (2)     % of the combined
    voting power of all classes of our outstanding common stock on
    all matters (     % if the underwriters
    exercise their option to purchase additional Class A common
    shares in full).    74172-0172. c/o WPX 74172-0172.
  Number of Class A



Number of Class BShares Beneficially

Percentage

Shares Beneficially

PercentageName of Beneficial Owner

Owned

of Class

Owned

of ClassThe Williams Companies, Inc.Alan S. ArmstrongRalph A. HillDonald R. ChappelTed T. TimmermansJames J. BenderRobyn L. EwingRodney J. SailorAll executive officers and directors as a group (seven persons)Total  139




---



##### Table of Contents



ARRANGEMENTS
    BETWEEN WILLIAMS AND OUR COMPANY      Separation
    and Distribution Agreement
    Transfer of Assets and Assumption of
    Liabilities.
    This Offering.
  The Distribution.
    Representations and Warranties.
 140




---



##### Table of Contents



Contractual Restrictions.
  
    take any action that would limit the ability of Williams to
    transfer its shares of our common stock or limit the rights of
    any transferee of Williams as a holder of our common stock;
    issue any shares of our capital stock, or any rights, warrants
    or options to acquire our capital stock, if the issuance would
    cause Williams to own less than 50% of the total value of all
    classes of our outstanding capital stock, 80% of the total
    voting power of all classes of our outstanding capital stock
    generally entitled to elect our directors or 80% of any class of
    outstanding capital stock not entitled to vote; or
    take any action, or fail to take any action, to the extent such
    action or failure could reasonably result in Williams being in
    breach or default under a contract of which Williams has
    notified us. 
   
 
  
    acquire any businesses or assets with an aggregate value of more
    than $50 million for all such acquisitions; 
 
  
    dispose of any assets with an aggregate value of more than
    $50 million for all such dispositions; and 
 
  
    acquire any equity or debt securities of any other person with
    an aggregate value of more than $50 million for all such
    acquisitions. 
      Financial Reporting.
  
    comply with all requirements under applicable law regarding
    disclosure controls and procedures and internal control over
    financial reporting;
    maintain internal systems and procedures that will provide
    Williams with reasonable assurance that our financial statements
    and other publicly reported information is reliable and timely
    prepared in accordance with GAAP and any other applicable law;
    provide Williams with financial reports, including consolidated
    financial statements (and notes thereto) and discussion and
    analysis by management of our financial condition and liquidity,
    in the form, and in accordance with the dates, specified by
    Williams;
    unless required by law, use the auditors (and lead audit
    partners) directed by Williams; and
    unless required by law, to the extent requested by Williams,
    keep our accounting practices and principles consistent with
    those of Williams.  Releases.
 141




---



##### Table of Contents



Confidentiality.
  Further Assurances.
  Indemnification.
  
    the liabilities being assumed by us pursuant to the separation
    and distribution agreement;
    the operation of our business;
    any breach by us of the separation and distribution agreement or
    the ancillary agreements; and
    any untrue statement or alleged untrue statement of a material
    fact or omission or alleged omission to state a material fact
    required to be stated therein or necessary to make the
    statements therein not misleading, with respect to all
    information (i) contained in the registration statement of
    which this prospectus is a part or in this prospectus,
    (ii) contained in any public filings made by us with the
    SEC following the separation; and (iii) provided by us to
    Williams specifically for inclusion in Williams annual or
    quarterly reports following the separation.    
    the liabilities being retained by Williams pursuant to the
    separation and distribution agreement;
    the operation of Williams business;
    any breach by Williams of the separation and distribution
    agreement or the ancillary agreements; and
    certain pending or threatened litigation related to the
    2000-2001
    California Energy Crisis and the reporting of certain natural
    gas-related information to trade publications.    Termination.
  Dispute Resolution.
  
    first, the parties will use commercially reasonable efforts to
    resolve the dispute through negotiations between our
    representatives and Williams representatives;
    if negotiations fail, then the parties will attempt to resolve
    the dispute through non-binding mediation; and
    if mediation fails, then the parties may seek relief in any
    court of competent jurisdiction. 142




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##### Table of Contents



Expenses.
  Administrative
    Services and Transition Services Agreements
    
    cash management and treasury administration;
    finance and accounting;
    tax;
    internal audit;
    investor relations;
    payroll and human resource administration;
    information technology;
    legal and government affairs;
    insurance and claims administration;
    records management;
    real estate and facilities management;
    sourcing and procurement; and
    mail, print and other office services.   
  out-of-pocket
 
   143




---



##### Table of Contents



Registration
    Rights Agreement
  lock-up
  Shares Covered.
  Demand Registration.
  12-month
  Piggy-Back Registration.
  Registration Expenses.
  Indemnification.
  Transfer.
  Duration.
  
    such shares have been sold pursuant to an effective registration
    statement under the Securities Act;
    such shares have been sold to the public pursuant to
    Rule 144 under the Securities Act; 144




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##### Table of Contents




    such shares have been otherwise transferred and new certificates
    evidencing such shares have been delivered and do not bear a
    legend restricting further transfer of such shares, provided
    that subsequent public distribution of such shares does not
    require registration or qualification of them under the
    Securities Act or any similar state law;
    such shares have ceased to be outstanding; or
    the distribution date.  Tax
    Sharing Agreement
    Tax Returns and Taxes.
  Pro Forma Returns and Reimbursements.
  Redeterminations.
 
  Spin-off.
 
 145




---



##### Table of Contents



two-year
  Indemnities.
  Proceedings and Cooperation.
 
  Information
    Technology Transition Costs
 
 
   
 146




---



##### Table of Contents



OTHER
    RELATED PARTY TRANSACTIONS    Reimbursement
    of Expenses of Williams
      Commodity
    Sales Contracts
 
   
    Gathering,
    Processing and Treating Contracts
   
   
 147




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##### Table of Contents



life-of-lease
 
  Transportation
    Contracts
        Derivative
    Contracts
    Agreements
    Related to the Piceance Disposition
    Contribution Agreement.
  Conveyance, Contribution, and Assumption
    Agreement.
  Piceance Omnibus Agreement.
 148




---



##### Table of Contents



Transition Services Agreement.
  Meter Agency Agreements.
 149




---



##### Table of Contents



DESCRIPTION
    OF OUR CONCURRENT FINANCING TRANSACTIONS    Notes
  non-U.S. persons
    Credit
    Facility
    
    a ratio of Debt to Capitalization (as such terms will be defined
    in the Credit Facility) no greater than 60% for us and our
    consolidated subsidiaries as calculated at the end of each
    fiscal quarter; and
    if our senior unsecured debt rating at the time of this offering
    is below investment grade with a stable outlook, an additional
    covenant will require a minimum ratio of Net Present Value of
    Projected Future Cash Flows from Proved Reserves to Debt (as
    defined in the Credit Facility) for us and our consolidated
    subsidiaries as calculated at the end of each fiscal quarter.
    This covenant would fall away if and when an investment grade
    rating with a stable outlook is received.   150




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##### Table of Contents



DESCRIPTION
    OF CAPITAL STOCK    Authorized
    Capitalization
 
   
    Common
    Stock
  Voting
    Rights
  one-for-one
  Dividends
    
    shares of Class A common stock may be paid only to holders
    of Class A common stock, and
    shares of Class B common stock may be paid only to holders
    of Class B common stock.     151




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##### Table of Contents



Conversion
      one-for-one
  Other
    Rights
          Preferred
    Stock
    
    the designation of the series; 152




---



##### Table of Contents




    the number of shares of the series, which our board may, except
    where otherwise provided in the preferred stock designation,
    increase or decrease, but not below the number of shares then
    outstanding;
    whether dividends, if any, will be cumulative or non-cumulative
    and the dividend rate of the series;
    the dates at which dividends, if any, will be payable;
    the redemption rights and price or prices, if any, for shares of
    the series;
    the terms and amounts of any sinking fund provided for the
    purchase or redemption of shares of the series;
    the amounts payable on shares of the series in the event of any
    voluntary or involuntary liquidation, dissolution or
    winding-up
    of the affairs of our company;
    whether the shares of the series will have conversion privileges
    and if so, the terms and conditions of such privileges,
    including provision for adjustment of the conversion rate, if
    any;
    restrictions on the issuance of shares of the same series or of
    any other class or series; and
    the voting rights, if any, of the holders of the series.  Provisions
    of Amended and Restated Certificate of Incorporation Governing
    Corporate Opportunities
     153




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##### Table of Contents



Anti-Takeover
    Effects of Certificate of Incorporation and Bylaws
    Provisions
    
    acquisition of us by means of a tender offer or merger;
    acquisition of us by means of a proxy contest or
    otherwise; or
    removal of our incumbent officers and directors.    Classified
    Board
    Election
    and Removal of Directors
      Size
    of Board and Vacancies
   154




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##### Table of Contents



Stockholder
    Action by Written Consent
    Stockholder
    Meetings
    Amendments
    to Certain Provisions of our Bylaws
    Amendment
    of Certain Provisions of our Certificate of
    Incorporation
    Requirements
    for Advance Notification of Stockholder Nominations and
    Proposals
   155




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##### Table of Contents



No
    Cumulative Voting
    Undesignated
    Preferred Stock
    Delaware
    Anti-Takeover Statute
    
    the business combination, or the transaction in
    which the stockholder became an interested
    stockholder is approved by the board of directors prior to
    the date the interested stockholder attained that
    status;
    upon completion of the transaction that resulted in the
    stockholder becoming an interested stockholder, the
    interested stockholder owned at least 85% of the
    voting stock of the corporation outstanding at the time the
    transaction commenced (excluding for purposes of determining the
    voting stock outstanding and not outstanding, voting stock owned
    by the interested stockholder, those shares owned by persons who
    are directors and also officers, and employee stock plans in
    which employee participants do not have the right to determine
    confidentiality whether shares held subject to the plan will be
    tendered in a tender or exchange offer); or
    on or subsequent to the date a person became an interested
    stockholder, the business combination is
    approved by the board of directors and authorized at an annual
    or special meeting of stockholders by the affirmative vote of at
    least two-thirds of the outstanding voting stock that is not
    owned by the interested stockholder.    Limitations
    on Liability and Indemnification of Officers and
    Directors
    
    for any breach of the directors duty of loyalty to the
    corporation or its stockholders; 156




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##### Table of Contents




    for acts or omissions not in good faith or which involve
    intentional misconduct or a knowing violation of law;
    pursuant to Section 174 of the Delaware General Corporation
    Law (providing for liability of directors for unlawful payment
    of dividends or unlawful stock purchases or redemptions); or
    for any transaction from which a director derived an improper
    personal benefit.    Transfer
    Agent and Registrar
    Listing
 
   
 157




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##### Table of Contents



SHARES ELIGIBLE
    FOR FUTURE SALE      Rule 144
  lock-up
  
    1.0% of the number of shares of Class A common stock then
    outstanding, which is
    approximately          
    (           if
    the underwriters exercise their option to purchase additional
    Class A common shares in full) shares of Class A
    common stock upon the completion of this offering; and
    the average weekly trading volume of our Class A common
    stock on the NYSE during the four calendar weeks preceding each
    such sale, subject to certain restrictions.    Lock-up
    Agreements
   158




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##### Table of Contents



Shares Issued
    Under Employee Plans
  Form S-8 lock-up
  Registration
    Rights
    Spin-off
  lock-up
 159




---



##### Table of Contents



CERTAIN
    U.S. FEDERAL INCOME TAX CONSIDERATIONS    
    tax consequences to holders who may be subject to special tax
    treatment, such as dealers in securities or currencies,
    financial institutions, regulated investment companies, real
    estate investment trusts, expatriates, tax-exempt entities,
    traders in securities that elect to use a
    mark-to-market
    method of accounting for their securities or insurance companies;
    tax consequences to persons holding shares of our Class A
    common stock as part of a hedging, integrated, or conversion
    transaction or a straddle or persons deemed to sell shares of
    our Class A common stock under the constructive sale
    provisions of the Code;
    tax consequences to persons who at any time hold more than 5% of
    the total fair market value of any class of our stock;
    tax consequences to U.S. holders of shares of our
    Class A common stock whose functional currency
    is not the U.S. dollar;
    tax consequences to partnerships or other pass-through entities
    and investors in such entities; or
    alternative minimum tax consequences, if any.          Consequences
    to U.S. Holders
    
    an individual citizen or resident of the United States;
    a corporation (or any other entity treated as a corporation for
    U.S. federal income tax purposes) created or organized in
    or under the laws of the United States, any state thereof or the
    District of Columbia;
    an estate the income of which is subject to U.S. federal
    income taxation regardless of its source; or 160




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##### Table of Contents




    a trust if (1) it is subject to the primary supervision of
    a court within the United States and one or more
    U.S. persons have the authority to control all substantial
    decisions of the trust, or (2) it has a valid election in
    effect under applicable U.S. Treasury regulations to be
    treated as a U.S. person.  Distributions
      Sale,
    Exchange, Redemption or Certain Other Taxable Dispositions of
    our Class A Common Stock
    Information
    Reporting and Backup Withholding
  Form W-9
  Consequences
    to Non-U.S.
    Holders
  non-U.S. holder non-U.S. holder non-U.S. holders
 161




