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As filed with the Securities and Exchange Commission on April 29, 2011
Registration No. 333-          
 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
 
 
Form S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
 
 
 
WPX Energy, Inc.
(Exact name of registrant as specified in its charter)
 
 
 
 
         
Delaware
  1311   45-1836028
(State or other jurisdiction of
Incorporation or organization)
  (Primary Standard Industrial
Classification Code Number)
  (I.R.S. Employer
Identification Number)
One Williams Center
Tulsa, Oklahoma 74172-0172
(918) 573-2000
(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)
 
James J. Bender, Esq.
General Counsel and Corporate Secretary
One Williams Center, Suite 4900
Tulsa, Oklahoma 74172-0172
(918) 573-2000
(Name, address, including zip code, and telephone number, including area code, of agent for service)
 
 
 
 
Copies to:
 
     
Richard M. Russo
Robyn E. Zolman
Gibson, Dunn & Crutcher LLP
1801 California Street, Suite 4200
Denver, CO 80202
  J. Michael Chambers
Ryan J. Maierson
Latham & Watkins LLP
717 Texas Avenue, 16th floor
Houston, TX 77002
 
Approximate date of commencement of proposed sale to the public:  As soon as practicable after the effective date of this registration statement.
 
If any of the securities being registered on this Form are being offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box:  o
 
If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  o
 
If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  o
 
If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  o
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
 
             
Large accelerated filer o
  Accelerated filer o   Non-accelerated filer þ
(Do not check if a smaller reporting company)
  Smaller reporting company o
 
CALCULATION OF REGISTRATION FEE
 
             
      Proposed Maximum
    Amount of
Title of Each Class of Securities to be Registered     Aggregate Offering Price(1)     Registration Fee(2)
Class A common stock
    $750,000,000     $87,075
             
(1) Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o) under the Securities Act of 1933, as amended.
(2) Calculated pursuant to Rule 457(o) under the Securities Act of 1933, as amended.
 
The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until this registration statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.
 


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The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.
 
Subject to Completion, dated April 29, 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 intend to apply 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     Total  
Price to the public
  $               $            
Underwriting discounts and commissions
  $       $    
Proceeds to us (before expenses)
  $       $  
 
We have granted the underwriters a 30-day option to purchase up to an additional           shares of Class A common stock on the same terms and conditions set forth above if the underwriters sell more than      shares of Class A common stock in this offering.
 
Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed on the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.
 
Barclays Capital, on behalf of the underwriters, expects to deliver the shares on or about          , 2011.
Barclays Capital Citi      J.P. Morgan
 
Prospectus dated          , 2011


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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, neither we nor the underwriters have independently verified such data and neither we nor the underwriters make any representation as to the accuracy of such information. Similarly, we believe our internal research is reliable but it has not been verified by any independent sources.


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


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PROSPECTUS SUMMARY
 
This summary highlights certain information contained elsewhere in this prospectus. This summary is not complete and does not contain all of the information that you should consider before investing in our Class A common stock. You should read this entire prospectus carefully, including the risks discussed under “Risk Factors” and the financial statements and notes thereto included elsewhere in this prospectus. Some of the statements in this summary constitute forward-looking statements. See “Forward-Looking Statements.”
 
Except where the context otherwise requires or where otherwise indicated, (1) all references to “Williams” refer to The Williams Companies, Inc., our parent company, and its subsidiaries, other than us, and (2) all references to “WPX Energy,” “WPX,” the “Company,” “we,” “us” and “our” refer to WPX Energy, Inc. and its subsidiaries.
 
Overview
 
We are an independent natural gas and oil exploration and production company engaged in the exploitation and development of long-life unconventional properties. We are focused on profitably exploiting our significant natural gas reserve base and related NGLs in the Piceance Basin of the Rocky Mountain region, and on developing and growing our positions in the Bakken Shale oil play in North Dakota and the Marcellus Shale natural gas play in Pennsylvania. Our other areas of domestic operations include the Powder River Basin in Wyoming and the San Juan Basin in the southwestern United States. In addition, we own a 69 percent controlling ownership interest in Apco Oil and Gas International, Inc. (“Apco”), which holds oil and gas concessions in Argentina and Colombia and trades on the NASDAQ Capital Market under the symbol “APAGF.”
 
We have built a geographically diverse portfolio of natural gas and oil reserves through organic development and strategic acquisitions. For the five years ended December 31, 2010, we have grown production at a compound annual growth rate of 12 percent. As of December 31, 2010, our proved reserves were 4,473 Bcfe, 59 percent of which were proved developed reserves. Average daily production for the month ended March 31, 2011 was 1,251 MMcfe/d. Our Piceance Basin operations form the majority of our proved reserves and current production, providing a low-cost, scalable asset base.
 
The following table provides summary data for each of our primary areas of operation as of December 31, 2010, unless otherwise noted.
 
                                                                         
    Estimated Net
    March 2011
                      2011 Budget Estimate        
    Proved Reserves     Average Daily
          Identified Drilling
          Drilling
       
          % Proved
    Net Production
          Locations           Capital(2)
    PV-10(3)
 
Basin/Shale
  Bcfe     Developed     (MMcfe/d)(1)     Net Acreage     Gross     Net     Gross Wells     (Millions)     (Millions)  
 
Piceance Basin
    2,927       53 %     723       211,000       10,708       8,496       376     $ 575     $ 2,707  
Bakken Shale(4)
    136       11 %     12       89,420       758       397       41       260       399  
Marcellus Shale
    28       71 %     14       99,301       761       450       62       170       29  
Powder River Basin
    348       75 %     220       425,550       2,374       1,023       411       70       317  
San Juan Basin
    554       79 %     131       120,998       1,485       704       51       40       477  
Apco(5)
    190       60 %     57       404,304       526       180       37       30       358  
Other(6)
    290       72 %     94       327,390       2,185       112       94       85       257  
                                                                         
Total
    4,473       59 %     1,251       1,677,963       18,797       11,362       1,072     $ 1,230     $ 4,544  
                                                                         
 
 
(1) Represents average daily net production for the month ended March 31, 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


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


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Our Business Strategy
 
Our business strategy is to increase shareholder value by finding and developing reserves and producing natural gas, oil and NGLs at costs that generate an attractive rate of return on our investment.
 
     Efficiently Allocate Capital for Optimal Portfolio Returns.  We expect to allocate capital to the most profitable opportunities in our portfolio based on commodity price cycles and other market conditions, enabling us to continue to grow our reserves and production in a manner that maximizes our return on investment. In determining which drilling opportunities to pursue, we target a minimum after-tax internal rate of return on each operated well we drill of 15 percent. While we have a significant portfolio of drilling opportunities that we believe meet or exceed our return targets even in challenging commodity price environments, we are disciplined in our approach to capital spending and will adjust our drilling capital expenditures based on our level of expected cash flows, access to capital and overall liquidity position. For example, in 2009 we demonstrated our capital discipline by reducing drilling expenditures in response to prevailing commodity prices and their impact on these factors.
 
     Continue Our Low-Cost Development Approach.  We manage costs by focusing on establishing large scale, contiguous acreage blocks on which 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 our cost-disciplined approach 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 low-cost 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 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 March 31, 2011, our estimated domestic natural gas production revenues were 65 percent hedged for 2011 and 40 percent hedged for 2012. Estimated domestic oil production revenues were 47 percent hedged for 2011 and 49 percent hedged for 2012 as of the same date.


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Our Competitive Strengths
 
We have a number of competitive strengths that we believe will help us to successfully execute our business strategies:
 
     A Leading Piceance Basin Cost Structure.  We have a large position in the lowest cost area of the Piceance Basin, which we believe provides us economies of scale in our operations, allowing us to continuously drive down operating costs and increase efficiencies. The existing substantial midstream infrastructure in the Piceance Basin contributes to our low-cost structure and provides take-away capacity for our natural gas and NGLs. Because of this low-cost 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 14,000 gross operated drilling locations, for which approximately 500 gross operated wells are budgeted for 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 low-cost 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 low-cost model and to apply our highly specialized technical expertise in the development of those resources.


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Our Relationship with Williams
 
We are currently a wholly-owned subsidiary of The Williams Companies, Inc., an integrated energy company with 2010 consolidated revenues in excess of $9 billion that trades on the New York Stock Exchange (“NYSE”) under the symbol “WMB.” We were formed in April 2011 to hold Williams’ exploration and production business and to effect this offering and the related transactions.
 
Upon the completion of this offering, we will be a public company, and investors in this offering will own all of our outstanding Class A common stock. Williams will not own any of our Class A common stock, but will directly own all of our outstanding Class B common stock, which will represent approximately           percent of the total shares of common stock outstanding and approximately           percent of the combined voting power of all outstanding classes of our common stock, or approximately           percent and           percent, respectively, if the underwriters exercise their option to purchase additional Class A common shares in full. As a result, Williams will have the ability to elect all of the members of our board of directors and to determine the outcome of other matters submitted to a vote of our stockholders. For a discussion of related risks, please read “Risk Factors—Risks Related to Our Relationship with Williams.”
 
We intend to distribute to Williams a substantial portion of the proceeds we receive in this offering and our concurrent sale of debt securities. See “Use of Proceeds.” Williams has advised us that it intends to use the funds it receives from the proceeds of this offering and our concurrent sale of debt securities to repay a portion of its indebtedness, and that following the completion of this offering, it intends to distribute all of the shares of our common stock that it owns through a tax-free distribution, or spin-off, to Williams’ stockholders. The determination of whether, and if so, when, to proceed with the spin-off is entirely within the discretion of Williams, although Williams has indicated its intention to complete the spin-off in 2012 and to convert its Class B common shares to Class A common shares immediately prior to such spin-off, assuming such conversion would not jeopardize the ability to consummate the tax-free distribution or the tax-free treatment of any related restructuring transaction undertaken by Williams. Williams has the sole discretion to determine the form, the structure and all other terms of any transactions to effect the spin-off. If Williams does not proceed with the spin-off, it could elect to dispose of our Class B common stock, or the Class A common stock into which the Class B common stock is convertible, in a number of different types of transactions, including additional public offerings, open market sales, sales to one or more third parties or split-off offerings that would allow Williams’ stockholders the opportunity to exchange Williams shares for shares of our common stock or a combination of these transactions. Except for the “lock-up” period described under “Underwriting,” Williams is not subject to any contractual obligation to maintain its Class B share ownership. For more information on the potential effects of Williams’ disposition of our common stock by means of the anticipated spin-off or otherwise, please read “Risk Factors—Risks Related to Our Relationship with Williams.”
 
We currently depend on Williams for a number of administrative functions. Prior to the completion of this offering, we will enter into agreements with Williams related to the separation of our business operations from Williams. These agreements will be in effect as of the completion of this offering and will govern various interim and ongoing relationships between Williams and us, including the extent and manner of our dependence on Williams for administrative services following the completion of this offering. Under the terms of these agreements, we are entitled to the ongoing assistance of Williams only for a limited period of time following the spin-off. For more information regarding these agreements, see “Arrangements Between Williams and Our Company” and the historical combined financial statements and the notes thereto included elsewhere in this prospectus. All of the agreements relating to our separation from Williams will be made in the context of a parent-subsidiary relationship and will be entered into in the overall context of our separation from Williams. The terms of these agreements may be more or less favorable to us than if they had been negotiated with unaffiliated third parties. See “Risk Factors—Risks Related to Our Relationship with Williams—We may have potential business conflicts of interest with Williams regarding our past and ongoing relationships, and because of Williams’ controlling ownership in us, the resolution of these conflicts may not be favorable to us.”
 
Our planned two-step separation process ((1) our initial public offering and concurrent sale of debt securities, including a distribution of a portion of the proceeds to Williams, followed by (2) a spin-off of our


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common stock in the form of a distribution by Williams to its stockholders) provides us with capital and enables Williams to repay debt while simultaneously achieving the benefits of our complete separation from Williams in a tax-efficient manner. In addition, we believe that our separation from Williams will enable us to realize the following benefits:
 
     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, subject to certain restrictions in order to maintain the tax-free treatment of our separation from Williams. See “Risk Factors—Risks Related to our Relationship with Williams.”
 
Our Restructuring
 
Prior to the completion of this offering:
 
  •   Williams will contribute and transfer to us the assets and liabilities associated with our business and will forgive or contribute to our capital all intercompany debt associated with our business;
 
  •   we will effect a recapitalization whereby the outstanding shares of our common stock, all of which are owned by Williams, will be reclassified into     shares of Class B common stock in exchange for all of the assets (net of the liabilities assumed and the cash we distribute to Williams) contributed to us by Williams, and a new Class A common stock will be authorized; and
 
  •   we will amend and restate our certificate of incorporation and bylaws.
 
We refer to these transactions as our “restructuring transactions.”
 
Concurrent Financing Transactions
 
We expect that prior to the completion of this offering, we will have entered into a new five-year $1.5 billion senior unsecured credit facility (the “Credit Facility”), which will become effective upon the completion of this offering and for which we will pay associated financing costs. Concurrently with or shortly following the consummation of this offering, we expect to issue up to $1.5 billion aggregate principal amount of senior unsecured notes (the “Notes”) and pay associated financing costs. The offering of our Class A common stock is not contingent upon the entry into the Credit Facility or the completion of the offering of the Notes. See “Description of Our Concurrent Financing Transactions” for a more detailed description of these transactions.
 
Risk Factors
 
Investing in our Class A common stock involves substantial risk. You should carefully consider all of the information in this prospectus and, in particular, you should evaluate the risk factors and other cautionary statements set forth under “Risk Factors” beginning on page 17 in deciding whether to invest in our Class A common stock. In particular:
 
  •   Our business requires significant capital expenditures and we may be unable to obtain needed capital or financing on satisfactory terms.


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


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The Offering
 
Issuer WPX Energy, Inc.
 
Class A common stock offered            shares.
 
Common stock outstanding after this offering:
 
  Class A common stock
           shares, or           shares if the underwriters exercise their option to purchase additional Class A common shares in full.
 
  Class B common stock
           shares, or           shares if the underwriters exercise their option to purchase additional Class A common shares in full.
 
  Total common stock
           shares. Any shares of Class A common stock issued pursuant to the underwriters’ over-allotment 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 over-allotment 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 for general corporate purposes. As part of our restructuring transactions, the remainder of the net proceeds of this offering will be distributed to Williams. See “Use of Proceeds.”


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Dividend policy We do not anticipate paying any dividends on our common stock in the foreseeable future. See “Dividend Policy.”
 
Exchange Listing We intend to apply to have our shares of Class A common stock listed on the NYSE under the symbol “WPX.”
 
Unless we specifically state otherwise, all information in this prospectus regarding our Class A common stock:
 
  •   gives effect to our restructuring transactions;
 
  •   assumes no exercise by the underwriters of their option to purchase additional Class A common shares; and
 
  •   excludes shares of Class A common stock reserved for issuance, if any, under equity incentive plans.


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Summary Combined Historical and Unaudited Pro Forma Combined Financial Data
 
Set forth below is our summary combined historical and unaudited pro forma combined financial data for the periods indicated. The historical financial data for the years ended December 31, 2010, 2009 and 2008 and the balance sheet data as of December 31, 2010 and 2009 have been derived from our audited financial statements included in this prospectus.
 
The pro forma financial data was prepared as if our separation from Williams and the related transactions described below had occurred as of January 1, 2010. The pro forma financial data gives effect to the following transactions:
 
  •   the completion of our restructuring transactions, including the forgiveness or contribution to our capital of the unsecured notes payable to Williams;
 
  •   the receipt of approximately $      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 $      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 $      billion to Williams from the combined net proceeds from this offering and the expected offering of the Notes in connection with our restructuring transactions.
 
You should read the following summary financial data in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our historical and pro forma financial statements and related notes thereto appearing elsewhere in this prospectus.
 
The unaudited pro forma combined financial data does not purport to represent what our financial position and results of operations actually would have been had the restructuring transactions occurred on the dates indicated or to project our future financial performance.
 


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    Pro Forma
       
    Year Ended
    Historical Year Ended
 
    December 31,     December 31,  
    2010     2010     2009     2008  
    (Millions)  
 
Statement of Operations Data:
                               
Revenues, including affiliate(1)
                $ 4,053     $ 3,700     $ 6,226  
Costs and expenses:
                               
Lease and facility operating, including affiliate
            295       273       284  
Gathering, processing and transportation, including affiliate
            324       270       225  
Taxes other than income
            125       94       255  
Gas management (including charges for unutilized pipeline capacity)
            1,774       1,496       3,248  
Exploration
            76       56       38  
Depreciation, depletion and amortization
            881       894       758  
Impairment of producing properties and costs of acquired unproved reserves
            678       15       148  
Goodwill impairment
            1,003              
General and administrative, including affiliate
            252       251       253  
Gain on sale of contractual right to international production payment
                        (148 )
Other—net
            (15 )     33       7  
                                 
Total costs and expenses
            5,393       3,382       5,068  
Operating income (loss)
            (1,340 )     318       1,158  
Interest expense, including affiliate
            (124 )     (100 )     (74 )
Interest capitalized
            16       18       20  
Investment income and other
            21       7       22  
                                 
Income (loss) before income taxes
            (1,427 )     243       1,126  
Provision (benefit) for income taxes
            (151 )     94       400  
                                 
Income (loss) from continuing operations(2)
            (1,276 )     149       726  
Income (loss) from discontinued operations
            (3 )     (3 )     10  
                                 
Net income (loss)
            (1,279 )     146       736  
Less: Net income attributable to noncontrolling interests
            8       6       8  
                                 
Net income (loss) attributable to WPX Energy
          $ (1,287 )   $ 140     $ 728  
                                 
 
 
(1) Includes gas management revenues of $1,742 million, $1,456 million and $3,244 million for 2010, 2009 and 2008, respectively. These revenues were offset by the gas management expenses shown in the table above. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations.”
 
(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 $148 million of impairment charges related to producing properties in the Arkoma Basin offset by a $148 million gain related to the sale of a right to an international production payment. See Notes 4 and 12 of Notes to Combined Financial Statements for further discussion of asset sales, impairments and other accruals in 2010, 2009 and 2008.
 

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    Pro Forma
    Historical
 
    At December 31,     At December 31,  
    2010     2010     2009  
    (Millions)  
 
Balance Sheet Data:
                       
Cash and cash equivalents
          $ 37     $ 34  
Properties and equipment, net
            8,501       7,724  
Total assets
            9,847       10,555  
Unsecured notes payable to Williams—current
            2,261       1,216  
Total equity
            4,520       5,420  
Total liabilities and equity
            9,847       10,555  
 
                                 
    Pro Forma
       
    Year Ended
       
    December 31,     Historical Year Ended December 31,  
    2010     2010     2009     2008  
    (Millions)  
 
Other Financial Data:
                               
Net cash provided by operating activities
          $ 1,054     $ 1,179     $ 2,006  
Net cash used in investing activities
            (2,337 )     (1,435 )     (2,252 )
Net cash provided by financing activities
            1,286       258       228  
Adjusted EBITDAX(1)
            1,335       1,308       1,996  
Capital expenditures
            (1,856 )     (1,434 )     (2,467 )
 
 
(1) Adjusted EBITDAX is a non-GAAP financial measure. For a definition of Adjusted EBITDAX and a reconciliation of Adjusted EBITDAX to our net income (loss), see “—Summary Combined Historical Operating and Reserve Data—Non-GAAP Financial Measures and Reconciliations” below.

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Summary Combined Historical Operating and Reserve Data
 
The following table presents summary combined data with respect to our estimated net proved natural gas and oil reserves as of the dates indicated. Approximately 93 percent of our year-end 2010 U.S. proved reserves estimates were audited by Netherland, Sewell & Associates, Inc. (“NSAI”) and approximately one percent were audited by Miller and Lents, Ltd. (“M&L”). Approximately 96 percent of Apco’s year-end 2010 proved reserves estimates (which constitute approximately 94 percent of our year-end 2010 proved reserves estimates for international properties) were reviewed and certified by Ralph E. Davis Associates, Inc. In the judgment of these independent reserve petroleum engineers, our estimates reviewed in their respective reports are, in the aggregate, reasonable and have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Because our acquisition in the Bakken Shale was completed in late December 2010, our year-end estimated reserves for those properties are based on internal estimates only. All of the reserve estimates mentioned above were prepared in a manner consistent with the rules of the Securities and Exchange Commission (the “SEC”) regarding oil and natural gas reserve reporting that are currently in effect. You should refer to “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Business” when evaluating the material presented below.
 
                 
    At December 31,  
    2010     2009  
 
Estimated Proved Reserves(1)
               
Natural Gas (Bcf)(2)
    4,214       4,316  
Oil (MMbbls)
    43       23  
Total (Bcfe)
    4,473       4,452  
PV-10 (in millions)
  $ 4,544     $ 2,620  
Standardized Measure of Discounted Future Net Cash Flows (in millions)(3)
  $ 3,080     $ 1,923  
 
 
(1) Includes approximately 69 percent of Apco’s reserves, which corresponds to our ownership interest in Apco. Our estimated proved reserves, PV-10 and Standardized Measure were determined using the 12-month average beginning-of-month price for natural gas and oil for 2009 and 2010, which were $3.87 per MMbtu of natural gas and $57.65 per barrel of oil during 2009 and $4.38 per MMbtu of natural gas and $75.96 per barrel of oil during 2010 for domestic properties. The 12-month average beginning-of-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 volumes include NGL volumes which are extracted downstream at the processing plants.
 
(3) Standardized Measure represents the present value of estimated future cash inflows from proved natural gas and oil reserves, less future development and production costs and income tax expenses, discounted at ten percent per annum to reflect timing of future cash flows and using the same pricing assumptions as were used to calculate PV-10. Standardized Measure differs from PV-10 because Standardized Measure includes the effect of future income taxes. For a reconciliation of the non-GAAP financial measure of PV-10 to Standardized Measure, the most directly comparable GAAP financial measure, see “—Non-GAAP Financial Measures and Reconciliations” below.


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The following table summarizes our net production for the years indicated.
 
                         
    Year Ended December 31,  
    2010     2009     2008  
 
Production Data(1):
                       
Natural Gas (MMcf)
    415,224       434,412       402,358  
Oil (MBbls)
    2,894       2,801       2,722  
Combined Equivalent Volumes (MMcfe)
    432,588       451,218       418,690  
Average Daily Combined Equivalent Volumes (MMcfe/d)
    1,185       1,236       1,144  
 
 
(1) Includes approximately 69 percent of Apco’s production, which corresponds to our ownership interest in Apco.
 
The following tables summarize our domestic sales price and cost information for the years indicated.
 
                         
    Year Ended December 31,  
    2010     2009     2008  
 
Realized average price per unit:
                       
Natural gas, without hedges (per Mcf)(1)
  $ 4.32     $ 3.41     $ 6.94  
Impact of hedges (per Mcf)(1)
    0.81       1.43       0.09  
                         
Natural gas, with hedges (per Mcf)(1)
  $ 5.13     $ 4.84     $ 7.03  
                         
Oil, without hedges (per Bbl)
  $ 66.17     $ 44.92     $ 84.63  
Impact of hedges (per Bbl)
                 
                         
Oil, with hedges (per Bbl)
  $ 66.17     $ 44.92     $ 84.63  
                         
Price per Boe, without hedges(2)
  $ 26.45     $ 20.71     $ 42.12  
                         
Price per Boe, with hedges(2)
  $ 31.29     $ 29.27     $ 42.63  
                         
Price per Mcfe, without hedges(2)
  $ 4.41     $ 3.45     $ 7.02  
                         
Price per Mcfe, with hedges(2)
  $ 5.21     $ 4.88     $ 7.10  
                         
 
 
(1) Includes NGLs.
 
(2) Realized average prices include market prices, net of fuel and shrink.
 
                         
    Year Ended December 31,  
    2010     2009     2008  
 
Expenses per Mcfe:
                       
Operating expenses:
                       
Lifting costs and workovers
  $ 0.48     $ 0.41     $ 0.48  
Facilities operating expense
    0.14       0.14       0.15  
Other operating and maintenance
    0.05       0.05       0.04  
                         
Total LOE
  $ 0.67     $ 0.60     $ 0.67  
Gathering, processing and transportation charges
    0.78       0.63       0.56  
Taxes other than income
    0.26       0.19       0.61  
                         
Production cost
  $ 1.71     $ 1.42     $ 1.84  
                         
General and administrative
  $ 0.59     $ 0.56     $ 0.61  
Depreciation, depletion and amortization
  $ 2.09     $ 2.03     $ 1.86  


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Non-GAAP Financial Measures and Reconciliations
 
Adjusted EBITDAX
 
Adjusted EBITDAX is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies.
 
We define Adjusted EBITDAX as earnings before interest expense, income taxes, depreciation, depletion and amortization, exploration expenses and the other items described below. Adjusted EBITDAX is not a measure of net income as determined by United States generally accepted accounting principles, or GAAP.
 
Management believes Adjusted EBITDAX is useful because it allows them to more effectively evaluate our operating performance and compare the results of our operations from period to period and against our peers without regard to our financing methods or capital structure. We exclude the items listed above from net income in arriving at Adjusted EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP or as an indicator of our liquidity. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDAX. Our computations of Adjusted EBITDAX may not be comparable to other similarly titled measures of other companies. We believe that Adjusted EBITDAX is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet debt service requirements.
 
The following table presents a reconciliation of the non-GAAP financial measure of Adjusted EBITDAX to the GAAP financial measure of net income (loss).
 
                                 
    Pro Forma
       
    Year Ended
    Historical
 
    December 31,     Year Ended December 31,  
    2010     2010     2009     2008  
    (Millions)  
 
Adjusted EBITDAX Reconciliation to Net Income (Loss):
                               
Net income (loss)
                   $ (1,279 )   $ 146     $ 736  
Interest expense
            124       100       74  
Provision (benefit) for income taxes
            (151 )     94       400  
Depreciation, depletion and amortization
            881       894       758  
Exploration expenses
            76       56       38  
                                 
EBITDAX
            (349 )     1,290       2,006  
Gain on sale of contractual right to international production payment
                        (148 )
Impairments of goodwill, producing properties and cost of acquired unproved reserves
            1,681       15       148  
(Income) loss from discontinued operations
            3       3       (10 )
                                 
Adjusted EBITDAX
          $ 1,335     $ 1,308     $ 1,996  
                                 
 
PV-10
 
PV-10 is a non-GAAP financial measure and represents the year-end present value of estimated future cash inflows from proved natural gas and crude oil reserves, less future development and production costs, discounted at 10 percent per annum to reflect the timing of future cash flows and using pricing assumptions in effect at the end of the period. PV-10 differs from Standardized Measure because it does not include the effects of income taxes on future net revenues. Neither PV-10 nor Standardized Measure represents an estimate


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of fair market value of our natural gas and crude oil properties. PV-10 is used by the industry and by our management as an arbitrary reserve asset value measure to compare against past reserve bases and the reserve bases of other business entities that are not dependent on the taxpaying status of the entity.
 
The following table provides a reconciliation of our Standardized Measure to PV-10 and includes 69 percent of Apco’s metrics, which corresponds to our ownership interest in Apco.
 
                 
    At December 31,  
    2010     2009  
    (Millions)  
 
Standardized Measure of Discounted Future Net Cash Flows
  $ 3,080     $ 1,923  
Present value of future income tax discounted at 10%
    1,464       697  
                 
PV-10
  $ 4,544     $ 2,620  
                 


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


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


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The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate.
 
Approximately 41 percent of our total estimated proved reserves at December 31, 2010 were proved undeveloped reserves and may not be ultimately developed or produced. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. The reserve data included in the reserve engineer reports assumes that substantial capital expenditures are required to develop such reserves. We cannot be certain that the estimated costs of the development of these reserves are accurate, that development will occur as scheduled or that the results of such development will be as estimated. Delays in the development of our reserves or increases in costs to drill and develop such reserves will reduce the PV-10 value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify our proved reserves as unproved reserves.
 
The present value of future net revenues from our proved reserves will not necessarily be the same as the value we ultimately realize of our estimated natural gas and oil reserves.
 
You should not assume that the present value of future net revenues from our proved reserves is the current market value of our estimated natural gas and oil reserves. For the year ended December 31, 2008, we based the estimated discounted future net revenues from our proved reserves on prices and costs in effect on the day of the estimate in accordance with previous SEC requirements. In accordance with new SEC requirements for the years ended December 31, 2009 and 2010, we have based the estimated discounted future net revenues from our proved reserves on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the preceding twelve months without giving effect to derivative transactions. Actual future net revenues from our natural gas and oil properties will be affected by factors such as:
 
  •   actual prices we receive for natural gas and oil;
 
  •   actual cost of development and production expenditures;
 
  •   the amount and timing of actual production; and
 
  •   changes in governmental regulations or taxation.
 
The timing of both our production and our incurrence of expenses in connection with the development and production of natural gas and oil properties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value. In addition, the 10 percent discount factor we use when calculating discounted future net revenues may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general.
 
Certain of our domestic undeveloped leasehold assets are subject to leases that will expire over the next several years unless production is established on units containing the acreage.
 
The majority of our acreage in the Marcellus Shale and Bakken Shale is not currently held by production. Unless production in paying quantities is established on units containing these leases during their terms, the leases will expire. If our leases expire and we are unable to renew the leases, we will lose our right to develop the related properties. Our drilling plans for these areas are subject to change based upon various factors, including drilling results, natural gas and oil prices, availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints and regulatory and lease issues.
 
Prices for natural gas, oil and NGLs are volatile, and this volatility could adversely affect our financial results, cash flows, access to capital and ability to maintain our existing business.
 
Our revenues, operating results, future rate of growth and the value of our business depend primarily upon the prices of natural gas, oil and NGLs. Price volatility can impact both the amount we receive for our


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products and the volume of products we sell. Prices affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital.
 
The markets for natural gas, oil and NGLs are likely to continue to be volatile. Wide fluctuations in prices might result from relatively minor changes in the supply of and demand for these commodities, market uncertainty and other factors that are beyond our control, including:
 
  •   Worldwide and domestic supplies of and demand for natural gas, oil and NGLs;
 
  •   Turmoil in the Middle East and other producing regions;
 
  •   The activities of the Organization of Petroleum Exporting Countries;
 
  •   Terrorist attacks on production or transportation assets;
 
  •   Weather conditions;
 
  •   The level of consumer demand;
 
  •   Variations in local market conditions (basis differential);
 
  •   The price and availability of other types of fuels;
 
  •   The availability of pipeline capacity;
 
  •   Supply disruptions, including plant outages and transportation disruptions;
 
  •   The price and quantity of foreign imports of natural gas and oil;
 
  •   Domestic and foreign governmental regulations and taxes;
 
  •   Volatility in the natural gas and oil markets;
 
  •   The overall economic environment;
 
  •   The credit of participants in the markets where products are bought and sold; and
 
  •   The adoption of regulations or legislation relating to climate change.
 
Our business depends on access to natural gas, oil and NGL transportation systems and facilities.
 
The marketability of our natural gas, oil and NGL production depends in large part on the operation, availability, proximity, capacity and expansion of transportation systems and facilities owned by third parties. For example, we can provide no assurance that sufficient transportation capacity will exist for expected production from the Bakken Shale and Marcellus Shale or that we will be able to obtain sufficient transportation capacity on economic terms.
 
A lack of available capacity on transportation systems and facilities or delays in their planned expansions could result in the shut-in of producing wells or the delay or discontinuance of drilling plans for properties. A lack of availability of these systems and facilities for an extended period of time could negatively affect our revenues. In addition, we have entered into contracts for firm transportation and any failure to renew those contracts on the same or better commercial terms could increase our costs and our exposure to the risks described above.
 
We may have excess capacity under our firm transportation contracts, or the terms of certain of those contracts may be less favorable than those we could obtain currently.
 
We have entered into contracts for firm transportation that may exceed our transportation needs. Any excess transportation commitments will result in excess transportation costs that could negatively affect our results of operations. In addition, certain of the contracts we have entered into may be on terms less favorable to us than we could obtain if we were negotiating them at current rates, which also could negatively affect our results of operations.


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We have limited control over activities on properties we do not operate, which could reduce our production and revenues.
 
If we do not operate the properties in which we own an interest, we do not have control over normal operating procedures, expenditures or future development of underlying properties. The failure of an operator of our wells to adequately perform operations or an operator’s breach of the applicable agreements could reduce our production and revenues or increase our costs. As of December 31, 2010, we were not the operator of approximately 15 percent of our total domestic net production. Apco generally has outside-operated interests in its properties. The success and timing of our drilling and development activities on properties operated by others depend upon a number of factors outside of our control, including the operator’s timing and amount of capital expenditures, expertise and financial resources, inclusion of other participants in drilling wells and use of technology. Because we do not have a majority interest in most wells we do not operate, we may not be in a position to remove the operator in the event of poor performance.
 
We might not be able to successfully manage the risks associated with selling and marketing products in the wholesale energy markets.
 
Our portfolio of derivative and other energy contracts includes wholesale contracts to buy and sell natural gas, oil and NGLs that are settled by the delivery of the commodity or cash. If the values of these contracts change in a direction or manner that we do not anticipate or cannot manage, it could negatively affect our results of operations. In the past, certain marketing and trading companies have experienced severe financial problems due to price volatility in the energy commodity markets. In certain instances this volatility has caused companies to be unable to deliver energy commodities that they had guaranteed under contract. If such a delivery failure were to occur in one of our contracts, we might incur additional losses to the extent of amounts, if any, already paid to, or received from, counterparties. In addition, in our business, we often extend credit to our counterparties. We are exposed to the risk that we might not be able to collect amounts owed to us. If the counterparty to such a transaction fails to perform and any collateral that secures our counterparty’s obligation is inadequate, we will suffer a loss. Downturns in the economy or disruptions in the global credit markets could cause more of our counterparties to fail to perform than we expect.
 
Our risk management and measurement systems and hedging activities might not be effective and could increase the volatility of our results.
 
The systems we use to quantify commodity price risk associated with our businesses might not always be followed or might not always be effective. Further, such systems do not in themselves manage risk, particularly risks outside of our control, and adverse changes in energy commodity market prices, volatility, adverse correlation of commodity prices, the liquidity of markets, changes in interest rates and other risks discussed in this prospectus might still adversely affect our earnings, cash flows and balance sheet under applicable accounting rules, even if risks have been identified. Furthermore, no single hedging arrangement can adequately address all commodity price risks present in a given contract. For example, a forward contract that would be effective in hedging commodity price volatility risks would not hedge the contract’s counterparty credit or performance risk. Therefore, unhedged risks will always continue to exist.
 
Our use of hedging arrangements through which we attempt to reduce the economic risk of our participation in commodity markets could result in increased volatility of our reported results. Changes in the fair values (gains and losses) of derivatives that qualify as hedges under GAAP to the extent that such hedges are not fully effective in offsetting changes to the value of the hedged commodity, as well as changes in the fair value of derivatives that do not qualify or have not been designated as hedges under GAAP, must be recorded in our income. This creates the risk of volatility in earnings even if no economic impact to us has occurred during the applicable period.
 
The impact of changes in market prices for natural gas, oil and NGLs on the average prices paid or received by us may be reduced based on the level of our hedging activities. These hedging arrangements may limit or enhance our margins if the market prices for natural gas, oil or NGLs were to change substantially


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from the price established by the hedges. In addition, our hedging arrangements expose us to the risk of financial loss if our production volumes are less than expected.
 
The adoption and implementation of new statutory and regulatory requirements for derivative transactions could have an adverse impact on our ability to hedge risks associated with our business and increase the working capital requirements to conduct these activities.
 
In July 2010, federal legislation known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) was enacted. The Dodd-Frank Act provides for new statutory and regulatory requirements for derivative transactions, including oil and gas hedging transactions. Among other things, the Dodd-Frank Act provides for the creation of position limits for certain derivatives transactions, as well as requiring certain transactions to be cleared on exchanges for which cash collateral will be required. The final impact of the Dodd-Frank Act on our hedging activities is uncertain at this time due to the requirement that the SEC and the Commodities Futures Trading Commission (“CFTC”) promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. These new rules and regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts or reduce the availability of derivatives. Although we believe the derivative contracts that we enter into should not be impacted by position limits and should be exempt from the requirement to clear transactions through a central exchange or to post collateral, the impact upon our businesses will depend on the outcome of the implementing regulations adopted by the CFTC.
 
Depending on the rules and definitions adopted by the CFTC or similar rules that may be adopted by other regulatory bodies, we might in the future be required to provide cash collateral for our commodities hedging transactions under circumstances in which we do not currently post cash collateral. Posting of such additional cash collateral could impact liquidity and reduce our cash available for capital expenditures. A requirement to post cash collateral could therefore reduce our ability to execute hedges to reduce commodity price uncertainty and thus protect cash flows. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable.
 
We are exposed to the credit risk of our customers and counterparties, and our credit risk management may not be adequate to protect against such risk.
 
We are subject to the risk of loss resulting from nonpayment and/or nonperformance by our customers and counterparties in the ordinary course of our business. Our credit procedures and policies may not be adequate to fully eliminate customer and counterparty credit risk. We cannot predict to what extent our business would be impacted by deteriorating conditions in the economy, including declines in our customers’ and counterparties’ creditworthiness. If we fail to adequately assess the creditworthiness of existing or future customers and counterparties, unanticipated deterioration in their creditworthiness and any resulting increase in nonpayment and/or nonperformance by them could cause us to write-down or write-off doubtful accounts. Such write-downs or write-offs could negatively affect our operating results in the periods in which they occur and, if significant, could have a material adverse effect on our business, results of operations, cash flows and financial condition.
 
We face competition in acquiring new properties, marketing natural gas and oil and securing equipment and trained personnel in the natural gas and oil industry.
 
Our ability to acquire additional drilling locations and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing natural gas and oil and securing equipment and trained personnel. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business.


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Our operations are subject to operational hazards and unforeseen interruptions for which they may not be adequately insured.
 
There are operational risks associated with drilling for, production, gathering, transporting, storage, processing and treating of natural gas and oil and the fractionation and storage of NGLs, including:
 
  •   Hurricanes, tornadoes, floods, extreme weather conditions and other natural disasters;
 
  •   Aging infrastructure and mechanical problems;
 
  •   Damages to pipelines, pipeline blockages or other pipeline interruptions;
 
  •   Uncontrolled releases of natural gas (including sour gas), oil, NGLs, brine or industrial chemicals;
 
  •   Operator error;
 
  •   Pollution and environmental risks;
 
  •   Fires, explosions and blowouts;
 
  •   Risks related to truck and rail loading and unloading; and
 
  •   Terrorist attacks or threatened attacks on our facilities or those of other energy companies.
 
Any of these risks could result in loss of human life, personal injuries, significant damage to property, environmental pollution, impairment of our operations and substantial losses to us. In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses, and only at levels we believe to be appropriate. The location of certain segments of our facilities in or near populated areas, including residential areas, commercial business centers and industrial sites, could increase the level of damages resulting from these risks. In spite of our precautions, an event such as those described above could cause considerable harm to people or property and could have a material adverse effect on our financial condition and results of operations, particularly if the event is not fully covered by insurance. Accidents or other operating risks could further result in loss of service available to our customers.
 
We do not insure against all potential losses and could be seriously harmed by unexpected liabilities or by the inability of our insurers to satisfy our claims.
 
We are not fully insured against all risks inherent to our business, including environmental accidents. We do not maintain insurance in the type and amount to cover all possible risks of loss.
 
We currently maintain excess liability insurance with limits of $610 million per occurrence and in the annual aggregate with a $2 million per occurrence deductible. This insurance covers us, our parent, our subsidiaries and certain of our affiliates for legal and contractual liabilities arising out of bodily injury or property damage, including resulting loss of use to third parties. This excess liability insurance includes coverage for sudden and accidental pollution liability for full limits, with the first $135 million of insurance also providing gradual pollution liability coverage for natural gas and NGL operations.
 
Although we maintain property insurance on property we own, lease or are responsible to insure, the policy may not cover the full replacement cost of all damaged assets or the entire amount of business interruption loss we may experience. In addition, certain perils may be excluded from coverage or sub-limited. We may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. We may elect to self insure a portion of our risks. We do not insure our underground pipelines for physical damage, except at certain locations. All of our insurance is subject to deductibles. If a significant accident or event occurs for which we are not fully insured it could adversely affect our operations and financial condition.
 
In addition, any insurance company that provides coverage to us may experience negative developments that could impair their ability to pay any of our claims. As a result, we could be exposed to greater losses than anticipated and may have to obtain replacement insurance, if available, at a greater cost.


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Potential changes in accounting standards might cause us to revise our financial results and disclosures in the future, which might change the way analysts measure our business or financial performance.
 
Regulators and legislators continue to take a renewed look at accounting practices, financial and reserves disclosures and companies’ relationships with their independent public accounting firms and reserves consultants. It remains unclear what new laws or regulations will be adopted, and we cannot predict the ultimate impact of that any such new laws or regulations could have. In addition, the Financial Accounting Standards Board or the SEC could enact new accounting standards that might impact how we are required to record revenues, expenses, assets, liabilities and equity. Any significant change in accounting standards or disclosure requirements could have a material adverse effect on our business, results of operations and financial condition.
 
Our investments and projects located outside of the United States expose us to risks related to the laws of other countries, and the taxes, economic conditions, fluctuations in currency rates, political conditions and policies of foreign governments. These risks might delay or reduce our realization of value from our international projects.
 
We currently own and might acquire and/or dispose of material energy-related investments and projects outside the United States, principally Argentina and Colombia. The economic, political and legal conditions and regulatory environment in the countries in which we have interests or in which we might pursue acquisition or investment opportunities present risks that are different from or greater than those in the United States. These risks include delays in construction and interruption of business, as well as risks of war, expropriation, nationalization, renegotiation, trade sanctions or nullification of existing contracts and changes in law or tax policy, including with respect to the prices we realize for the commodities we produce and sell. The uncertainty of the legal environment in certain foreign countries in which we develop or acquire projects or make investments could make it more difficult to obtain nonrecourse project financing or other financing on suitable terms, could adversely affect the ability of certain customers to honor their obligations with respect to such projects or investments and could impair our ability to enforce our rights under agreements relating to such projects or investments.
 
Operations and investments in foreign countries also can present currency exchange rate and convertibility, inflation and repatriation risk. In certain situations under which we develop or acquire projects or make investments, economic and monetary conditions and other factors could affect our ability to convert to U.S. dollars our earnings denominated in foreign currencies. In addition, risk from fluctuations in currency exchange rates can arise when our foreign subsidiaries expend or borrow funds in one type of currency, but receive revenue in another. In such cases, an adverse change in exchange rates can reduce our ability to meet expenses, including debt service obligations. We may or may not put contracts in place designed to mitigate our foreign currency exchange risks. We have some exposures that are not hedged and which could result in losses or volatility in our results of operations.
 
Our operating results might fluctuate on a seasonal and quarterly basis.
 
Our revenues can have seasonal characteristics. In many parts of the country, demand for natural gas and other fuels peaks during the winter. As a result, our overall operating results in the future might fluctuate substantially on a seasonal basis. Demand for natural gas and other fuels could vary significantly from our expectations depending on the nature and location of our facilities and the terms of our natural gas transportation arrangements relative to demand created by unusual weather patterns.
 
Our debt agreements impose restrictions on us that may limit our access to credit and adversely affect our ability to operate our business.
 
Our Credit Facility and the indenture governing the Notes are expected to contain various covenants that restrict or limit, among other things, our ability to grant liens to support indebtedness, merge or sell substantially all of our assets, make certain distributions during an event of default and incur additional debt. In addition, our debt agreements will contain financial covenants and other limitations with which we will


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need to comply. These covenants could adversely affect our ability to finance our future operations or capital needs or engage in, expand or pursue our business activities and prevent us from engaging in certain transactions that might otherwise be considered beneficial to us. Our ability to comply with these covenants may be affected by events beyond our control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, our current assumptions about future economic conditions turn out to be incorrect or unexpected events occur, our ability to comply with these covenants may be significantly impaired.
 
Our failure to comply with the covenants in our debt agreements could result in events of default. Upon the occurrence of such an event of default, the lenders could elect to declare all amounts outstanding under a particular facility to be immediately due and payable and terminate all commitments, if any, to extend further credit. Certain payment defaults or an acceleration under one debt agreement could cause a cross-default or cross-acceleration of another debt agreement. Such a cross-default or cross-acceleration could have a wider impact on our liquidity than might otherwise arise from a default or acceleration of a single debt instrument. If an event of default occurs, or if other debt agreements cross-default, and the lenders under the affected debt agreements accelerate the maturity of any loans or other debt outstanding to us, we may not have sufficient liquidity to repay amounts outstanding under such debt agreements. For more information regarding our anticipated debt agreements, please read “Description of our Concurrent Financing Transactions.”
 
Our ability to repay, extend or refinance our debt obligations and to obtain future credit will depend primarily on our operating performance, which will be affected by general economic, financial, competitive, legislative, regulatory, business and other factors, many of which are beyond our control. Our ability to refinance our debt obligations or obtain future credit will also depend upon the current conditions in the credit markets and the availability of credit generally. If we are unable to meet our debt service obligations or obtain future credit on favorable terms, if at all, we could be forced to restructure or refinance our indebtedness, seek additional equity capital or sell assets. We may be unable to obtain financing or sell assets on satisfactory terms, or at all.
 
Difficult conditions in the global capital markets, the credit markets and the economy in general could negatively affect our business and results of operations
 
Our business may be negatively impacted by adverse economic conditions or future disruptions in global financial markets. Included among these potential negative impacts are reduced energy demand and lower commodity prices, increased difficulty in collecting amounts owed to us by our customers and reduced access to credit markets. Our ability to access the capital markets may be restricted at a time when we would like, or need, to raise financing. If financing is not available when needed, or is available only on unfavorable terms, we may be unable to implement our business plans or otherwise take advantage of business opportunities or respond to competitive pressures.
 
We are subject to risks associated with climate change.
 
There is a growing belief that emissions of greenhouse gases (“GHGs”) may be linked to climate change. Climate change and the costs that may be associated with its impacts and the regulation of GHGs have the potential to affect our business in many ways, including negatively impacting the costs we incur in providing our products and services, the demand for and consumption of our products and services (due to change in both costs and weather patterns), and the economic health of the regions in which we operate, all of which can create financial risks.
 
In addition, legislative and regulatory responses related to GHGs and climate change create the potential for financial risk. The U.S. Congress has previously considered legislation and certain states have for some time been considering various forms of legislation related to GHG emissions. There have also been international efforts seeking legally binding reductions in emissions of GHGs. In addition, increased public awareness and concern may result in more state, regional and/or federal requirements to reduce or mitigate GHG emissions.


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Numerous states have announced or adopted programs to stabilize and reduce GHGs. In addition, on December 7, 2009, the EPA issued a final determination that six GHGs are a threat to public safety and welfare. Also in 2009, the EPA finalized a GHG emission standard for mobile sources. On September 22, 2009, the EPA finalized a GHG reporting rule that requires large sources of GHG emissions to monitor, maintain records on, and annually report their GHG emissions. On November 8, 2010, the EPA also issued GHG monitoring and reporting regulations that went into effect on December 30, 2010, specifically for oil and natural gas facilities, including onshore and offshore oil and natural gas production facilities that emit 25,000 metric tons or more of carbon dioxide equivalent per year. The rule requires reporting of GHG emissions by regulated facilities to the EPA by March 2012 for emissions during 2011 and annually thereafter. We are required to report our GHG emissions to the EPA by March 2012 under this rule. The EPA also issued a final rule that makes certain stationary sources and newer modification projects subject to permitting requirements for GHG emissions, beginning in 2011, under the CAA. Several of the EPA’s GHG rules are being challenged in pending court proceedings, and depending on the outcome of such proceedings, such rules may be modified or rescinded or the EPA could develop new rules.
 
The recent actions of the EPA and the passage of any federal or state climate change laws or regulations could result in increased costs to (i) operate and maintain our facilities, (ii) install new emission controls on our facilities and (iii) administer and manage any GHG emissions program. If we are unable to recover or pass through a significant level of our costs related to complying with climate change regulatory requirements imposed on us, it could have a material adverse effect on our results of operations and financial condition. To the extent financial markets view climate change and GHG emissions as a financial risk, this could negatively impact our cost of and access to capital. Legislation or regulations that may be adopted to address climate change could also affect the markets for our products by making our products more or less desirable than competing sources of energy.
 
Our operations are subject to governmental laws and regulations relating to the protection of the environment, which may expose us to significant costs and liabilities and could exceed current expectations.
 
Substantial costs, liabilities, delays and other significant issues could arise from environmental laws and regulations inherent in drilling and well completion, gathering, transportation, and storage, and we may incur substantial costs and liabilities in the performance of these types of operations. Our operations are subject to extensive federal, state and local laws and regulations governing environmental protection, the discharge of materials into the environment and the security of chemical and industrial facilities. These laws include:
 
  •   Clean Air Act (“CAA”) and analogous state laws, which impose obligations related to air emissions;
 
  •   Clean Water Act (“CWA”), and analogous state laws, which regulate discharge of wastewaters and storm water from some our facilities into state and federal waters, including wetlands;
 
  •   Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), and analogous state laws, which regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or locations to which we have sent wastes for disposal;
 
  •   Resource Conservation and Recovery Act (“RCRA”), and analogous state laws, which impose requirements for the handling and discharge of solid and hazardous waste from our facilities;
 
  •   National Environmental Policy Act (“NEPA”), which requires federal agencies to study likely environment impacts of a proposed federal action before it is approved, such as drilling on federal lands;
 
  •   Safe Drinking Water Act (“SDWA”), which restricts the disposal, treatment or release of water produced or used during oil and gas development;
 
  •   Endangered Species Act (“ESA”), and analogous state laws, which seek to ensure that activities do not jeopardize endangered or threatened animals, fish and plant species, nor destroy or modify the critical habitat of such species; and


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  •   Oil Pollution Act (“OPA”) of 1990, which requires oil storage facilities and vessels to submit to the federal government plans detailing how they will respond to large discharges, requires updates to technology and equipment, regulation of above ground storage tanks and sets forth liability for spills by responsible parties.
 
Various governmental authorities, including the U.S. Environmental Protection Agency (“EPA”), the U.S. Department of the Interior, the Bureau of Indian Affairs and analogous state agencies and tribal governments, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly actions. Failure to comply with these laws, regulations and permits may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, the imposition of stricter conditions on or revocation of permits, the issuance of injunctions limiting or preventing some or all of our operations, delays in granting permits and cancellation of leases.
 
There is inherent risk of the incurrence of environmental costs and liabilities in our business, some of which may be material, due to the handling of our products as they are gathered, transported, processed, fractionated and stored, air emissions related to our operations, historical industry operations, and water and waste disposal practices. Joint and several, strict liability may be incurred without regard to fault under certain environmental laws and regulations, including CERCLA, RCRA and analogous state laws, for the remediation of contaminated areas and in connection with spills or releases of natural gas, oil and wastes on, under, or from our properties and facilities. Private parties may have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage arising from our operations. Some sites we operate are located near current or former third-party oil and natural gas operations or facilities, and there is a risk that contamination has migrated from those sites to ours. In addition, increasingly strict laws, regulations and enforcement policies could materially increase our compliance costs and the cost of any remediation that may become necessary. Our insurance may not cover all environmental risks and costs or may not provide sufficient coverage if an environmental claim is made against us.
 
In March 2010, the EPA announced its National Enforcement Initiatives for 2011 to 2013, which includes the addition of “Energy Extraction Activities” to its enforcement priorities list. To address its concerns regarding the pollution risks raised by new techniques for oil and gas extraction and coal mining, the EPA is developing an initiative to ensure that energy extraction activities are complying with federal environmental requirements. This initiative could involve a large scale investigation of our facilities and processes, and could lead to potential enforcement actions, penalties or injunctive relief against us.
 
Our business may be adversely affected by increased costs due to stricter pollution control equipment requirements or liabilities resulting from non-compliance with required operating or other regulatory permits. Also, we might not be able to obtain or maintain from time to time all required environmental regulatory approvals for our operations. If there is a delay in obtaining any required environmental regulatory approvals, or if we fail to obtain and comply with them, the operation or construction of our facilities could be prevented or become subject to additional costs.
 
We are generally responsible for all liabilities associated with the environmental condition of our facilities and assets, whether acquired or developed, regardless of when the liabilities arose and whether they are known or unknown. In connection with certain acquisitions and divestitures, we could acquire, or be required to provide indemnification against, environmental liabilities that could expose us to material losses, which may not be covered by insurance. In addition, the steps we could be required to take to bring certain facilities into compliance could be prohibitively expensive, and we might be required to shut down, divest or alter the operation of those facilities, which might cause us to incur losses.
 
We make assumptions and develop expectations about possible expenditures related to environmental conditions based on current laws and regulations and current interpretations of those laws and regulations. If the interpretation of laws or regulations, or the laws and regulations themselves, change, our assumptions may change, and any new capital costs may be incurred to comply with such changes. In addition, new environmental laws and regulations might adversely affect our products and activities, including drilling,


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processing, fractionation, storage and transportation, as well as waste management and air emissions. For instance, federal and state agencies could impose additional safety requirements, any of which could affect our profitability.
 
Our exploration and production operations outside the United States are subject to various types of regulations similar to those described above imposed by the governments of the countries in which we operate, and may affect our operations and costs within those countries.
 
Legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.
 
Legislation has been introduced in the United States Congress called the Fracturing Responsibility and Awareness of Chemicals Act (the “FRAC Act”) to amend the SDWA to eliminate an existing exemption for hydraulic fracturing activities from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as require disclosure of the chemical constituents of the fluids used in the fracturing process. Hydraulic fracturing involves the injection of water, sand and additives under pressure into rock formations in order to stimulate natural gas production. We find that the use of hydraulic fracturing is necessary to produce commercial quantities of natural gas and oil from many reservoirs. If adopted, this legislation could establish an additional level of regulation and permitting at the federal level, and could make it easier for third parties opposed to the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect the environment, including groundwater, soil or surface water. At this time, it is not clear what action, if any, the United States Congress will take on the FRAC Act. Scrutiny of hydraulic fracturing activities continues in other ways, with the EPA having commenced a multi-year study of the potential environmental impacts of hydraulic fracturing, the initial results of which are anticipated to be available by late 2012. Several states have also adopted or considered legislation requiring the disclosure of fracturing fluids and other restrictions on hydraulic fracturing, including states in which we operate (e.g., Wyoming, Pennsylvania, Texas, Colorado, North Dakota and New Mexico). The U.S. Department of the Interior is also considering disclosure requirements or other mandates for hydraulic fracturing on federal land, which, if adopted, would affect our operations on federal lands. If new federal or state laws or regulations that significantly restrict hydraulic fracturing are adopted, such legal requirements could result in delays, eliminate certain drilling and injection activities, make it more difficult or costly for us to perform fracturing and increase our costs of compliance and doing business as well as delay or prevent the development of unconventional gas resources from shale formations which are not commercial without the use of hydraulic fracturing.
 
Our ability to produce gas could be impaired if we are unable to acquire adequate supplies of water for our drilling and completion operations or are unable to dispose of the water we use at a reasonable cost and within applicable environmental rules.
 
Our inability to locate sufficient amounts of water, or dispose of or recycle water used in our exploration and production operations, could adversely impact our operations, particularly with respect to our Marcellus Shale, San Juan Basin, Bakken Shale and Piceance Basin operations. Moreover, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of natural gas. The CWA imposes restrictions and strict controls regarding the discharge of produced waters and other natural gas and oil waste into navigable waters. Permits must be obtained to discharge pollutants to waters and to conduct construction activities in waters and wetlands. The CWA and similar state laws provide for civil, criminal and administrative penalties for any unauthorized discharges of pollutants and unauthorized discharges of reportable quantities of oil and other hazardous substances. Many state discharge regulations and the Federal National Pollutant Discharge Elimination System general permits issued by the EPA prohibit the discharge of produced water and sand, drilling fluids, drill cuttings and certain other substances related to the natural gas and oil industry into coastal waters. The EPA has also adopted regulations requiring certain natural gas and oil exploration and production facilities to obtain permits for storm water discharges. Compliance with environmental regulations and permit


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requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells may increase our operating costs and cause delays, interruptions or termination of our operations, the extent of which cannot be predicted.
 
Legal and regulatory proceedings and investigations relating to the energy industry, and the complex government regulations to which our businesses are subject, have adversely affected our business and may continue to do so. The operation of our businesses might also be adversely affected by changes in regulations or in their interpretation or implementation, or the introduction of new laws, regulations or permitting requirements applicable to our businesses or our customers.
 
Public and regulatory scrutiny of the energy industry has resulted in increased regulation being either proposed or implemented. Adverse effects may continue as a result of the uncertainty of ongoing inquiries, investigations and court proceedings, or additional inquiries and proceedings by federal or state regulatory agencies or private plaintiffs. In addition, we cannot predict the outcome of any of these inquiries or whether these inquiries will lead to additional legal proceedings against us, civil or criminal fines or penalties, or other regulatory action, including legislation or increased permitting requirements. Current legal proceedings or other matters against us, including environmental matters, suits, regulatory appeals, challenges to our permits by citizen groups and similar matters, might result in adverse decisions against us. The result of such adverse decisions, either individually or in the aggregate, could be material and may not be covered fully or at all by insurance.
 
In addition, existing regulations might be revised or reinterpreted, new laws, regulations and permitting requirements might be adopted or become applicable to us, our facilities, our customers, our vendors or our service providers, and future changes in laws and regulations could have a material adverse effect on our financial condition, results of operations and cash flows. For example, several ruptures on third party pipelines have occurred recently. In response, various legislative and regulatory reforms associated with pipeline safety and integrity have been proposed, including new regulations covering gathering pipelines that have not previously been subject to regulation. Such reforms, if adopted, could significantly increase our costs.
 
Certain of our properties, including our operations in the Bakken Shale, are located on Native American tribal lands and are subject to various federal and tribal approvals and regulations, which may increase our costs and delay or prevent our efforts to conduct planned operations.
 
Various federal agencies within the U.S. Department of the Interior, particularly the Bureau of Indian Affairs, Bureau of Land Management and the Office of Natural Resources Revenue, along with each Native American tribe, promulgate and enforce regulations pertaining to gas and oil operations on Native American tribal lands. These regulations and approval requirements relate to such matters as lease provisions, drilling and production requirements, environmental standards and royalty considerations. In addition, each Native American tribe is a sovereign nation having the right to enforce laws and regulations and to grant approvals independent from federal, state and local statutes and regulations. These tribal laws and regulations include various taxes, fees, requirements to employ Native American tribal members and other conditions that apply to lessees, operators and contractors conducting operations on Native American tribal lands. Lessees and operators conducting operations on tribal lands are generally subject to the Native American tribal court system. In addition, if our relationships with any of the relevant Native American tribes were to deteriorate, we could face significant risks to our ability to continue the projected development of our leases on Native American tribal lands. One or more of these factors may increase our costs of doing business on Native American tribal lands and impact the viability of, or prevent or delay our ability to conduct, our natural gas or oil development and production operations on such lands.
 
Tax laws and regulations may change over time, including the elimination of federal income tax deductions currently available with respect to oil and gas exploration and development.
 