---



##### Table of Contents



Distributions
  non-U.S. holder
  non-U.S. holder non-U.S. holder
  Sale,
    Exchange, Redemption or Other Taxable Disposition of our
    Class A Common Stock
  non-U.S. holder
  
    that gain is effectively connected with the conduct of a trade
    or business in the United States (and, if required by an
    applicable income tax treaty, is attributable to a
    U.S. permanent establishment);
    the
    non-U.S. holder
    is an individual who is present in the United States for
    183 days or more in the taxable year of that disposition,
    and certain other conditions are met; or
    our Class A common stock constitutes a U.S. real
    property interest by reason of our status as a
    U.S. real property holding corporation (a
    USRPHC) for U.S. federal income tax purposes at
    any time within the shorter of the five-year period preceding
    the disposition or the period that the
    non-U.S. holder
    held our Class A common stock.  non-U.S. holder non-U.S. holder non-U.S. holder Form W-8BEN non-U.S. holder non-U.S. holder
  non-U.S. holder
 162




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##### Table of Contents



Non-U.S. holders
  Information
    Reporting and Backup Withholding
  non-U.S. holders
  non-U.S. holder non-U.S. holder non-U.S. holder non-U.S. holder U.S.-related
    New
    Legislation Relating to Foreign Accounts
  non-U.S. entities U.S.-owned
  Health
    Care Education and Reconciliation Act of 2010
   163




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##### Table of Contents



UNDERWRITING   
  
 Number ofUnderwriters

SharesBarclays Capital Inc.Citigroup Global Markets Inc.J.P. Morgan Securities LLCMerrill Lynch Incorporated, Pierce, Fenner & SmithDeutsche Bank Securities Inc.Goldman, Sachs & Co.Morgan Stanley & Co. LLC.Wells Fargo Securities, LLCCredit Suisse Securities (USA) LLCRBC Capital Markets, LLCScotia Capital (USA) Inc.UBS Securities LLCHoward Weil IncorporatedTotal  
    
    the obligation to purchase all of the shares of Class A
    common stock offered hereby (other than those shares of
    Class A common stock covered by their option to purchase
    additional shares as described below), if any of the shares are
    purchased;
    the representations and warranties made by us to the
    underwriters are true;
    there is no material change in our business or the financial
    markets; and
    we deliver customary closing documents to the underwriters.  Commissions
    and Expenses
    No Exercise


Full ExercisePer shareTotal    164




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##### Table of Contents



Option to
    Purchase Additional Shares
 
   
  Lock-Up
    Agreements
    180-day
  
    during the last 17 days of the
    180-day
    restricted period we issue an earnings release or material news
    or a material event relating to us occurs; or
    prior to the expiration of the
    180-day
    restricted period, we announce that we will release earnings
    results during the
    16-day
    period beginning on the last day of the
    180-day
    period,  18-day
  lock-up lock-up
 165




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##### Table of Contents



Directed
    Share Program
  180-day  Lock-Up
  Offering
    Price Determination
    
    the history and prospects for the industry in which we compete;
    our financial information;
    the ability of our management and our business potential and
    earning prospects;
    the prevailing securities markets at the time of this
    offering; and
    the recent market prices of, and the demand for, publicly traded
    shares of generally comparable companies.  Indemnification
 
   
  Stabilization,
    Short Positions and Penalty Bids
    
    Stabilizing transactions permit bids to purchase the underlying
    security so long as the stabilizing bids do not exceed a
    specified maximum.
    A short position involves a sale by the underwriters of shares
    in excess of the number of shares the underwriters are obligated
    to purchase in the offering, which creates the syndicate short
    position. This short position may be either a covered short
    position or a naked short position. In a covered short position,
    the number of shares involved in the sales made by the
    underwriters in excess of the number of shares they are
    obligated to purchase is not greater than the number of shares
    that they may purchase by exercising their option to purchase
    additional shares. In a naked short position, the number of
    shares involved is greater than the number of shares in their
    option to purchase additional shares. The underwriters may close
    out any short position by either exercising their option to
    purchase additional shares
    and/or
    purchasing shares in the open market. In determining the source
    of shares to close out the short position, the underwriters will
    consider, among other things, the price of shares available for
    purchase in the open market as compared to the price at which
    they may purchase shares through their option to purchase
    additional shares. A naked short position is more likely to be
    created 166




---



##### Table of Contents



if the underwriters are concerned that there could be downward
    pressure on the price of the shares in the open market after
    pricing that could adversely affect investors who purchase in
    the offering.  
    Syndicate covering transactions involve purchases of the
    Class A common stock in the open market after the
    distribution has been completed in order to cover syndicate
    short positions.
    Penalty bids permit the representatives to reclaim a selling
    concession from a syndicate member when the Class A common
    stock originally sold by the syndicate member is purchased in a
    stabilizing or syndicate covering transaction to cover syndicate
    short positions.      Electronic
    Distribution
  and/or
  and/or
  New York
    Stock Exchange
 
   
  Discretionary
    Sales
    Stamp
    Taxes
   167




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##### Table of Contents



Relationships
 
 
 
   
 
  and/or and/or and/or
 
  Selling
    Restrictions
  European
    Economic Area
    (a)
    to qualified investors as defined in the Prospectus
    Directive, including:  (i)
    (in the case of Relevant Member States other than Early
    Implementing Member States), legal entities which are authorized
    or regulated to operate in the financial markets or, if not so
    authorized or regulated, whose corporate purpose is solely to
    invest in securities, or any legal entity which has two or more
    of (i) an average of at least 250 employees during the
    last financial year; (ii) a total balance sheet of more
    than 43.0 million and (iii) an annual turnover
    of more than 50.0 million as shown in its last annual
    or consolidated accounts; or  (ii)
    (in the case of Early Implementing Member States), persons or
    entities that are described in points (1) to (4) of
    Section I of Annex II to Directive 2004/39/EC, and
    those who are treated on request as professional clients in
    accordance with Annex II to Directive 2004/39/EC, or
    recognized as eligible counterparties in accordance with
    Article 24 of Directive 2004/39/EC unless they have
    requested that they be treated as non-professional clients;  (b)
    to fewer than 100 (or, in the case of Early Implementing Member
    States, 150) natural or legal persons (other than
    qualified investors as defined in the Prospectus
    Directive), as permitted in the Prospectus Directive, subject to
    obtaining the prior consent of the representatives for any such
    offer; or  (c)
    in any other circumstances falling within Article 3(2) of
    the Prospectus Directive,   168




---



##### Table of Contents



2003/71 2010/73/EU.
  United
    Kingdom
   
  Switzerland
 
 
   
 
   
 
  Dubai
    International Financial Centre
 
 
   
 169




---



##### Table of Contents



and/or
 
  Australia
    (a)
    you confirm and warrant that you are either:  (i)
    a sophisticated investor under
    section 708(8)(a) or (b) of the Corporations Act;  (ii)
    a sophisticated investor under
    section 708(8)(c) or (d) of the Corporations Act and
    that you have provided an accountants certificate to us
    which complies with the requirements of
    section 708(8)(c)(i) or (ii) of the Corporations Act
    and related regulations before the offer has been made;(iii)
    a person associated with the Company under section 708(12)
    of the Corporations Act; or  (iv)
    a professional investor within the meaning of
    section 708(11)(a) or (b) of the Corporations Act,    (b)
    you warrant and agree that you will not offer any of the shares
    for resale in Australia within 12 months of those shares
    being issued unless any such resale offer is exempt from the
    requirement to issue a disclosure document under
    section 708 of the Corporations Act.  Hong
    Kong
    India
   170




---



##### Table of Contents



Japan
  (tekikaku-kikan-toshika)
  Korea
    Singapore
      (a)
    a corporation (which is not an accredited investor (as defined
    in Section 4A of the SFA)) the sole business of which is to
    hold investments and the entire share capital of which is owned
    by one or more individuals, each of whom is an accredited
    investor; or  (b)
    a trust (where the trustee is not an accredited investor (as
    defined in Section 4A of the SFA)) whose sole whole purpose
    is to hold investments and each beneficiary is an accredited
    investor, shares, debentures and units of shares and debentures
    of that corporation or the beneficiaries rights and
    interest (howsoever described) in that trust shall not be
    transferable within six months after that corporation or that
    trust has acquired the shares under Section 275 of the SFA
    except:  (i)
    to an institutional investor under Section 274 of the SFA
    or to a relevant person (as defined in Section 275(2) of
    the SFA) and in accordance with the conditions, specified in
    Section 275 of the SFA;  (ii)
    (in the case of a corporation) where the transfer arises from an
    offer referred to in Section 275(1A) of the SFA, or (in the
    case of a trust) where the transfer arises from an offer that is
    made on terms that such rights or interests are acquired at a
    consideration of not less than S$200,000 (or its equivalent in a
    foreign currency) for each transaction, whether such amount is
    to be paid for in cash or by exchange of securities or other
    assets; 171




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##### Table of Contents



(iii)
    where no consideration is or will be given for the
    transfer; or  (iv)
    where the transfer is by operation of law.   LEGAL
    MATTERS   EXPERTS       WHERE YOU
    CAN FIND MORE INFORMATION  Form S-1
  1-800-SEC-0330
 172




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##### Table of Contents



INDEX TO
    FINANCIAL STATEMENTS  
 PageUnaudited pro forma combined financial statementsIntroduction


F-2Pro Forma Combined Balance Sheet as of
    March 31, 2011 (unaudited)


F-3Pro Forma Combined Statement of Operations for
    the three months ended March 31, 2011 and the year ended
    December 31, 2010 (unaudited)


F-4Notes to Pro Forma Combined Financial Statements
    (unaudited)


F-5Interim unaudited condensed combined financial statementsCondensed Combined Statement of Operations for
    the three months ended March 31, 2011 and 2010
    (unaudited)


F-8Condensed Combined Balance Sheet as of
    March 31, 2011 and December 31, 2010 (unaudited)


F-9Condensed Combined Statement of Equity for the
    three months ended March 31, 2011 and 2010 (unaudited)


F-10Condensed Combined Statement of Cash Flows for
    the three months ended March 31, 2011 and 2010
    (unaudited)


F-11Notes to Condensed Combined Financial Statements
    (unaudited)


F-12Annual audited combined financial statementsReport of Independent Registered Public
    Accounting Firm


F-28Combined Statement of Operations for the years
    ended December 31, 2010, 2009 and 2008


F-29Combined Balance Sheet as of December 31,
    2010 and 2009


F-30Combined Statement of Equity for the years ended
    December 31, 2010, 2009 and 2008


F-31Combined Statement of Cash Flows for the years
    ended December 31, 2010, 2009 and 2008


F-32Notes to Combined Financial Statements


F-33  
 F-1




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##### Table of Contents



WPX
    Energy
  Unaudited
    Pro Forma Combined Financial Statements
 Introduction   
     F-2




---



##### Table of Contents



WPX
    Energy
 Unaudited
    Pro Forma Combined Balance SheetMarch 31, 2011 Pro Forma AdjustmentsCombined


Restructuring


Concurrent Financing


Offering


CombinedHistorical (a)


Transactions


Transactions


Transactions


Pro Forma(millions)AssetsCurrent assets:Cash and cash equivalents

$
40


$



$
1,480
(c)

$
705
(g)

$
540(7
)(d)(1,678
)(e)Accounts receivable:Trade, net of allowance for doubtful accounts


356















356Affiliate


43















43Derivative assets


306















306Inventories


43















43Other


56















56Total current assets


844







(205
)


705



1,344Investments


109















109Properties and equipment, net


8,503















8,503Derivative assets


167















167Other noncurrent assets


141







20
(c)






1687
(d)Total assets

$
9,764


$



$
(178
)

$
705


$
10,291Liabilities and EquityCurrent liabilities:Accounts payable:Trade

$
387


$



$



$



$
387Affiliates


51















51Accrued and other current liabilities


156















156Deferred income taxes


58















58Notes payable to Williams


2,364



(2,364
)(a)










Derivative liabilities


143















143Total current liabilities


3,159



(2,364
)










795Deferred income taxes


1,612















1,612Long-term debt










1,500
(c)






1,500Derivative liabilities


158















158Asset retirement obligations


290















290Other noncurrent liabilities


105



46
(a)










151Equity:Owners net investment


4,258



2,364
(a)
    (46)(a)


(1,678
)(e)






(4,898
)(b)Accumulated other comprehensive income


108















108Class A common stock














705
(g)


705Class B common stock






4,898
(b)










4,898Noncontrolling interests


74















74Total equity


4,440



2,318



(1,678
)


705



5,785Total liabilities and equity

$
9,764


$



$
(178
)

$
705


$
10,291    F-3




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##### Table of Contents



WPX
    Energy
  Unaudited Pro Forma Combined Statement of
    Operations
  Three Months Ended March 31, 2011


Year Ended December 31, 2010Combined


Pro Forma


Combined


Combined


Pro Forma


CombinedHistorical


Adjustments


Pro Forma


Historical


Adjustments


Pro Forma(Millions - except per share amounts)Revenues

$
984


$



$
984


$
4,034


$



$
4,034Costs and expenses:Lease and facility operating expense, including affiliate


70







70



286







286Gathering, processing and transportation, including affiliate


115







115



326







326Taxes other than income


31







31



125







125Gas management (including charges for unutilized pipeline
    capacity)


417







417



1,771







1,771Exploration


13







13



73







73Depreciation, depletion and amortization


216







216



875







875Impairment of producing properties and costs of acquired
    unproved reserves














678







678Goodwill impairment














1,003







1,003General and administrative, including affiliate


70







70



253







253Other  net


3







3



(19
)






(19
)Total costs and expenses


935







935



5,371







5,371Operating income (loss)


49







49



(1,337
)






(1,337
)Interest expense, including affiliate


(49
)


46
(a)


(27
)


(124
)


119
(a)


(103
)(24
)(f)










(98
)(f)Interest capitalized


4







4



16







16Investment income and other


6







6



21







21Income (loss) before income taxes


10



22



32



(1,424
)


21



(1,403
)Provision (benefit) for income taxes


3



8
(h)


11



(150
)


8
(h)


(142
)Income (loss) from continuing operations


7



14



21



(1,274
)


13



(1,261
)Loss from discontinued operations


(8
)






(8
)


(8
)






(8
)Net income (loss)

$
(1
)

$
14


$
13


$
(1,282
)

$
13


$
(1,269
)Pro forma income (loss) from continuing operations per share
    (Note 3):Basic

$







$











$Diluted

$







$











$Weighted average shares outstanding:Basic







(g)











(g)Diluted







(g)











(g)    F-4




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##### Table of Contents



WPX
    Energy
  Notes
    to Pro Forma Combined Financial Statements
 (Unaudited)
  Note 1.
    Basis of
    Presentation     
   
    Note 2.
    Pro Forma
    Adjustments  Restructuring
    Transactions
 
   
 F-5




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##### Table of Contents



WPX
    Energy
  Notes to
    Pro Forma Combined Financial
    Statements  (Continued)
 
   
 
  
    In June 2011, Williams contributed to our capital all notes
    payable to Williams owed by the combined entities and, as a
    result, as of July 1, 2011, we have and will receive our
    investment in these certain subsidiaries without any debt to
    Williams. The balance of these notes payable to Williams at
    March 31, 2011 was $2.4 billion and is reflected in
    adjustment (a) in the unaudited pro forma combined balance
    sheet as a decrease in the historical balance of notes payable
    to Williams and an increase in our total equity. Additionally,
    the unaudited pro forma combined statement of operations
    reflects the elimination of $46 million and
    $119 million of affiliate interest expense associated with
    these notes for the three months ended March 31, 2011 and
    the year ended December 31, 2010, respectively, that is
    replaced by the interest incurred on the new senior unsecured
    notes. 
 
  
    The indemnifications included in the separation and distribution
    agreement result in the addition of a $46 million
    non-current liability as of March 31, 2011, which
    represents the net asset (net of related liabilities) we have
    recorded related to Williams former power business
    matters. We will be required to pay Williams for any net cash
    received upon ultimate resolution of these matters. For
    additional information regarding these indemnifications and the
    Williams former power business matters, see
    Arrangements Between Williams and Our Company and
    Note 11 of Notes to Combined Financial Statements,
    respectively. 
    Concurrent
    Financing Transactions
          
    interest expense on the notes;
    amortized debt issuance costs related to our debt; and
    commitment fees and amortized costs related to our new credit
    facility.   F-6




---



##### Table of Contents



WPX
    Energy
  Notes to
    Pro Forma Combined Financial
    Statements  (Continued)
    Offering
    Transactions
    Other
    Adjustments
    Note 3.
    Earnings
    per Share   F-7




---



##### Table of Contents



WPX
    Energy
    (Note 1)
    Condensed Combined Statement of Operations(Unaudited)  Three Months Ended March 31,2011


2010(Dollars in millions)Revenues:Oil and gas sales, including affiliate

$
572


$
587Gas management, including affiliate


408



556Hedge ineffectiveness and mark to market gains and losses


2



9Other


2



12Total revenues


984



1,164Costs and expenses:Lease and facility operating, including affiliate


70



66Gathering, processing and transportation, including affiliate


115



72Taxes other than income


31



40Gas management (including charges for unutilized pipeline
    capacity)


417



558Exploration


13



8Depreciation, depletion and amortization


216



216General and administrative, including affiliate


70



61Other  net


3



Total costs and expenses


935



1,021Operating income


49



143Interest expense, including affiliate


(49
)


(25
)Interest capitalized


4



4Investment income and other


6



5Income before income taxes


10



127Provision for income taxes


3



44Income from continuing operations


7



83Loss from discontinued operations


(8
)


Net income (loss)


(1
)


83Less: Net income attributable to noncontrolling interests


2



2Net income (loss) attributable to WPX Energy

$
(3
)

$
81Supplemental pro forma combined basic loss per common share
    (Note 2)

$Supplemental pro forma combined diluted loss per common share
    (Note 2)

$    F-8




---



##### Table of Contents



WPX
    Energy
    (Note 1)
    Condensed Combined Balance Sheet(Unaudited)  SupplementalPro FormaMarch 31,


March 31,


December 31,2011 (Note 2)


2011


2010(Dollars in millions)AssetsCurrent assets:Cash and cash equivalents

$
40


$
40


$
37Accounts receivable:Trade, net of allowance for doubtful accounts of $19 at
    March 31, 2011 and $16 at December 31, 2010


356



356



362Affiliate


43



43



60Derivative assets


306



306



400Inventories


43



43



77Other


56



56



22Total current assets


844



844



958Investments


109



109



105Properties and equipment (successful efforts method of
    accounting)


12,789



12,789



12,564Less  accumulated depreciation, depletion and
    amortization


(4,286
)


(4,286
)


(4,115
)Properties and equipment, net


8,503



8,503



8,449Derivative assets


167



167



173Other noncurrent assets


141



141



161Total assets

$
9,764


$
9,764


$
9,846Liabilities and EquityCurrent liabilities:Accounts payable:Trade

$
387


$
387


$
451Affiliates


51



51



64Accrued and other current liabilities


156



156



158Deferred income taxes


58



58



87Notes payable to Williams


2,364



2,364



2,261Accrued distribution to Williams


1,678







Derivative liabilities


143



143



146Total current liabilities


4,837



3,159



3,167Deferred income taxes


1,612



1,612



1,629Derivative liabilities


158



158



143Asset retirement obligations


290



290



282Other noncurrent liabilities


105



105



125Contingent liabilities and commitments (Note 8)Equity:Owners net equity:Owners net investment


4,258



4,258



4,260Accrued distribution to Williams


(1,678
)






Accumulated other comprehensive income


108



108



168Total owners net equity


2,688



4,366



4,428Noncontrolling interests in combined subsidiaries


74



74



72Total equity


2,762



4,440



4,500Total liabilities and equity

$
9,764


$
9,764


$
9,846    F-9




---



##### Table of Contents



WPX
    Energy
    (Note 1)
 Condensed
    Combined Statement of Equity(Unaudited)  Three Months Ended March 31,2011


2010Owners Net


Noncontrolling





Owners Net


NoncontrollingEquity


Interests*


Total


Equity


Interests*


Total(Millions)Beginning balance

$
4,428


$
72


$
4,500


$
5,341


$
64


$
5,405Comprehensive income (loss):Net income (loss)


(3
)


2



(1
)


81



2



83Other comprehensive income (loss), net of tax:Net change in cash flow hedges


(60
)






(60
)


163







163Total comprehensive income (loss)


(63
)


2



(61
)


244



2



246Net transfers with Williams


1







1



1







1Ending balance

$
4,366


$
74


$
4,440


$
5,586


$
66


$
5,652     *
    
    Represents the 31 percent interest in Apco Oil and Gas
    International Inc. owned by others.   F-10




---



##### Table of Contents



WPX
    Energy
    (Note 1)
 Condensed
    Combined Statement of Cash Flows(Unaudited)  Three Months Ended March 31,2011


2010(Dollars in millions)Operating Activities:Net income (loss)

$
(1
)

$
83Adjustments to reconcile net income (loss) to net cash provided
    by operating activities:Depreciation, depletion, and amortization


218



218Deferred income taxes provision (benefit)


(11
)


29Provision for impairment of properties and equipment (including
    certain exploration expenses)


24



4Cash provided (used) by operating assets and liabilities:Accounts receivable and payable  affiliate


4



6Accounts receivable  trade


2



34Inventories


33



11Margin deposits and customer margin deposits payable


(19
)


11Other current assets






1Accounts payable  trade


(18
)


(30
)Accrued and other current liabilities


13



(19
)Changes in current and noncurrent derivative assets and
    liabilities


17



(15
)Other, including changes in noncurrent assets and liabilities


(22
)


(4
)Net cash provided by operating activities


240



329Investing Activities:Capital expenditures*


(319
)


(284
)Purchases of investments


(4
)


(2
)Other  net


(19
)


Net cash used by investing activities


(342
)


(286
)Financing Activities:Net changes in notes payable to parent


103



(40
)Net changes in owners investment


2



1Net cash provided (used) by financing activities


105



(39
)Increase in cash and cash equivalents


3



4Cash and cash equivalents at beginning of period


37



34Cash and cash equivalents at end of period

$
40


$
38* Increases to property, plant, and equipment

$
(271
)

$
(271
)Changes in related accounts payable and accrued liabilities


(48
)


(13
)Capital expenditures

$
(319
)

$
(284
)    F-11




---



##### Table of Contents



WPX
    Energy



Notes to
    Condensed Combined Financial Statements

(Unaudited) Note 1.
    General   
   
    Note 2.
    Basis of
    Presentation      Discontinued
    operations
     F-12




---



##### Table of Contents



WPX
    Energy
  Notes to
    Condensed Combined Financial
    Statements(Continued)
  Unaudited
    Supplemental pro forma balance sheet and pro forma combined loss
    per share
 
   
    Note 3.
    Discontinued
    Operations  Summarized
    Results of Discontinued Operations
  Three Months Ended March 31,2011


2010(Millions)Revenues

$
3


$
5Income (loss) from discontinued operations before impairment and
    income taxes

$
(2
)

$
Impairment of producing properties


(11
)


(Provision) benefit for income taxes


5



Loss from discontinued operations

$
(8
)

$
      F-13




---



##### Table of Contents



WPX
    Energy
  Notes to
    Condensed Combined Financial
    Statements(Continued)
  4.
    Related
    Party Transactions  Transactions
    with Williams and Other Affiliated Entities
    Three MonthsEndedMarch 31,2011


2010(Millions)Oil and gas sales revenues  sales of NGLs to WPZ

$
81


$
57Gas management revenues  sales of natural gas for
    fuel and shrink to WPZ and another Williams subsidiary


132



167Lease and facility operating expenses from Williams-direct
    employee salary and benefit costs


5



6Gathering, processing and transportation expense from WPZ:Gathering and processing


75



25Transportation


10



6General and administrative from Williams:Direct employee salary and benefit costs


28



25Charges for general and administrative services


15



14Allocated general corporate costs


16



16Other


3



3Interest expense on notes payable to Williams


46



25     March 31,


December 31,2011


2010(Millions)Current:Accounts receivable:Due from WPZ and another Williams subsidiary

$
43


$
60Accounts payable:Due to WPZ

$
8


$
12Due to Williams for cash overdraft


33



38Due to Williams for accrued payroll and benefits


10



14$
51


$
64Current derivative asset with WPZ

$
4


$
Current derivative liability with WPZ

$
3


$
  F-14




---



##### Table of Contents



WPX
    Energy
  Notes to
    Condensed Combined Financial
    Statements(Continued)
  Note 5.
    Exploration
    Expenses    Three MonthsEndedMarch 31,2011


2010(Millions)Geologic and geophysical costs

$
2


$
5Unproved leasehold property impairment, amortization and
    expiration


11



3Total exploration expense

$
13


$
8   Note 6.
    Inventories  March 31,


December 31,2011


2010(Millions)Natural gas in underground storage

$
3


$
31Materials, supplies and other


40



46Total inventories

$
43


$
77   Note 7.
    Provision
    for Income Taxes    Three MonthsEndedMarch 31,2011


2010(Millions)Current:Federal

$
6


$
15State


1



(2
)Foreign


2



29



15Deferred:Federal


(5
)


27State


(1
)


2Foreign






(6
)


29Total provision

$
3


$
44        F-15




---



##### Table of Contents



WPX
    Energy
  Notes to
    Condensed Combined Financial
    Statements(Continued)
  Note 8.
    Contingent
    Liabilities and Commitments  Royalty
    litigation
     F-16




---



##### Table of Contents



WPX
    Energy
  Notes to
    Condensed Combined Financial
    Statements(Continued)
    Environmental
    matters
    Matters
    related to Williams former power business
  California
    energy crisis
    true-up 2000-2001
    Reporting
    of natural gas-related information to trade
    publications
     F-17




---



##### Table of Contents



WPX
    Energy
  Notes to
    Condensed Combined Financial
    Statements(Continued)
    Other
    Divestiture Indemnifications
        Summary
    Commitments
    (Millions)2011

$
1522012


2042013


1982014


1772015


170Thereafter


634Total

$
1,535    F-18




---



##### Table of Contents



WPX
    Energy
  Notes to
    Condensed Combined Financial
    Statements(Continued)
    12-year
    (Millions)2011

$
172012


332013


272014


232015


9Thereafter


15Total

$
124   Note 9.
    Fair
    Value Measurements    March 31, 2011

December 31, 2010Level 1

Level 2

Level 3

Total

Level 1

Level 2

Level 3

Total(Millions)





(Millions)Assets:Energy derivatives

$
58


$
412


$
3


$
473


$
97


$
474


$
2


$
573Liabilities:Energy derivatives

$
54


$
245


$
2


$
301


$
78


$
210


$
1


$
289        F-19




---



##### Table of Contents



WPX
    Energy
  Notes to
    Condensed Combined Financial
    Statements(Continued)
              Level 3
    Fair Value Measurements Using Significant Unobservable
    Inputs
  Three Months Ended March 31,2011


2010(Millions)Beginning balance

$
1


$
1Realized and unrealized gains included in income from continuing
    operations


5



Settlements


(2
)


Transfers into Level 3






Transfers out of Level 3


(3
)


Ending balance

$
1


$
1Unrealized gains included in income from continuing operations
    relating to instruments still held at March 31

$
3


$
  F-20




---



##### Table of Contents



WPX
    Energy
  Notes to
    Condensed Combined Financial
    Statements(Continued)
    Note 10.
    Financial
    Instruments, Derivatives, Guarantees, and Concentration of
    Credit Risk  Financial
    Instruments
  Fair-value
    methods
    Cash and cash equivalents and restricted
    cash and/or
  Other
  Energy derivatives
    March 31, 2011