Tax laws and regulations are highly complex and subject to interpretation, and the tax laws, treaties and regulations to which we are subject may change over time. Our tax filings are based upon our interpretation of the tax laws in effect in various jurisdictions at the time that the filings were made. If these laws, treaties or


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regulations change, or if the taxing authorities do not agree with our interpretation of the effects of such laws, treaties and regulations, it could have a material adverse effect on us.
 
Among the changes contained in President Obama’s budget proposal for fiscal year 2012, released by the White House on February 14, 2011, is the elimination of certain U.S. federal income tax provisions currently available to oil and gas exploration and production companies. Such changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties; (ii) the elimination of current expensing of intangible drilling and development costs; (iii) the elimination of the deduction for certain U.S. production activities; and (iv) an extension of the amortization period for certain geological and geophysical expenditures. Members of Congress have introduced legislation with similar provisions in the current session. It is unclear, however, whether any such changes will be enacted or how soon such changes could be effective.
 
The passage of any legislation as a result of the budget proposal or any other similar change in U.S. federal income tax law could eliminate certain tax deductions that are currently available with respect to oil and gas exploration and development. The elimination of such federal tax deductions, as well as any changes to or the imposition of new state or local taxes (including the imposition of, or increases in production, severance, or similar taxes) could negatively affect our financial condition and results of operations.
 
Our acquisition attempts may not be successful or may result in completed acquisitions that do not perform as anticipated.
 
We have made and may continue to make acquisitions of businesses and properties. However, suitable acquisition candidates may not continue to be available on terms and conditions we find acceptable. The following are some of the risks associated with acquisitions, including any completed or future acquisitions:
 
  •   some of the acquired businesses or properties may not produce revenues, reserves, earnings or cash flow at anticipated levels or could have environmental, permitting or other problems for which contractual protections prove inadequate;
 
  •   we may assume liabilities that were not disclosed to us or that exceed our estimates;
 
  •   properties we acquire may be subject to burdens on title that we were not aware of at the time of acquisition or that interfere with our ability to hold the property for production;
 
  •   we may be unable to integrate acquired businesses successfully and realize anticipated economic, operational and other benefits in a timely manner, which could result in substantial costs and delays or other operational, technical or financial problems;
 
  •   acquisitions could disrupt our ongoing business, distract management, divert resources and make it difficult to maintain our current business standards, controls and procedures; and
 
  •   we may issue additional equity or debt securities related to future acquisitions.
 
Substantial acquisitions or other transactions could require significant external capital and could change our risk and property profile.
 
In order to finance acquisitions of additional producing or undeveloped properties, we may need to alter or increase our capitalization substantially through the issuance of debt or equity securities, the sale of production payments or other means. These changes in capitalization may significantly affect our risk profile. Additionally, significant acquisitions or other transactions can change the character of our operations and business. The character of the new properties may be substantially different in operating or geological characteristics or geographic location than our existing properties. Furthermore, we may not be able to obtain external funding for future acquisitions or other transactions or to obtain external funding on terms acceptable to us.


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Failure of our service providers or disruptions to our outsourcing relationships might negatively impact our ability to conduct our business.
 
We rely on Williams for certain services necessary for us to be able to conduct our business. Williams may outsource some or all of these services to third parties, and a failure of all or part of Williams’ relationships with its outsourcing providers could lead to delays in or interruptions of these services. Our reliance on Williams and others as service providers and on Williams’ outsourcing relationships, and our limited ability to control certain costs, could have a material adverse effect on our business, results of operations and financial condition.
 
Some studies indicate a high failure rate of outsourcing relationships. A deterioration in the timeliness or quality of the services performed by the outsourcing providers or a failure of all or part of these relationships could lead to loss of institutional knowledge and interruption of services necessary for us to be able to conduct our business. The expiration of such agreements or the transition of services between providers could lead to similar losses of institutional knowledge or disruptions.
 
Certain of our accounting, information technology, application development and help desk services are currently provided by Williams’ outsourcing provider from service centers outside of the United States. The economic and political conditions in certain countries from which Williams’ outsourcing providers may provide services to us present similar risks of business operations located outside of the United States, including risks of interruption of business, war, expropriation, nationalization, renegotiation, trade sanctions or nullification of existing contracts and changes in law or tax policy, that are greater than in the United States.
 
Our assets and operations can be adversely affected by weather and other natural phenomena.
 
Our assets and operations can be adversely affected by hurricanes, floods, earthquakes, tornadoes and other natural phenomena and weather conditions, including extreme temperatures. Insurance may be inadequate, and in some instances, we have been unable to obtain insurance on commercially reasonable terms, or insurance has not been available at all. A significant disruption in operations or a significant liability for which we were not fully insured could have a material adverse effect on our business, results of operations and financial condition.
 
Our customers’ energy needs vary with weather conditions. To the extent weather conditions are affected by climate change or demand is impacted by regulations associated with climate change, customers’ energy use could increase or decrease depending on the duration and magnitude of the changes, leading either to increased investment or decreased revenues.
 
Acts of terrorism could have a material adverse effect on our financial condition, results of operations and cash flows.
 
Our assets and the assets of our customers and others may be targets of terrorist activities that could disrupt our business or cause significant harm to our operations, such as full or partial disruption to the ability to produce, process, transport or distribute natural gas, oil, or NGLs. Acts of terrorism as well as events occurring in response to or in connection with acts of terrorism could cause environmental repercussions that could result in a significant decrease in revenues or significant reconstruction or remediation costs.
 
We have identified two significant deficiencies in our internal control over financial reporting that when aggregated with other control deficiencies constituted a material weakness in such internal controls. Our failure to achieve and maintain effective internal controls could have a material adverse effect on our business in the future, on the price of our Class A common stock and our access to the capital markets.
 
Although we are not currently subject to the requirements of Section 404 of the Sarbanes-Oxley Act of 2002 (“Sarbanes-Oxley”), during the preparation of our financial statements for the year ended December 31, 2010, two significant deficiencies in our internal controls were identified pertaining to aspects of depreciation, depletion and amortization of property, plant and equipment. These significant deficiencies, in addition to various control deficiencies not considered to rise to the level of a significant deficiency, in the aggregate were


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deemed to constitute a material weakness as defined under Public Company Accounting Oversight Board Standard No. 5. Adjustments to the estimated carrying value of property, plant and equipment as a result of such significant deficiencies aggregating approximately $20 million have been reflected in our financial statements as of December 31, 2010. We have taken steps to remediate the internal controls related to the identified deficiencies, although we cannot provide assurance that these steps will prove to be effective.
 
We cannot be certain that future significant deficiencies or material weaknesses will not develop or be identified. As of December 31, 2012, we will be required to assess the effectiveness of our internal control over financial reporting under Sarbanes-Oxley, and we will be required to have our independent registered public accounting firm audit the operating effectiveness of our internal control over financial reporting. If we or our independent registered public accounting firm were to conclude that our internal control over financial reporting was not effective, investors could lose confidence in our reported financial information, the price of our Class A common stock could decline and access to the capital markets or other sources of financing could be limited.
 
Risks Related to Our Relationship with Williams
 
We may not realize the potential benefits from our separation from Williams.
 
We may not realize the benefits that we anticipate from our separation from Williams. These benefits include the following:
 
  •   allowing our management to focus its efforts on our business and strategic priorities;
 
  •   enhancing our market recognition with investors;
 
  •   providing us with direct access to the debt and equity capital markets;
 
  •   improving our ability to pursue acquisitions through the use of shares of our common stock as consideration; and
 
  •   enabling us to allocate our capital more efficiently.
 
We may not achieve the anticipated benefits from our separation for a variety of reasons. For example, the process of separating our business from Williams and operating as an independent public company may distract our management from focusing on our business and strategic priorities. In addition, although we will have direct access to the debt and equity capital markets following the separation, we may not be able to issue debt or equity on terms acceptable to us or at all. The availability of shares of our common stock for use as consideration for acquisitions also will not ensure that we will be able to successfully pursue acquisitions or that the acquisitions will be successful. Moreover, even with equity compensation tied to our business we may not be able to attract and retain employees as desired. We also may not fully realize the anticipated benefits from our separation if any of the matters identified as risks in this “Risk Factors” section were to occur. If we do not realize the anticipated benefits from our separation for any reason, our business may be materially adversely affected.
 
Our historical and pro forma combined financial information may not be representative of the results we would have achieved as a stand-alone public company and may not be a reliable indicator of our future results.
 
The historical and pro forma combined financial information that we have included in this prospectus has been derived from Williams’ accounting records and may not necessarily reflect what our financial position, results of operations or cash flows would have been had we been an independent, stand-alone entity during the periods presented or those that we will achieve in the future. Williams did not account for us, and we were not operated, as a separate, stand-alone company for the historical periods presented. The costs and expenses reflected in our historical financial information include an allocation for certain corporate functions historically provided by Williams, including executive oversight, cash management and treasury administration, financing and accounting, tax, internal audit, investor relations, payroll and human resources administration, information technology, legal, regulatory and government affairs, insurance and claims administration, records


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management, real estate and facilities management, sourcing and procurement, mail, print and other office services, and other services, that may be different from the comparable expenses that we would have incurred had we operated as a stand-alone company. These allocations were based on what we and Williams considered to be reasonable reflections of the historical utilization levels of these services required in support of our business. We have not adjusted our historical or pro forma combined financial information to reflect changes that will occur in our cost structure and operations as a result of our transition to becoming a stand-alone public company, including changes in our employee base, potential increased costs associated with reduced economies of scale and increased costs associated with the SEC reporting and the NYSE requirements. Therefore, our historical and pro forma combined financial information may not necessarily be indicative of what our financial position, results of operations or cash flows will be in the future. For additional information, see “Selected Historical Combined Financial Data” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and our financial statements and related notes included elsewhere in this prospectus.
 
Following this offering, we will continue to depend on Williams to provide us with certain services for our business; the services that Williams will provide to us following the separation may not be sufficient to meet our needs, and we may have difficulty finding replacement services or be required to pay increased costs to replace these services after our agreements with Williams expire.
 
Certain administrative services required by us for the operation of our business are currently provided by Williams and its subsidiaries, including services related to cash management and treasury administration, financing and accounting, tax, internal audit, investor relations, payroll and human resources administration, information technology, legal, regulatory and government affairs, insurance and claims administration, records management, real estate and facilities management, sourcing and procurement, mail, print and other office services. Prior to the completion of this offering, we will enter into agreements with Williams related to the separation of our business operations from Williams, including an administrative services agreement and a transition services agreement. The services provided under the administrative services agreement will commence on the date this offering is completed and terminate upon the earlier of (i) the date immediately prior to the date Williams distributes all of our shares of common stock that it owns to its stockholders (which we refer to as the distribution date) or (ii) sixty days’ notice by Williams if it determines that the provision of such services involves certain conflicts of interest between Williams and us or would cause Williams to violate applicable law. The services provided under the transition services agreement will commence on the distribution date and terminate upon the earlier of (i) one year after the distribution date or (ii) sixty days’ notice by either party. In addition, Williams may immediately terminate any of the services it provides to us under the transition services agreement if it determines that the provision of such services involves certain conflicts of interest between Williams and us or would cause Williams to violate applicable law. We believe it is necessary for Williams to provide services for us under the administrative services agreement and the transition services agreement to facilitate the efficient operation of our business as we transition to becoming a stand alone public company. We will, as a result, initially depend on Williams for services following this offering. While these services are being provided to us by Williams, our operational flexibility to modify or implement changes with respect to such services or the amounts we pay for them will be limited. After the expiration or termination of these agreements, we may not be able to replace these services or enter into appropriate third-party agreements on terms and conditions, including cost, comparable to those that we will receive from Williams under our agreements with Williams. Although we intend to replace portions of the services currently provided by Williams, we may encounter difficulties replacing certain services or be unable to negotiate pricing or other terms as favorable as those we currently have in effect. See “Arrangements Between Williams and Our Company—Administrative Services and Transition Services Agreements.”
 
Your investment in our Class A common stock may be adversely affected if Williams does not spin-off the common stock owned by Williams.
 
Williams has advised us that, following the completion of this offering, it intends to spin-off all of the shares of our common stock that it owns to its stockholders. Williams has indicated that it intends to complete the spin-off in 2012 and to convert its Class B common shares to Class A common shares immediately prior


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to such spin-off, assuming such conversion would not jeopardize the ability to consummate the tax-free spin-off or the tax-free treatment of any related restructuring transaction undertaken by Williams. Williams may decide not to complete this offering or the spin-off if, at any time, Williams’ board of directors determines, in its sole discretion, that this offering or the spin-off is not in the best interests of Williams or its stockholders. Unless and until such a spin-off occurs, we will face the risks discussed in this prospectus relating to our continuing relationship with Williams, including its control of us and potential conflicts of interest between Williams and us. In addition, if a spin-off does not occur, the liquidity of the market for our Class A common stock may be constrained for as long as Williams, or a successor controlling shareholder, continues to hold a significant position in our common stock. A lack of liquidity in the market for our Class A common stock may adversely affect our share price.
 
Our share price may decline because of Williams’ ability to sell shares of our common stock.
 
Sales of substantial amounts of our common stock after this offering, or the possibility of those sales, could adversely affect the market price of our Class A common stock and impede our ability to raise capital through the issuance of equity securities. See “Shares Eligible for Future Sale” for a discussion of possible future sales of our common stock.
 
After the completion of this offering, Williams will own 100% of our outstanding Class B common stock, giving Williams     % of the shares of our outstanding common stock, or     % if the underwriters exercise their option to purchase additional Class A common shares in full. Williams has advised us that it intends to complete the distribution of all of our common stock owned by Williams to its stockholders by the end of 2012. Common stock so distributed will be freely tradable by such Williams stockholders who are not deemed to be our affiliates or are otherwise subject to lock-up agreements.
 
Williams has no contractual obligation to retain its shares of our common stock, except for a limited period described under “Underwriting” during which it will not sell any of its shares of our common stock without the consent of Barclays Capital Inc. until 180 days after the date of this prospectus, subject to extension in certain circumstances. Subject to applicable U.S. federal and state securities laws, after the expiration of this 180-day waiting period (or before, with consent of the underwriters to this offering), Williams may sell any and all of the shares of our common stock that it beneficially owns or distribute any or all of these shares of our common stock to its stockholders. This 180-day waiting period does not apply to the distribution by Williams of its remaining ownership interest in us to its common stockholders. The registration rights agreement described elsewhere in this prospectus grants Williams the right to require us to register the shares of our common stock it holds in specified circumstances. In addition, after the expiration of this 180-day waiting period, we could issue and sell additional shares of our Class A common stock. Any sale by Williams or us of our common stock in the public market, or the perception that sales could occur (for example, as a result of the distribution), could adversely affect prevailing market prices for the shares of our common stock.
 
As long as we are controlled by Williams, your ability to influence the outcome of matters requiring stockholder approval will be limited.
 
After the completion of this offering, Williams will not own any shares of our Class A common stock and will own 100% of our outstanding Class B common stock, giving Williams     % of the shares of our outstanding common stock and     % of the combined voting power of our outstanding common stock, or     % and     %, respectively, if the underwriters exercise their option to purchase additional Class A common shares in full. As long as Williams has voting control of our company, Williams will have the ability to take many stockholder actions, including the election or removal of directors, irrespective of the vote of, and without prior notice to, any other stockholder. As a result, Williams will have the ability to influence or control all matters affecting us, including:
 
  •   the composition of our board of directors and, through our board of directors, decision-making with respect to our business direction and policies, including the appointment and removal of our officers;
 
  •   any determinations with respect to acquisitions of businesses, mergers, or other business combinations;


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  •   our acquisition or disposition of assets;
 
  •   our capital structure;
 
  •   changes to the agreements relating to our separation from Williams;
 
  •   our payment or non-payment of dividends on our common stock; and
 
  •   determinations with respect to our tax returns.
 
Williams’ interests may not be the same as, or may conflict with, the interests of our other stockholders. As a result, actions that Williams takes with respect to us, as our controlling stockholder, may not be favorable to us. In addition, this voting control may discourage transactions involving a change of control of our company, including transactions in which you, as a holder of our Class A common stock, might otherwise receive a premium for your shares over the then-current market price. Furthermore, Williams is not prohibited from selling a controlling interest in our company to a third party without your approval or without providing for a purchase of your shares. At any time following the completion of this offering and the expiration or waiver of the applicable lock-up period described under “Underwriting,” Williams has the right to spin-off shares of our common stock that it owns to its stockholders. In addition, after the expiration or waiver of the applicable lock-up period described under “Underwriting,” Williams has the right to sell a controlling interest in us to a third party, without your approval and without providing for a purchase of your shares. There is no assurance that Williams will effect the spin-off, and if Williams elects not to effect the spin-off, it could remain our stockholder for an extended or indefinite period of time. In addition, Williams may decide not to complete the spin-off if, at any time, Williams’ board of directors determines, in its sole discretion, that the spin-off is not in the best interests of Williams or its stockholders. As a result, the spin-off may not occur by 2012 or at all. See “Shares Eligible For Future Sale.”
 
We may have potential business conflicts of interest with Williams regarding our past and ongoing relationships, and because of Williams’ controlling ownership in us, the resolution of these conflicts may not be favorable to us.
 
Conflicts of interest may arise between Williams and us in a number of areas relating to our past and ongoing relationships, including:
 
  •   labor, tax, employee benefit, indemnification and other matters arising under agreements with Williams;
 
  •   employee recruiting and retention;
 
  •   sales or distributions by Williams of all or any portion of its ownership interest in us, which could be to one of our competitors; and
 
  •   business opportunities that may be attractive to both Williams and us.
 
We may not be able to resolve any potential conflicts, and, even if we do so, the resolution may be less favorable to us than if we were dealing with an unaffiliated party.
 
Finally, in connection with this offering, we will enter into several agreements with Williams. These agreements will be made in the context of a parent-subsidiary relationship and will be entered into in the overall context of our separation from Williams. The terms of these agreements may be more or less favorable to us than if they had been negotiated with unaffiliated third parties. While we are controlled by Williams, Williams may seek to cause us to amend these agreements on terms that may be less favorable to us than the original terms of the agreement.
 
During the terms of the administrative services agreement and the transition services agreement, and for one year thereafter, neither we nor Williams will be permitted to solicit each other’s employees for employment without the other’s consent.


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Pursuant to the terms of our amended and restated certificate of incorporation, Williams is not required to offer corporate opportunities to us, and certain of our directors and officers are permitted to offer certain corporate opportunities to Williams before us.
 
Our amended and restated certificate of incorporation provides that, until both (1) Williams and its subsidiaries no longer beneficially own 50% or more of the voting power of all then outstanding shares of our capital stock generally entitled to vote in the election of our directors and (2) no person who is a director or officer of Williams or of a subsidiary of Williams is also a director or officer of ours:
 
  •   Williams is free to compete with us in any activity or line of business;
 
  •   we do not have any interest or expectancy in any business opportunity, transaction, or other matter in which Williams engages or seeks to engage merely because we engage in the same or similar lines of business;
 
  •   to the fullest extent permitted by law, Williams will have no duty to communicate its knowledge of, or offer, any potential business opportunity, transaction, or other matter to us, and Williams is free to pursue or acquire such business opportunity, transaction, or other matter for itself or direct the business opportunity, transaction, or other matter to its affiliates; and
 
  •   if any director or officer of Williams who is also one of our officers or directors becomes aware of a potential business opportunity, transaction, or other matter (other than one expressly offered to that director or officer in writing solely in his or her capacity as our director or officer), that director or officer will have no duty to communicate or offer that business opportunity to us, and will be permitted to communicate or offer that business opportunity to Williams (or its affiliates) and that director or officer will not, to the fullest extent permitted by law, be deemed to have (1) breached or acted in a manner inconsistent with or opposed to his or her fiduciary or other duties to us regarding the business opportunity or (2) acted in bad faith or in a manner inconsistent with the best interests of our company or our stockholders.
 
At the completion of this offering, our board of directors will include persons who are also directors and/or officers of Williams. In addition, after the completion of the spin-off of our stock to Williams’ stockholders, we expect that our board of directors will continue to include persons who are also directors and/or officers of Williams. As a result, Williams may gain the benefit of corporate opportunities that are presented to these directors.
 
Our agreements with Williams require us to assume the past, present, and future liabilities related to our business and may be less favorable to us than if they had been negotiated with unaffiliated third parties.
 
We negotiated all of our agreements with Williams as a wholly-owned subsidiary of Williams and will enter into these agreements prior to the completion of this offering. If these agreements had been negotiated with unaffiliated third parties, they might have been more favorable to us. Pursuant to the separation and distribution agreement, we have assumed all past, present and future liabilities (other than tax liabilities which will be governed by the tax sharing agreement as described herein; see “Arrangements Between Williams and Our Company—Tax Sharing Agreement”) related to our business, and we will agree to indemnify Williams for these liabilities, among other matters. Such liabilities include unknown liabilities that could be significant. The allocation of assets and liabilities between Williams and us may not reflect the allocation that would have been reached between two unaffiliated parties. See “Arrangements Between Williams and Our Company” for a description of these obligations and the allocation of liabilities between Williams and us.
 
Our agreements with Williams may limit our ability to obtain additional financing or make acquisitions.
 
We may engage, or desire to engage, in future financings or acquisitions. However, because our agreements with Williams are designed to preserve the tax-free status of the spin-off and any related restructuring transaction, we will agree to certain restrictions in those agreements that may severely limit our ability to effect future financings or acquisitions. For the spin-off of our stock to Williams’ stockholders to be tax-free to Williams and its stockholders, among other things, Williams must own at least 80% of the voting


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power of all then outstanding shares of our capital stock entitled to vote generally in the election of directors (and at least 80% of the then outstanding shares of any class of non-voting stock) at the time of the spin-off. Therefore, the tax sharing agreement and the separation and distribution agreement restrict our ability to issue or sell additional common stock or other securities (including securities convertible into our common stock) prior to the spin-off to the extent that such issuances or sales would reduce Williams’ ownership below certain threshold levels.
 
In addition, we will agree in the separation and distribution agreement that we will not (without Williams’ prior written consent) take any of the following actions prior to the spin-off:
 
  •   acquire any businesses or assets with an aggregate value of more than $           million for all such acquisitions;
 
  •   dispose of any assets with an aggregate value of more than $           million for all such dispositions; and
 
  •   acquire any equity or debt securities of any other person with an aggregate value of more than $           million for all such acquisitions.
 
The separation and distribution agreement will also provide that for so long as Williams owns 50% or more of the voting power of all then outstanding shares of our capital stock entitled to vote generally in the election of directors, we will not (without the prior written consent of Williams) take any actions that could reasonably result in Williams being in breach or in default under any contract or agreement. Also, for so long as Williams is required to consolidate our results of operations and financial position, we may not incur any additional indebtedness (other than under our Credit Facility and the issuance of the Notes) without the prior written consent of Williams.
 
Our tax sharing agreement with Williams may limit our ability to take certain actions and may require us to indemnify Williams for significant tax liabilities.
 
Under the tax sharing agreement, we will agree to take reasonable action or reasonably refrain from taking action to ensure that the spin-off of our stock to Williams’ stockholders and any related restructuring transaction qualify for tax-free status under section 355 and section 368(a)(1)(D) of the Internal Revenue Code of 1986, as amended (the “Code”) (unless Williams receives a private letter ruling from the Internal Revenue Service (“IRS”) or the IRS issues other guidance that can be relied on conclusively to the effect that a contemplated matter or transaction would not jeopardize such tax-free status of the spin-off and related restructuring transaction). We will also make various other covenants in the tax sharing agreement intended to ensure the tax-free status of the spin-off and any related restructuring transaction. These covenants may restrict our ability to sell assets outside the ordinary course of business, to issue or sell additional common stock or other securities (including securities convertible into our common stock), or to enter into any other corporate transaction that would cause us to undergo either a 50% or greater change in the ownership of our voting stock or a 50% or greater change in the ownership (measured by value) of all classes of our stock (in either case, taking into account shares issued in this offering). See “Arrangements Between Williams and Our Company—Tax Sharing Agreement” for a description of these restrictions.
 
Further, under the tax sharing agreement, we are required to indemnify Williams against certain tax-related liabilities incurred by Williams (including any of its subsidiaries) relating to the spin-off of our stock to Williams’ stockholders or relating to any related restructuring transaction undertaken by Williams, to the extent caused by our breach of any representations or covenants made in the tax sharing agreement or the separation and distribution agreement, or made in connection with the private letter ruling or tax opinion. These liabilities include the substantial tax-related liability (calculated without regard to any net operating loss or other tax attribute of Williams) that would result if the spin-off of our stock to Williams’ stockholders failed to qualify as a tax-free transaction.


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We will not have complete control over our tax decisions and could be liable for income taxes owed by Williams.
 
For so long as Williams continues to own at least 80% of the total voting power and value of our common stock, we and our U.S. subsidiaries will be included in Williams’ consolidated group for U.S. federal income tax purposes. In addition, we or one or more of our U.S. subsidiaries may be included in the combined, consolidated or unitary tax returns of Williams or one or more of its subsidiaries for U.S. state or local income tax purposes. Under the tax sharing agreement, for each period in which we or any of our subsidiaries are consolidated or combined with Williams for purposes of any tax return, Williams will prepare a pro forma tax return for us as if we filed our own consolidated, combined or unitary return, except that such pro forma tax return will only include current income, deductions, credits and losses from us (with certain exceptions), will not include any carryovers or carrybacks of losses or credits and will be calculated without regard to the federal Alternative Minimum Tax. We will reimburse Williams for any taxes shown on the pro forma tax returns, and Williams will reimburse us for any current losses or credits we recognize based on the pro forma tax returns. In addition, by virtue of Williams’ controlling ownership and the tax sharing agreement, Williams will effectively control all of our U.S. tax decisions in connection with any consolidated, combined or unitary income tax returns in which we (or any of our subsidiaries) are included. The tax sharing agreement provides that Williams will have sole authority to respond to and conduct all tax proceedings (including tax audits) relating to us, to prepare and file all consolidated, combined or unitary income tax returns on our behalf (including the making of any tax elections), and to determine the reimbursement amounts in connection with any pro forma tax returns. This arrangement may result in conflicts of interest between Williams and us. For example, under the tax sharing agreement, Williams will be able to choose to contest, compromise or settle any adjustment or deficiency proposed by the relevant taxing authority in a manner that may be beneficial to Williams and detrimental to us. See “Arrangements Between Williams and Our Company—Tax Sharing Agreement.”
 
Moreover, notwithstanding the tax sharing agreement, U.S. federal law provides that each member of a consolidated group is liable for the group’s entire tax obligation. Thus, to the extent Williams or other members of Williams’ consolidated group fail to make any U.S. federal income tax payments required by law, we could be liable for the shortfall. Similar principles may apply for foreign, state or local income tax purposes where we file combined, consolidated or unitary returns with Williams or its subsidiaries for federal, foreign, state or local income tax purposes.
 
      If, following the completion of the spin-off of our stock to Williams’ stockholders, there is a determination that the spin-off is taxable for U.S. federal income tax purposes because the facts, assumptions, representations, or undertakings underlying the IRS private letter ruling or tax opinion are incorrect or for any other reason, then Williams and its stockholders could incur significant income tax liabilities, and we could incur significant liabilities.
 
The spin-off will be conditioned upon, among other things, Williams’ receipt of a private letter ruling from the IRS and an opinion of its outside tax advisor reasonably acceptable to the Williams board of directors, to the effect that the distribution by Williams of the shares of our common stock held by Williams after the offering, and any related restructuring transaction undertaken by Williams, will qualify for U.S. federal income tax purposes as a tax-free transaction under section 355 and section 368(a)(1)(D) of the Code. The ruling and opinion will rely on certain facts, assumptions, representations and undertakings from Williams and us regarding the past and future conduct of the companies’ respective businesses and other matters. If any of these facts, assumptions, representations, or undertakings are, or become, incorrect or not otherwise satisfied, Williams and its stockholders may not be able to rely on the private letter ruling and opinion of its tax advisor and could be subject to significant tax liabilities. In addition, notwithstanding the opinion of Williams’ tax advisor, the IRS could conclude upon audit that the spin-off is taxable if it determines that any of these facts, assumptions, representations, or undertakings are, or have become, not correct or have been violated or if it disagrees with the conclusions in the opinion, or for other reasons, including as a result of certain significant changes in the stock ownership of Williams or us after the spin-off. If the spin-off is determined to be taxable for U.S. federal income tax purposes for any reason, Williams and/or its stockholders could incur significant


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income tax liabilities, and we could incur significant liabilities. For a description of the sharing of such liabilities between Williams and us, see “Arrangements Between Williams and Our Company—Tax Sharing Agreement.”
 
      Third parties may seek to hold us responsible for liabilities of Williams that we did not assume in our agreements.
 
Third parties may seek to hold us responsible for retained liabilities of Williams. Under our agreements with Williams, Williams will agree to indemnify us for claims and losses relating to these retained liabilities. However, if those liabilities are significant and we are ultimately held liable for them, we cannot assure you that we will be able to recover the full amount of our losses from Williams.
 
      Our prior and continuing relationship with Williams exposes us to risks attributable to businesses of Williams.
 
Williams is obligated to indemnify us for losses that a party may seek to impose upon us or our affiliates for liabilities relating to the business of Williams that are incurred through a breach of the separation and distribution agreement or any ancillary agreement by Williams or its affiliates other than us, or losses that are attributable to Williams in connection with this offering or are not expressly assumed by us under our agreements with Williams. Immediately following this offering, any claims made against us that are properly attributable to Williams in accordance with these arrangements would require us to exercise our rights under our agreements with Williams to obtain payment from Williams. We are exposed to the risk that, in these circumstances, Williams cannot, or will not, make the required payment.
 