December 31, 2010Carrying


Fair


Carrying


FairAsset (Liability)

Amount


Value


Amount


Value(Millions)Cash and cash equivalents

$
40


$
40


$
37


$
37Restricted cash

$
23


$
23


$
24


$
24Other

$
(8
)

$
(8
)

$
(25
)

$
(25
)Net energy derivatives:Energy commodity cash flow hedges

$
170


$
170


$
266


$
266Other energy derivatives

$
2


$
2


$
18


$
18   Energy
    Commodity Derivatives
  Risk
    management activities
     F-21




---



##### Table of Contents



WPX
    Energy
  Notes to
    Condensed Combined Financial
    Statements(Continued)
      Weighted AverageNotional


PriceCommodity

Period


Contract Type

Location

Volume (BBtu)


($/MMBtu)Natural Gas


Apr-Dec 2011


Costless Collar

Rockies


12,375


$5.30 - $7.10Natural Gas


Apr-Dec 2011


Costless Collar

San Juan


24,750


$5.27 - $7.06Natural Gas


Apr-Dec 2011


Costless Collar

MidCon


22,000


$5.10 - $7.00Natural Gas


Apr-Dec 2011


Costless Collar

SoCal


8,250


$5.83 - $7.56Natural Gas


Apr-Dec 2011


Costless Collar

Appalachia


8,250


$6.50 - $8.14Natural Gas


Apr-Dec 2011


Location Swaps

Rockies


26,125


$5.31Natural Gas


Apr-Dec 2011


Location Swaps

San Juan


30,250


$5.10Natural Gas


Apr-Dec 2011


Location Swaps

MidCon


6,875


$5.05Natural Gas


Apr-Dec 2011


Location Swaps

SoCal


11,000


$4.95Natural Gas


Apr-Dec 2011


Location Swaps

Appalachia


28,875


$5.32Natural Gas


2012


Location Swaps

Rockies


34,770


$4.76Natural Gas


2012


Location Swaps

San Juan


40,260


$4.94Natural Gas


2012


Location Swaps

MidCon


30,195


$4.75Natural Gas


2012


Location Swaps

SoCal


11,895


$5.14Natural Gas


2012


Location Swaps

Appalachia


42,090


$5.55Notional


Weighted AverageCommodity

Period


Contract Type

Location

Volume (Mbbls)


Price ($/Bbl)Crude Oil


Apr-Dec 2011


Business Day Avg Swaps

WTI


1,077


$96.01Crude Oil


2012


Business Day Avg Swaps

WTI


2,624


$97.32        F-22




---



##### Table of Contents



WPX
    Energy
  Notes to
    Condensed Combined Financial
    Statements(Continued)
    Unit of

Central Hub

Basis

IndexDerivative Notional Volumes

Measure

Risk(a)(d)

Risk(b)

Risk(c)Not Designated as Hedging InstrumentsRisk Management


MMBtu



(6,542,400
)


(17,452,400
)


(30,877,696
)Other


MMBtu



(1,500
)


(226,500
)     (a)
    
    includes physical and financial derivative transactions that
    settle against the Henry Hub price;(b)
    
    includes financial derivative transactions priced off the
    difference in value between the Central Hub and another specific
    delivery point;(c)
    
    includes physical derivative transactions at an unknown future
    price, including purchases of 135,017,130 MMBtu primarily
    on behalf of WPZ and sales of 165,894,826 MMBtu.(d)
    
    includes financial derivatives entered into with WPZ to reduce
    its exposure to decreases in its revenues from fluctuations in
    NGL market prices or increases in costs and operating expenses
    from fluctuations in natural gas market prices. These contracts
    are offset by 3rd party agreements.  Fair
    values and gains (losses)
    March 31, 2011


December 31, 2010Assets


Liabilities


Assets


Liabilities(Millions)Designated as hedging instruments

$
230


$
60


$
288


$
22Not designated as hedging instruments:Legacy natural gas contracts from former power business


223



224



186



187All other


20



17



99



80Total derivatives not designated as hedging instruments


243



241



285



267Total derivatives

$
473


$
301


$
573


$
289  F-23




---



##### Table of Contents



WPX
    Energy
  Notes to
    Condensed Combined Financial
    Statements(Continued)
    Three Months EndedMarch 31,2011


2010


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

$
(20
)

$
284



AOCINet gain reclassified from AOCI into income (effective portion)

$
75


$
27



RevenuesGain (loss) recognized in income (ineffective portion)

$
(1
)

$
5



Revenues       Three Months Ended March 31,2011


2010(Millions)Gas management revenues

$
3


$
26Gas management expenses






Net gain

$
3


$
26   changes
    in current and noncurrent derivative assets and liabilities
  Credit-risk-related
    features
  and/or out-of-the-money
   F-24




---



##### Table of Contents



WPX
    Energy
  Notes to
    Condensed Combined Financial
    Statements(Continued)
    Cash flow
    hedges
    Concentration
    of Credit Risk
  Derivative
    assets and liabilities
    InvestmentCounterparty Type

Grade(a)


Total(Millions)Gas and electric utilities

$
6


$
7Energy marketers and traders






142Financial institutions


324



324$
330



473Credit reserves






Gross credit exposure from derivatives





$
473    F-25




---



##### Table of Contents



WPX
    Energy
  Notes to
    Condensed Combined Financial
    Statements(Continued)
    InvestmentCounterparty Type

Grade(a)


Total(Millions)Gas and electric utilities

$
3


$
3Energy marketers and traders






1Financial institutions


192



192$
195



196Credit reserves






Net credit exposure from derivatives





$
196     (a)
    
    We determine investment grade primarily using publicly available
    credit ratings. We include counterparties with a minimum
    Standard & Poors rating of BBB- or Moodys
    Investors Service rating of Baa3 in investment grade.      Note 11.
    Subsequent
    Events       F-26




---



##### Table of Contents



WPX
    Energy
  Notes to
    Condensed Combined Financial
    Statements(Continued)
         
   
 F-27




---



##### Table of Contents



Report of
    Independent Registered Public Accounting Firm             Ernst &
    Young LLP
   
 
 
 F-28




---



##### Table of Contents



WPX
    Energy
    (Note 1)Combined Statement of
    Operations
  Years Ended December 31,2010


2009


2008(Dollars in millions)Revenues:Oil and gas sales, including affiliate

$
2,225


$
2,168


$
2,882Gas management, including affiliate


1,742



1,456



3,241Hedge ineffectiveness and mark to market gains and losses


27



18



29Other


40



39



32Total revenues


4,034



3,681



6,184Costs and expenses:Lease and facility operating, including affiliate


286



263



272Gathering, processing and transportation, including affiliate


326



273



229Taxes other than income


125



93



254Gas management (including charges for unutilized pipeline
    capacity)


1,771



1,495



3,248Exploration


73



54



37Depreciation, depletion and amortization


875



887



738Impairment of producing properties and costs of acquired
    unproved reserves


678



15



Goodwill impairment


1,003







General and administrative, including affiliate


253



251



247Gain on sale of contractual right to international production
    payment










(148
)Other  net


(19
)


33



6Total costs and expenses


5,371



3,364



4,883Operating income (loss)


(1,337
)


317



1,301Interest expense, including affiliate


(124
)


(100
)


(74
)Interest capitalized


16



18



20Investment income and other


21



8



22Income (loss) before income taxes


(1,424
)


243



1,269Provision (benefit) for income taxes


(150
)


94



452Income (loss) from continuing operations


(1,274
)


149



817Loss from discontinued operations


(8
)


(7
)


(87
)Net income (loss)


(1,282
)


142



730Less: Net income attributable to noncontrolling interests


8



6



8Net income (loss) attributable to WPX Energy

$
(1,290
)

$
136


$
722Unaudited Supplemental pro forma combined basic loss per common
    share (Note 1)

$Unaudited Supplemental pro forma combined diluted loss per
    common share (Note 1)

$    F-29




---



##### Table of Contents



WPX
    Energy
    (Note 1)Combined Balance Sheet
  December 31,2010


2009(Dollars in millions)AssetsCurrent assets:Cash and cash equivalents

$
37


$
34Accounts receivable:Trade, net of allowance for doubtful accounts of $16 and $19 as
    of December 31, 2010 and 2009, respectively


362



359Affiliate


60



54Derivative assets


400



650Inventories


77



61Other


22



41Total current assets


958



1,199Investments


105



95Properties and equipment, net (successful efforts method of
    accounting)


8,449



7,662Derivative assets


173



444Goodwill, net






1,003Other noncurrent assets


161



150Total assets

$
9,846


$
10,553Liabilities and EquityCurrent liabilities:Accounts payable:Trade

$
451


$
462Affiliates


64



37Accrued and other current liabilities


158



231Deferred income taxes


87



28Notes payable to Williams


2,261



1,216Derivative liabilities


146



578Total current liabilities


3,167



2,552Deferred income taxes


1,629



1,841Derivative liabilities


143



428Asset retirement obligations


282



235Other noncurrent liabilities


125



92Contingent liabilities and commitments (Note 11)Equity:Owners net equity:Owners net investment


4,260



5,269Accumulated other comprehensive income


168



72Total owners net equity


4,428



5,341Noncontrolling interests in combined subsidiaries


72



64Total equity


4,500



5,405Total liabilities and equity

$
9,846


$
10,553    F-30




---



##### Table of Contents



WPX
    Energy
    (Note 1)Combined Statement of
    Equity
  Accumulated OtherOwners Net


Comprehensive


Total Owners Net


NoncontrollingInvestment


Income (Loss)*


Equity


Interest**


Total(Dollars in millions)Balance at December 31, 2007

$
4,462


$
(161
)

$
4,301


$
55


$
4,356Comprehensive income:Net income


722







722



8



730Other comprehensive income:Change in fair value of cash flow hedges (net of $260 of income
    tax)






454



454







454Net reclassifications into earnings of net cash flow hedge
    losses (net of $3 income tax benefit)






5



5







5Total other comprehensive income


















459Total comprehensive income


















1,189Net transfers with Williams


(35
)






(35
)






(35
)Dividends to noncontrolling interests














(4
)


(4
)Balance at December 31, 2008


5,149



298



5,447



59



5,506Comprehensive income:Net income


136







136



6



142Other comprehensive income:Change in fair value of net cash flow hedges (net of $97 of
    income tax)






169



169







169Net reclassifications into earnings of cash flow hedge gain (net
    of $226 income tax provision)






(395
)


(395
)






(395
)Total other comprehensive loss


















(226
)Total comprehensive loss


















(84
)Net transfers with Williams


(16
)






(16
)






(16
)Dividends to noncontrolling interests














(1
)


(1
)Balance at December 31, 2009


5,269



72



5,341



64



5,405Comprehensive income:Net loss


(1,290
)






(1,290
)


8



(1,282
)Other comprehensive income:Change in fair value of net cash flow hedges (net of $184 of
    income tax)






321



321







321Net reclassifications into earnings of cash flow hedge gains
    (net of $129 income tax provision)






(225
)


(225
)






(225
)Total other comprehensive income


















96Total comprehensive loss


















(1,186
)Cash proceeds in excess of historical book value related to
    assets sold to an affiliate


244







244







244Net transfers with Williams


37







37







37Dividends to noncontrolling interests


















Balance at December 31, 2010

$
4,260


$
168


$
4,428


$
72


$
4,500     *
    
    Accumulated other Comprehensive income (loss) is comprised
    primarily of unrealized gains relating to natural gas hedges
    totaling $169 million (net of $97 million for income
    taxes), $74 million (net of $42 million for income
    taxes) and $299 million (net of $172 million for
    income taxes) as of December 31, 2010, 2009 and 2008,
    respectively.**
    
    Represents the 31 percent interest in Apco Oil and Gas
    International Inc. owned by others.   F-31




---



##### Table of Contents



WPX
    Energy
    (Note 1)Combined Statement of Cash
    Flows
  Years Ended December 31,2010


2009


2008(Dollars in millions)Operating ActivitiesNet income (loss)

$
(1,282
)

$
142


$
730Adjustments to reconcile net income (loss) to net cash provided
    by operating activities:Depreciation, depletion and amortization


882



894



758Deferred income tax provision (benefit)


(167
)


106



456Provision for impairment of goodwill and properties and
    equipment (including certain exploration expenses)


1,734



38



173Provision for loss on cost-based investment






11



Gain on sale of contractual right to international production
    payment










(148
)(Gain) loss on sales of other assets


(22
)


1



1Cash provided (used) by operating assets and liabilities:Accounts receivable and payable  affiliate


21



(72
)


20Accounts receivable  trade


7



103



127Other current assets


19



(17
)


(11
)Inventories


(16
)


24



(32
)Margin deposits and customer margin deposit payable


(1
)


4



87Accounts payable  trade


(54
)


(17
)


(91
)Accrued and other current liabilities


(62
)


(109
)


27Changes in current and noncurrent derivative assets and
    liabilities


(45
)


38



(119
)Other, including changes in other noncurrent assets and
    liabilities


42



35



31Net cash provided by operating activities


1,056



1,181



2,009Investing ActivitiesCapital expenditures*


(1,856
)


(1,434
)


(2,467
)Purchase of business


(949
)






Proceeds from sale of contractual right to international
    production payment










148Proceeds from sales of assets


493







72Purchases of investments


(7
)


(1
)


(5
)Other


(18
)






Net cash used in investing activities


(2,337
)


(1,435
)


(2,252
)Financing ActivitiesNet changes in notes payable to parent


1,045



270



269Net changes in owners net investment


241



(16
)


(38
)Other


(2
)


2



(6
)Net cash provided by financing activities


1,284



256



225Net change in cash and cash equivalents


3



2



(18
)Cash and cash equivalents at beginning of period


34



32



50Cash and cash equivalents at end of period

$
37


$
34


$
32* Increase to properties and equipment

$
(1,891
)