      Our directors and executive officers who own shares of common stock of Williams, who hold options to acquire common stock of Williams or other Williams equity-based awards, or who hold positions with Williams, may have actual or potential conflicts of interest.
 
Ownership of shares of common stock of Williams, options to acquire shares of common stock of Williams and other equity-based securities of Williams by certain of our directors and officers after this offering, and the presence of directors or officers of Williams on our board of directors could create, or appear to create, potential conflicts of interest when those directors and officers are faced with decisions that could have different implications for Williams than they do for us. Certain of our directors will hold director and/or officer positions with Williams or beneficially own significant amounts of common stock of Williams. See “Management.”
 
In addition, initially, if our board of directors does not form a compensation committee or nominating and governance committee in connection with the completion of this offering, the Williams nominating and governance committee may make recommendations to our board of directors regarding compensation for our directors and officers, which could also create, or appear to create, similar potential conflicts of interest. See “Management” for a description of the extent of the relationship between our directors and officers and directors and officers of Williams.
 
      We will be a “controlled company” within the meaning of the NYSE rules and, as a result, will qualify for, and intend to rely on, exemptions from certain corporate governance requirements that provide protection to stockholders of other companies.
 
After the completion of this offering and prior to the spin-off of our stock to Williams’ stockholders, Williams will own more than 50% of the voting power of all then outstanding shares of our capital stock entitled to vote generally in the election of directors, and we will be a “controlled company” under the NYSE corporate governance standards. As a controlled company, we intend to rely on certain exemptions from the NYSE standards that will enable us not to comply with certain NYSE corporate governance requirements, including the requirements that:
 
  •   a majority of our board of directors consists of independent directors;


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  •   we have a nominating and governance committee that is composed entirely of independent directors, with a written charter addressing the committee’s purpose and responsibilities;
 
  •   we have a compensation committee that is composed entirely of independent directors, with a written charter addressing the committee’s purpose and responsibilities; and
 
  •   we conduct an annual performance evaluation of the nominating and governance committee and compensation committee.
 
We intend to rely on some or all of these exemptions, and, as a result, prior to the spin-off, you will not have the same protection afforded to stockholders of companies that are subject to all of the NYSE corporate governance requirements.
 
Risks Related to this Offering
 
      No market currently exists for our Class A common stock. We cannot assure you that an active trading market will develop for our Class A common stock.
 
Prior to this offering, there has been no public market for shares of our Class A common stock. We cannot predict the extent to which investor interest in our company will lead to the development of a trading market on the NYSE or otherwise, or how liquid that market might become. If an active market does not develop, you may have difficulty selling any shares of our Class A common stock that you purchase in this initial public offering. The initial public offering price for the shares of our Class A common stock has been determined by negotiations between us and the representatives of the underwriters, and may not be indicative of prices that will prevail in the open market following this offering.
 
      If our Class A stock price fluctuates after this offering, you could lose a significant part of your investment.
 
The market price of our Class A stock may be influenced by many factors, some of which are beyond our control, including those described above in “—Risks Related to Our Business” and the following:
 
  •   the failure of securities analysts to cover our Class A common stock after this offering or changes in financial estimates by analysts;
 
  •   the inability to meet the financial estimates of analysts who follow our Class A common stock;
 
  •   strategic actions by us or our competitors;
 
  •   announcements by us or our competitors of significant contracts, acquisitions, joint marketing relationships, joint ventures or capital commitments;
 
  •   variations in our quarterly operating results and those of our competitors;
 
  •   general economic and stock market conditions;
 
  •   risks related to our business and our industry, including those discussed above;
 
  •   changes in conditions or trends in our industry, markets or customers;
 
  •   terrorist acts;
 
  •   future sales of our Class A common stock or other securities; and
 
  •   investor perceptions of the investment opportunity associated with our Class A common stock relative to other investment alternatives.
 
As a result of these factors, investors in our Class A common stock may not be able to resell their shares at or above the initial offering price or may not be able to resell them at all. These broad market and industry factors may materially reduce the market price of our Class A common stock, regardless of our operating performance. In addition, price volatility may be greater if the public float and trading volume of our Class A common stock is low.


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      Future sales, or the perception of future sales, of our common stock may depress the price of our Class A common stock.
 
The market price of our Class A common stock could decline significantly as a result of sales of a large number of shares of our common stock in the market after this offering, including shares which might be offered for sale by Williams. The perception that these sales might occur could depress the market price. These sales, or the possibility that these sales may occur, also might make it more difficult for us to sell equity securities in the future at a time and at a price that we deem appropriate.
 
Upon completion of this offering, we will have           shares of Class A common stock (           shares if the underwriters exercise their option to purchase additional Class A common shares in full) and           shares of Class B common stock outstanding (           shares if the underwriters exercise their option to purchase additional Class A common shares in full). The shares of Class A common stock offered in this offering will be freely tradable without restriction under the Securities Act of 1933, as amended (the “Securities Act”), except for any shares of Class A common stock that may be held or acquired by our directors, executive officers and other affiliates, as that term is defined in the Securities Act, which will be restricted securities under the Securities Act. Restricted securities may not be sold in the public market unless the sale is registered under the Securities Act or an exemption from registration is available. We will grant registration rights to Williams with respect to the common stock it owns. Any shares registered pursuant to the registration rights agreement with Williams described in “Arrangements Between Williams and Our Company” will be freely tradable in the public market.
 
In connection with this offering, we, our directors and executive officers, Williams and its directors and executive officers have each agreed to enter into a lock-up agreement and thereby be subject to a lock-up period, meaning that they and their permitted transferees will not be permitted to sell any of the shares of our common stock for 180 days after the date of this prospectus, subject to certain extensions without the prior consent of the underwriters. Although we have been advised that there is no present intention to do so, the underwriters may, in their sole discretion and without notice, release all or any portion of the shares of our common stock from the restrictions in any of the lock-up agreements described above. See “Underwriting.”
 
Also, in the future, we may issue our securities in connection with investments or acquisitions. The amount of shares of our common stock issued in connection with an investment or acquisition could constitute a material portion of our then outstanding shares of our common stock.
 
      We will not receive any benefit and accordingly you will suffer increased dilution if the underwriters exercise their option to purchase additional Class A common shares.
 
If the underwriters exercise their option to purchase additional Class A common shares, all of our net proceeds will be distributed to Williams in connection with our restructuring transactions. Accordingly, we will receive no benefit from the issuance of any shares of our Class A common stock subject to the underwriters’ over-allotment option.
 
      Our costs may increase as a result of operating as a public company, and our management will be required to devote substantial time to complying with public company regulations.
 
We have historically operated our business as a segment of a public company. As a stand-alone public company, we may incur additional legal, accounting, compliance and other expenses that we have not incurred historically. After this offering, we will become obligated to file with the SEC annual and quarterly information and other reports that are specified in Section 13 and other sections of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). We will also be required to ensure that we have the ability to prepare financial statements that are fully compliant with all SEC reporting requirements on a timely basis. In addition, we will also become subject to other reporting and corporate governance requirements, including certain requirements of the NYSE, and certain provisions of Sarbanes-Oxley and the regulations promulgated thereunder, which will impose significant compliance obligations upon us.
 
Sarbanes-Oxley, as well as new rules subsequently implemented by the SEC and the NYSE, have imposed increased regulation and disclosure and required enhanced corporate governance practices of public companies.


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We are committed to maintaining high standards of corporate governance and public disclosure, and our efforts to comply with evolving laws, regulations and standards in this regard are likely to result in increased marketing, selling and administrative expenses and a diversion of management’s time and attention from revenue-generating activities to compliance activities. These changes will require a significant commitment of additional resources. We may not be successful in implementing these requirements and implementing them could materially adversely affect our business, results of operations and financial condition. In addition, if we fail to implement the requirements with respect to our internal accounting and audit functions, our ability to report our operating results on a timely and accurate basis could be impaired. If we do not implement such requirements in a timely manner or with adequate compliance, we might be subject to sanctions or investigation by regulatory authorities, such as the SEC or the NYSE. Any such action could harm our reputation and the confidence of investors and clients in our company and could materially adversely affect our business and cause our share price to fall.
 
      Failure to achieve and maintain effective internal controls in accordance with Section 404 of
Sarbanes-Oxley could have a material adverse effect on our business and stock price.
 
As a public company, we will be required to document and test our internal control procedures in order to satisfy the requirements of Section 404 of Sarbanes-Oxley, which will require annual management assessments of the effectiveness of our internal control over financial reporting and a report by our independent registered public accounting firm that addresses the effectiveness of internal control over financial reporting. During the course of our testing, we may identify deficiencies which we may not be able to remediate in time to meet our deadline for compliance with Section 404. Testing and maintaining internal control can divert our management’s attention from other matters that are important to the operation of our business. We also expect the new regulations to increase our legal and financial compliance costs, make it more difficult to attract and retain qualified officers and members of our board of directors, particularly to serve on our audit committee, and make some activities more difficult, time consuming and costly. We may not be able to conclude on an ongoing basis that we have effective internal control over financial reporting in accordance with Section 404 or our independent registered public accounting firm may not be able or willing to issue an unqualified report on the effectiveness of our internal control over financial reporting. If we conclude that our internal control over financial reporting is not effective, we cannot be certain as to the timing of completion of our evaluation, testing and remediation actions or their effect on our operations because there is presently no precedent available by which to measure compliance adequacy. If either we are unable to conclude that we have effective internal control over financial reporting or our independent auditors are unable to provide us with an unqualified report as required by Section 404, then investors could lose confidence in our reported financial information, which could have a negative effect on the trading price of our Class A common stock.
 
      If securities or industry analysts do not publish research or reports about our business, if they adversely change their recommendations regarding our stock or if our operating results do not meet their expectations, our stock price could decline.
 
The trading market for our Class A common stock will be influenced by the research and reports that industry or securities analysts publish about us or our business. If one or more of these analysts cease coverage of our company or fail to publish reports on us regularly, we could lose visibility in the financial markets, which in turn could cause our stock price or trading volume to decline. Moreover, if one or more of the analysts who cover our company downgrades our stock or if our operating results do not meet their expectations, our stock price could decline.
 
      Investors purchasing Class A common stock in this offering will incur substantial and immediate dilution.
 
Dilution per share represents the difference between the initial public offering price per share of our Class A common stock and the net tangible book value per share of our common stock upon the completion of this offering. The initial public offering price of our Class A common stock is substantially higher than the net tangible book value per share of our outstanding common stock. Purchasers of our common stock in this offering will incur immediate and substantial dilution of $      per share in the net tangible book value of our common stock from an assumed initial public offering price of $      per share, which is the midpoint of the estimated offering price range set forth on the cover page of this prospectus. If the underwriters exercise their


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option to purchase additional Class A common shares in full, there will be dilution of $      per share in the net tangible book value of our common stock. This means that if we were to be liquidated immediately after this offering, there might be no assets available for distribution to you after satisfaction of all our obligations to creditors. For a further description of the effects of dilution in the net tangible book value of our common stock, see “Dilution.”
 
Further, if we issue additional equity securities to raise additional capital, your ownership interest in our company may be diluted and the value of your investment may be reduced.
 
      We do not anticipate paying any dividends on our common stock in the foreseeable future. As a result, you will need to sell your shares of common stock to receive any income or realize a return on your investment.
 
We do not anticipate paying any dividends on our common stock in the foreseeable future. Any declaration and payment of future dividends to holders of our common stock may be limited by the provisions of the Delaware General Corporation Law. The future payment of dividends will be at the sole discretion of our board of directors and will depend on many factors, including our earnings, capital requirements, financial condition and other considerations that our board of directors deems relevant. As a result, to receive any income or realize a return on your investment, you will need to sell your shares of Class A common stock. You may not be able to sell your shares of Class A common stock at or above the price you paid for them.
 
      Provisions of Delaware law, our charter documents and our stockholder rights plan may delay or prevent an acquisition of us that stockholders may consider favorable or may prevent efforts by our stockholders to change our directors or our management, which could decrease the value of your shares.
 
Section 203 of the Delaware General Corporation Law and provisions in our amended and restated certificate of incorporation and amended and restated bylaws could make it more difficult for a third party to acquire us without the consent of our board of directors. See “Description of Capital Stock—Anti-Takeover Effects of Certificate of Incorporation and Bylaws Provisions.” These provisions include the following:
 
  •   restrictions on business combinations for a three-year period with a stockholder who becomes the beneficial owner of more than 15% of our common stock;
 
  •   restrictions on the ability of our stockholders to remove directors;
 
  •   supermajority voting requirements for stockholders to amend our organizational documents; and
 
  •   a classified board of directors.
 
Although we believe these provisions protect our stockholders from coercive or otherwise unfair takeover tactics and thereby provide an opportunity to receive a higher bid by requiring potential acquirers to negotiate with our board of directors, these provisions apply even if the offer may be considered beneficial by some stockholders. Further, these provisions may discourage potential acquisition proposals and may delay, deter or prevent a change of control of our company, including through unsolicited transactions that some or all of our stockholders might consider to be desirable. As a result, efforts by our stockholders to change our direction or our management may be unsuccessful.


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FORWARD-LOOKING STATEMENTS
 
Certain matters contained in this prospectus include forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. These forward-looking statements relate to anticipated financial performance, management’s plans and objectives for future operations, business prospects, outcome of regulatory proceedings, market conditions and other matters.
 
All statements, other than statements of historical facts, included in this prospectus that address activities, events or developments that we expect, believe or anticipate will exist or may occur in the future, are forward-looking statements. In some cases, forward-looking statements can be identified by various forms of words such as “anticipates,” “believes,” “seeks,” “could,” “may,” “should,” “continues,” “estimates,” “expects,” “forecasts,” “intends,” “might,” “goals,” “objectives,” “targets,” “planned,” “potential,” “projects,” “scheduled,” “will” or other similar expressions. These forward-looking statements are based on management’s beliefs and assumptions and on information currently available to management and include, among others, statements regarding:
 
  •   Amounts and nature of future capital expenditures;
 
  •   Expansion and growth of our business and operations;
 
  •   Financial condition and liquidity;
 
  •   Business strategy;
 
  •   Estimates of proved gas and oil reserves;
 
  •   Reserve potential;
 
  •   Development drilling potential;
 
  •   Cash flow from operations or results of operations;
 
  •   Seasonality of our business; and
 
  •   Natural gas, crude oil and NGLs prices and demand.
 
Forward-looking statements are based on numerous assumptions, uncertainties and risks that could cause future events or results to be materially different from those stated or implied in this prospectus. Many of the factors that will determine these results are beyond our ability to control or predict. Specific factors that could cause actual results to differ from results contemplated by the forward-looking statements include, among others, the following:
 
  •   Availability of supplies (including the uncertainties inherent in assessing, estimating, acquiring and developing future natural gas and oil reserves), market demand, volatility of prices and the availability and cost of capital;
 
  •   Inflation, interest rates, fluctuation in foreign exchange and general economic conditions (including future disruptions and volatility in the global credit markets and the impact of these events on our customers and suppliers);
 
  •   The strength and financial resources of our competitors;
 
  •   Development of alternative energy sources;
 
  •   The impact of operational and development hazards;
 
  •   Costs of, changes in, or the results of laws, government regulations (including climate change legislation and/or potential additional regulation of drilling and completion of wells), environmental liabilities, litigation and rate proceedings;
 
  •   Changes in maintenance and construction costs;
 
  •   Changes in the current geopolitical situation;


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


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USE OF PROCEEDS
 
We estimate that our net proceeds from the sale of shares of Class A common stock in this offering, after deducting estimated underwriting discounts and commissions and estimated offering expenses, will be approximately $      million ($      million if the underwriters exercise their option to purchase additional Class A common shares in full), assuming the shares are offered at $      per share of Class A common stock, which is the midpoint of the estimated offering price range set forth on the cover page of this prospectus. We expect to retain approximately $500 million of the net proceeds from this offering for general corporate purposes. As part of our restructuring transactions, the remainder of the net proceeds of this offering will be distributed to Williams.
 
Concurrently with or shortly following the completion of this offering, we expect to issue up to $1.5 billion aggregate principal amount of Notes in a private offering exempt from registration under the Securities Act. The Notes will be offered and sold solely to qualified institutional buyers pursuant to Rule 144A and in offshore transactions to persons other than U.S. persons as defined in Regulation S under the Securities Act. As part of our restructuring transactions, all of the net proceeds of the sale of the Notes will be distributed to Williams. Our offering of Class A common stock is not contingent upon the completion of our offering of the Notes.
 
Williams has informed us that it expects to use the net proceeds distributed to it from this offering and the offering of the Notes to repay a portion of its indebtedness.


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


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CAPITALIZATION
 
The following table sets forth our cash and cash equivalents and capitalization as of December 31, 2010 on an actual basis and pro forma basis to give effect to:
 
  •   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 $      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 $      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 $      billion to Williams from the combined net proceeds from this offering and the expected offering of the Notes in connection with our restructuring transactions.
 
You should read this table in conjunction with “Use of Proceeds,” “Selected Historical Combined Financial Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our historical and pro forma combined financial statements and related notes included elsewhere in this prospectus.
 
                 
    At December 31, 2010  
    Historical     Pro Forma  
    (Millions)  
 
Cash and cash equivalents
  $ 37          
Debt:
               
Senior unsecured credit facility(1)
             
Unsecured notes payable to Williams—current
    2,261          
Senior unsecured notes
             
                 
Total debt
    2,261          
Equity:
               
Owner’s net investment
    4,280          
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
             
Noncontrolling interests
    72          
Accumulated other comprehensive income
    168            
                 
Total equity
    4,520          
                 
Total capitalization
  $ 6,781          
                 
 
 
(1) Our Credit Facility is expected to provide for borrowings of up to $1.5 billion, all of which is expected to be available to us at the closing of that facility. Our future borrowing capacity may be reduced by letters of credit issued under the Credit Facility. See “Description of our Concurrent Financing Transactions—Credit Facility.”


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DILUTION
 
If you invest in our Class A common stock, your ownership interest will be diluted to the extent of the difference between the initial public offering price per share of our Class A common stock and the net tangible book value per share of our common stock upon the completion of this offering.
 
Our net tangible book value represents the amount of our total tangible assets less total liabilities. As of December 31, 2010, after giving effect to our restructuring transactions, our pro forma net tangible book value was approximately $      million, or approximately $      per share based on           shares of our Class B common stock outstanding immediately prior to the completion of this offering. After giving effect to the sale of our shares of Class A common stock at the initial public offering price per share, and after deducting estimated underwriting discounts and commissions and estimated offering expenses payable by us, our pro forma net tangible book value as of December 31, 2010, which we refer to as our pro forma net tangible book value, would have been approximately $      million, or $      per share of our common stock. This represents an immediate dilution of $      per share to new investors purchasing shares of our Class A common stock in this offering.
 
                 
Assumed initial public offering price per share
              $        
Pro forma net tangible book value per share as of December 31, 2010 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
          $    
                 
 
The foregoing discussion does not give effect to shares of Class A common stock that we will issue if the underwriters exercise their option to purchase additional shares.
 
The following table summarizes the total number of shares of our common stock on an aggregate basis purchased from us, the total consideration paid and the average price per share paid. The calculations regarding shares purchased by new investors in this offering reflect an assumed initial public offering price of $      per share, which is the midpoint of the estimated offering price range set forth on the cover page of this prospectus, and do not reflect the estimated underwriting discount and offering expenses.
 
                                                 
                Percentage
                Average
 
    Shares Purchased     of Voting
    Total Consideration     Price Per
 
    Number     Percent     Rights     Amount     Percent     Share  
 
Williams
             %     %   $                   %   $        
New investors in this offering
                                               
                                                 
Total
            100 %     100 %   $         100 %   $    
                                                 
 
If the underwriters exercise their option to purchase additional Class A common shares in full, the following will occur:
 
  •   the number of shares of Class A common stock held by new investors will increase to          , or approximately     % of our total outstanding common stock and approximately     % of the total voting power of our common stock; and
 
  •   the number of shares of our Class B common stock held by Williams will be reduced to          , or approximately     % of our total outstanding common stock and approximately     % of the total voting power of our common stock.


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SELECTED HISTORICAL COMBINED FINANCIAL DATA
 
The following tables set forth our selected historical combined financial data for the periods indicated below. Our selected historical combined financial data as of December 31, 2010 and 2009 and for the fiscal years ended December 31, 2010, 2009 and 2008 have been derived from our audited historical combined financial statements included elsewhere in this prospectus. Our selected historical combined financial data as of December 31, 2008, 2007 and 2006 and for the years ended December 31, 2007 and 2006 have been derived from our unaudited accounting records not included in this prospectus.
 
The financial statements included in this prospectus may not necessarily reflect our financial position, results of operations and cash flows as if we had operated as a stand-alone public company during all periods presented. Accordingly, our historical results should not be relied upon as an indicator of our future performance.
 
The following selected historical financial and operating data should be read in conjunction with “Use of Proceeds,” “Capitalization,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Arrangements Between Williams and Our Company” and our combined financial statements and related notes included elsewhere in this prospectus.
 
                                         
    Year Ended December 31,  
    2010     2009     2008     2007     2006  
    (Millions)  
 
Statement of operations data:
                                       
Revenues
  $ 4,053     $ 3,700     $ 6,226     $ 4,521     $ 4,671  
Income (loss) from continuing operations(1)
    (1,276 )     149       726       191       108  
Income (loss) from discontinued operations(2)
    (3 )     (3 )     10       147       2  
                                         
Net income (loss)
    (1,279 )     146       736       338       110  
Less: Net income attributable to noncontrolling interests
    8       6       8       11       12  
                                         
Net income (loss) attributable to WPX Energy
  $ (1,287 )   $ 140     $ 728     $ 327     $ 98  
                                         
Balance sheet data (end of period):
                                       
Notes payable to Williams — current
  $ 2,261     $ 1,216     $ 925     $ 656     $  
Notes receivable from Williams
                            64  
Third party debt
                            34  
Total assets
    9,847       10,555       11,627       10,571       11,223  
Total equity
    4,520       5,420       5,515       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 $148 million of impairment charges related to producing properties in the Arkoma Basin offset by a $148 million gain related to the sale of a right to an international production payment. See Notes 4 and 12 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 relates to Williams’ former power business that was substantially disposed of in 2007. The activity in 2010, 2009 and 2008 primarily relates to remaining indemnity and other obligations related to the former power business. Activity in 2007 and 2006 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.


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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
 
We are currently a wholly owned subsidiary of The Williams Companies, Inc. and were formed in April 2011 to hold the exploration and production businesses of Williams. We will have no material assets or liabilities as a separate corporate entity until the contribution to us by Williams of the businesses described in this prospectus. Williams conducts our businesses through various subsidiaries. This prospectus, including the combined financial statements and the following discussion, describes us and our financial condition and operations as if we had held the subsidiaries that will be transferred to us prior to completion of this offering for all historical periods presented. The following discussion should be read in conjunction with the selected historical combined financial data and the combined financial statements and the related notes included elsewhere in this prospectus. The matters discussed below may contain forward-looking statements that reflect our plans, estimates and beliefs. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to these differences include, but are not limited to, those discussed below and elsewhere in this prospectus, particularly in “Risk Factors” and “Forward-Looking Statements.”
 
We are an independent natural gas and oil exploration and production company engaged in the exploitation and development of long-life unconventional properties. We are focused on profitably exploiting our significant natural gas reserve base and related NGLs in the Piceance Basin of the Rocky Mountain region, and on developing and growing our position in the Bakken Shale oil play in North Dakota and our Marcellus Shale natural gas position in Pennsylvania. Our other areas of domestic operations include the Powder River Basin in Wyoming and the San Juan Basin in the southwestern United States. In addition, we own a 69 percent controlling ownership interest in Apco, which holds oil and gas concessions in Argentina and Colombia and trades on the NASDAQ Capital Market under the symbol “APAGF.”
 
In addition to our exploration and development activities, we engage in natural gas sales and marketing. Our sales and marketing activities to date include the sale of our natural gas and oil production, in addition to third party purchases and sales of natural gas, including sales to Williams Partners L.P. (NYSE: “WPZ”) (“Williams Partners”) for use in its midstream business. Following the completion of the spin-off of our stock to Williams’ stockholders, we do not expect to continue to provide these services to Williams Partners on a long-term basis. Our sales and marketing activities currently include the management of various natural gas related contracts such as transportation, storage and related hedges. We also sell natural gas purchased from working interest owners in operated wells and other area third party producers. We primarily engage in these activities to enhance the value received from the sale of our natural gas and oil production. Revenues associated with the sale of our production are recorded in oil and gas revenues. The revenues and expenses related to other marketing activities are reported on a gross basis as part of gas management revenues and costs and expenses.
 
Basis of Presentation
 
The combined financial statements included elsewhere in this prospectus have been derived from the accounting records of Williams, principally representing the Exploration and Production segment. We have used the historical results of operations, and historical basis of assets and liabilities of the subsidiaries we will own and operate after the consummation of this offering, to prepare the combined financial statements. The following discussion and analysis of results of operations, financial condition and liquidity and critical accounting estimates relates to our current continuing operations and should be read in conjunction with the combined financial statements and notes thereto included in this prospectus.
 
The Combined Statement of Operations included elsewhere in this prospectus includes allocations of costs for corporate functions historically provided to us by Williams. These allocations include the following costs:
 
Corporate Services.  Represents costs for certain employees of Williams who provide general and administrative services on our behalf. These charges are either directly identifiable or allocated based upon usage factors for our operations. In addition, we receive other allocated costs for our share of general corporate expenses of Williams, which are determined based on our relative use of the service or on a three-factor


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formula, which considers revenue, properties and equipment and payroll. All of these costs are reflected in general and administrative expense in the Combined Statement of Operations.
 
Employee Benefits and Incentives.  Represents benefit costs and other incentives, including group health and welfare benefits, pension plans, postretirement benefit plans and employee stock-based compensation plans. Costs associated with incentive and stock-based compensation plans are determined on a specific identification basis for certain direct employees. All other employee benefit costs have historically been allocated using a percentage factor derived from a ratio of benefit costs to salary costs for Williams’ domestic employees. These costs are included in lease and facility operating expenses and general and administrative expenses in the Combined Statement of Operations.
 
Subsequent to the completion of this offering, we will be charged for costs related to these corporate services and employee benefits and incentives under an administrative services agreement using methodologies that are consistent with these historic accounting practices.
 
Interest Expense.  Williams utilizes a centralized approach to cash management and the financing of its businesses. Cash receipts and cash expenditures for costs and expenses from our domestic operations are transferred to or from Williams on a regular basis and recorded as increases or decreases in the balance due under unsecured promissory notes we have in place with Williams. The notes bear interest based on Williams’ weighted average cost of debt and such interest is added monthly to the note principal. Prior to or concurrent with the contribution to us by Williams of the businesses described in this prospectus, Williams will forgive or contribute to our capital any amounts due to it under these notes. Subsequent to the completion of this offering, we will maintain separate cash accounts from Williams and our interest expense will relate only to our borrowings (which will consist of the Notes and any amounts drawn under our Credit Facility).
 
Our management believes the assumptions and methodologies underlying the allocation of expenses from Williams are reasonable. However, such expenses may not be indicative of the actual level of expense that would have been or will be incurred by us if we were to operate as an independent, publicly traded company. We will enter into an administrative services agreement and a transition services agreement with Williams that will provide for continuation for some of these services in exchange for fees specified in these agreements. See “Arrangements Between Williams and Our Company.”
 
We believe the assumptions underlying the combined financial statements are reasonable. However, the combined financial statements may not necessarily reflect our future results of operations, financial position and cash flows or what these items would have been had we been a stand-alone company during the periods presented.
 
Overview of 2010
 
The effects of the severe economic recession during late 2008 and 2009 eased during 2010. Crude oil and NGL prices have returned to attractive levels, but natural gas prices have remained low. Forward natural gas prices declined during 2010, primarily as a result of significant increases in near- and long-term supplies, which have outpaced near-term demand growth. The decline in forward natural gas prices contributed significantly to impairments we recorded in 2010.
 
In December 2010, we acquired a company that held approximately 85,800 net acres in North Dakota’s Bakken Shale oil play for cash consideration of approximately $949 million. This acquisition diversified our interests into light, sweet crude oil production.
 
In July 2010, we acquired additional leasehold acreage positions in the Marcellus Shale and a five percent overriding royalty interest associated with these acreage positions for cash consideration of $599 million. These acquisitions nearly doubled our net acreage holdings in the Marcellus Shale. During 2010, we also invested a total of $164 million to acquire additional unproved leasehold acreage positions in the Marcellus Shale.
 
In November 2010, we completed the sale of certain gathering and processing assets in the Piceance Basin to Williams Partners for consideration of $702 million in cash and approximately 1.8 million Williams


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Partners common units. Because the Williams Partners common units received by us in this transaction were intended to be (and have since been) distributed through a dividend to Williams, these units have been presented net within equity. In conjunction with this sale, we entered into a gathering and processing agreement with Williams Partners. Prior periods reflect our gathering and processing costs at an internal cost-of-service rate. Our gathering, processing and transportation costs increased as a result of our new agreement with Williams Partners.
 