$
(1,291
)

$
(2,520
)Changes in related accounts payable


35



(143
)


53Capital expenditures

$
(1,856
)

$
(1,434
)

$
(2,467
)    F-32




---



##### Table of Contents



WPX
    Energy
  Notes
    to Combined Financial Statements
  1.
    Description
    of Business, Basis of Presentation and Summary of Significant
    Accounting Policies  Description
    of Business
   
   
    Basis of
    Presentation
 
   
 
   
   F-33




---



##### Table of Contents



WPX
    Energy
  Notes to
    Combined Financial Statements(Continued)
    Discontinued
    operations
        Summary
    of Significant Accounting Policies
  Basis of
    combination
    Use of
    estimates
      
    Impairment assessments of long-lived assets and goodwill;
    Assessments of litigation-related contingencies; F-34




---



##### Table of Contents



WPX
    Energy
  Notes to
    Combined Financial Statements(Continued)
   
    Valuations of derivatives;
    Hedge accounting correlations and probability;
    Estimation of oil and natural gas reserves.    Cash and
    cash equivalents
      Restricted
    cash
    Accounts
    receivable
    Inventories
    Properties
    and equipment
     F-35




---



##### Table of Contents



WPX
    Energy
  Notes to
    Combined Financial Statements(Continued)
    Other
    capitalized costs
    Depreciation,
    depletion and amortization
  units-of-production units-of-production units-of-production
      Impairment
    of long-lived assets
       F-36




---



##### Table of Contents



WPX
    Energy
  Notes to
    Combined Financial Statements(Continued)
    Asset
    retirement obligations
    Goodwill
        Derivative
    instruments and hedging activities
        Derivative Treatment

Accounting MethodNormal purchases and normal sales exception

Accrual accountingDesignated in a qualifying hedging relationship

Hedge accountingAll other derivatives

Mark-to-market accounting  F-37




---



##### Table of Contents



WPX
    Energy
  Notes to
    Combined Financial Statements(Continued)
            
    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.   F-38




---



##### Table of Contents



WPX
    Energy
  Notes to
    Combined Financial Statements(Continued)
  Business
    segment information
    Oil and
    gas sales revenues
    Gas
    management revenues and expenses
      Capitalization
    of interest
    Income
    taxes
   F-39




---



##### Table of Contents



WPX
    Energy
  Notes to
    Combined Financial Statements(Continued)
    Employee
    stock-based compensation
      Foreign
    exchange
    Earnings
    (loss) per share
    Unaudited
    Supplemental Pro forma combined loss per share
    2.
    Restatement
    of Prior Periods  Materiality Considering the Effects of Prior Year Misstatements
    when Quantifying Misstatements in Current Year Financial
    Statements,
 F-40




---



##### Table of Contents



WPX
    Energy
  Notes to
    Combined Financial Statements(Continued)
    Year Ended


Year Ended


Year EndedDecember 31, 2010


December 31, 2009


December 31, 2008Previously





As


Previously





As


Previously





AsReported(1)


Adjustments


Adjusted


Reported(1)


Adjustments


Adjusted


Reported(1)


Adjustments


AdjustedRevenues:Oil and gas sales, including affiliate

$
2,228


$
(3
)

$
2,225


$
2,170


$
(2
)

$
2,168


$
2,882


$



$
2,882Gas management, including affiliate


1,742







1,742



1,456







1,456



3,244



(3
)


3,241Hedge ineffectiveness and mark to market gains and losses


27







27



18







18



29







29Other


40







40



39







39



32







32Total revenues


4,037



(3
)


4,034



3,683



(2
)


3,681



6,187



(3
)


6,184Costs and expenses:Lease and facility operating, including affiliate


286







286



263







263



272







272Gathering, processing and transportation, including affiliate


323



3



326



268



5



273



223



6



229Taxes other than income


125







125



93







93



254







254Gas management (including charges for unutilized pipeline
    capacity)


1,774



(3
)


1,771



1,496



(1
)


1,495



3,248







3,248Exploration


73







73



54







54



37







37Depreciation, depletion and amortization


874



1



875



887







887



738







738Impairment of producing properties and costs of acquired
    unproved reserves


678







678



15







15











Goodwill impairment


1,003







1,003























General and administrative, including affiliate


252



1



253



251







251



247







247Gain on sale of contractual right to international production
    payment


























(148
)






(148
)Othernet


(19
)






(19
)


33







33



6







6Total costs and expenses


5,369



2



5,371



3,360



4



3,364



4,877



6



4,883Operating income (loss)


(1,332
)


(5
)


(1,337
)


323



(6
)


317



1,310



(9
)


1,301Interest expense, including affiliate


(124
)






(124
)


(100
)






(100
)


(74
)






(74
)Interest capitalized


16







16



18







18



20







20Investment income and other


21







21



8







8



22







22Income (loss) before income taxes


(1,419
)


(5
)


(1,424
)


249



(6
)


243



1,278



(9
)


1,269Provision (benefit) for income taxes


(148
)


(2
)


(150
)


96



(2
)


94



455



(3
)


452Income (loss) from continuing operations


(1,271
)


(3
)


(1,274
)


153



(4
)


149



823



(6
)


817Loss from discontinued operations


(8
)






(8
)


(7
)






(7
)


(87
)






(87
)Net income (loss)


(1,279
)


(3
)


(1,282
)


146



(4
)


142



736



(6
)


730Less: Net income attributable to noncontrolling interests


8







8



6







6



8







8Net income (loss) attributable to WPX Energy

$
(1,287
)

$
(3
)

$
(1,290
)

$
140


$
(4
)

$
136


$
728


$
(6
)

$
722     (1)
    
    Includes reclassifications made to report the results of
    operations of our Arkoma properties as discontinued operations
    (See Note 1). F-41




---



##### Table of Contents



WPX
    Energy
  Notes to
    Combined Financial Statements(Continued)
   December 31, 2010


December 31, 2009Previously





As


Previously





AsReported(1)


Adjustments


Adjusted


Reported(1)


Adjustments


AdjustedAssetsCurrent assets:Cash and cash equivalents

$
37


$



$
37


$
34


$



$
34Accounts receivable:Trade, net of allowance for doubtful accounts of $15 and $19 as
    of December 31, 2010 and 2009, respectively


362







362



361



(2
)


359Affiliate


60







60



54







54Derivative assets


400







400



650







650Inventories


77







77



61







61Other


22







22



41







41Total current assets


958







958



1,201



(2
)


1,199Investments


105







105



95







95Properties and equipment, net (successful efforts method of
    accounting)


8,450



(1
)


8,449



7,662







7,662Derivative assets


173







173



444







444Goodwill, net














1,003







1,003Other noncurrent assets


161







161



150







150Total assets

$
9,847


$
(1
)

$
9,846


$
10,555


$
(2
)

$
10,553Liabilities and EquityCurrent liabilities:Accounts payable:Trade

$
446


$
5


$
451


$
460


$
2


$
462Affiliate


64







64



37







37Accrued and other current liabilities


144



14



158



220



11



231Deferred income taxes


87







87



28







28Notes payable to Williams


2,261







2,261



1,216







1,216Derivative liabilities


146







146



578







578Total current liabilities


3,148



19



3,167



2,539



13



2,552Deferred income taxes


1,629







1,629



1,841







1,841Derivative liabilities


143







143



428







428Asset retirement obligations


282







282



235







235Other noncurrent liabilities


125







125



92







92Contingent liabilities and commitments (Note 11)Equity:Owners net equity:Owners net investment


4,280



(20
)


4,260



5,284



(15
)


5,269Accumulated other comprehensive income


168







168



72







72Total owners net equity


4,448



(20
)


4,428



5,356



(15
)


5,341Noncontrolling interests in combined subsidiaries


72







72



64







64Total equity


4,520



(20
)


4,500



5,420



(15
)


5,405Total liabilities and equity

$
9,847


$
(1
)

$
9,846



10,555


$
(2
)


10,553     (1)
    
    Includes reclassifications made to report the financial position
    of our Arkoma properties as held for sale (See Note 1). F-42




---



##### Table of Contents



WPX
    Energy
  Notes to
    Combined Financial Statements(Continued)
  3.
    Discontinued
    Operations  Summarized
    Results of Discontinued Operations
  2010


2009


2008Revenues

$
16


$
17


$
43Income (loss) from discontinued operations before impairments,
    gain on sale and income taxes

$
(13
)

$
(11
)

$
4(Impairments) and gain on sale










(140
)Benefit for income taxes


5



4



49Loss from discontinued operations

$
(8
)

$
(7
)

$
(87
)       4.
    Related
    Party Transactions  Transactions
    with Williams and Other Affiliated Entities
      
    Sales of natural gas liquids (NGLs) related to our production to
    WPZ at market prices at the time of sale and included within our
    oil and gas sales revenues; and
    Sale to WPZ and another Williams subsidiary of natural gas
    procured by Williams Gas Marketing Services for those
    companies fuel and shrink replacement at market prices at
    the time of sale and included in our gas management revenues.    
    Gathering, treating and processing services under several
    contracts for our production primarily in the San Juan and
    Piceance Basins; and F-43




---



##### Table of Contents



WPX
    Energy
  Notes to
    Combined Financial Statements(Continued)
   
    Pipeline transportation for both our oil and gas sales and gas
    management activities which includes commitments totaling
    $442 million (see Note 11 for capacity commitments
    with affiliates).       
   
   F-44




---



##### Table of Contents



WPX
    Energy
  Notes to
    Combined Financial Statements(Continued)
    2010


2009


2008(Millions)Oil and gas sales revenuessales of NGLs to WPZ

$
277


$
116


$
36Gas management revenuessales of natural gas for fuel and
    shrink to WPZ and another Williams subsidiary


509



431



1,042Lease and facility operating expenses from Williams-direct
    employee salary and benefit costs


23



23



19Gathering, processing and transportation expense fromWPZ:Gathering and processing


163



72



44Transportation


25



28



34General and administrative from Williams:Direct employee salary and benefit costs


102



100



92Charges for general and administrative services


58



60



60Allocated general corporate costs


64



63



56Other


12



13



12Interest expense on notes payable to Williams


119



92



64     December 31,2010


2009(Millions)Current:Accounts receivable:Due from WPZ and another Williams subsidiary

$
60


$
54Accounts payable:Due to WPZ

$
12


$
2Due to Williams for cash overdraft.


38



26Due to Williams for accrued payroll and benefits


14



9$
64


$
37    F-45




---



##### Table of Contents



WPX
    Energy
  Notes to
    Combined Financial Statements(Continued)
    5.
    Investment
    Income and Other    Years Ended December 31,2010


2009


2008(Millions)Equity earnings

$
20


$
18


$
20Impairment of cost-based investment






(11
)


Other


1



1



2Total investment income and other

$
21


$
8


$
22     Investments
    December 31,2010


2009(Millions)Petrolera Entre Lomas S.A.40.8%

$
82


$
81Other


23



14$
105


$
95     6.
    Asset
    Sales, Impairments, Exploration Expenses and Other
    Accruals    Years Ended December 31,2010


2009


2008(Millions)Goodwill impairment

$
1,003


$



$
Impairment of producing properties and costs of acquired
    unproved reserves*


678



15



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






32



Gain on sale of contractual right to an international production
    payment










(148
)(Gain) loss on sales of other assets


(22
)


1



1     *
    
    Excludes unproved leasehold property impairment, amortization
    and expiration included in exploration expenses. F-46




---



##### Table of Contents



WPX
    Energy
  Notes to
    Combined Financial Statements(Continued)
               Years Ended December 312010


2009


2008(Millions)Geologic and geophysical costs

$
22


$
33


$
13Dry hole costs


17



11



16Unproved leasehold property impairment, amortization and
    expiration


34



10



8Total exploration expense

$
73


$
54


$
37   Additional
    Items
   F-47




---



##### Table of Contents



WPX
    Energy
  Notes to
    Combined Financial Statements(Continued)
  7.
    Properties
    and Equipment    EstimatedUseful Life(a)


December 31,(Years)


2010


2009(Millions)Proved properties


(b)


$
9,822


$
8,784Unproved properties


(c)



1,893



922Gathering, processing and other facilities


15-25



119



787Construction in progress


(c)



603



573Other


3-25



127



123Total properties and equipment, at cost






12,564



11,189Accumulated depreciation, depletion and amortization






(4,115
)


(3,527
)Properties and equipmentnet





$
8,449


$
7,662     (a)
    
    Estimated useful lives are presented as of December 31,
    2010.(b)
    
    Proved properties are depreciated, depleted and amortized using
    the
    units-of-production
    method (see Note 1).(c)
    
    Unproved properties and construction in progress are not yet
    subject to depreciation and depletion.            No. 2010-03,
 F-48




---



##### Table of Contents



WPX
    Energy
  Notes to
    Combined Financial Statements(Continued)
  Asset
    Retirement Obligations
      2010


2009(Millions)Balance, January 1

$
242


$
194Liabilities incurred during the period


43



18Liabilities settled during the period


(2
)


(1
)Liabilities associated with assets sold


(22
)


Estimate revisions


3



15Accretion expense*


21



16Balance, December 31

$
285


$
242Amount reflected as current

$
3


$
7     *
    
    Accretion expense is included in lease and facility operating
    expense on the Combined Statement of Operations.  8.
    Accrued
    and other current liabilities    December 31,2010


2009(Millions)Taxes other than income taxes

$
76


$
126Customer margin deposit payable


25



31Other


57



74$
158


$
231   9.
    Unsecured
    Credit Agreement  out-of-the-money
 F-49




---



##### Table of Contents



WPX
    Energy
  Notes to
    Combined Financial Statements(Continued)
  10.
    Income
    Taxes      Years Ended December 31,2010