Our 2010 operating income (loss) changed unfavorably by $1.7 billion compared to 2009. Operating income (loss) for 2010 includes a $1 billion full impairment charge related to goodwill and $678 million of pre-tax charges associated with impairments of certain producing properties and costs of acquired unproved reserves, while 2009 included an expense of $32 million associated with contractual penalties from the early termination of drilling rig contracts. Partially offsetting these costs is the impact of an improved energy commodity price environment in 2010 compared to 2009. Highlights of the comparative periods, primarily related to our production activities, include:
 
                         
    Years Ended December 31,  
    2010     2009     % Change  
 
Average daily domestic production (MMcfe/d)
    1,132       1,182       (4) %
Average daily total production (MMcfe/d)
    1,185       1,236       (4) %
Domestic production realized average price ($/Mcfe)(1)
  $ 5.21     $ 4.88       7 %
Capital expenditures and acquisitions ($ millions)
  $ 2,805     $ 1,434       96 %
Domestic oil and gas revenues ($ millions)
  $ 2,154     $ 2,105       2 %
Revenues ($ millions)
  $ 4,053     $ 3,700       10 %
Operating income (loss) ($ millions)
  $ (1,340 )   $ 318       NM  
 
 
(1) Realized average prices include market prices, net of fuel and shrink and hedge gains and losses. The realized hedge gain per Mcfe was $0.81 and $1.43 for 2010 and 2009, respectively.
 
NM: A percentage calculation is not meaningful due to a change in signs.
 
As a result of significant declines in forward natural gas prices during third quarter 2010, we performed an interim assessment of our capitalized costs related to property and goodwill. As a result of these assessments, we recorded a $503 million impairment charge related to the capitalized costs of our Barnett Shale properties and a $175 million impairment charge related to capitalized costs of acquired unproved reserves in the Piceance Highlands, which were acquired in 2008. Additionally, we fully impaired our goodwill in the amount of $1 billion. These impairments were based on our assessment of estimated future discounted cash flows and other information. See Notes 4 and 12 of Notes to Combined Financial Statements for a further discussion of the impairments.
 
Outlook for 2011
 
We believe we are well positioned to execute our business strategy of finding and developing reserves and producing natural gas and oil at costs that generate an attractive rate of return on our investments. Economic and commodity price indicators for 2011 and beyond reflect improvement in the macroeconomic environment. However, given the potential volatility of these measures, it is possible that commodity prices could decline, negatively impacting future operating results and increasing the risk of nonperformance of counterparties or impairments of long-lived assets.
 
We believe that our portfolio of reserves provides an opportunity to continue to grow in our strategic areas, including the Piceance Basin, the Marcellus Shale and the Bakken Shale. We are also focused on developing a more balanced portfolio that may include a larger portion of oil and NGLs reserves and production than we have historically maintained, which we believe will generate long-term, sustainable value for shareholders. Currently, we expect 2011 capital expenditures of approximately $1.3 to $1.6 billion.


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We continue to operate with a focus on increasing shareholder value and investing in our businesses in a way that enhances our competitive position by:
 
  •   Continuing to invest in and grow our production and reserves;
 
  •   Retaining the flexibility to make adjustments to our planned levels of capital and investment expenditures in response to changes in economic conditions or business opportunities;
 
  •   Continuing to diversify our commodity portfolio through the development of our Bakken Shale oil play position and liquids-rich basins with high concentrations of NGLs;
 
  •   Maintaining our industry leadership position in relationship to costs; and
 
  •   Continuing to maintain an active hedging program around our commodity price risks.
 
Potential risks or obstacles that could impact the execution of our plan include:
 
  •   Lower than anticipated energy commodity prices;
 
  •   Lower than expected levels of cash flow from operations;
 
  •   Unavailability of capital;
 
  •   Counterparty credit and performance risk;
 
  •   Decreased drilling success;
 
  •   General economic, financial markets or industry downturn;
 
  •   Changes in the political and regulatory environments; and
 
  •   Increase in the cost of, or shortages or delays in the availability of, drilling rigs and equipment, supplies, skilled labor or transportation.
 
We continue to address certain of these risks through utilization of commodity hedging strategies, disciplined investment strategies and maintaining adequate liquidity. In addition, we utilize master netting agreements and collateral requirements with our counterparties to reduce credit risk and liquidity requirements.
 
Commodity Price Risk Management
 
To manage the commodity price risk and volatility of owning producing gas and oil properties, we enter into derivative contracts for a portion of our future production. For 2011, we have the following contracts for our daily domestic production, shown at weighted average volumes and basin-level weighted average prices:
 
             
    2011 Natural Gas
          Weighted Average
          Price ($/MMBtu)
    Volume
    Floor-Ceiling
    (MMBtu/d)     for Collars
 
Collar agreements — Rockies
    45     $5.30 - $7.10
Collar agreements — San Juan
    90     $5.27 - $7.06
Collar agreements — Mid-Continent
    80     $5.10 - $7.00
Collar agreements — Southern California
    30     $5.83 - $7.56
Collar agreements — Appalachia
    30     $6.50 - $8.14
Fixed price at basin swaps
    368     $5.21
 
                 
    2011 Crude Oil  
    Volume
    Weighted Average
 
    (Bbls/d)     Price ($/Bbl)  
 
WTI Crude Oil fixed-price (entered into first-quarter 2011)
    3,623     $ 95.88  


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The following is a summary of our agreements and contracts for daily domestic production shown at weighted average volumes and basin-level weighted average prices for the years ended December 31, 2010, 2009 and 2008:
 
                                     
    2010   2009   2008
          Weighted Average
        Weighted Average
        Weighted Average
          Price ($/MMBtu)
        Price ($/MMBtu)
        Price ($/MMBtu)
    Volume
    Floor-Ceiling
  Volume
    Floor-Ceiling
  Volume
    Floor-Ceiling
    (MMBtu/d)     for Collars   (MMBtu/d)     for Collars   (MMBtu/d)     for Collars
 
Collars — Rockies
    100     $6.53 - $8.94     150     $6.11 - $9.04     170     $6.16 - $9.14
Collars — San Juan
    233     $5.75 - $7.82     245     $6.58 - $9.62     202     $6.35 - $8.96
Collars — Mid-Continent
    105     $5.37 - $7.41     95     $7.08 - $9.73     63     $7.02 - $9.72
Collars — Southern California
    45     $4.80 - $6.43                
Collars — Other
    28     $5.63 - $6.87                
NYMEX and basis fixed-price
    120     $4.40     106     $3.67     70     $3.97
 
Additionally, we utilize contracted pipeline capacity to move our production from the Rockies to other locations when pricing differentials are favorable to Rockies pricing. We hold a long-term obligation to deliver on a firm basis 200,000 MMbtu/d of natural gas at monthly index pricing to a buyer at the White River Hub (Greasewood-Meeker, CO), which is a major market hub exiting the Piceance Basin. Our interests in the Piceance Basin hold sufficient reserves to meet this obligation, which expires in 2014.


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Results of Operations
 
The following table and discussion summarize our combined results of operations for the years ended December 31, 2010, 2009 and 2008.
 
Year-Over-Year Results of Operations
 
                                         
    Historical
 
    Year Ended December 31,  
    2010           2009           2008  
    (Millions)  
          % Change
          % Change
       
          from 2009           from 2008        
 
Revenues:
                                       
Oil and gas sales, including affiliate
  $ 2,243       3 %   $ 2,183       (25 %)   $ 2,917  
Gas management, including affiliate
    1,742       20 %     1,456       (55 %)     3,244  
Hedge ineffectiveness and mark-to-market gains and losses
    27       50 %     18       (38 %)     29  
Other
    41       (5 %)     43       19 %     36  
                                         
Total revenues
  $ 4,053             $ 3,700             $ 6,226  
                                         
Costs and expenses:
                                       
Lease and facility operating, including affiliate
  $ 295       8 %   $ 273       (4 %)   $ 284  
Gathering, processing and transportation, including affiliate
    324       20 %     270       20 %     225  
Taxes other than income
    125       33 %     94       (63 %)     255  
Gas management (including charges for unutilized pipeline capacity)
    1,774       19 %     1,496       (54 %)     3,248  
Exploration
    76       36 %     56       47 %     38  
Depreciation, depletion and amortization
    881       (1 %)     894       18 %     758  
Impairment of producing properties and costs of acquired unproved reserves
    678       NM       15       NM       148  
Goodwill impairment
    1,003       NM             NM        
General and administrative, including affiliate
    252       0 %     251       (1 %)     253  
Gain on sale of contractual right to international production payment
          NM             NM       (148 )
Other — net
    (15 )     NM       33       NM       7  
                                         
Total costs and expenses
  $ 5,393             $ 3,382             $ 5,068  
                                         
Operating income (loss)
  $ (1,340 )           $ 318             $ 1,158  
Interest expense, including affiliate
    (124 )     24 %     (100 )     35 %     (74 )
Interest capitalized
    16       (11 %)     18       (10 %)     20  
Investment income and other
    21       200 %     7       (68 %)     22  
                                         
Income (loss) before income taxes
  $ (1,427 )           $ 243             $ 1,126  
Provision (benefit) for income taxes
    (151 )     NM       94       (77 %)     400  
                                         
Income (loss) from continuing operations
  $ (1,276 )           $ 149             $ 726  
Income (loss) from discontinued operations
    (3 )             (3 )             10  
                                         
Net income (loss)
  $ (1,279 )           $ 146             $ 736  
Less: Net income attributable to noncontrolling interests
    8       33 %     6       (25 %)     8  
                                         
Net income (loss) attributable to WPX Energy
  $ (1,287 )           $ 140             $ 728  
                                         
 
 
NM: A percentage calculation is not meaningful due to a change in signs, a zero-value denominator or a percentage change greater than 200.


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2010 vs. 2009
 
The increase in total revenues is primarily due to the following:
 
  •   $60 million higher oil and gas sales revenues from an increase of $139 million resulting from a 7 percent increase in domestic realized average prices including the effect of hedges, partially offset by a decrease of $90 million associated with a four percent decrease in domestic production volumes sold. Oil and gas revenues in 2010 and 2009 include approximately $202 million and $93 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 $278 million in related costs and expenses.
 
The increase in costs and expenses is primarily due to the following:
 
  •   $22 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 $0.67 per Mcfe in 2010 and $0.60 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;
 
  •   $54 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 $0.78 per Mcfe in 2010 and $0.63 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;
 
  •   $31 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 $0.26 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;
 
  •   $278 million increase in gas management expenses, primarily due to a 19 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;
 
  •   $20 million higher exploration expense primarily due to an increase in impairment, amortization and expiration of unproved leasehold costs; and
 
  •   $1,681 million impairments of property and goodwill in 2010 as previously discussed. In 2009, $15 million of impairments were recorded in the Barnett Shale.
 
Partially offsetting the increased costs and expenses in 2010 are decreases due to the following:
 
  •   $13 million lower depreciation, depletion and amortization expenses primarily due to lower domestic production volumes; and
 
  •   Other — net includes $32 million of expenses in 2009 related to penalties from the early release of drilling rigs.
 
The $1,658 million decrease in operating income (loss) is primarily due to the impairments, partially offset by a seven percent increase in domestic realized average prices on production and the other previously discussed changes in revenues and costs and expenses.


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Interest expense increased primarily due to higher average amounts outstanding under our unsecured notes payable to Williams.
 
Provision (benefit) for income taxes changed favorably due to the pre-tax loss in 2010 compared to pre-tax income in 2009. See Note 8 of Notes to Combined Financial Statements for a reconciliation of the effective tax rates compared to the federal statutory rate for both years.
 
2009 vs. 2008
 
The decrease in total revenues is primarily due to the following:
 
  •   $734 million lower oil and gas sales revenues primarily from a $961 million decrease resulting from a 31 percent decrease in domestic realized average prices, partially offset by an increase of $221 million associated with an eight percent increase in domestic production volumes sold. Oil and gas revenues in 2009 and 2008 include approximately $93 million and $85 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;
 
  •   $1,788 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 $1,752 million in related costs and expenses; and
 
  •   $11 million lower hedge ineffectiveness and mark-to-market gains and losses primarily due to the absence of a $10 million favorable impact in 2008 for the initial consideration of our own nonperformance risk in estimating the fair value of our derivative liabilities.
 
The decrease in total costs and expenses is primarily due to the following:
 
  •   $161 million lower taxes other than income, including severance and ad valorem, primarily due to 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;
 
  •   $1,752 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
 
  •   The absence in 2009 of $148 million of property impairments recorded in 2008 in the Arkoma Basin.
 
Partially offsetting the decreased costs and expenses are increases due to the following:
 
  •   $45 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 $0.63 per Mcfe in 2009 and $0.56 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
 
  •   $18 million higher exploration expense primarily due to an increase in geologic and geophysical services.


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  •   $136 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 quarter of 2009 primarily due to new SEC reserves reporting rules. Our proved reserves decreased primarily due to the new SEC reserves reporting rules and the related price impact;
 
  •   The absence in 2009 of a $148 million gain recorded in 2008 from the sale of our contractual right to a production payment in Peru;
 
  •   $32 million of expense in 2009 related to penalties from the early release of drilling rigs as previously discussed; and
 
  •   $15 million of impairment expense in 2009 related to costs of acquired unproved reserves from our 2008 acquisition in the Barnett Shale. This impairment was based on our assessment of estimated future discounted cash flows and additional information obtained from drilling and other activities in 2009.
 
The $840 million decrease in operating income is primarily due to the 31 percent decrease in realized average domestic prices and the other previously discussed changes in revenues and costs and expenses.
 
Provision (benefit) for income taxes changed favorably primarily due to lower pre-tax income. See Note 8 of Notes to Combined Financial Statements for a reconciliation of the effective tax rates compared to the federal statutory rate for both years.
 
Management’s Discussion and Analysis of Financial Condition and Liquidity
 
Overview
 
In 2010, we continued to focus upon growth through continued disciplined investments in expanding our natural gas, oil and NGL portfolio. Examples of this growth included continued investment in our development drilling programs, as well as acquisitions that expanded our presence in the Marcellus Shale and provided our initial entry into the Bakken Shale areas. These investments were funded through cash flow from operations, advances on our notes payable from Williams and the proceeds from the sale of our Piceance Basin gathering and processing assets to Williams Partners.
 
Our historical liquidity needs have been managed through an internal cash management program with Williams. Daily cash activity from our domestic operations was transferred to or from Williams on a regular basis and were recorded as increases or decreases in the balance due under unsecured promissory notes we have in place with Williams. In consideration of our liquidity under these conditions, we note the following:
 
  •   As of December 31, 2010, Williams maintained liquidity through cash, cash equivalents and available credit capacity under credit facilities. Additionally, at that date we had an unsecured credit agreement that served to reduce our margin requirements related to our hedging activities. See additional discussion in the following “—Liquidity” section.
 
  •   Our credit exposure to derivative counterparties is partially mitigated by master netting agreements and collateral support.
 
  •   Apco’s liquidity requirements have historically been provided by its cash flows from operations.
 
Outlook
 
Upon completion of this offering, we expect our capital structure will provide us financial flexibility to meet our requirements for working capital, capital expenditures and tax and debt payments while maintaining a sufficient level of liquidity. We intend to retain approximately $500 million of the net proceeds from this offering and to distribute the remaining net proceeds, along with all of the net proceeds from the offering of the Notes, to Williams. We also expect to have access to a new unsecured $1.5 billion Credit Facility that is planned to be in place at the time this offering is complete. This Credit Facility combined with the


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$500 million in cash described above and our expected cash flows from operations should be sufficient to allow us to pursue our business strategy and accomplish our goals for 2011.
 
If energy commodity prices are lower than we expect for 2011, we believe the effect on our cash flows from operations would be partially mitigated by our hedging program. In addition, we note the following assumptions for 2011:
 
  •   Our capital expenditures are estimated to be between $1.3 billion and $1.6 billion, and are generally considered to be largely discretionary; and
 
  •   Apco’s liquidity requirements will continue to be provided from its cash flows from operations and available liquidity under its credit facility.
 
Potential risks associated with our planned levels of liquidity and the planned capital and investment expenditures discussed above include:
 
  •   Sustained reductions in energy commodity prices from the range of current expectations;
 
  •   Lower than expected levels of cash flow from operations; and
 
  •   Higher than expected collateral obligations that may be required, including those required under new commercial agreements.
 
Liquidity
 
We plan to conservatively manage our balance sheet. Subsequent to this offering, we expect to maintain liquidity through a combination of cash on hand and available capacity under our $1.5 billion Credit Facility. In addition, we expect our forecasted levels of cash flow from operations to provide additional liquidity to assist us in meeting our desired level of capital expenditures and working capital requirements. Additional sources of liquidity, if needed, could be sought through bank financings, the issuance of long term debt and equity securities and proceeds from asset sales.
 
Currently we utilize an unsecured credit arrangement in order to reduce margin requirements related to our hedging activities as well as lower transaction fees. We expect that this facility will be terminated concurrently with the completion of this offering and the expected issuance of our Notes and closing of our Credit Facility. Upon termination, we expect we will be able to negotiate agreements with the respective counterparties to our hedging contracts and keep margin requirements, if any, to a minimum.
 
We have certain contractual obligations, primarily interstate transportation agreements, which contain collateral support requirements based on our credit ratings. Because Williams has an investment grade credit rating and guaranteed these contracts, we have not historically been required to provide collateral support. After the completion of this offering, Williams has informed us that it expects it will obtain releases of the guarantees. Depending on our credit rating, we may be required to issue letters of credit under our Credit Facility to satisfy the provisions of these contracts.
 
Our ability to borrow money will be impacted by several factors, including our credit ratings. Credit ratings agencies perform independent analysis when assigning credit ratings. A lower than anticipated initial credit rating or a downgrade of that rating would increase our future cost of borrowing and could result in a requirement that we post additional collateral with third parties, thereby negatively affecting our available liquidity.


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Sources (Uses) of Cash
 
                         
    Years Ended December 31,  
    2010     2009     2008  
          (Millions)        
 
Net cash provided (used) by:
                       
Operating activities
  $ 1,054     $ 1,179     $ 2,006  
Financing activities
    1,286       258       228  
Investing activities
    (2,337 )     (1,435 )     (2,252 )
                         
Increase (decrease) in cash and cash equivalents
  $ 3     $ 2     $ (18 )
                         
 
Operating activities
 
Our net cash provided by operating activities in 2010 decreased from 2009 primarily due to the payments made to reduce certain accrued liabilities affecting our operations.
 
Our net cash provided by operating activities in 2009 decreased primarily due to the lower realized energy commodity prices during 2009 when compared to 2008.
 
Financing activities
 
Our net cash provided by financing activities in 2010 increased from 2009 primarily due to higher borrowings from Williams to fund our capital expenditures, including those related to the acquisition of Marcellus Shale properties and our entry into the Bakken Shale.
 
Investing Activities
 
Our net cash used by investing activities in 2010 increased from 2009 primarily due to our capital expenditures related to the acquisition of Marcellus Shale properties and our entry into the Bakken Shale.
 
Significant expenditures include:
 
2010
 
  •   Expenditures for drilling and completion were approximately $950 million.
 
  •   Our acquisition in July 2010 of properties in the Marcellus Shale for $599 million (see “—Overview of 2010”).
 
  •   Our acquisition in December 2010 of oil and gas properties in the Bakken Shale for $949 million (see “—Overview of 2010”).
 
  •   The sale in November 2010 of certain gathering and processing assets in the Piceance Basin to Williams Partners for $702 million in cash and approximately 1.8 million Williams Partners common units, which units were subsequently distributed to Williams.
 
2009
 
  •   Expenditures for drilling and completion were approximately $1.0 billion.
 
  •   A $253 million payment for the purchase of additional properties in the Piceance Basin.
 
2008
 
  •   Expenditures for drilling and completion were approximately $1.65 billion.
 
  •   Acquisitions of certain interests in the Piceance Basin for $285 million. A third party subsequently exercised its contractual option to purchase a 49 percent interest in a portion of the acquired assets for $71 million.
 
  •   Our sale of a contractual right to a production payment in Peru for $148 million.


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Off-Balance Sheet Financing Arrangements
 
We had no guarantees of off-balance sheet debt to third parties or any other off-balance sheet arrangements at December 31, 2010.
 
Contractual Obligations
 
The table below summarizes the maturity dates of our contractual obligations at December 31, 2010, including obligations related to discontinued operations.
 
                                         
          2012 -
    2014 -
             
    2011     2013     2015     Thereafter     Total  
    (Millions)  
 
Operating leases and associated service commitments
                                       
Drilling rig commitments(1)
  $ 81     $ 20     $ 2     $     $ 103  
Other
    5       5       5       15       30  
Transportation and storage commitments
    204       408       340       635       1,587  
Natural gas purchase commitments(2)
    163       414       374       828       1,779  
Oil and gas activities(3)
    59       132       117       209       517  
Other long-term liabilities, including current portion:
                                       
Physical and financial derivatives(4)(5)
    489       1,058       870       3,634       6,051  
                                         
Total
  $ 1,001     $ 2,037     $ 1,708     $ 5,321     $ 10,067  
                                         
 
 
(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 December 31, 2010 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 $290 million as of December 31, 2010. 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 $5.4 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 December 31, 2010, 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 $2.1 billion at December 31, 2010, resulting from product sales or net positive settlements, are not reflected in these amounts. In addition, product sales may require additional purchase obligations to fulfill sales obligations that are not reflected in these amounts.
 
Effects of Inflation
 
Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy. Operating costs are influenced by both competition for specialized services and specific price changes in natural gas, oil, NGLs and other commodities. We tend to experience inflationary pressure on the cost of services and equipment as increasing oil and gas prices increase drilling activity in our areas of operation.


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Environmental
 
We are subject to the Clean Air Act (“CAA”) and to the Clean Air Act Amendments of 1990 (“1990 Amendments”), which added significantly to the existing requirements established by the CAA. Pursuant to requirements of the 1990 Amendments and EPA rules designed to mitigate the migration of ground-level ozone (“NOx”), we are planning installation of air pollution controls on existing sources at certain facilities in order to reduce NOx emissions. For many of these facilities, we are developing more cost effective and innovative compressor engine control designs.
 
In March 2008, the EPA promulgated a new, lower National Ambient Air Quality Standard (“NAAQS”) for NOx. Within two years, the EPA was expected to designate new eight-hour ozone non-attainment areas. However, in September 2009, the EPA announced it would reconsider the 2008 NAAQS for NOx to ensure that the standards were clearly grounded in science and were protective of both public health and the environment. As a result, the EPA delayed designation of new eight-hour ozone non-attainment areas under the 2008 standards until the reconsideration is complete. In January 2010, the EPA proposed to further reduce the NOx NAAQS from the March 2008 levels. The EPA must provide new ozone NAAQS by July 29, 2011. Designation of new eight-hour ozone non-attainment areas are expected to result in additional federal and state regulatory actions that will likely impact our operations and increase the cost of additions to property, plant and equipment — net on the Combined Balance Sheet. We are unable at this time to estimate the cost of additions that may be required to meet this new regulation.
 
Under the CAA, the EPA must review and if appropriate revise New Source Review Standards every eight years. EPA has agreed to a proposed consent decree to revise the leak detection and repair requirements for oil and gas facilities. Under the consent agreement, EPA must finalize those rules by November 2011.
 
Additionally, in August 2010, the EPA promulgated National Emission Standards for Hazardous Air Pollutants (“NESHAP”) regulations that will impact our operations. Furthermore, the EPA promulgated the Greenhouse Gas (“GHG”) Mandatory Reporting Rule on October 30, 2009, which requires facilities that emit 25,000 metric tons or more of carbon dioxide equivalent per year from stationary fossil fuel combustion sources to report GHG emissions to the EPA annually beginning September 30, 2011 for calendar year 2010. On November 30, 2010, the EPA issued additional regulations that expand the scope of the Mandatory Reporting Rule to include fugitive and vented greenhouse gas emissions effective January 1, 2011. Facilities that emit 25,000 metric tons or more carbon dioxide equivalent per year from stationary fossil-fuel combustion and fugitive/vented sources combined will be required to report GHG combustion and fugitive/vented emissions to the EPA annually beginning March 31, 2012, for calendar year 2011.
 
In February 2010, the EPA promulgated a final rule establishing a new one-hour nitrogen dioxide NAAQS. The effective date of the new nitrogen dioxide standard was April 12, 2010. This new standard is subject to numerous challenges in the federal court. We are unable at this time to estimate the cost of additions that may be required to meet this new regulation.
 
Our facilities and operations are also subject to the Clean Water Act (“CWA”) and implementing regulations of the EPA and the U.S. Army Corps of Engineers (“Corps”). In December 2010, the EPA and the Corps submitted new guidelines governing federal jurisdiction over wetlands and other “isolated waters” to Office of Management and Budget for review. They would, if adopted, significantly expand federal jurisdiction and permitting requirements under the CWA. Additionally, the draft guidance addresses the expanded scope of the CWA’s key term “waters of the United States” to all CWA provisions, which prior guidance limited to Section 404 determinations. We are unable at this time to estimate the cost that may be required to meet this proposed guidance.
 
Quantitative and Qualitative Disclosures About Market Risk
 
Interest Rate Risk
 
Historically, our current interest rate risk exposure was substantially mitigated through our cash management program and the effects of our intercompany note with Williams. The Notes will be fixed rate debt in order to mitigate the impact of fluctuations in interest rates and we expect that any borrowings under


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our Credit Facility could be at a variable interest rate and could expose us to the risk of increasing interest rates. See Note 2 of Notes to Combined Financial Statements.
 
Commodity Price Risk
 
We are exposed to the impact of fluctuations in the market price of natural gas, NGLs and crude oil, as well as other market factors, such as market volatility and energy commodity price correlations. We are exposed to these risks in connection with our owned energy-related assets, our long-term energy-related contracts and our proprietary trading activities. We manage the risks associated with these market fluctuations using various derivatives and nonderivative energy-related contracts. The fair value of derivative contracts is subject to many factors, including changes in energy commodity market prices, the liquidity and volatility of the markets in which the contracts are transacted and changes in interest rates. See Note 13 of Notes to Combined Financial Statements.
 
We measure the risk in our portfolios using a value-at-risk methodology to estimate the potential one-day loss from adverse changes in the fair value of the portfolios. Value at risk requires a number of key assumptions and is not necessarily representative of actual losses in fair value that could be incurred from the portfolios. Our value-at-risk model uses a Monte Carlo method to simulate hypothetical movements in future market prices and assumes that, as a result of changes in commodity prices, there is a 95 percent probability that the one-day loss in fair value of the portfolios will not exceed the value at risk. The simulation method uses historical correlations and market forward prices and volatilities. In applying the value-at-risk methodology, we do not consider that the simulated hypothetical movements affect the positions or would cause any potential liquidity issues, nor do we consider that changing the portfolios in response to market conditions could affect market prices and could take longer than a one-day holding period to execute. While a one-day holding period has historically been the industry standard, a longer holding period could more accurately represent the true market risk given market liquidity and our own credit and liquidity constraints.
 
We segregate our derivative contracts into trading and nontrading contracts, as defined in the following paragraphs. We calculate value at risk separately for these two categories. Contracts designated as normal purchases or sales and nonderivative energy contracts have been excluded from our estimation of value at risk.
 
Trading
 
We have policies and procedures that govern our trading and risk management activities. These policies cover authority and delegation thereof in addition to control requirements, authorized commodities and term and exposure limitations. Value-at-risk is limited in aggregate and calculated at a 95 percent confidence level.
 
Our trading portfolio consists of derivative contracts entered into for purposes other than economically hedging our commodity price-risk exposure. The fair value of our trading derivatives was a net asset of $2 million at December 31, 2010. The value at risk for contracts held for trading purposes was less than $1 million at December 31, 2010 and December 31, 2009.
 
Nontrading
 
Our nontrading portfolio consists of derivative contracts that hedge or could potentially hedge the price risk exposure from our natural gas purchases and sales. The fair value of our derivatives not designated as hedging instruments was a net asset of $16 million at December 31, 2010.
 
The value at risk for derivative contracts held for nontrading purposes was $24 million at December 31, 2010, and $34 million at December 31, 2009. During the year ended December 31, 2010, our value at risk for these contracts ranged from a high of $33 million to a low of $21 million. The decrease in value at risk primarily reflects the realization of certain derivative positions and the market price impact, partially offset by new derivative contracts.
 
Certain of the derivative contracts held for nontrading purposes are accounted for as cash flow hedges. Of the total fair value of nontrading derivatives, cash flow hedges had a net asset value of $266 million as of December 31, 2010. Though these contracts are included in our value-at-risk calculation, any changes in the


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fair value of the effective portion of these hedge contracts would generally not be reflected in earnings until the associated hedged item affects earnings.
 
Critical Accounting Estimates
 
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates, judgments and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. We believe that the nature of these estimates and assumptions is material due to the subjectivity and judgment necessary, or the susceptibility of such matters to change, and the impact of these on our financial condition or results of operations.
 
In our management’s opinion, the more significant reporting areas impacted by management’s judgments and estimates are impairments of goodwill and long-lived assets, accounting for derivative instruments and hedging activities, successful efforts method of accounting, contingent liabilities, valuation of deferred tax assets and tax contingencies.
 
Impairments of Goodwill and Long-Lived Assets
 
We have assessed goodwill for impairment annually as of the end of the year and we have performed interim assessments of goodwill if impairment triggering events or circumstances were present. One such triggering event is a significant decline in forward natural gas prices. Early in 2010, we evaluated the impact of declines in forward gas prices across all future production periods and determined that the impact was not significant enough to warrant a full impairment review. Forward natural gas prices through 2025 used in these prior analyses had declined less than 10 percent, on average, from December 31, 2009 through March 31, 2010 and June 30, 2010. During the third quarter of 2010, these forward natural gas prices through 2025 declined an additional 19 percent for a total year-to-date decline of more than 22 percent on average through September 30, 2010. Based on forward prices as of September 30, 2010, we evaluated the impact of this decline across all future production periods and determined that a full impairment review was warranted.
 
As a result, we evaluated our goodwill of approximately $1 billion resulting from a 2001 acquisition related to our domestic natural gas production operations (the “reporting unit”). Our impairment evaluation of goodwill first considered management’s estimate of the fair value of the reporting unit compared to its carrying value, including goodwill. If the carrying value of the reporting unit exceeded its fair value, a computation of the implied fair value of the goodwill was compared with its related carrying value. If the carrying value of the reporting unit goodwill exceeded the implied fair value of that goodwill, an impairment loss was recognized in the amount of the excess. Because quoted market prices were not available for the reporting unit, management applied reasonable judgments (including market supported assumptions when available) in estimating the fair value for the reporting unit. We estimated the fair value of the reporting unit on a stand-alone basis and also considered Williams’ market capitalization and third party estimates in corroborating our estimate of the fair value of the reporting unit.
 
The fair value of the reporting unit was estimated primarily by valuing proved and unproved reserves. We use an income approach (discounted cash flows) for valuing reserves, based on inputs we believed would be utilized by market participants. The significant inputs into the valuation of proved and unproved reserves include reserve quantities, forward natural gas prices, anticipated drilling and operating costs, anticipated production curves, income taxes and appropriate discount rates. To estimate the fair value of the reporting unit and the implied fair value of goodwill under a hypothetical acquisition of the reporting unit, we assumed a tax structure where a buyer would obtain a step-up in the tax basis of the net assets acquired.
 
In our assessment as of September 30, 2010, the carrying value of the reporting unit, including goodwill, exceeded its fair value. We then determined that the implied fair value of the goodwill was zero. As a result, we recognized a full $1 billion impairment charge related to our goodwill. See Notes 4 and 12 of Notes to Combined Financial Statements for additional discussion and significant inputs into the fair value determination.


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We evaluate our long-lived assets for impairment when we believe events or changes in circumstances indicate that we may not be able to recover the carrying value. Our computations utilize judgments and assumptions that include the estimated fair value of the asset, undiscounted future cash flows, discounted future cash flows and the current and future economic environment in which the asset is operated.
 
As a result of significant declines in forward natural gas prices during the third quarter of 2010, we assessed our natural gas producing properties and acquired unproved reserve costs for impairment using estimates of future cash flows. Significant judgments and assumptions in these assessments include estimates of natural gas reserves quantities, estimates of future natural gas prices using a forward NYMEX curve adjusted for locational basis differentials, drilling plans, expected capital costs and our estimate of an applicable discount rate commensurate with the risk of the underlying cash flow estimates. The assessment performed at September 30, 2010 identified certain properties with a carrying value in excess of their calculated fair values. As a result, we recognized a $678 million impairment charge. See Notes 4 and 12 of Notes to Combined Financial Statements for additional discussion and significant inputs into the fair value determination.
 
In addition to those long-lived assets described above for which impairment charges were recorded, certain others were reviewed for which no impairment was required. These reviews included our other domestic producing properties and acquired unproved reserve costs, and utilized inputs generally consistent with those described above. Judgments and assumptions are inherent in our estimate of future cash flows used to evaluate these assets. The use of alternate judgments and assumptions could result in the recognition of different levels of impairment charges in the combined financial statements. For our other producing assets reviewed, but for which impairment charges were not recorded, we estimate that approximately 12 percent could be at risk for impairment if forward prices across all future periods decline by approximately 8 to 12 percent, on average, as compared to the forward prices at December 31, 2010. A substantial portion of the remaining carrying value of these other assets (primarily related to our assets in the Piceance Basin) could be at risk for impairment if forward prices across all future periods decline by at least 30 percent, on average, as compared to the prices at December 31, 2010.
 
Accounting for Derivative Instruments and Hedging Activities
 
We review our energy contracts to determine whether they are, or contain, derivatives. Our energy derivatives portfolio is largely comprised of exchange-traded products or like products and the tenure of our derivatives portfolio is relatively short-term, with more than 99 percent of the value of our derivatives portfolio expiring in the next 24 months. We further assess the appropriate accounting method for any derivatives identified, which could include:
 
  •   qualifying for and electing cash flow hedge accounting, which recognizes changes in the fair value of the derivative in other comprehensive income (to the extent the hedge is effective) until the hedged item is recognized in earnings;
 
  •   qualifying for and electing accrual accounting under the normal purchases and normal sales exception; or
 
  •   applying mark-to-market accounting, which recognizes changes in the fair value of the derivative in earnings.
 
If cash flow hedge accounting or accrual accounting is not applied, a derivative is subject to mark-to-market accounting. Determination of the accounting method involves significant judgments and assumptions, which are further described below.
 
The determination of whether a derivative contract qualifies as a cash flow hedge includes an analysis of historical market price information to assess whether the derivative is expected to be highly effective in offsetting the cash flows attributed to the hedged risk. We also assess whether the hedged forecasted transaction is probable of occurring. This assessment requires us to exercise judgment and consider a wide variety of factors in addition to our intent, including internal and external forecasts, historical experience, changing market and business conditions, our financial and operational ability to carry out the forecasted


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transaction, the length of time until the forecasted transaction is projected to occur and the quantity of the forecasted transaction. In addition, we compare actual cash flows to those that were expected from the underlying risk. If a hedged forecasted transaction is not probable of occurring, or if the derivative contract is not expected to be highly effective, the derivative does not qualify for hedge accounting.
 
For derivatives designated as cash flow hedges, we must periodically assess whether they continue to qualify for hedge accounting. We prospectively discontinue hedge accounting and recognize future changes in fair value directly in earnings if we no longer expect the hedge to be highly effective, or if we believe that the hedged forecasted transaction is no longer probable of occurring. If the forecasted transaction becomes probable of not occurring, we reclassify amounts previously recorded in other comprehensive income into earnings in addition to prospectively discontinuing hedge accounting. If the effectiveness of the derivative improves and is again expected to be highly effective in offsetting the cash flows attributed to the hedged risk, or if the forecasted transaction again becomes probable, we may prospectively re-designate the derivative as a hedge of the underlying risk.
 
Derivatives for which the normal purchases and normal sales exception has been elected are accounted for on an accrual basis. In determining whether a derivative is eligible for this exception, we assess whether the contract provides for the purchase or sale of a commodity that will be physically delivered in quantities expected to be used or sold over a reasonable period in the normal course of business. In making this assessment, we consider numerous factors, including the quantities provided under the contract in relation to our business needs, delivery locations per the contract in relation to our operating locations, duration of time between entering the contract and delivery, past trends and expected future demand and our past practices and customs with regard to such contracts. Additionally, we assess whether it is probable that the contract will result in physical delivery of the commodity and not net financial settlement.
 
Since our energy derivative contracts could be accounted for in three different ways, two of which are elective, our accounting method could be different from that used by another party for a similar transaction. Furthermore, the accounting method may influence the level of volatility in the financial statements associated with changes in the fair value of derivatives, as generally depicted below:
 
                 
    Combined Statement of Operations   Combined Balance Sheet
Accounting Method
  Drivers   Impact   Drivers   Impact
 
Accrual Accounting
  Realizations   Less Volatility   None   No Impact
Cash Flow Hedge
Accounting
  Realizations &
Ineffectiveness
  Less Volatility   Fair Value Changes   More Volatility
Mark-to-Market Accounting
  Fair Value Changes   More Volatility   Fair Value Changes   More Volatility
 
Our determination of the accounting method does not impact our cash flows related to derivatives.
 
Additional discussion of the accounting for energy contracts at fair value is included in Notes 1 and 12 of Notes to Combined Financial Statements.
 
Successful Efforts Method of Accounting for Oil and Gas Exploration and Production Activities
 
We use the successful efforts method of accounting for our oil- and gas-producing activities. Estimated natural gas and oil reserves and forward market prices for oil and gas are a significant part of our financial calculations. Following are examples of how these estimates affect financial results:
 
  •   An increase (decrease) in estimated proved oil and gas reserves can reduce (increase) our unit-of-production depreciation, depletion and amortization rates; and
 
  •   Changes in oil and gas reserves and forward market prices both impact projected future cash flows from our oil and gas properties. This, in turn, can impact our periodic impairment analyses.
 
The process of estimating natural gas and oil reserves is very complex, requiring significant judgment in the evaluation of all available geological, geophysical, engineering and economic data. After being estimated internally, approximately 94 percent of our domestic reserve estimates are audited by independent experts. The


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data may change substantially over time as a result of numerous factors, including additional development cost and activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, material revisions to existing reserve estimates could occur from time to time. Such changes could trigger an impairment of our oil and gas properties and have an impact on our depreciation, depletion and amortization expense prospectively. For example, a change of approximately 10 percent in our total oil and gas reserves could change our annual depreciation, depletion and amortization expense between approximately $76 million and $93 million. The actual impact would depend on the specific basins impacted and whether the change resulted from proved developed, proved undeveloped or a combination of these reserve categories.
 
Forward market prices, which are utilized in our impairment analyses, include estimates of prices for periods that extend beyond those with quoted market prices. This forward market price information is consistent with that generally used in evaluating our drilling decisions and acquisition plans. These market prices for future periods impact the production economics underlying oil and gas reserve estimates. The prices of natural gas and oil are volatile and change from period to period, thus impacting our estimates. Significant unfavorable changes in the forward price curve could result in an impairment of our oil and gas properties.
 
We record the cost of leasehold acquisitions as incurred. Individually significant lease acquisition costs are assessed annually, or as conditions warrant, for impairment considering our future drilling plans, the remaining lease term and recent drilling results. Lease acquisition costs that are not individually significant are aggregated by prospect or geographically, and the portion of such costs estimated to be nonproductive prior to lease expiration is amortized over the average holding period. Changes in our assumptions regarding the estimates of the nonproductive portion of these leasehold acquisitions could result in impairment of these costs. Upon determination that specific acreage will not be developed, the costs associated with that acreage would be impaired.
 
Contingent Liabilities
 
We record liabilities for estimated loss contingencies, including environmental matters, when we assess that a loss is probable and the amount of the loss can be reasonably estimated. Revisions to contingent liabilities are generally reflected in income when new or different facts or information become known or circumstances change that affect the previous assumptions with respect to the likelihood or amount of loss. Liabilities for contingent losses are based upon our assumptions and estimates and upon advice of legal counsel, engineers or other third parties regarding the probable outcomes of the matter. As new developments occur or more information becomes available, our assumptions and estimates of these liabilities may change. Changes in our assumptions and estimates or outcomes different from our current assumptions and estimates could materially affect future results of operations for any particular quarterly or annual period. See Note 9 of Notes to Combined Financial Statements.
 
Valuation of Deferred Tax Assets and Liabilities
 
Our domestic operations are included in the consolidated and combined federal and state income tax returns for Williams, except for certain separate state filings. The income tax provision has been calculated on a separate return basis, which requires judgment in computing a stand-alone effective state tax rate as we did not exist as a stand-alone filer during these periods. If the effective state tax rate were to be revised upward by one percent, this would result in an increase to our net deferred income tax liability of approximately $30 million.
 
We have deferred tax assets resulting from certain investments and businesses that have a tax basis in excess of book basis and from certain separate state losses generated in the current and prior years. We must evaluate whether we will ultimately realize these tax benefits and establish a valuation allowance for those that may not be realizable. This evaluation considers tax planning strategies, including assumptions about the availability and character of future taxable income. When assessing the need for a valuation allowance, we consider forecasts of future company performance, the estimated impact of potential asset dispositions, and our ability and intent to execute tax planning strategies to utilize tax carryovers. The ultimate amount of deferred


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tax assets realized could be materially different from those recorded, as influenced by potential changes in jurisdictional income tax laws and the circumstances surrounding the actual realization of related tax assets. For example, Williams manages its tax position based upon its entire portfolio, which may not be indicative of tax planning strategies available to us if we were operating as an independent company.
 
See Note 8 of Notes to Combined Financial Statements for additional information.
 
Fair Value Measurements
 
A limited amount of our energy derivative assets and liabilities trade in markets with lower availability of pricing information requiring us to use unobservable inputs and are considered Level 3 in the fair value hierarchy. At December 31, 2010, less than 1 percent of our energy derivative assets and liabilities measured at fair value on a recurring basis are included in Level 3. For Level 2 transactions, we do not make significant adjustments to observable prices in measuring fair value as we do not generally trade in inactive markets.
 
The determination of fair value for our energy derivative assets and liabilities also incorporates the time value of money and various credit risk factors which can include the credit standing of the counterparties involved, master netting arrangements, the impact of credit enhancements (such as cash collateral posted and letters of credit) and our nonperformance risk on our energy derivative liabilities. The determination of the fair value of our energy derivative liabilities does not consider noncash collateral credit enhancements. For net derivative assets, we apply a credit spread, based on the credit rating of the counterparty, against the net derivative asset with that counterparty. For net derivative liabilities we apply our own credit rating. We derive the credit spreads by using the corporate industrial credit curves for each rating category and building a curve based on certain points in time for each rating category. The spread comes from the discount factor of the individual corporate curves versus the discount factor of the LIBOR curve. At December 31, 2010, the credit reserve is less than $1 million on both on our net derivative assets and net derivative liabilities. Considering these factors and that we do not have significant risk from our net credit exposure to derivative counterparties, the impact of credit risk is not significant to the overall fair value of our derivatives portfolio.
 
At December 31, 2010, 89 percent of the fair value of our derivatives portfolio expires in the next 12 months and more than 99 percent expires in the next 24 months. Our derivatives portfolio is largely comprised of exchange-traded products or like products where price transparency has not historically been a concern. Due to the nature of the markets in which we transact and the relatively short tenure of our derivatives portfolio, we do not believe it is necessary to make an adjustment for illiquidity. We regularly analyze the liquidity of the markets based on the prevalence of broker pricing and exchange pricing for products in our derivatives portfolio.
 
The instruments included in Level 3 at December 31, 2010, consist of natural gas index transactions that are used to manage the physical requirements of our business. The change in the overall fair value of instruments included in Level 3 primarily results from changes in commodity prices during the month of delivery. There are generally no active forward markets or quoted prices for natural gas index transactions.
 
We have an unsecured credit agreement through December 2015 with certain banks that, so long as certain conditions are met, serves to reduce our usage of cash and other credit facilities for margin requirements related to instruments included in the facility. We anticipate this agreement will be dissolved and individual contracts will be executed with the same banks under similar margining requirements. See further discussion in “—Management’s Discussion and Analysis of Financial Condition and Liquidity.”
 
For the years ended December 31, 2010 and 2009, we recognized impairments of certain assets that were measured at fair value on a nonrecurring basis. These impairment measurements are included in Level 3 as they include significant unobservable inputs, such as our estimate of future cash flows and the probabilities of alternative scenarios. See Note 12 of Notes to Combined Financial Statements.


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BUSINESS
 
Overview
 
We are an independent natural gas and oil exploration and production company engaged in the exploitation and development of long-life unconventional properties. We are focused on profitably exploiting our significant natural gas reserve base and related NGLs in the Piceance Basin of the Rocky Mountain region, and on developing and growing our positions in the Bakken Shale oil play in North Dakota and the Marcellus Shale natural gas play in Pennsylvania. Our other areas of domestic operations include the Powder River Basin in Wyoming and the San Juan Basin in the southwestern United States. In addition, we own a 69 percent controlling ownership interest in Apco, which holds oil and gas concessions in Argentina and Colombia and trades on the NASDAQ Capital Market under the symbol “APAGF.” Our international interests make up approximately five percent of our total proved reserves. In consideration of this percentage, unless specifically referenced herein, the information included in this section relates only to our domestic activity.
 
We have built a geographically diverse portfolio of natural gas and oil reserves through organic development and strategic acquisitions. For the five years ended December 31, 2010, we have grown production at a compound annual growth rate of 12 percent. As of December 31, 2010, our proved reserves were 4,473 Bcfe, 59 percent of which were proved developed reserves. Average daily production for the month ended March 31, 2011 was 1,251 MMcfe/d. Our Piceance Basin operations form the majority of our proved reserves and current production, providing a low-cost, scalable asset base.
 
The following table provides summary data for each of our primary areas of operation as of December 31, 2010, unless otherwise noted.
 
                                                                         
    Estimated Net
    March 2011
                      2011 Budget Estimate        
    Proved Reserves     Average Daily
          Identified Drilling
          Drilling
       
          % Proved
    Net Production
    Net
    Locations     Gross
    Capital(2)
    PV-10(3)
 
Basin/Shale
  Bcfe     Developed     (MMcfe/d)(1)     Acreage     Gross     Net     Wells     (Millions)     (Millions)  
 
Piceance Basin
    2,927       53 %     723       211,000       10,708       8,496       376     $ 575     $ 2,707  
Bakken Shale(4)
    136       11 %     12       89,420       758       397       41       260       399  
Marcellus Shale
    28       71 %     14       99,301       761       450       62       170       29  
Powder River Basin
    348       75 %     220       425,550       2,374       1,023       411       70       317  
San Juan Basin
    554       79 %     131       120,998       1,485       704       51       40       477  
Apco(5)
    190       60 %     57       404,304       526       180       37       30       358  
Other(6)
    290       72 %     94       327,390       2,185       112       94       85       257  
                                                                         
Total
    4,473       59 %     1,251       1,677,963       18,797       11,362       1,072     $ 1,230     $ 4,544  
                                                                         
 
 
(1) Represents average daily net production for the month ended March 31, 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 Identified Drilling Locations, Gross Wells and Drilling Capital.


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(6) Other includes Barnett Shale, Arkoma and Green River Basins and miscellaneous smaller properties.
 
2011 Capital Expenditures Budget
 
Our total 2011 capital expenditures budget is expected to be between $1.3 billion and $1.6 billion, and will consist of the following, representing the midpoint of this range:
 
  •   approximately $1.23 billion for development drilling; and
 
  •   approximately $220.0 million for facilities, infrastructure, and land/acquisitions.
 
While we have budgeted between $1.3 billion and $1.6 billion of capital deployment in 2011, the ultimate amount and allocation of capital spent in 2011 could vary. We will evaluate market conditions in each of our operating areas to determine the estimated economic returns on capital employed. If those returns exceed or fall short of our thresholds, our capital expenditures and allocations could change accordingly. In addition, we believe that after completion of this offering we will be well positioned to pursue large scale strategic acquisitions that are not included in our 2011 capital expenditures budget, subject to restrictions to maintain the tax-free treatment of our separation from Williams. See “Risk Factors—Risks Related to Our Relationship with Williams.”
 
Our Business Strategy
 
Our business strategy is to increase shareholder value by finding and developing reserves and producing natural gas, oil and NGLs at costs that generate an attractive rate of return on our investment.
 
  •   Efficiently Allocate Capital for Optimal Portfolio Returns.  We expect to allocate capital to the most profitable opportunities in our portfolio based on commodity price cycles and other market conditions, enabling us to continue to grow our reserves and production in a manner that maximizes our return on investment. In determining which drilling opportunities to pursue, we target a minimum after-tax internal rate of return on each operated well we drill of 15 percent. While we have a significant portfolio of drilling opportunities that we believe meet or exceed our return targets even in challenging commodity price environments, we are disciplined in our approach to capital spending and will adjust our drilling capital expenditures based on our level of expected cash flows, access to capital and overall liquidity position. For example, in 2009 we demonstrated our capital discipline by reducing drilling expenditures in response to prevailing commodity prices and their impact on these factors.
 
  •   Continue Our Low-Cost Development Approach.  We manage costs by focusing on establishing large scale, contiguous acreage blocks on which 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 our cost-disciplined approach 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 low-cost 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 will continue to pursue other oil- and liquids-rich organic development and acquisition opportunities that meet our investment returns and strategic criteria.


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  •   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 March 31, 2011, our estimated domestic natural gas production revenues were 65 percent hedged for 2011 and 40 percent hedged for 2012. Estimated domestic oil production revenues were 47 percent hedged for 2011 and 49 percent hedged for 2012 as of the same date.
 
Our Competitive Strengths
 
We have a number of competitive strengths that we believe will help us to successfully execute our business strategies:
 
  •   A Leading Piceance Basin Cost Structure.  We have a large position in the lowest cost area of the Piceance Basin, which we believe provides us economies of scale in our operations, allowing us to continuously drive down operating costs and increase efficiencies. The existing substantial midstream infrastructure in the Piceance Basin contributes to our low-cost structure and provides take-away capacity for our natural gas and NGLs. Because of this low-cost 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 14,000 gross operated drilling locations, for which approximately 500 gross operated wells are budgeted for 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 low-cost 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.


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  •   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 low-cost model and to apply our highly specialized technical expertise in the development of those resources.
 
Our Recent Acquisition History
 
An important part of our strategy to grow our business and enhance shareholder value is to acquire properties complementary to our existing positions as well as undeveloped acreage with significant resource potential in new geographic areas. Following is a summary of selected recent acquisitions in the Bakken Shale, Marcellus Shale and Piceance Basin.
 
Bakken Shale
 
  •   In December 2010, we acquired Dakota-3 E&P Company LLC, a company that holds approximately 85,800 net acres on the Fort Berthold Indian Reservation in the Williston Basin, with then-current net oil production of 3,300 barrels per day from 24 existing wells, for $949 million.
 
Marcellus Shale
 
  •   In July 2010, we acquired 42,000 net acres of largely undeveloped properties primarily located in Susquehanna County in northeastern Pennsylvania for $599 million.
 
  •   During 2010, we also acquired additional unproved leasehold acreage positions in the Marcellus Shale for a total of $164 million.
 
  •   In June 2009, we initiated our strategy of securing acreage in the Marcellus Shale with our participation and exploration agreement to develop natural gas wells with Rex Energy Corporation. We acquired a 50 percent interest in 44,000 net acres in Pennsylvania’s Westmoreland, Clearfield and Centre Counties for $33 million in a “drill to earn” structure.
 
Piceance Basin
 
  •   In September 2009, we completed a bolt-on acquisition of 21,800 net acres in the Piceance Basin, east of our existing properties, for $253 million. The asset included then current production of 24 MMcfe/d from 28 wells, related gas and water gathering facilities, 94 approved drilling permits and more than 800 drillable locations at 10-acre spacing. In December 2009, we increased our working interest in these properties through an additional $22 million acquisition.
 
  •   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


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  3,300 wells connected to the gathering system, which includes pipelines ranging up to 30-inch trunk lines. As part of this sale, we agreed to continue to use this gathering system for our production in this area for the life of our leases. See “Other Related Party Transactions—Agreements Related to the Piceance Disposition.”
 
  •   In January 2008, we sold a contractual right to a production payment on certain future hydrocarbon production in Peru for $148 million. As a result of the contract termination, we have no further interests associated with this crude oil concession, which we had obtained through our acquisition of Barrett Resources Corporation in 2001.
 
Significant Properties
 
Our principal areas of operation are the Piceance Basin, Bakken Shale, Marcellus Shale, Powder River Basin, San Juan Basin and, through our ownership of Apco, Colombia and Argentina. A map of our properties within these geographic areas and our other properties can be found on the inside cover of this prospectus.
 
Piceance Basin
 
We entered the Piceance Basin in May 2001 with the acquisition of Barrett Resources and since that time have grown to become the largest natural gas producer in Colorado. Our Piceance Basin properties currently comprise our largest area of concentrated development drilling.
 
For the month of March 2011, we had an average 723 MMcfe/d of net production from our Piceance Basin properties. Approximately 23 million gallons of NGLs are currently recovered each month from our Piceance Basin properties. A large majority of our natural gas production in this basin currently is gathered through a system owned by Williams Partners and delivered to markets through a number of interstate pipelines. See “Other Related Party Transactions—Gathering, Processing and Treating Contracts.” As of December 31, 2010, our properties in the Piceance Basin included:
 
  •   211,000 total net acres, including 108,165 undeveloped net acres;
 
  •   2,927 Bcfe of estimated net proved reserves;
 
  •   3,587 net producing wells; and
 
  •   1,596 undrilled proved drilling locations and 10,708 total undrilled locations.
 
During 2010, we operated an average of 11 drilling rigs in the basin, including nine in the Piceance Valley and two in the Piceance Highlands. As of March 31, 2011 we were operating 11 rigs and have an average of 11 rigs budgeted for 2011. We have allocated approximately $575 million in capital expenditures to drill 376 gross wells on our Piceance Basin properties in 2011.
 
The Piceance Basin is located in northwestern Colorado. Our operations in the basin are divided into two areas: the Piceance Valley and the Piceance Highlands. Our Piceance Valley area includes operations along the Colorado River valley and is the more developed area where we have produced consistent, repeatable results. The Piceance Highlands, which are those areas at higher elevations above the river valley, contain vast development opportunities that position us well for growth in the future as infrastructure expands and efficiency improvements continue. Our development activities in the basin are primarily focused on the Williams Fork section within the Mesaverde formation. The Williams Fork can be over 2,000 feet in thickness and is comprised of several tight, interbedded, lenticular sandstone lenses encountered at depths ranging from 7,000 to 13,000 feet. In order to maximize producing rates and recovery of natural gas reserves we must hydraulically fracture the well using a fluid system comprised of 99 percent water and sand. Advancements in completion technology, including the use of microseismic data have enabled us to more effectively stimulate the reservoir and recover a greater percentage of the natural gas in place. We are currently evaluating deeper horizons such as the Mancos and Niobrara shale formations, which have the potential to provide additional development opportunities.


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Initial development of the Piceance Basin was limited to conventional drilling and completion techniques. In response to the unique challenges posed by the geology of this area, we collaborated with our drilling contractors to build “fit-for-purpose” type drilling rigs, and beginning in 2005, were the first operator to introduce these types of drilling rigs to the Piceance Basin. Utilizing advancements in drilling technology and several innovative modifications, these special purpose rigs are capable of drilling 22 wells from a single well pad, drilling faster and extending the directional length of our wells, and can accommodate completion and production activities simultaneously. In addition to reducing surface impacts, these rigs are quieter, safer to operate, and have allowed us to significantly reduce cycle times from spud to spud and getting our gas to market. We have pioneered several other innovative practices such as green completions, which essentially eliminate gas flaring and emissions during completion operations, and using a “clustered” plan of development approach taking advantage of centralized facilities, as well as allowing us to fracture stimulate wells from over two miles away from the pumping equipment. In addition, all of our producing wells and associated facilities are fully automated and utilize our state-of-the art telemetry system, which provides our well technicians with real time data to ensure we are optimizing well performance. Our innovative approaches to drilling in the Piceance Basin have earned us positive state and federal recognition.
 
Bakken Shale
 
In December 2010 we acquired approximately 85,800 net acres in the Williston Basin. All of our properties in the Williston Basin are on the Fort Berthold Indian Reservation in North Dakota, where we will be the primary operator. Based on our geologic interpretation of the Bakken formation, the evolution of completion techniques, our own drilling results as well as the publicly available drilling results for other operators in the basin, we believe that a substantial portion of our Williston Basin acreage is prospective in the Bakken formation, the primary target for all of the well locations in our current drilling inventory.
 
For the month of March 2011, we had an average of 1.9 Mboe/d of net production from our Bakken Shale wells, down from prior months due to adverse weather conditions. As of December 31, 2010, our properties in the Bakken Shale included:
 
  •   89,420 total net acres, including 75,397 undeveloped net acres;
 
  •   23 MMboe of estimated net proved reserves; and
 
  •   13 net producing wells.
 
As of March 31, 2011 we were operating three rigs and plan to add an additional two rigs during 2011. We have allocated approximately $260 million in capital expenditures to drill 41 gross wells on our Bakken Shale properties in 2011.
 
We plan to develop oil reserves through horizontal drilling from both the Middle Bakken and Upper Three Forks shale oil formations utilizing drilling and completion expertise gained in part through experience in our other basins. Based on our subsurface geological analysis, we believe that our position lies in the area of the basin’s greatest potential recovery for Bakken formation oil. Currently our Bakken Shale development has the highest incremental returns of any of our drilling programs.
 
The Williston Basin is spread across North Dakota, South Dakota, Montana and parts of southern Canada, covering approximately 202,000 square miles, of which 143,000 square miles are in the United States. The basin produces oil and natural gas from numerous producing horizons including the Bakken, Three Forks, Madison and Red River formations. A report issued by the U.S. Geological Survey in April 2008 classified the Bakken formation, ranging from 3.0 to 4.3 billion barrels of recoverable oil, then as the largest continuous oil accumulation ever assessed by it in the contiguous United States. In 2010, based on current drilling success rates and production levels, the North Dakota Geological Survey estimated the Bakken formation to contain 11.0 billion barrels of recoverable oil. In 2010, the North Dakota Geological Survey also estimated the recoverable oil from the Three Forks formation to be almost 2 billion barrels.
 
The Devonian-age Bakken formation is found within the Williston Basin underlying portions of North Dakota and Montana and is comprised of three lithologic members referred to as the Upper, Middle and


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Lower Bakken shales. The formation ranges up to 150 feet thick and is a continuous and structurally simple reservoir. The upper and lower shales are highly organic, thermally mature and over pressured and can act as both a source and reservoir for the oil. The Middle Bakken, which varies in composition from a silty dolomite to shaly limestone or sand, serves as the productive formation and is a critical reservoir for commercial production. Generally, the Bakken formation is found at vertical depths of 8,500 to 11,500 feet.
 
The Three Forks formation, generally found immediately under the Bakken formation, has also proven to contain productive reservoir rock that may add incremental reserves to our existing leasehold positions. The Three Forks formation typically consists of interbedded dolomites and shale with local development of a discontinuous sandy member at the top, known as the Sanish sand. The Three Forks formation is an unconventional carbonate play. Similar to the Bakken formation, the Three Forks formation has recently been exploited utilizing the same horizontal drilling and advanced completion techniques as the Bakken development. Drilling in the Three Forks formation began in mid-2008 and a number of operators are currently drilling wells targeting this formation. Based on our geologic interpretation of the Three Forks formation and the evolution of completion techniques, we believe that most of our Williston Basin acreage is prospective in the Three Forks formation. We are in the process of completing a well drilled in the Three Forks formation.
 