2009


2008(Millions)Provision (benefit):Current:Federal

$
7


$
(17
)

$
(52
)State


1



(1
)


(3
)Foreign


11



9



819



(9
)


(47
)Deferred:Federal


(159
)


97



470State


(10
)


6



30Foreign










(1
)(169
)


103



499Total provision (benefit)

$
(150
)

$
94


$
452     Years Ended December 31,2010


2009


2008(Millions)Provision (benefit) at statutory rate

$
(498
)

$
85


$
444Increases (decreases) in taxes resulting from:State income taxes (net of federal benefit)


(6
)


3



18Foreign operationsnet


3



5



(2
)Goodwill impairment


351







Othernet






1



(8
)Provision (benefit) for income taxes

$
(150
)

$
94


$
452  F-50




---



##### Table of Contents



WPX
    Energy
  Notes to
    Combined Financial Statements(Continued)
      December 31,2010


2009(Millions)Deferred tax liabilities:Properties and equipment

$
1,723


$
1,939Derivatives, net


110



61Total deferred tax liabilities


1,833



2,000Deferred tax assets:Accrued liabilities and other


117



131State loss carryovers


22



22Total deferred tax assets


139



153Less: valuation allowance


22



22Total net deferred tax assets


117



131Net deferred tax liabilities

$
1,716


$
1,869               11.
    Contingent
    Liabilities and Commitments  Royalty
    litigation
   F-51




---



##### Table of Contents



WPX
    Energy
  Notes to
    Combined Financial Statements(Continued)
      Environmental
    matters
    Matters
    related to Williams former power business
  California
    energy crisis
   F-52




---



##### Table of Contents



WPX
    Energy
  Notes to
    Combined Financial Statements(Continued)
    true-up 2000-2001
    Reporting
    of natural gas-related information to trade
    publications
      Other
    Divestiture Indemnifications
       F-53




---



##### Table of Contents



WPX
    Energy
  Notes to
    Combined Financial Statements(Continued)
  Summary
    Commitments
    (Millions)2011

$
2042012


2082013


2002014


1742015


166Thereafter


635Total

$
1,587       12-year
 F-54




---



##### Table of Contents



WPX
    Energy
  Notes to
    Combined Financial Statements(Continued)
     (Millions)2011

$
142012


102013


92014


42015


3Thereafter


15Total

$
55   month-to-month
  12.
    Employee
    Benefit Plans      Pension
    plans
    Other
    postretirement benefits
    Defined
    contribution plan
   F-55




---



##### Table of Contents



WPX
    Energy
  Notes to
    Combined Financial Statements(Continued)
    13.
    Stock-Based
    Compensation        Employee
    stock-based awards
        Stock
    Options
    F-56




---



##### Table of Contents



WPX
    Energy
  Notes to
    Combined Financial Statements(Continued)
  Weighted-Average


AggregateExercise


IntrinsicStock Options

Options


Price


Value(Millions)





(Millions)Outstanding at December 31, 2009


1.6


$
17.47Granted


0.2


$
21.22Exercised


(0.1
)

$
7.65


$
2Expired


(0.1
)

$
42.29Forfeited





$
Outstanding at December 31, 2010


1.6


$
18.23


$
13Exercisable at December 31, 2010


1.2


$
18.20


$
10       Stock Options Outstanding


Stock Options ExercisableWeighted-








Weighted-Weighted-


Average





Weighted-


AverageAverage


Remaining





Average


RemainingExercise


Contractual





Exercise


ContractualRange of Exercise Prices

Options


Price


Life


Options


Price


Life(Millions)





(Years)


(Millions)





(Years)$2.58 to $11.84


0.6


$
8.79



4.9



0.5


$
7.88



3.4$11.85 to 21.67


0.6


$
20.32



6.1



0.4


$
19.79



4.3$21.68 to $33.65


0.2


$
27.84



6.0



0.2


$
27.84



6.0$33.66 to $36.50


0.2


$
36.21



5.9



0.1


$
36.09



5.5Total


1.6


$
18.23



5.6



1.2


$
18.20



4.4     2010


2009


2008Weighted-average grant date fair value of options granted

$
7.02


$
5.60


$
12.83Weighted-average assumptions:Dividend yield


2.6
%


1.6
%


1.2
%Volatility


39.0
%


60.8
%


33.4
%Risk-free interest rate


3.0
%


2.3
%


3.5
%Expected life (years)


6.5



6.5



6.5    F-57




---



##### Table of Contents



WPX
    Energy
  Notes to
    Combined Financial Statements(Continued)
  Nonvested
    Restricted Stock Units
    Weighted-AverageRestricted Stock Units

Shares


Fair Value*(Millions)Nonvested at December 31, 2009


1.7


$
18.24Granted


0.6


$
21.19Forfeited


(0.1
)

$
19.36Cancelled


(0.1
)

$
0.00Vested


(0.3
)

$
28.35Nonvested at December 31, 2010


1.8


$
17.96     *
    
    Performance-based shares are primarily valued using the
    end-of-period
    market price until certification that the performance objectives
    have been completed, a value of zero once it has been determined
    that it is unlikely that performance objectives will be met, or
    a valuation pricing model. All other shares are valued at the
    grant-date market price.  Other
    restricted stock unit information
  2010


2009


2008Weighted-average grant date fair value of restricted stock units
    granted during the year, per share

$
21.19


$
10.53


$
32.34Total fair value of restricted stock units vested during the
    year ($s in millions)

$
9


$
8


$
6   14.
    Fair
    Value Measurements      
    Level 1Quoted prices for identical assets or
    liabilities in active markets that we have the ability to
    access. Active markets are those in which transactions for the
    asset or liability occur in sufficient frequency and volume to
    provide pricing information on an ongoing basis. Our
    Level 1 primarily consists of financial instruments that
    are exchange traded;
    Level 2Inputs are other than quoted prices in active
    markets included in Level 1, that are either directly or
    indirectly observable. These inputs are either directly
    observable in the marketplace or F-58




---



##### Table of Contents



WPX
    Energy
  Notes to
    Combined Financial Statements(Continued)
  indirectly observable through corroboration with market data for
    substantially the full contractual term of the asset or
    liability being measured. Our Level 2 primarily consists of
    over-the-counter
    (OTC) instruments such as forwards, swaps, and options. These
    options, which hedge future sales of production, are structured
    as costless collars and are financially settled. They are valued
    using an industry standard Black-Scholes option pricing model.
    Prior to 2009, these options were included in Level 3
    because a significant input to the model, implied volatility by
    location, was considered unobservable. However, due to the
    increased transparency, we now consider this input to be
    observable and have included these options in Level 2; and  
    Level 3Inputs that are not observable for which there
    is little, if any, market activity for the asset or liability
    being measured. These inputs reflect managements best
    estimate of the assumptions market participants would use in
    determining fair value. Our Level 3 consists of instruments
    valued using industry standard pricing models and other
    valuation methods that utilize unobservable pricing inputs that
    are significant to the overall fair value.      Fair
    Value Measurements Using:
  December 31, 2010


December 31, 2009Level 1


Level 2


Level 3


Total


Level 1


Level 2


Level 3


Total(Millions)


(Millions)Energy derivative assets

$
97


$
474


$
2


$
573


$
178


$
912


$
4


$
1,094Energy derivative liabilities

$
78


$
210


$
1


$
289


$
177


$
826


$
3


$
1,006            F-59




---



##### Table of Contents



WPX
    Energy
  Notes to
    Combined Financial Statements(Continued)
            Level 3
    Fair Value Measurements Using Significant Unobservable
    Inputs
  Year Ended December 31,2010


2009


2008Net Energy


Net Energy


Net EnergyDerivatives


Derivatives


Derivatives(Millions)Beginning balance

$
1


$
506


$
(5
)Realized and unrealized gains (losses):Included in income (loss) from continuing operations


1



476



96Included in other comprehensive income (loss)






(329
)


478Purchases, issuances, and settlements


(1
)


(479
)


(61
)Transfers into Level 3










3Transfers out of Level 3






(173
)


(5
)Ending balance

$
1


$
1


$
506Unrealized gains included in income from continuing operations
    relating to instruments held at December 31

$



$



$
    F-60




---



##### Table of Contents



WPX
    Energy
  Notes to
    Combined Financial Statements(Continued)
    Fair
    Value Measurements Using:
  Total Losses for the YearsEnded December 31,2010


2009(Millions)Impairments:Goodwill (see Note 6)

$
1,003
(a)

$
Producing properties and costs of acquired unproved reserves
    (see Note 6)


678
(b)


15
(c)Cost-based investment (see Note 5)






11
(d)$
1,681


$
26     (a)
    
    Due to a significant decline in forward natural gas prices
    across all future production periods during 2010, we determined
    that we had a trigger event and thus performed an interim
    impairment assessment of the approximate $1 billion of
    goodwill related to our domestic natural gas production
    operations (the reporting unit). Forward natural gas prices
    through 2025 as of September 30, 2010, used in our analysis
    declined more than 22 percent on average compared to the
    forward prices as of December 31, 2009. We estimated the
    fair value of the reporting unit on a stand-alone basis by
    valuing proved and unproved reserves, as well as estimating the
    fair values of other assets and liabilities which are identified
    to the reporting unit. We used an income approach (discounted
    cash flow) for valuing reserves. The significant inputs into the
    valuation of proved and unproved reserves included reserve
    quantities, forward natural gas prices, anticipated drilling and
    operating costs, anticipated production curves, income taxes,
    and appropriate discount rates. To estimate the fair value of
    the reporting unit and the implied fair value of goodwill under
    a hypothetical acquisition of the reporting unit, we assumed a
    tax structure where a buyer would obtain a
    step-up in
    the tax basis of the net assets acquired. Significant
    assumptions in valuing proved reserves included reserves
    quantities of more than 4.4 trillion cubic feet of gas
    equivalent; forward prices averaging approximately $4.65 per
    thousand cubic feet of gas equivalent (Mcfe) for natural gas
    (adjusted for locational differences), natural gas liquids and
    oil; and an after-tax discount rate of 11 percent. Unproved
    reserves (probable and possible) were valued using similar
    assumptions adjusted further for the uncertainty associated with
    these reserves by using after- tax discount rates of
    13 percent and 15 percent, respectively, commensurate
    with our estimate of the risk of those reserves. In our
    assessment as of September 30, 2010, the carrying value of
    the reporting unit, including goodwill, exceeded its estimated
    fair value. We then determined that the implied fair value of
    the goodwill was zero. As a result of our analysis, we
    recognized a full $1 billion impairment charge related to
    this goodwill.(b)
    
    As of September 30, 2010, we also believed we had a trigger
    event as a result of recent significant declines in forward
    natural gas prices and therefore, we assessed the carrying value
    of our natural gas-producing properties and costs of acquired
    unproved reserves for impairments. Our assessment utilized
    estimates of future cash flows. Significant judgments and
    assumptions in these assessments are similar to those used in
    the goodwill evaluation and include estimates of natural gas
    reserve quantities, estimates of future natural gas prices using
    a forward NYMEX curve adjusted for locational basis
    differentials, drilling plans, expected capital costs, and an
    applicable discount rate commensurate with risk of the
    underlying cash flow estimates. The assessment performed at
    September 30, 2010, identified certain properties with a
    carrying value in excess of their calculated fair values. As a
    result, we recorded a $678 million impairment charge in the F-61




---



##### Table of Contents



WPX
    Energy
  Notes to
    Combined Financial Statements(Continued)
  third-quarter 2010 as further described below. Fair value
    measured for these properties at September 30, 2010, was
    estimated to be approximately $320 million.  
    $503 million of the impairment charge related to natural
    gas-producing properties in the Barnett Shale. Significant
    assumptions in valuing these properties included proved reserves
    quantities of more than 227 billion cubic feet of gas
    equivalent, forward weighted average prices averaging
    approximately $4.67 per Mcfe for natural gas (adjusted for
    locational differences), natural gas liquids and oil, and an
    after-tax discount rate of 11 percent.
    $175 million of the impairment charge related to acquired
    unproved reserves in the Piceance Highlands acquired in 2008
    Significant assumptions in valuing these unproved reserves
    included evaluation of probable and possible reserves
    quantities, drilling plans, forward natural gas (adjusted for
    locational differences) and natural gas liquids prices, and an
    after-tax discount rate of 13 percent.  (c)
    
    Fair value of costs of acquired reserves in the Barnett Shale
    measured at December 31, 2009, was $22 million.
    Significant assumption in valuing these unproved reserves
    included evaluation of probable and possible reserves
    quantities, drilling plans, forward natural gas prices (adjusted
    for locational differences) and an after-tax discount rate of
    11 percent.(d)
    
    Fair value measured at March 31, 2009, was zero. This value
    was based on an
    other-than-temporary
    decline in the value of our investment considering the
    deteriorating financial condition of a Venezuelan corporation in
    which we own a 4 percent interest.  15.
    Financial
    Instruments, Derivatives, Guarantees and Concentration of Credit
    Risk    Cash and cash equivalents and restricted
    cash: and/or
  Other:
  Energy derivatives:
    December 31,2010


2009Carrying


Fair


Carrying


FairAsset (Liability)

Amount


Value


Amount


Value(Millions)Cash and cash equivalents

$
37


$
37


$
34


$
34Restricted cash


24



24



19



19Other


(25
)


(25
)


(26
)


(26
)Net energy derivatives:Energy commodity cash flow hedges


266



266



180



180Other energy derivatives


18



18



(92
)


(92
)  F-62




---



##### Table of Contents



WPX
    Energy
  Notes to
    Combined Financial Statements(Continued)
  Energy
    Commodity Derivatives
        Weighted AverageNotional Volume


PriceCommodity

Period


Contract Type

Location

(BBtu)


($/MMBtu)Natural Gas


2011


Costless Collar

Rockies


16,425


$5.30 - $7.10Natural Gas


2011


Costless Collar

San Juan


32,850


$5.27 - $7.06Natural Gas


2011


Costless Collar

MidCon


29,200


$5.10 - $7.00Natural Gas


2011


Costless Collar

SoCal


10,950


$5.83 - $7.56Natural Gas


2011


Costless Collar

Appalachia


10,950


$6.50 - $8.14Natural Gas


2011


Location Swaps

Rockies


27,375


$5.57Natural Gas


2011


Location Swaps

San Juan


38,325


$5.14Natural Gas


2011


Location Swaps

MidCon


7,300


$5.22Natural Gas


2011


Location Swaps

SoCal


7,300


$5.34Natural Gas


2011


Location Swaps

Appalachia


23,725


$5.59Natural Gas


2012


Location Swaps

Rockies


25,620


$4.79Natural Gas


2012


Location Swaps

San Juan


26,535


$5.06Natural Gas


2012


Location Swaps

MidCon


14,640


$4.74Natural Gas


2012


Location Swaps

SoCal


9,150


$5.22Natural Gas


2012


Location Swaps

Appalachia


20,130


$5.93    F-63




---



##### Table of Contents



WPX
    Energy
  Notes to
    Combined Financial Statements(Continued)
        Unit of


Central Hub


Basis


IndexDerivative Notional Volumes

Measure


Risk(a)


Risk(b)


Risk(c)Not Designated as Hedging InstrumentsRisk Management


MMBtu



(9,077,499
)


(20,195,000
)


16,586,059Other


MMBtu



150,400



(14,766,500
)     (a)
    
    includes physical and financial derivative transactions that
    settle against the Henry Hub price;(b)
    
    includes financial derivative transactions priced off the
    difference in value between the Central Hub and another specific
    delivery point;(c)
    
    includes physical derivative transactions at an unknown future
    price, including purchases of 84,583,157 MMBtu primarily on
    behalf of WPZ and sales of 67,997,098 MMBtu.  Fair
    values and gains (losses)
    December 31,2010


2009Assets


Liabilities


Assets


Liabilities(Millions)Designated as hedging instruments

$
288


$
22


$
352


$
172Not designated as hedging instruments:Legacy natural gas contracts from former power business


186



187



505



526Hedges for storage contracts and other


99



80



237



308Total derivatives not designated as hedging instruments


285



267



742



834Total derivatives

$
573


$
289


$
1,094


$
1,006  F-64




---



##### Table of Contents



WPX
    Energy
  Notes to
    Combined Financial Statements(Continued)
    Years Ended December 31,2010


2009


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

$
505


$
266



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

$
354


$
621



RevenuesGain recognized in income (ineffective portion)

$
9


$
4



Revenues     (1)
    
    Gains reclassified from accumulated other comprehensive income
    (loss) primarily represent realized gains associated with our
    production reflected in oil and gas sales.      Years EndedDecember 31,2010


2009(Millions)Gas management revenues

$
47


$
33Gas management expenses


28



33Net gain

$
19


$
     Credit-risk-related
    features
  and/or out-of-the-money
   F-65




---



##### Table of Contents



WPX
    Energy
  Notes to
    Combined Financial Statements(Continued)
    Cash flow
    hedges
    Concentration
    of Credit Risk
  Cash
    equivalents
    Accounts
    receivable
    2010


2009(Millions)Receivables by product or service:Sale of natural gas and related products and services

$
272


$
286Joint interest owners


83



66Other


7



7Total

$
362


$
359     Derivative
    assets and liabilities
   F-66




---



##### Table of Contents



WPX
    Energy
  Notes to
    Combined Financial Statements(Continued)
        InvestmentCounterparty Type

Grade*


Total(Millions)Gas and electric utilities

$
7


$
8Energy marketers and traders






133Financial institutions


432



432$
439



573Credit reserves






Gross credit exposure from derivatives





$
573     InvestmentCounterparty Type

Grade*


Total(Millions)Gas and electric utilities

$
3


$
3Financial institutions


317



317$
320



320Credit reserves






Net credit exposure from derivatives





$
320     *
    
    We determine investment grade primarily using publicly available
    credit ratings. We include counterparties with a minimum
    Standard & Poors rating of BBB- or Moodys
    Investors Service rating of Baa3 in investment grade.   F-67




---



##### Table of Contents



WPX
    Energy
  Notes to
    Combined Financial Statements(Continued)
      Revenues
    Net
    Assets of Operations in Foreign Locations
    16.
    Subsequent
    Events  Information subsequent to initial date of independent
    registered public accounting firm report
           F-68




---



##### Table of Contents



WPX
    Energy
  Notes to
    Combined Financial Statements(Continued)
       
   
 F-69




---



##### Table of Contents



WPX
    Energy
  Supplemental
    Oil and Gas Disclosures
 (Unaudited)
      Capitalized
    Costs
  As of December 31, 2009Entitys share ofinternationalConsolidated


equity methodDomestic


International


Total


investeeProved Properties

$
9,176


$
180


$
9,356


$
187Unproved properties


945



3



948



10,121



183



10,304



187Accumulated depreciation, depletion and amortization and
    valuation provisions


(3,213
)


(94
)


(3,307
)


(109
)Net capitalized costs

$
6,908


$
89


$
6,997


$
78   As of December 31, 2010Entitys share ofinternationalConsolidated


equity methodDomestic


International


Total


investeeProved Properties

$
9,854


$
213


$
10,067


$
220Unproved properties


2,094



3



2,097



11,948



216



12,164



220Accumulated depreciation, depletion and amortization and
    valuation provisions


(3,867
)


(109
)


(3,976
)


(129
)Net capitalized costs

$
8,081



107


$
8,188


$
91   
    Excluded from capitalized costs are equipment and facilities in
    support of oil and gas production of $312 million and
    $727 million, net, for 2010 and 2009, respectively.
    Proved properties include capitalized costs for oil and gas
    leaseholds holding proved reserves, development wells including
    uncompleted development well costs, and successful exploratory
    wells.
    Unproved properties consist primarily of unproved leasehold
    costs and costs for acquired unproven reserves. F-70




---



##### Table of Contents



WPX
    Energy
  Supplemental
    Oil and Gas Disclosures(Continued)
 (Unaudited)
  Cost
    Incurred
  Entitys share ofinternationalequity methodDomestic


International


investee(Millions)For the Year Ended December 31, 2008Acquisition

$
543


$



$
Exploration


38



9



7Development


1,699



27



25$
2,280


$
36


$
32For the Year Ended December 31, 2009Acquisition

$
305


$
3


$
Exploration


51



3



3Development


878



19



21$
1,234


$
25


$
24For the Year Ended December 31, 2010Acquisition

$
1,731


$



$
Exploration


22



13



3Development


988



27



25$
2,741


$
40


$
28   
    Costs incurred include capitalized and expensed items.
    Acquisition costs are as follows: The 2010 costs are primarily
    for additional leasehold in the Williston and Marcellus Basins
    and include approximately $422 million of proved property
    values. The 2009 costs are primarily for additional leasehold
    and reserve acquisitions in the Piceance Basin, and include
    $85 million of proved property values. The 2008 costs are
    primarily for additional leasehold and reserve acquisitions in
    the Piceance and Fort Worth Basins. Included in the 2008
    acquisition amounts is $140 million of proved property
    values and $71 million related to an interest in a portion
    of acquired assets that a third party subsequently exercised its
    contractual option to purchase from us, on the same terms and
    conditions.
    Exploration costs include the costs incurred for geological and
    geophysical activity, drilling and equipping exploratory wells,
    including costs incurred during the year for wells determined to
    be dry holes, exploratory lease acquisitions, and retaining
    undeveloped leaseholds.
    Development costs include costs incurred to gain access to and
    prepare well locations for drilling and to drill and equip wells
    in our development basins.
    We have classified our step-out drilling and site preparation
    costs in the Powder River Basin as development, although the
    immediate offsets are frequently in the dewatering stages in as
    much as it better reflects the low risk profile of the costs
    incurred. F-71




---



##### Table of Contents



WPX
    Energy
  Supplemental
    Oil and Gas Disclosures(Continued)
 (Unaudited)
  Results
    of Operations
  Domestic


International


Total(Millions)For the Year Ended December 31, 2008Revenues:Oil and gas revenues

$
2,810


$
72


$
2,882Other revenues


32







32Total revenues


2,842



72



2,914Costs:Lease and facility operating


255



17



272Gathering, processing & transportation


229







229Taxes other than income


242



12



254Exploration expenses


31



6



37Depreciation, depletion & amortization


724



14



738General and administrative


217



7



224Gain on sale of international production payment right






(148
)


(148
)Other (income) expense


4



2



6Total costs


1,702



(90
)


1,612Results of operations


1,140



162



1,302(Provision) benefit for income taxes


(416
)


(59
)


(475
)Exploration and production net income (loss)

$
724


$
103


$
827   F-72




---



##### Table of Contents



WPX
    Energy
  Supplemental
    Oil and Gas Disclosures(Continued)
 (Unaudited)
  Domestic


International


Total(Millions)For the Year Ended December 31, 2009Revenues:Oil and gas revenues

$
2,090


$
78


$
2,168Other revenues


39







39Total revenues


2,129



78



2,207Costs:Lease and facility operating


247



16



263Gathering, processing & transportation


273







273Taxes other than income


80



13



93Exploration expenses


52



2



54Depreciation, depletion & amortization


870



17



887Impairment of costs of acquired unproved reserves


15







15General and administrative


221



9



230Other (income) expense


33







33Total costs


1,791



57



1,848Results of operations


338



21



359(Provision) benefit for income taxes


(123
)


(8
)


(131
)Exploration and production net income (loss)

$
215


$
13


$
228   F-73




---



##### Table of Contents



WPX
    Energy
  Supplemental
    Oil and Gas Disclosures(Continued)
 (Unaudited)
  Domestic


International


Total(Millions)For the Year Ended December 31, 2010Revenues:Oil and gas revenues

$
2,136


$
89


$
2,225Other revenues


40







40Total revenues


2,176



89



2,265Costs:Lease and facility operating


267



19



286Gathering, processing & transportation


326







326Taxes other than income


109



16



125Exploration expenses


67



6



73Depreciation, depletion & amortization


858



17



875Impairment of certain natural gas properties in the
    Ft. Worth Basin


503







503Impairment of costs of acquired unproved reserves


175







175Goodwill impairment


1,003







1,003General and administrative


225



9



234Other (income) expense


(19
)






(19
)Total costs


3,514



67



3,581Results of operations


(1,338
)


22



(1,316
)(Provision) benefit for income taxes


123



(8
)


115Exploration and production net income (loss)

$
(1,215
)

$
14


$
(1,201
)   
    Amount for all years exclude the equity earnings from the
    international equity method investee. Equity earnings from this
    investee were $16 million, $14 million and
    $16 million in 2010, 2009 and 2008.
    Oil and gas revenues consist primarily of natural gas production
    sold and includes the impact of hedges.
    Other revenues consist of activities that are an indirect part
    of the producing activities. Other expenses in 2009 also include
    $32 million of expense related to penalties from the early
    release of drilling rigs.
    Exploration expenses include the costs of geological and
    geophysical activity, drilling and equipping exploratory wells
    determined to be dry holes, and the cost of retaining
    undeveloped leaseholds including lease amortization and
    impairments.
    Depreciation, depletion and amortization includes depreciation
    of support equipment. Additionally, 2009 includes
    $17 million additional depreciation, depletion and
    amortization as a result of our recalculation of fourth quarter
    depreciation, depletion and amortization utilizing our year-end
    reserves which were lower than 2008. The lower reserves are
    primarily a result of the application of new rules issued by the
    SEC. F-74




---



##### Table of Contents



WPX
    Energy
  Supplemental
    Oil and Gas Disclosures(Continued)
 (Unaudited)
   Proved
    Reserves
  Entitys share ofinternationalequity methodDomestic


International(1)


investee(2)


Combined(Bcfe)


(MMBoe)


(MMBoe)


(Bcfe)For The Year Ended December 31, 2008Proved reserves at the beginning of period


4,143



21



15



4,357Revisions


(220
)


1







(208
)Purchases


31











31Extensions and discoveries


791



2



1



810Wellhead production


(406
)


(2
)


(2
)


(434
)Proved reserves at the end of period


4,339



22



14



4,556Proved developed reserves at end of period


2,456



15



10



2,607For the year ended December 31, 2009Proved reserves at the beginning of period


4,339



22



14



4,556Revisions


(859
)


2



1



(841
)Purchases


159











159Extensions and discoveries


1,051



5



7



1,123Wellhead production


(435
)


(3
)


(2
)


(466
)Proved reserves at the end of period


4,255



26



20



4,531Proved developed reserves at end of period


2,387



17



12



2,562For the year ended December 31, 2010Proved reserves at the beginning of period


4,255



26



20



4,531Revisions


(233
)


(2
)


1



(242
)Purchases


162











162Extensions and discoveries


508



4



4



557Wellhead production


(420
)


(3
)


(2
)


(450
)Proved reserves at the end of period


4,272



25



23



4,558Proved developed reserves at end of period


2,498



15



14



2,671     (1)
    
    Reserves attributable to a consolidated subsidiary (Apco) in
    which there is a 31 percent noncontrolling interest.(2)
    