Our Middle Bakken development is expected to be comparable to other established operators in the area. For our typical well drilled in the Middle Bakken formation, we expect the initial 30 day production rates to be in the range of 750 Boe/d to 1,100 Boe/d, drilling capital to be in the $8 million to $9 million range and reserve estimates to be from 650 to 850 Mbbls, depending on the area.
 
Our acreage in the Bakken Shale, as well as a portion of our acreage in the Piceance Basin and Powder River Basin, is leased to us by or with the approval of the federal government or its agencies, and is subject to federal authority, NEPA, the Bureau of Indian Affairs or other regulatory regimes that require governmental agencies to evaluate the potential environmental impacts of a proposed project on government owned lands. These regulatory regimes impose obligations on the federal government and governmental agencies that may result in legal challenges and potentially lengthy delays in obtaining project permits or approvals and could result in certain instances in the cancellation of existing leases.
 
Marcellus Shale
 
Our Marcellus Shale acreage is located in four principal areas of the play within Pennsylvania: the northeast portion of the play in and near Susquehanna County; the southwest in and around Westmoreland County; centrally in Clearfield and Centre Counties and the east in Columbia County. We have continued to expand our position since our entry into the Marcellus Shale in 2009, both organically and through third-party acquisitions. We are the primary operator on our acreage for all four areas and plan to develop our acreage using horizontal drilling and completion expertise in part gained through operations in our other basins. Our most established area is in Westmoreland County but in the future we expect our most significant drilling area to be in Susquehanna County. A third party gathering system providing the main trunkline out of the area is expected to go into service in the third quarter of 2011.
 
For the month of March 2011, we had an average of 14 MMcfe/d of net production from our Marcellus Shale properties. As of December 31, 2010, our properties in the Marcellus Shale included:
 
  •   99,301 total net acres, including 98,387 undeveloped net acres;
 
  •   28 Bcfe of estimated net proved reserves; and
 
  •   Six net producing wells.
 
As of March 31, 2011 we were operating five rigs and have an average of five rigs budgeted for 2011. We have allocated approximately $170 million in capital expenditures to drill 62 gross wells on our Marcellus Shale properties in 2011.
 
The Marcellus Shale formation is the most expansive shale gas play in the United States, spanning six states in the northeastern United States. In April 2009, the United States Department of Energy (the “DOE”) identified an estimated potential recoverable resource in the Marcellus Shale formation of over 260 trillion


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cubic feet of natural gas. The Marcellus Shale is a black, organic rich shale formation located at depths between 4,000 and 8,500 feet, covering approximately 95,000 square miles at an average net thickness of 50 feet to 300 feet.
 
The first commercial well in the Marcellus Shale was drilled and completed in 2005 in Pennsylvania. Since the beginning of 2005, there have been 6,963 wells permitted in Pennsylvania in the Marcellus Shale and 3,030 of the approved wells have been drilled. In 2010, 1,386 wells were drilled in the Marcellus Shale, making it one of the most active and prominent shale gas plays in the United States, and active, widespread drilling in this area is expected to continue. During 2010, there were more than 80 operators active in the play.
 
Powder River Basin
 
We own a large position in coal bed methane reserves in the Powder River Basin and together with our partner Anadarko Petroleum Corporation control 950,982 acres, of which our ownership represents 425,550 net acres. We share operations with our partner and both companies have extensive experience producing from coal formations in the Powder River Basin dating from its earliest commercial growth in the late 1990s. The natural gas produced is gathered by a system owned by our joint venture partner.
 
For the month of March 2011, we had an average of 220 MMcfe/d of net production from our Powder River Basin properties. As of December 31, 2010, our properties in the Powder River Basin included:
 
  •   425,550 total net acres, including 175,371 undeveloped net acres;
 
  •   348 Bcfe of estimated net proved reserves; and
 
  •   2,885 net producing wells.
 
We have allocated approximately $70 million in capital expenditures to drill 411 gross wells on our Powder River Basin properties in 2011. We plan to drill 80 operated wells, participate in 253 wells drilled by our joint venture partner and participate in the drilling of 78 wells drilled by others in 2011.
 
Our Powder River Basin properties are located in northeastern Wyoming. Our development operations in this basin are focused on coal bed methane plays in the Big George and Wyodak project areas. Initially, coal bed methane wells typically produce water in a process called dewatering. This process lowers pressure, allowing the natural gas to flow to the wellbore. As the coal seam pressure declines, the wells begin producing methane gas at an increasing rate. As the wells mature, the production peaks, stabilizes and then begins declining. The average life of a coal bed methane well in the Powder River Basin ranges from five to 15 years. While these wells generally produce at much lower rates with fewer reserves attributed to them when compared to conventional natural gas wells in the Rocky Mountains, they also typically have higher drilling success rates and lower capital costs.
 
The coal seams that we target in the Powder River Basin have been extensively mapped as a result of a variety of natural resource development projects that have occurred in the region. Industry data from over 25,000 wellbores drilled through the Ft. Union coal formation allows us to determine critical data such as the aerial extent, thickness, gas saturation, formation pressure and relative permeability of the coal seams we target for development, which we believe significantly reduces our dry hole risk.
 
San Juan Basin
 
We acquired our San Juan Basin properties in 1985. These properties represented the first major area of natural gas exploration and development activities for Williams following its acquisition of Northwest Energy in 1982. Our San Juan Basin properties include holdings across the basin producing primarily from the Mesa Verde, Fruitland Coal and Mancos shale gas formations. We are the operator of our largest producing unit, the Rosa Unit, on the east side of the basin in New Mexico, on two other units in New Mexico, on three units in Colorado and miscellaneous other areas equating to 60 percent of our current net production. We have various other third party operators on other units within the basin.


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For the month of March 2011, we had an average 131 MMcfe/d of net production from our San Juan Basin properties. As of December 31, 2010, our properties in the San Juan Basin included:
 
  •   120,998 total net acres, including 1,576 undeveloped net acres;
 
  •   554 Bcfe of estimated net proved reserves; and
 
  •   881 net producing wells.
 
We have allocated approximately $40 million in capital expenditures to drill 51 gross wells on our San Juan Basin properties in 2011. We plan to drill 16 operated wells in 2011 and participate in the drilling of 35 wells operated by our partners in 2011.
 
According to a September 2010 Wood Mackenzie report, the San Juan Basin is one of the oldest and most prolific coal bed methane plays in the world. This report states that production from the San Juan Basin in 2010 was expected to average 3.5 Bcfe/d with approximately 60 percent of net gas production derived from the Fruitland coal bed. The Fruitland coal bed extends to depths of approximately 4,200 ft with net thickness ranging from zero to 100 feet. The Mesa Verde play is the top producing tight gas play in the basin with total thickness ranging from 500 to 2,500 feet. The Mesa Verde is underlain by the upper Mancos Shale and overlain by the Lewis Shale.
 
Apco
 
We hold an approximate 69 percent controlling equity interest in Apco. Apco in turn owns interests in several blocks in Argentina, including concessions in the Neuquén, Austral, Northwest and San Jorge Basins, and in 3 exploration permits in Colombia, with its primary properties consisting of the Neuquén and Austral Basin concessions. Apco’s oil and gas reserves are approximately 57 percent oil, 39 percent natural gas and four percent liquefied petroleum gas. For the month of March 2011, Apco had an average of 13.8 Mboe/d of net production. As of December 31, 2010, Apco’s properties included:
 
  •   586,288 total net acres, including 556,661 undeveloped net acres;
 
  •   45.9 MMboe of estimated net proved reserves; and
 
  •   322 net producing wells.
 
Apco intends to participate in the drilling of 37 wells operated by its partners in 2011 of which Apco has allocated, for its direct ownership interest, approximately $30 million in capital expenditures.
 
The government of Argentina has implemented price control mechanisms over the sale of natural gas and over gasoline prices in the country. As a result of these controls and other actions by the Argentine government, sales price realizations for natural gas and oil sold in Argentina are generally below international market levels and are significantly influenced by Argentine governmental actions.
 
Neuquén Basin.  Apco participates in a joint venture partnership with Petrolera and Petrobras Argentina S.A. and Pecom Energía S.A. for the exploration and development of the Entre Lomas oil and gas concession in the provinces of Río Negro and Neuquén in southwest Argentina. In 2007, the partners created two new joint ventures consisting of the same partners with the same interests in order to expand operations into two areas adjacent to Entre Lomas, the Agua Amarga exploration permit in the province of Río Negro, and the Bajada del Palo concession in the province of Neuquén. In 2009, a portion of the Agua Amarga permit was converted to a 25-year exploitation concession called Charco del Palenque.
 
The Entre Lomas concession covers a surface area of approximately 183,000 acres and produces oil and gas from seven fields, the largest of which is Charco Bayo/Piedras Blancas. The Entre Lomas concession has a primary term of 25 years that expires in the year 2016 with an option to extend for an additional ten-year period based on terms to be agreed with the government. The Bajada del Palo concession has a total surface area of approximately 111,000 acres. In 2009, the Bajada del Palo concession term was extended to September 2025.


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The Agua Amarga exploration area was awarded to Petrolera by the province of Río Negro in 2007. The property has a total surface area of approximately 95,000 acres and is located immediately to the southeast of the Entre Lomas concession. The first exploration period was scheduled to end in May 2010 and was extended for one year until May 2011. The completion of Apco’s work commitments and additional activities executed in the area has enabled Apco to request an additional one-year extension. If granted, the first exploration period would end on May 2012. In 2009, a portion of the Agua Amarga area covering approximately 18,000 acres was converted to an exploitation concession called Charco del Palenque with a 25-year term and a five-year optional extension period.
 
Austral Basin Properties.  Apco holds a 25.78 percent non-operated interest in a joint venture engaged in exploration and production activities in three concessions located on the island of Tierra del Fuego, which we refer to as the “TDF concessions.” The operator of the TDF concessions is ROCH S.A., a privately owned Argentine oil and gas company. The TDF concessions cover a total surface area of approximately 467,000 gross acres, or 120,000 acres net to Apco. Each of the concessions extends three kilometers offshore with their eastern boundaries paralleling the coastline. The most developed of the three concessions is the Las Violetas concession which is the largest onshore concession on the Argentine side of the island of Tierra del Fuego. The concessions have terms of 25 years that expire in 2016 with an option to extend the concessions for an additional ten-year period based on terms to be agreed with the government.
 
Northwest Basin Properties.  Apco holds a 1.5 percent non-operated interest in the Acambuco concession located in the province of Salta in northwest Argentina on the border with Bolivia. The concession covers an area of 294,000 acres, and is one of the largest gas producing concessions in Argentina. Wells drilled to the Huamampampa formation in the Acambuco concession have generally required one year to drill with total costs for drilling and completion ranging from $50 to $70 million.
 
San Jorge Basin Properties.  In the San Jorge Basin, Apco’s areas are more prospective and exploratory in nature. In the Sur Río Deseado Este concession in the province of Santa Cruz, Apco has a 16.94 percent working interest in an exploitation area with limited oil production and an 88 percent working interest in an exploratory area in the northern sector of the concession. Apco sold its interest in the Cañadón Ramirez concession at the end of 2010.
 
Other Properties
 
Our other holdings are comprised of assets in the Barnett Shale located in north central Texas, gas reserves in the Green River Basin of southwest Wyoming, interests in the Arkoma Basin in southeastern Oklahoma and additional international assets in northwest Argentina that are not part of Apco’s holdings.
 
For the month of March 2011, we had an average of 91 MMcfe/d of net production from our other properties. As of December 31, 2010, our other properties included:
 
  •   327,390 total net acres, including 245,497 undeveloped net acres;
 
  •   290 Bcfe of estimated net proved reserves; and
 
  •   532 net producing wells.
 
As of March 31, 2011 we were operating one rig on our other properties. We have allocated approximately $85 million in capital expenditures to drill 94 gross wells on our other properties in 2011.
 
Our Barnett Shale properties produce predominately natural gas from horizontal wells, where we are the primary operator and have drilled more than 200 wells. Our Arkoma Basin properties include 441 gross wells producing gas from coal and shale formations. We have initiated a process to seek offers to sell our Arkoma Basin properties, which include approximately 104,000 net acres, including approximately 48,000 undeveloped net acres.


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Reserves and Production Information
 
We have significant oil and gas producing activities primarily in the Rocky Mountain, northeast and Mid-continent areas of the United States. Additionally, we have international oil and gas producing activities, primarily in Argentina. Proved reserves and revenues related to international activities are approximately five percent and three percent, respectively, of our total international and domestic proved reserves and revenues from producing activities. Accordingly, unless specifically stated otherwise, the information in the remainder of this “Business” section relates only to the oil and gas activities in the United States.
 
Oil and Gas Reserves
 
The following table outlines our estimated net proved reserves expressed on a gas equivalent basis for the reporting periods December 31, 2010, 2009 and 2008. We prepare our own reserves estimates and the majority of our reserves are audited by NSAI and M&L. Proved reserves information is reported as gas equivalents, since oil volumes are insignificant in the three years shown below. Reserves for 2010 are approximately 97 percent natural gas. Reserves are more than 99 percent natural gas for 2009 and 2008. Oil reserves increased to approximately three percent of total proved reserves in 2010 as a result of a fourth quarter acquisition of properties in the Bakken Shale.
 
Summary of oil and gas reserves:
 
                         
    December 31,  
    2010     2009     2008  
    (Bcfe)(1)  
 
Proved developed reserves
    2,498       2,387       2,456  
Proved undeveloped reserves
    1,774       1,868       1,883  
                         
Total proved reserves
    4,272       4,255       4,339  
                         
 
 
(1) Gas equivalents are calculated using a ratio of six thousand cubic feet of natural gas to one barrel of oil.
 
         
    Estimated Net
 
    Proved Reserves
 
Basin / Shale
  December 31, 2010  
    (Bcfe)  
 
Piceance Basin
    2,927  
Bakken Shale
    136  
Marcellus Shale
    28  
Powder River Basin
    348  
San Juan Basin
    554  
Other(1)
    279  
         
Total(2)
    4,272  
         
 
 
(1) Other includes Barnett Shale, Arkoma and Green River Basins and miscellaneous smaller properties.
 
(2) Of our total 4,272 Bcfe of net proved reserves as of December 31, 2010, three percent are oil.
 
We have not filed on a recurring basis estimates of our total proved net oil and gas reserves with any U.S. regulatory authority or agency other than with the DOE and the SEC. The estimates furnished to the DOE have been consistent with those furnished to the SEC.
 
Our 2010 year-end estimated proved reserves were derived using the 12-month average, first-of-the-month Henry Hub spot price of $4.38 per MMbtu, adjusted for locational price differentials. During 2010, we added 508 Bcfe of net additions to our proved reserves through drilling 1,162 gross wells at a capital cost of approximately $988 million.


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


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reserves. Inherent in the methodology is a requirement for significant well density of economically producing wells to establish reasonable certainty. In fields where producing wells are less concentrated, only direct offsets from proved producing wells were assigned the proved undeveloped reserves classification. No new technologies were used to assign proved undeveloped reserves.
 
At December 31, 2010, our proved undeveloped reserves were 1,774 Bcfe, a decrease of 94 Bcfe over our December 31, 2009 proved undeveloped reserves estimate of 1,868 Bcfe. During 2010, 280 Bcfe of our December 31, 2009 proved undeveloped reserves were converted to proved developed reserves. An additional 129 Bcfe was added due to the development of unproved locations. As of 2010 year-end, we have reclassified a net 253 Bcfe from proved to probable reserves attributable to locations not expected to be developed within five years. These reclassified reserves are predominately in the Piceance Basin where we have a large inventory of drilling locations and have been offset by the addition of 342 Bcfe of new proved undeveloped drilling locations.
 
All proved undeveloped locations are scheduled to be spud within the next five years. Based on current projections, we expect to add additional rigs in 2013 in the Piceance Basin. Our undeveloped estimate contains 91 Bcfe of aging proved undeveloped reserves, or those reserves which are approaching the five-year limit before being reclassified to probable reserves. The majority of these are scheduled to be spud by year-end 2011.
 
Oil and Gas Properties and Production, Production Prices and Production Costs
 
The following table summarizes our net production for the years indicated.
 
                         
    Year Ended December 31,  
    2010     2009     2008  
 
Production Data(1):
                       
Natural Gas (MMcf)
    415,224       434,412       402,358  
Oil (MBbls)
    2,894       2,801       2,722  
Combined Equivalent Volumes (MMcfe)
    432,588       451,218       418,690  
Average Daily Combined Equivalent Volumes (MMcfe/d)
    1,185       1,236       1,144  
 
 
(1) Includes approximately 69 percent of Apco’s production, which corresponds to our ownership interest in Apco.


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The following tables summarize our domestic sales price and cost information for the years indicated.
 
                         
    Year Ended December 31,  
    2010     2009     2008  
 
Realized average price per unit:
                       
Natural gas, without hedges (per Mcf)(1)
  $ 4.32     $ 3.41     $ 6.94  
Impact of hedges (per Mcf)(1)
    0.81       1.43       0.09  
                         
Natural gas, with hedges (per Mcf)(1)
  $ 5.13     $ 4.84     $ 7.03  
                         
Oil, without hedges (per Bbl)
  $ 66.17     $ 44.92     $ 84.63  
Impact of hedges (per Bbl)
                 
                         
Oil, with hedges (per Bbl)
  $ 66.17     $ 44.92     $ 84.63  
                         
Price per Boe, without hedges(2)
  $ 26.45     $ 20.71     $ 42.12  
                         
Price per Boe, with hedges(2)
  $ 31.29     $ 29.27     $ 42.63  
                         
Price per Mcfe, without hedges(2)
  $ 4.41     $ 3.45     $ 7.02  
                         
Price per Mcfe, with hedges(2)
  $ 5.21     $ 4.88     $ 7.10  
                         
 
 
(1) Includes NGLs.
 
(2) Realized average prices include market prices, net of fuel and shrink.
 
                         
    Year Ended December 31,  
    2010     2009     2008  
 
Expenses per Mcfe:
                       
Operating expenses:
                       
Lifting costs and workovers
  $ 0.48     $ 0.41     $ 0.48  
Facilities operating expense
    0.14       0.14       0.15  
Other operating and maintenance
    0.05       0.05       0.04  
                         
Total LOE
  $ 0.67     $ 0.60     $ 0.67  
Gathering, processing and transportation charges
    0.78       0.63       0.56  
Taxes other than income
    0.26       0.19       0.61  
                         
Production cost
  $ 1.71     $ 1.42     $ 1.84  
                         
General and administrative
  $ 0.59     $ 0.56     $ 0.61  
Depreciation, depletion and amortization
  $ 2.09     $ 2.03     $ 1.86  


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Productive Oil and Gas Wells
 
The table below summarizes 2010 productive wells by area.*
 
                                 
    Gas Wells
    Gas Wells
    Oil Wells
    Oil Wells
 
    (Gross)     (Net)     (Gross)     (Net)  
 
Piceance Basin
    3,923       3,587              
Bakken Shale
                19       13  
Marcellus Shale
    14       6              
Powder River Basin
    6,404       2,884              
San Juan Basin
    3,267       881              
Other(1)
    1,626       532              
                                 
Total
    15,234       7,890       19       13  
                                 
 
 
We use the term “gross” to refer to all wells or acreage in which we have at least a partial working interest and “net” to refer to our ownership represented by that working interest.
 
(1) Other includes Barnett Shale, Arkoma and Green River Basins and miscellaneous smaller properties.
 
At December 31, 2010, there were 181 gross and 105 net producing wells with multiple completions.
 
Developed and Undeveloped Acreage
 
The following table summarizes our leased acreage as of December 31, 2010.
 
                                                 
    Developed     Undeveloped     Total  
    Gross Acres     Net Acres     Gross Acres     Net Acres     Gross Acres     Net Acres  
 
Piceance Basin
    133,428       102,835       157,017       108,165       290,445       211,000  
Bakken Shale
    16,178       13,483       114,245       75,937       130,423       89,420  
Marcellus Shale
    1,828       914       108,023       98,387       109,851       99,301  
Powder River Basin
    551,113       250,179       399,869       175,371       950,982       425,550  
San Juan Basin
    237,587       119,422       2,100       1,576       239,687       120,998  
Other(1)
    149,414       81,731       326,778       241,254       476,191       322,986  
                                                 
Total
    1,089,548       568,565       1,108,032       700,690       2,197,580       1,269,255  
                                                 
 
 
(1) Other includes Barnett Shale, Arkoma and Green River Basins, other Williston Basin acreage and miscellaneous smaller properties.


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Drilling and Exploratory Activities
 
We focus on lower-risk development drilling. Our development drilling success rate was approximately 99 percent in each of 2010, 2009 and 2008.
 
The following table summarizes domestic drilling activity by number and type of well for the periods indicated.
 
                                                 
    2010     2009     2008  
 
      Gross Wells       Net Wells       Gross Wells       Net Wells       Gross Wells       Net Wells  
                                                 
Piceance Basin
    398       360       349       303       687       624  
Bakken Shale
                n/a       n/a       n/a       n/a  
Marcellus Shale
    8       3       8       4       n/a       n/a  
Powder River Basin
    531       242       233       95       702       324  
San Juan Basin
    43       15       77       39       95       37  
Other(1)
    177       38       208       45       298       65  
Productive exploration
                3       1       4       2  
Nonproductive, including exploration
    5       3       4       1       1        
                                                 
Total
    1,162       661       882       488       1,787       1,052  
                                                 
 
 
(1) Other includes Barnett Shale, Arkoma and Green River Basins and miscellaneous smaller properties.
 
In 2010, we drilled five gross nonproductive development wells and three net nonproductive development wells. Total gross operated wells drilled were 656 in 2010, 472 in 2009 and 1,125 in 2008.
 
Present Activities
 
At December 31, 2010, we had 27 gross (16 net) wells in the process of being drilled.
 
Gas Management
 
Our sales and marketing activities to date include the sale of our natural gas and oil production, in addition to third party purchases and subsequent sales to Williams Partners for fuel and shrink gas. Following the completion of the spin-off of our stock to Williams’ stockholders, we do not expect to continue to provide fuel and shrink gas services to Williams Partners’ midstream business on a long-term basis. Our sales and marketing activities also include the management of various natural gas related contracts such as transportation, storage and related hedges. We also sell natural gas purchased from working interest owners in operated wells and other area third party producers. We primarily engage in these activities to enhance the value received from the sale of our natural gas and oil production. Revenues associated with the sale of our production are recorded in oil and gas revenues. The revenues and expenses related to other marketing activities are reported on a gross basis as part of gas management revenues and costs and expenses.
 
Delivery Commitments
 
We hold a long-term obligation to deliver on a firm basis 200,000 MMBtu/d of natural gas to a buyer at the White River Hub (Greasewood-Meeker, Colorado), which is the major market hub exiting the Piceance Basin. The Piceance, being our largest producing basin, generates ample production to fulfill this obligation without risk of nonperformance during periods of normal infrastructure and market operations. While the daily volume of natural gas is large and represents a significant percentage of our daily production, this transaction does not represent a material exposure. This obligation expires in 2014.
 
Purchase Commitments
 
In connection with a gathering agreement entered into by Williams Partners with a third party in December 2010, we concurrently agreed to buy up to 200,000 MMBtu/d of natural gas at Transco Station 515 (Marcellus Shale) priced at market prices from the same third party. Purchases under the 12-year contract are expected to begin in the third quarter of 2011. We expect to sell this natural gas in the open market and may utilize available transportation capacity to facilitate the sales.


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Hedging Activity
 
To manage the commodity price risk and volatility of owning producing natural gas properties, we enter into derivative contracts for a portion of our expected future production. See further discussion in “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
 
Customers
 
Oil and gas production is sold through our sales and marketing activities to a variety of purchasers under various length contracts ranging from one day to multi-year at market based prices. Our third party customers include other producers, utility companies, power generators, banks, marketing and trading companies and midstream service providers. In 2010, natural gas sales to BP Energy Company accounted for approximately 13 percent of our revenues. We believe that the loss of one or more of our current natural gas, oil or NGLs purchasers would not have a material adverse effect on our ability to sell our production, because any individual purchaser could be readily replaced by another purchaser, absent a broad market disruption.
 
Title to Properties
 
Our title to properties is subject to royalty, overriding royalty, carried, net profits, working and other similar interests and contractual arrangements customary in the natural gas and oil industry, to liens for current taxes not yet due and to other encumbrances. In addition, leases on Native American reservations are subject to Bureau of Indian Affairs and other approvals unique to those locations. As is customary in the industry in the case of undeveloped properties, a limited investigation of record title is made at the time of acquisition. Drilling title opinions are usually prepared before commencement of drilling operations. We believe we have satisfactory title to substantially all of our active properties in accordance with standards generally accepted in the natural gas and oil industry. Nevertheless, we are involved in title disputes from time to time which can result in litigation and delay or loss of our ability to realize the benefits of our leases.
 
Seasonality
 
Generally, the demand for natural gas decreases during the spring and fall months and increases during the winter months and in some areas during the summer months. Seasonal anomalies such as mild winters or hot summers can lessen or intensify this fluctuation. Conversely, during extreme weather events such as blizzards, hurricanes, or heat waves, pipeline systems can become temporary constraints to supply meeting demand thus amplifying localized price spikes. In addition, pipelines, utilities, local distribution companies and industrial users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the warmer months. This can lessen seasonal demand fluctuations. World weather and resultant prices for liquefied natural gas can also affect deliveries of competing liquefied natural gas into this country from abroad, affecting the price of domestically produced natural gas. In addition, adverse weather conditions can also affect our production rates or otherwise disrupt our operations.
 
Competition
 
We compete with other oil and gas concerns, including major and independent oil and gas companies in the development, production and marketing of natural gas. We compete in areas such as acquisition of oil and gas properties and obtaining necessary equipment, supplies and services. We also compete in recruiting and retaining skilled employees.
 
In our gas management services business, we compete directly with large independent energy marketers, marketing affiliates of regulated pipelines and utilities and natural gas producers. We also compete with brokerage houses, energy hedge funds and other energy-based companies offering similar services.
 
Environmental Matters and Regulation
 
Our operations are subject to numerous federal, state, local, Native American tribal and foreign laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental


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


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Congress from time to time that would reclassify certain natural gas and oil exploration and production wastes as “hazardous wastes,” which would make the reclassified wastes subject to much more stringent handling, disposal and clean-up requirements. If such legislation were to be enacted, it could have a significant impact on our operating costs, as well as the natural gas and oil industry in general. An environmental organization recently petitioned the EPA to reconsider certain RCRA exemptions for exploration and production wastes. Moreover, ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste oils, may be regulated as hazardous waste.
 
We own or lease, and have in the past owned or leased, onshore properties that for many years have been used for or associated with the exploration and production of natural gas and oil. Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us on or under other locations where such wastes have been taken for disposal. In addition, a portion of these properties have been operated by third parties whose treatment and disposal or release of wastes was not under our control. These properties and the wastes disposed thereon may be subject to CERCLA, the CWA, the RCRA and analogous state laws. Under such laws, we could be required to remove or remediate previously disposed wastes (including waste disposed of or released by prior owners or operators) or property contamination (including groundwater contamination by prior owners or operators), or to perform remedial plugging or closure operations to prevent future contamination.
 
Waste Discharges.  The CWA and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or an analogous state agency. The CWA and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. Spill prevention, control and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of navigable waters by a petroleum hydrocarbon tank spill, rupture or leak. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. Federal and state regulatory agencies can impose administrative, civil and criminal penalties as well as other enforcement mechanisms for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations. In 2007, 2008 and 2010, we received three separate information requests from the EPA pursuant to Section 308 of the CWA. The information requests required us to provide the EPA with information about releases at three of our facilities and our compliance with spill prevention, control and countermeasure requirements. We have responded to these information requests and no proceeding or enforcement actions have been initiated. We believe that our operations are in substantial compliance with the CWA.
 
Air Emissions.  The CAA and associated state laws and regulations restricts the emission of air pollutants from many sources, including oil and gas operations. New facilities may be required to obtain permits before construction can begin, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. More stringent regulations governing emissions of toxic air pollutants and greenhouse gases (“GHGs”) have been developed by the EPA and may increase the costs of compliance for some facilities.
 
Oil Pollution Act.  The Oil Pollution Act of 1990, as amended (“OPA”) and regulations thereunder impose a variety of requirements on “responsible parties” related to the prevention of oil spills and liability for damages resulting from such spills in United States waters. A “responsible party” includes the owner or operator of an onshore facility, pipeline or vessel, or the lessee or permittee of the area in which an offshore facility is located. OPA assigns liability to each responsible party for oil cleanup costs and a variety of public and private damages. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of a federal safety, construction or operating regulation. If the party fails to report a spill or to cooperate fully in the cleanup, liability limits likewise do not apply. Few defenses exist to the liability imposed by OPA. OPA imposes ongoing requirements on a responsible party, including the preparation of oil spill response plans and


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proof of financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill.
 
National Environmental Policy Act.  Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. The process involves the preparation of either an environmental assessment or environmental impact statement depending on whether the specific circumstances surrounding the proposed federal action will have a significant impact on the human environment. The NEPA process involves public input through comments which can alter the nature of a proposed project either by limiting the scope of the project or requiring resource-specific mitigation. NEPA decisions can be appealed through the court system by process participants. This process may result in delaying the permitting and development of projects, increase the costs of permitting and developing some facilities and could result in certain instances in the cancellation of existing leases.
 
Endangered Species Act.  The Endangered Species Act (“ESA”) restricts activities that may affect endangered or threatened species or their habitats. While some of our operations may be located in areas that are designated as habitats for endangered or threatened species, we believe that we are in substantial compliance with the ESA. However, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected states.
 