    Represents Apcos 40.8% interest in reserves of Petrolera
    Entre Lomas S.A.  
    The SEC defines proved oil and gas reserves
    (Rule 4-10(a)
    of
    Regulation S-X)
    as those quantities of oil and gas, which, by analysis of
    geoscience and engineering data, can be estimated with
    reasonable certainty to be economically produciblefrom a
    given date forward, from known reservoirs, and under existing
    economic conditions, operating methods, and government
    regulationsprior to the time at which contracts providing
    the right to operate expire, unless evidence indicates that
    renewal is F-75




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##### Table of Contents



WPX
    Energy
  Supplemental
    Oil and Gas Disclosures(Continued)
 (Unaudited)
  reasonably certain, regardless of whether deterministic or
    probabilistic methods are used for the estimation. The project
    to extract the hydrocarbons must have commenced or the operator
    must be reasonably certain that it will commence the project
    within a reasonable time. Proved reserves consist of two
    categories, proved developed reserves and proved undeveloped
    reserves. Proved developed reserves are currently producing
    wells and wells awaiting minor sales connection expenditure,
    recompletion, additional perforations or borehole stimulation
    treatments. Proved undeveloped reserves are those reserves which
    are expected to be recovered from new wells on undrilled acreage
    or from existing wells where a relatively major expenditure is
    required for recompletion. Proved reserves on undrilled acreage
    are generally limited to those that can be developed within five
    years according to planned drilling activity. Proved reserves on
    undrilled acreage also can include locations that are more than
    one offset away from current producing wells where there is a
    reasonable certainty of production when drilled or where it can
    be demonstrated with reasonable certainty that there is
    continuity of production from the existing productive formation.  
    Purchases in 2008, 2009 and 2010 include proved developed
    reserves of 17 Bcfe, 2.4 Bcfe and 42 Bcfe,
    respectively.
    Revisions in 2010 primarily relate to the reclassification of
    reserves from proved to probable reserves attributable to
    locations not expected to be developed within five years. A
    significant portion of the revisions for 2009 are a result of
    the impact of the new SEC rules. Proved reserves are lower
    because of the lower
    12-month
    average,
    first-of-the-month
    price as compared to the 2008 year-end price, and the
    revision of proved undeveloped reserve estimates based on new
    guidance. Approximately one-half of the revisions for 2008
    relate to the impact of lower average year-end natural gas
    prices used in 2008 compared to the 2007.
    Extensions and discoveries in 2009 are higher than other years
    due in part to the expanded definition of oil and gas reserves
    supported by reliable technology and reasonable certainty used
    for reserves estimation.
    Natural gas reserves are computed at 14.73 pounds per square
    inch absolute and 60 degrees Fahrenheit. Domestic crude oil
    reserves are insignificant and have been included in the
    domestic proved reserves on a basis of billion cubic feet
    equivalents (Bcfe).  Standardized
    Measure of Discounted Future Net Cash Flows Relating to Proved
    Oil and Gas Reserves
 
  12-month
 
   F-76




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##### Table of Contents



WPX
    Energy
  Supplemental
    Oil and Gas Disclosures(Continued)
 (Unaudited)
    Standardized
    Measure of Discounted Future Net Cash Flows
  Entitys shareof internationalequity methodAs of December 31, 2009

Domestic


International(1)


investee(2)(Millions)Future cash inflows

$
11,729


$
664


$
614Less:Future production costs


3,990



227



228Future development costs


2,833



83



91Future income tax provisions


1,404



67



73Future net cash flows


3,502



287



222Less 10 percent annual discount for estimated timing of
    cash flows


(1,789
)


(112
)


(93
)Standardized measure of discounted future net cash inflows

$
1,713


$
175


$
129   Entitys shareof internationalequity methodAs of December 31, 2010

Domestic


International(1)


investee(2)Future cash inflows

$
16,151


$
779


$
787Less:Future production costs


4,927



273



278Future development costs


2,960



89



92Future income tax provisions


2,722



98



114Future net cash flows


5,542



319



303Less 10 percent annual discount for estimated timing of
    cash flows


(2,728
)


(121
)


(117
)Standardized measure of discounted future net cash inflows

$
2,814


$
198


$
186     (1)
    
    Amounts attributable to a consolidated subsidiary (Apco) in
    which there is a 31 percent noncontrolling interest.(2)
    
    Represents Apcos 40.8% interest in Petrolera Entre Lomas
    S.A. F-77




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##### Table of Contents



WPX
    Energy
  Supplemental
    Oil and Gas Disclosures(Continued)
 (Unaudited)
   Sources
    of Change in Standardized Measure of Discounted Future Net Cash
    Flows
  Entitys shareof internationalequity methodFor the Year Ended December 31, 2008

Domestic


International(1)


investee(2)(Millions)Standardized measure of discounted future net cash flows
    beginning of period

$
4,803


$
149


$
115Changes during the year:Sales of oil and gas produced, net of operating costs


(2,091
)


(55
)


(55
)Net change in prices and production costs


(2,548
)


25



34Extensions, discoveries and improved recovery, less estimated
    future costs


1,423







Development costs incurred during year


817



33



25Changes in estimated future development costs


(724
)


(36
)


(36
)Purchase of reserves in place, less estimated future costs


55







Revisions of previous quantity estimates


(395
)


50



38Accretion of discount


714



13



18Net change in income taxes


1,108



3



Other


11



(7
)


(8
)Net changes


(1,630
)


26



16Standardized measure of discounted future net cash flows end of
    period

$
3,173


$
175


$
131   F-78




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##### Table of Contents



WPX
    Energy
  Supplemental
    Oil and Gas Disclosures(Continued)
 (Unaudited)
  Entitys shareof internationalequity methodFor the Year Ended December 31, 2009

Domestic


International(1)


investee(2)(Millions)Standardized measure of discounted future net cash flows
    beginning of period

$
3,173


$
175


$
131Changes during the year:Sales of oil and gas produced, net of operating costs


(1,006
)


(49
)


(45
)Net change in prices and production costs


(3,310
)


(35
)


(49
)Extensions, discoveries and improved recovery, less estimated
    future costs


1,131







Development costs incurred during year


389



17



21Changes in estimated future development costs


701



(1
)


(3
)Purchase of reserves in place, less estimated future costs


171







Revisions of previous quantity estimates


(923
)


79



88Accretion of discount


450



21



17Net change in income taxes


932



(4
)


(2
)Other


5



(28
)


(29
)Net changes


(1,460
)






(2
)Standardized measure of discounted future net cash flows end of
    period

$
1,713


$
175


$
129   F-79




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##### Table of Contents



WPX
    Energy
  Supplemental
    Oil and Gas Disclosures(Continued)
 (Unaudited)
  Entitys shareof internationalequity methodFor the Year Ended December 31, 2010

Domestic


International(1)


investee(2)(Millions)Standardized measure of discounted future net cash flows
    beginning of period

$
1,713


$
175


$
129Changes during the year:Sales of oil and gas produced, net of operating costs


(1,446
)


(59
)


(55
)Net change in prices and production costs


1,921



34



43Extensions, discoveries and improved recovery, less estimated
    future costs


724







Development costs incurred during year


633



26



25Changes in estimated future development costs


(292
)


(12
)


(15
)Purchase of reserves in place, less estimated future costs


439



2



Revisions of previous quantity estimates


(332
)


26



63Accretion of discount


220



22



17Net change in income taxes


(758
)


(13
)


(20
)Other


(8
)


(3
)


(1
)Net changes


1,101



23



57Standardized measure of discounted future net cash flows end of
    period

$
2,814


$
198


$
186     (1)
    
    Amounts attributable to a consolidated subsidiary (Apco) in
    which there is a 31 percent noncontrolling interest.(2)
    
    Represents Apcos 40.8% interest in Petrolera Entre Lomas
    S.A.   F-80




---



##### Table of Contents



Shares
 WPX
    Energy, Inc.
 Class A
    Common Stock
   Prospectus
 ,
    2011
   Barclays
    Capital
 Citi
 J.P. Morgan
 
 BofA Merrill Lynch
 
 
 
 Deutsche Bank
    Securities
 
 
 Goldman, Sachs
    & Co.
 
 
 Morgan
    Stanley
 
 
 Wells Fargo
    Securities
 
 
 
 Credit Suisse
 
 
 RBC Capital Markets
 
 
 Scotia Capital
 
 
 UBS Investment Bank
 
 
 Howard Weil Incorporated




---



##### Table of Contents



PART II
  INFORMATION
    NOT REQUIRED IN PROSPECTUS
  Item 13.
    Other
    Expenses of Issuance and Distribution.    SEC registration fee

$
87,075FINRA filing fee


75,500NYSE listing fee


*Printing and engraving expenses


*Legal fees and expenses


*Accounting fees and expenses


*Transfer agent and Registrar fees


*Miscellaneous


*Total

$
*     *
    
    To be provided by amendment  Item 14.
    Indemnification
    of Officers and Directors.        Item 15.
    Recent
    Sales of Unregistered Securities.   II-1




---



##### Table of Contents



Item 16.
    Exhibits
    and Financial Statement Schedules.  (a)
    Exhibits    (b)
    Financial Statement Schedules    SCHEDULE IIVALUATION
    AND QUALIFYING ACCOUNTS
  Charged(Credited)Beginning


to Costs and








EndingBalance


Expenses


Other


Deductions


Balance(Millions)2010:Allowance for doubtful accountsaccounts and notes
    receivable(a)

$
19


$
(3
)

$



$



$
16Price-risk management credit
    reservesliabilities(b)


(3
)


3
(d)










2009:Allowance for doubtful accountsaccounts and notes
    receivable(a)


25



3







(9
)(c)


19Price-risk management credit
    reservesassets(a)


6



(3
)(d)


(3
)(e)






Price-risk management credit
    reservesliabilities(b)


(15
)


12
(d)










(3
)2008:Allowance for doubtful accountsaccounts and notes
    receivable(a)


14



12







(1
)(c)


25Price-risk management credit
    reservesassets(a)


1



1
(d)


4
(e)






6Price-risk management credit reservesliabilities(b)






(16
)(d)


1
(e)






(15
)     (a)
    
    Deducted from related assets.(b)
    
    Deducted from related liabilities.(c)
    
    Represents recoveries of balances previously written off.(d)
    
    Included in revenues.(e)
    
    Included in accumulated other comprehensive income (loss).  Item 17.
    Undertakings.       II-2




---



##### Table of Contents



II-3




---



##### Table of Contents



Signatures
 
   
     By:
    /s/  Ralph
    A. Hill       
 Date: July 18, 2011

By:

/s/  Ralph
    A.
    HillRalph
    A. Hill, Chief Executive Officer(Principal Executive Officer)Date: July 18, 2011

By:

/s/  Donald
    R.
    ChappelDonald
    R. Chappel, Chief Financial Officer
    (Principal Financial Officer)Date: July 18, 2011

By:

/s/  Ted
    T.
    TimmermansTed
    T. Timmermans, Chief Accounting Officer
    (Principal Accounting Officer)Date: July 18, 2011

By:

/s/  Alan
    S.
    ArmstrongAlan
    S. Armstrong, Chairman of the Board  
 II-4




---



##### Table of Contents



EXHIBIT INDEX
  
 Exhibit No.

Description1
.1*

Form of Underwriting Agreement2
.1

Contribution Agreement, dated as of October 26, 2010, by
    and among Williams Production RMT Company LLC, Williams Energy
    Services, LLC, Williams Partners GP LLC, Williams Partners L.P.,
    Williams Partners Operating LLC and Williams Field Services
    Group, LLC3
.1

Form of Amended and Restated Certificate of Incorporation of WPX
    Energy, Inc.3
.2

Form of Amended and Restated Bylaws of WPX Energy, Inc.4
.1*

Form of Specimen Class A Common Stock Certificate4
.2*

Form of Specimen Class B Common Stock Certificate5
.1

Opinion of Gibson, Dunn & Crutcher LLP10
.1

Form of Separation and Distribution Agreement10
.2

Form of Administrative Services Agreement10
.3

Form of Transition Services Agreement10
.4

Form of Tax Sharing Agreement10
.5

Form of Registration Rights Agreement10
.6

Credit Agreement, dated as of June 3, 2011, by and among
    WPX Energy, Inc., the lenders named therein, and Citibank,
    N.A., as Administrative Agent and Swingline Lender (incorporated
    by reference to Exhibit 10.3 to The Williams Companies,
    Inc.s current report on
    Form 8-K
    (File No.
    001-04174)
    filed with the SEC on June 9, 2011)10
.7#

Amended and Restated Gas Gathering, Processing, Dehydrating and
    Treating Agreement by and among Williams Field Services Company,
    LLC, Williams Production RMT Company LLC, Williams Production
    Ryan Gulch LLC and WPX Energy Marketing, LLC, effective as of
    August 1, 201110
.8

Form of WPX Energy, Inc. 2011 Incentive Plan10
.9

Form of WPX Energy, Inc. 2011 Employee Stock Purchase Plan(21
.1)

List of Subsidiaries23
.1

Consent of Gibson, Dunn & Crutcher LLP (included in
    Exhibit 5.1)23
.2

Consent of Ernst & Young LLP23
.3

Consent of Independent Petroleum Engineers and Geologists,
    Netherland, Sewell & Associates, Inc.23
.4

Consent of Independent Petroleum Engineers and Geologists,
    Miller and Lents, Ltd.23
.5

Consent of Independent Petroleum Engineers, Ralph E. Davis
    Associates, Inc.(24
.1)

Powers of Attorney (included on signature page of the initial
    registration statement)(99
.1)

Report of Independent Petroleum Engineers and Geologists,
    Netherland, Sewell & Associates, Inc.(99
.2)

Report of Independent Petroleum Engineers and Geologists, Miller
    and Lents, Ltd.(99
.3)

Report of Independent Petroleum Engineers, Ralph E. Davis
    Associates, Inc.  
    

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