Worker Safety.  The Occupational Safety and Health Act (“OSHA”) and comparable state statutes regulate the protection of the health and safety of workers. The OSHA hazard communication standard requires maintenance of information about hazardous materials used or produced in operations and provision of such information to employees. Other OSHA standards regulate specific worker safety aspects of our operations. Failure to comply with OSHA requirements can lead to the imposition of penalties.
 
Safe Drinking Water Act.  The Safe Drinking Water Act (“SDWA”) and comparable state statutes restrict the disposal, treatment or release of water produced or used during oil and gas development. Subsurface emplacement of fluids (including disposal wells or enhanced oil recovery) is governed by federal or state regulatory authorities that, in some cases, includes the state oil and gas regulatory authority or the state’s environmental authority. These regulations may increase the costs of compliance for some facilities.
 
We utilize hydraulic fracturing in our operations as a means of maximizing the productivity of our wells. Recently, there has been a heightened debate over whether the fluids used in hydraulic fracturing may contaminate drinking water supply and proposals have been made to revisit the environmental exemption for hydraulic fracturing under the SDWA or to enact separate federal legislation or legislation at the state and local government levels that would regulate hydraulic fracturing. Both the United States House of Representatives and Senate are considering Fracturing Responsibility and Awareness of Chemicals Act (“FRAC Act”) bills and a number of states, including states in which we have operations, are looking to more closely regulate hydraulic fracturing due to concerns about water supply. A committee of the U.S. House of Representatives is also conducting an investigation of hydraulic fracturing practices. The recent congressional legislative efforts seek to regulate hydraulic fracturing to Underground Injection Control program requirements, which would significantly increase well capital costs. If the exemption for hydraulic fracturing is removed from the SDWA, or if the FRAC Act or other legislation is enacted at the federal, state or local level, any restrictions on the use of hydraulic fracturing contained in any such legislation could have a significant impact on our financial condition and results of operations.
 
Federal agencies are also considering regulation of hydraulic fracturing. The EPA recently asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the SDWA’s Underground Injection Control Program. While the EPA has yet to take any action to enforce or implement this newly asserted regulatory authority, the EPA’s interpretation without formal rule making has been challenged and industry groups have filed suit challenging the EPA’s interpretation. If the EPA prevails in this lawsuit, its interpretation could result in enforcement actions against service providers or companies that used diesel products in the hydraulic fracturing process or could require such providers or companies to conduct additional


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studies regarding diesel in the groundwater. Furthermore, the State of Colorado, in response to an EPA request, has asked companies operating in Colorado, including us, to report whether diesel products were used in the hydraulic fracturing process from 2004 to 2009. In response to this inquiry we consulted our service providers and reported to the State of Colorado that at least nine wells were subject to hydraulic fracturing utilizing fluids that contained chemical products that contained diesel fuel as a component. The State of Colorado may conduct additional investigations related to this inquiry. Any enforcement actions or requirements of additional studies or investigations by the EPA or the State of Colorado could increase our operating costs and cause delays or interruptions of our operations.
 
The EPA is also collecting information as part of a study into the effects of hydraulic fracturing on drinking water. The results of this study, expected in late 2012, could result in additional regulations, which could lead to operational burdens similar to those described above. Disclosure of chemicals used in the hydraulic fracturing process could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. The United States Department of the Interior is considering whether to impose disclosure requirements or other mandates for hydraulic fracturing on federal land.
 
Several states have adopted, and other states are considering adopting, regulations that could restrict or impose additional requirements relating to hydraulic fracturing in certain circumstances including states in which we operate (e.g., Wyoming, Pennsylvania, Texas, Colorado, North Dakota and New Mexico). For example, on March 1, 2011, a bill was introduced in the Texas Senate that, if adopted, would require written disclosure to the Railroad Commission of Texas of specific information about the fluids and additives used in hydraulic fracturing treatment operations, and on March 11, 2011, a bill was introduced in the Texas House of Representatives that would require service companies to submit “master lists” of base fluids, additives and chemical constituents to be used in hydraulic fracturing activities in Texas, subject to certain trade secret protections, to the Railroad Commission. In addition, at least three local governments in Texas have imposed temporary moratoria on drilling permits within city limits so that local ordinances may be reviewed to assess their adequacy to address such activities, while some state and local governments in the Marcellus Shale region in Pennsylvania and New York have considered or imposed temporary moratoria on drilling operations using hydraulic fracturing until further study of the potential environmental and human health impacts by EPA or the relative state agencies are completed. At this time, it is not possible to estimate the potential impact on our business of these state and local actions or the enactment of additional federal or state legislation or regulations affecting hydraulic fracturing. Additionally, some wastewater treatment plants in Pennsylvania have ceased processing wastewater from hydraulic fracturing operations, which will require us to utilize alternate methods of wastewater disposal.
 
In order to address the issue of disclosing the chemicals used in fracturing fluids, we are participating with the state-based Ground Water Protection Council’s effort to make information concerning the chemical products added to fracturing fluids available to the public on an web-based data base at http://fracfocus.org/. This website for the data base is now active and information is being uploaded by oil and gas companies as wells are being completed. The information included on this website is not incorporated by reference in this prospectus.
 
Global Warming and Climate Change.  Recent scientific studies have suggested that emissions of GHGs, including carbon dioxide and methane, may be contributing to warming of the earth’s atmosphere. Both houses of Congress have previously considered legislation to reduce emissions of GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. The EPA has begun to regulate GHG emissions. On December 15, 2009, the EPA published its findings that emissions of GHGs present an endangerment to public heath and the environment. These findings allow the EPA to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the CAA. The EPA has adopted two sets of regulations under the CAA. The first limits emissions of GHGs from motor vehicles beginning with the 2012 model year. The EPA has asserted that these final motor vehicle GHG emission standards trigger CAA construction and operating permit requirements for stationary sources, commencing when the motor vehicle standards take effect on January 2, 2011. On June 3, 2010, the EPA published its final


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rule to address the permitting of GHG emissions from stationary sources under the Prevention of Significant Deterioration and Title V permitting programs. This rule “tailors” these permitting programs to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting. Most recently, on November 30, 2010, the EPA published its final rule expanding the existing GHG monitoring and reporting rule to include onshore and offshore oil and natural gas production facilities and onshore oil and natural gas processing, transmission, storage, and distribution facilities. Reporting of GHG emissions from such facilities will be required on an annual basis, with reporting beginning in 2012 for emissions occurring in 2011. We are required to report our GHG emissions under this rule but are not subject to GHG permitting requirements. Several of the EPA’s GHG rules are being challenged in court proceedings and depending on the outcome of such proceedings, such rules may be modified or rescinded or the EPA could develop new rules.
 
Because regulation of GHG emissions is relatively new, further regulatory, legislative and judicial developments are likely to occur. Such developments may affect how these GHG initiatives will impact our operations. In addition to these regulatory developments, recent judicial decisions have allowed certain tort claims alleging property damage to proceed against GHG emissions sources may increase our litigation risk for such claims. New legislation or regulatory programs that restrict emissions of or require inventory of GHGs in areas where we operate have adversely affected or will adversely affect our operations by increasing costs. The cost increases so far have resulted from costs associated with inventorying our GHG emissions, and further costs may result from the potential new requirements to obtain GHG emissions permits, install additional emission control equipment and an increased monitoring and record-keeping burden.
 
Legislation or regulations that may be adopted to address climate change could also affect the markets for our products by making our products more or less desirable than competing sources of energy. To the extent that our products are competing with higher GHG emitting energy sources such as coal, our products would become more desirable in the market with more stringent limitations on GHG emissions. To the extent that our products are competing with lower GHG emitting energy sources such as solar and wind, our products would become less desirable in the market with more stringent limitations on GHG emissions. We cannot predict with any certainty at this time how these possibilities may affect our operations.
 
Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. If any such effects were to occur, they could adversely affect or delay demand for the oil or natural gas or otherwise cause us to incur significant costs in preparing for or responding to those effects.
 
Foreign Operations.  Our exploration and production operations outside the United States are subject to various types of regulations similar to those described above imposed by the governments of the countries in which we operate, and may affect our operations and costs within those countries. For example, the Argentine Department of Energy and the government of the provinces in which Apco’s oil and gas producing concessions are located have environmental control policies and regulations that must be adhered to when conducting oil and gas exploration and exploitation activities. Future environmental regulation of certain aspects of our operations in Argentina and Columbia that are currently unregulated and changes in the laws or regulations could materially affect our financial condition and results of operations.
 
Other Regulation of the Oil and Gas Industry
 
The oil and natural gas industry is extensively regulated by numerous federal, state, local and foreign authorities, including Native American tribes in the United States. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, and Native American tribes are authorized by statute to issue rules and regulations binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for noncompliance. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these


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burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.
 
The availability, terms and cost of transportation significantly affect sales of oil and natural gas. The interstate transportation and sale for resale of oil and natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the FERC. Federal and state regulations govern the price and terms for access to oil and natural gas pipeline transportation. The FERC’s regulations for interstate oil and natural gas transmission in some circumstances may also affect the intrastate transportation of oil and natural gas.
 
Although oil and natural gas prices are currently unregulated, Congress historically has been active in the area of oil and natural gas regulation. We cannot predict whether new legislation to regulate oil and natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on our operations. Sales of condensate and oil and NGLs are not currently regulated and are made at market prices.
 
Drilling and Production
 
Our operations are subject to various types of regulation at federal, state, local and Native American tribal levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states, and some counties, municipalities and Native American tribal areas where we operate also regulate one or more of the following activities:
 
  •   the location of wells;
 
  •   the method of drilling and casing wells;
 
  •   the timing of construction or drilling activities including seasonal wildlife closures;
 
  •   the employment of tribal members or use of tribal owned service businesses;
 
  •   the rates of production or “allowables;”
 
  •   the surface use and restoration of properties upon which wells are drilled;
 
  •   the plugging and abandoning of wells; and
 
  •   the notice to surface owners and other third parties.
 
State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of natural gas, oil and NGLs within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but there can be no assurance that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and gas that may be produced from our wells, negatively affect the economics of production from these wells, or to limit the number of locations we can drill.
 
Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production facilities and pipelines, and for site restoration, in areas where we operate. The New Mexico Oil Conservation requires the posting of performance bonds to fulfill financial requirements for owners and operators on state land. The Corps and many other state and local authorities also have regulations for plugging and abandonment, decommissioning and site restoration. Although the Corps does not require bonds or other financial assurances, some state agencies and municipalities do have such requirements.


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Natural Gas Sales and Transportation
 
Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production. The FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Various federal laws enacted since 1978 have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in first sales, which include all of our sales of our own production. Under the Energy Policy Act of 2005, the FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties.
 
The FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which we may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas and release of our natural gas pipeline capacity. Commencing in 1985, the FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. The FERC’s initiatives have led to the development of a competitive, open access market for natural gas purchases and sales that permits all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach currently pursued by the FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on our natural gas related activities.
 
Under the FERC’s current regulatory regime, transmission services must be provided on an open-access, nondiscriminatory basis at cost-based rates or at market-based rates if the transportation market at issue is sufficiently competitive. Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Although its policy is still in flux, the FERC has in the past reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our costs of transporting gas to point-of-sale locations.
 
Oil Sales and Transportation
 
Sales of crude oil, condensate and NGLs are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.
 
Our crude oil sales are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate regulation. The FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act and intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is of material difference from those of our competitors.
 
Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors.
 
Operation on Native American Reservations
 
A portion of our leases are, and some of our future leases may be, regulated by Native American tribes. In addition to regulation by various federal, state, local and foreign agencies and authorities, an entirely


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separate and distinct set of laws and regulations applies to lessees, operators and other parties within the boundaries of Native American reservations in the United States. Various federal agencies within the U.S. Department of the Interior, particularly the Bureau of Indian Affairs, the Office of Natural Resources Revenue and the Bureau of Land Management, and the EPA, together with each Native American tribe, promulgate and enforce regulations pertaining to oil and gas operations on Native American reservations. These regulations include lease provisions, royalty matters, drilling and production requirements, environmental standards, Tribal employment contractor preferences and numerous other matters.
 
Native American tribes are subject to various federal statutes and oversight by the Bureau of Indian Affairs and Bureau of Land Management. However, each Native American tribe is a sovereign nation and has the right to enact and enforce certain other laws and regulations entirely independent from federal, state and local statutes and regulations, as long as they do not supersede or conflict with such federal statutes. These tribal laws and regulations include various fees, taxes, requirements to employ Native American tribal members or use tribal owned service businesses and numerous other conditions that apply to lessees, operators and contractors conducting operations within the boundaries of a Native American reservation. Further, lessees and operators within a Native American reservation are subject to the Native American tribal court system, unless there is a specific waiver of sovereign immunity by the Native American tribe allowing resolution of disputes between the Native American tribe and those lessees or operators to occur in federal or state court.
 
Therefore, we are subject to various laws and regulations pertaining to Native American tribal surface ownership, Native American oil and gas leases, fees, taxes and other burdens, obligations and issues unique to oil and gas ownership and operations within Native American reservations. One or more of these requirements, or delays in obtaining necessary approvals or permits pursuant to these regulations, may increase our costs of doing business on Native American tribal lands and have an impact on the economic viability of any well or project on those lands.
 
Employees
 
At March 31, 2011, Williams had approximately 976 full-time employees dedicated to our business, including personnel who are now employed by certain of the subsidiaries that Williams will transfer to us prior to the completion of this offering. This number does not include employees of Williams who provide services to our business and other of Williams’ businesses. Prior to the completion of this offering, the employees of the subsidiaries that Williams will transfer to us will be transferred to an affiliate services company owned by Williams, and we will reimburse the services company for all direct and indirect expenses it incurs or payments it makes in connection with providing personnel to us. As a result, we will have no employees at the completion of this offering.
 
Offices
 
Our principal executive offices are located at One Williams Center, Tulsa, Oklahoma 74172.
 
Legal Proceedings
 
Royalty litigation
 
In September 2006, royalty interest owners in Garfield County, Colorado, filed a class action suit in District Court, Garfield County Colorado, alleging we improperly calculated oil and gas royalty payments, failed to account for the proceeds that we received from the sale of natural gas and extracted products, improperly charged certain expenses and failed to refund amounts withheld in excess of ad valorem tax obligations. Plaintiffs sought to certify a class of royalty interest owners, recover underpayment of royalties, and obtain corrected payments resulting from calculation errors. We entered into a final partial settlement agreement. The partial settlement agreement defined the class members for class certification, reserved two claims for court resolution, resolved all other class claims relating to past calculation of royalty and overriding royalty payments, and established certain rules to govern future royalty and overriding royalty payments. This settlement resolved all claims relating to past withholding for ad valorem tax payments and established a procedure for refunds of any such excess withholding in the future. The first reserved claim is whether we are


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entitled to deduct in our calculation of royalty payments a portion of the costs we incur beyond the tailgates of the treating or processing plants for mainline pipeline transportation. We received a favorable ruling on our motion for summary judgment on the first reserved claim. Plaintiffs appealed that ruling and the Colorado Court of Appeals found in our favor in April 2011. We anticipate knowing later in 2011 whether plaintiffs will pursue any further appeal of the first reserved claim. The second reserved claim relates to whether we are required to have proportionately increased the value of natural gas by transporting that gas on mainline transmission lines and, if required, whether we did so and are thus entitled to deduct a proportionate share of transportation costs in calculating royalty payments. We anticipate trial on the second reserved claim following resolution of the first reserved claim. We believe our royalty calculations have been properly determined in accordance with the appropriate contractual arrangements and Colorado law. At this time, the plaintiffs have not provided us a sufficient framework to calculate an estimated range of exposure related to their claims. However, it is reasonably possible that the ultimate resolution of this item could result in a future charge that may be material to our results of operations.
 
California energy crisis
 
Our former power business was engaged in power marketing in various geographic areas, including California. Prices charged for power by us and other traders and generators in California and other western states in 2000 and 2001 were challenged in various proceedings, including those before the FERC. We have entered into settlements with the State of California (“State Settlement”), major California utilities (“Utilities Settlement”), and others that substantially resolved each of these issues with these parties.
 
Although the State Settlement and Utilities Settlement resolved a significant portion of the refund issues among the settling parties, we continue to have potential refund exposure to nonsettling parties, including various California end users that did not participate in the Utilities Settlement. We are currently in settlement negotiations with certain California utilities aimed at eliminating or substantially reducing this exposure. If successful, and subject to a final “true-up” mechanism, the settlement agreement would also resolve our collection of accrued interest from counterparties as well as our payment of accrued interest on refund amounts. Thus, as currently contemplated by the parties, the settlement agreement would resolve most, if not all, of our legal issues arising from the 2000-2001 California Energy Crisis. With respect to these matters, amounts accrued are not material to our financial position.
 
Certain other issues also remain open at the FERC and for other nonsettling parties.
 
Reporting of natural gas-related information to trade publications
 
Civil suits based on allegations of manipulating published gas price indices have been brought against us and others, in each case seeking an unspecified amount of damages. We are currently a defendant in class action litigation and other litigation originally filed in state court in Colorado, Kansas, Missouri and Wisconsin brought on behalf of direct and indirect purchasers of natural gas in those states. These cases were transferred to the federal court in Nevada. In 2008, the court granted summary judgment in the Colorado case in favor of us and most of the other defendants based on plaintiffs’ lack of standing. On January 8, 2009, the court denied the plaintiffs’ request for reconsideration of the Colorado dismissal and entered judgment in our favor. We expect that the Colorado plaintiffs will appeal, but the appeal cannot occur until the case against the remaining defendant is concluded.
 
In the other cases, our joint motions for summary judgment to preclude the plaintiffs’ state law claims based upon federal preemption have been pending since late 2009. If the motions are granted, we expect a final judgment in our favor which the plaintiffs could appeal. If the motions are denied, the current stay of activity would be lifted, class certification would be addressed, and discovery would be completed as the cases proceed towards trial. Because of the uncertainty around these current pending unresolved issues, including an insufficient description of the purported classes and other related matters, we cannot reasonably estimate a range of potential exposures at this time. However, it is reasonably possible that the ultimate resolution of these items could result in future charges that may be material to our results of operations.


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MANAGEMENT
 
Directors and Executive Officers
 
Set forth below is certain information regarding persons who serve as our executive officers and directors. Prior to the completion of this offering, we may appoint additional persons to serve as our executive officers and directors upon completion of this offering.
 
             
Name
 
Age
 
Position
 
Alan S. Armstrong
    48     Chairman of the Board
Ralph A. Hill
    51     Chief Executive Officer
Donald R. Chappel
    59     Chief Financial Officer
Ted T. Timmermans
    54     Chief Accounting Officer
James J. Bender
    54     General Counsel and Corporate Secretary
Robyn L. Ewing
    55     Chief Administrative Officer
Rodney J. Sailor
    52     Treasurer and Deputy Chief Financial Officer
 
Alan S. Armstrong.  Mr. Armstrong was named Chairman of our Board in April 2011. Mr. Armstrong has been Chief Executive Officer, President and a Director of Williams since January 3, 2011. From February 2002 until January 2011, he was Senior Vice President—Midstream at Williams and acted as President of the Midstream business at Williams. From 1999 to February 2002, Mr. Armstrong was Vice President, Gathering and Processing for Midstream at Williams. From 1998 to 1999 he was Vice President, Commercial Development for Midstream at Williams. As of January 2011, Mr. Armstrong serves as Chairman of the Board and Chief Executive Officer of Williams Partners GP LLC, the general partner of Williams Partners, where he was Senior Vice President—Midstream from February 2010 and Chief Operating Officer and a director from February 2005.
 
Ralph A. Hill.  Mr. Hill was named Chief Executive Officer in April 2011. Prior to becoming our Chief Executive Officer, Mr. Hill was Senior Vice President—Exploration and Production and acted as President of the Exploration and Production business at Williams since 1998. He was Vice President and General Manager of Exploration and Production business at Williams from 1993 to 1998, as well as Senior Vice President and General Manager of Petroleum Services at Williams from 1998 to 2003. Mr. Hill has served as the Chairman of the Board and Chief Executive Officer of Apco since 2002. Mr. Hill has served as a director of Petrolera Entre Lomas S.A. since 2003. He joined Williams in June 1981 as a member of a management training program and has worked in numerous capacities within the Williams organization.
 
Donald R. Chappel.  Mr. Chappel was named Chief Financial Officer in April 2011. Mr. Chappel has been Senior Vice President and Chief Financial Officer of Williams since April 2003. Prior to joining Williams, Mr. Chappel held various financial, administrative, and operational leadership positions. Mr. Chappel is included in Institutional Investor magazine’s Best CFOs listing for 2011, 2010, 2008, 2007, and 2006. Mr. Chappel also serves as Chief Financial Officer and a director of Williams Partners GP LLC, the general partner of Williams Partners. Mr. Chappel was Chief Financial Officer, from August 2007, and a director, from January 2008, of the general partner of Williams Pipeline Partners L.P., until its merger with Williams Partners in August 2010. Mr. Chappel is a director of SUPERVALU Inc. and Energy Insurance Mutual Limited.
 
Ted T. Timmermans.  Mr. Timmermans was named Chief Accounting Officer in April 2011. Mr. Timmermans has been Vice President, Controller and Chief Accounting Officer of Williams since July 2005, and Vice President, Controller and Chief Accounting Officer of Williams Partners GP LLC, the general partner of Williams Partners since September 2005. Mr. Timmermans served as an Assistant Controller of Williams from April 1998 to July 2005. Mr. Timmermans served as Chief Accounting Officer of the general partner of Williams Pipeline Partners L.P., from 2008 until its merger with Williams Partners in August 2010.
 
James J. Bender.  Mr. Bender was named General Counsel and Corporate Secretary in April 2011. Mr. Bender has been Senior Vice President and General Counsel of Williams since December 2002, and General Counsel of Williams Partners GP LLC, the general partner of Williams Partners, since September


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2005. Mr. Bender served as the General Counsel of the general partner of Williams Pipeline Partners L.P., from 2007 until its merger with Williams Partners in August 2010. From June 2000 to June 2002, Mr. Bender was Senior Vice President and General Counsel of NRG Energy, Inc. Mr. Bender was Vice President, General Counsel, and Secretary of NRG Energy from June 1997 to June 2000. NRG Energy, Inc. filed a voluntary bankruptcy petition during 2003 and its plan of reorganization was approved in December 2003.
 
Robyn L. Ewing.  Ms. Ewing was named Chief Administrative Officer in April 2011. Ms. Ewing has been Senior Vice President and Chief Administrative Officer of Williams since April 2008. From 2004 to 2008 Ms. Ewing was Vice President of Human Resources at Williams. Prior to joining Williams, Ms. Ewing worked at MAPCO, which merged with Williams in April 1998. She began her career with Cities Service Company in 1976.
 
Rodney J. Sailor.  Mr. Sailor was named Treasurer and Deputy Chief Financial Officer in April 2011. Mr. Sailor has served as Vice President and Treasurer of Williams since July 2005. He served as Assistant Treasurer of Williams from 2001 to 2005 and was responsible for capital restructuring and capital markets transactions, management of Williams’ liquidity position and oversight of Williams’ balance sheet restructuring program. From 1985 to 2001, Mr. Sailor served in various capacities for Williams. Mr. Sailor was a director of Williams Partners GP LLC, the general partner of Williams Partners, from October 2007 to February 2010. Mr. Sailor has served as a director of Apco since September 2006.
 
Board Composition
 
Our business and affairs will be managed under the direction of our board of directors. Immediately following the completion of this offering, we expect that at least one member of our board of directors will be “independent” under applicable rules of the NYSE. Within one year following the completion of this offering, the board of directors will include three independent directors under applicable rules of the NYSE. The directors will have discretion to increase or decrease the size of the board of directors.
 
Status as a “Controlled Company”
 
Upon completion of this offering and prior to the anticipated spin-off of our stock to Williams’ stockholders, Williams will control a majority of the voting power for the election of our directors, and we will therefore be a “controlled company” under NYSE corporate governance standards. A controlled company need not comply with NYSE corporate governance rules that require its board of directors to have a majority of independent directors and independent compensation and nominating and corporate governance committees. We intend to avail ourselves of the controlled company exception under the NYSE corporate governance standards. Notwithstanding our status as a controlled company, we will remain subject to the NYSE corporate governance standard that requires us to have an audit committee composed entirely of independent directors. As a result, we must have at least one independent director on our audit committee by the date our Class A common stock is listed on the NYSE, or the listing date, at least two independent directors within 90 days of the listing date and at least three independent directors within one year of the listing date.
 
If Williams completes a spin-off of all of the shares of our common stock that it owns to its stockholders or holds less than a majority of the voting power for any other reason, we will no longer be a controlled company within the meaning of the NYSE corporate governance standards. Once we cease to be a controlled company, our board of directors will be required to have a compensation committee and a nominating and governance committee, each with at least one independent director. Within 90 days of ceasing to be a controlled company, we will be required to have each of a compensation committee and a nominating and governance committee with a majority of independent directors, and within one year of ceasing to be a controlled company, a majority of our board of directors must be comprised of independent directors.


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Board Committees
 
Audit committee
 
Prior to completion of this offering, our board of directors will establish an audit committee, composed of           directors. The audit committee will consist of the number of independent directors as required by the applicable NYSE rules within the applicable time periods following the completion of this offering. The board of directors will determine that all of the audit committee members are financially literate.
 
The audit committee’s functions will include providing assistance to the board of directors in fulfilling its oversight responsibility relating to our financial statements and the financial reporting process, compliance with legal and regulatory requirements, the qualifications and independence of our independent registered public accounting firm, our system of internal controls, the internal audit function, our code of ethical conduct, retaining and, if appropriate, terminating the independent registered public accounting firm, and approving audit and non-audit services to be performed by the independent registered public accounting firm. In addition, as the audit committee will be made up exclusively of independent directors, it will be responsible for the future amendment or establishment of all related party transactions between us and Williams.
 
In compliance with the NYSE listing standards, our audit committee will annually conduct a self-evaluation to determine whether it is functioning effectively. In addition, the audit committee will prepare the report of the committee required by the rules and regulations of the SEC to be included in our annual proxy statement.
 
Our board of directors will adopt a written charter for our audit committee, which will be available on our corporate website prior to or upon completion of this offering.
 
Other Committees
 
Because we will be a “controlled company” within the meaning of the NYSE corporate governance standards, we will not be required to, and will not, have a compensation or nominating and governance committee. While we are a controlled company, Williams’ nominating and corporate governance committee will identify and evaluate potential candidates for nomination as a director and recommend any such candidates to our board of directors.
 
Our board of directors may form a compensation committee and/or a nominating and governance committee after the completion of this offering.
 
Compensation Committee Interlocks and Insider Participation
 
Initially, compensation recommendations regarding our executive officers may be made by the Williams compensation committee. Our board of directors may appoint a successor compensation committee after the completion of this offering. None of our executive officers serves, or has served during the last completed fiscal year, on the compensation committee or board of directors of any other company that has one or more executive officers serving on our compensation committee or board of directors.
 
Code of Ethics
 
In connection with this offering, our board of directors will adopt a Code of Ethics for Senior Officers that applies to our Chief Executive Officer, Chief Financial Officer and Controller, or persons performing similar functions. Our code of ethics will be publicly available on our corporate website. Any waiver of our code of ethics with respect to our Chief Executive Officer, Chief Financial Officer and Controller, or persons performing similar functions may only be authorized by our audit committee and will be disclosed as required by applicable law.


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


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The principles of Williams’ pay philosophy influence the design and administration of its pay programs. Decisions about how to pay NEOs are based on these principles. The Committee uses several different types of pay that are linked to both long-term and short-term performance in the executive compensation programs. Included are long-term incentives, annual cash incentives, base pay and benefits. The chart below illustrates the linkage between the types of pay used and the pay principles.
 
                                 
    Long-term
    Annual Cash
             
Williams’ Pay Principles
  Incentives     Incentives     Base Pay     Benefits  
 
Pay should reinforce business objectives and values
    ü       ü       ü          
A significant portion of an NEO’s total pay should be variable based on performance
    ü       ü                  
Incentive pay should balance long-term, intermediate and short-term performance
    ü       ü                  
Incentives should align interest of NEOs with stockholders
    ü       ü                  
Pay opportunity should be competitive
    ü       ü       ü       ü  
A portion of pay should be provided to compensate for the core activities required for performing in the role
                    ü       ü  
Pay should foster a culture of collaboration with shared focus and commitment to Williams
    ü       ü                  
 
Looking Forward—Our pay philosophy, which will serve to influence the design and delivery of our pay programs, has been approved by the Committee. Our approved pay philosophy is substantially the same as Williams’ pay philosophy.
 
Williams’ 2010 Compensation Summary
 
In 2010, Williams, including its Exploration and Production business unit, continued to focus on creating stockholder value by delivering solid financial and operational performance. The effects of the economic recession during late 2008 and 2009 eased during 2010. Crude oil and NGL prices returned to attractive levels, but natural gas prices remained low. Williams continued to respond to the changing landscape and completed a number of significant business transactions as detailed on page 106. Williams took several actions, described below, to ensure that its executive pay program remains affordable and competitive in the current market and after market conditions improve.
 
Williams’ 2010 Pay Decisions
 
As indicated above, significant consideration was given to the need to balance Williams’ pay philosophy and practices with affordability and sustainability. Williams continued to grant long-term incentives in the form of performance-based restricted stock units (“RSUs”), stock options and time-based RSUs in 2010 to emphasize its commitment to pay for performance.
 
Consistent with its commitment to provide a meaningful connection between pay and performance, Williams has granted performance-based RSUs to NEOs since 2004. The performance-based RSUs granted in 2008 for the 2008-2010 performance period did not meet threshold targets set at the beginning of the period as a result of the global economic crisis. The challenging performance targets established in 2008 for the three-year performance period included economic assumptions that could not anticipate the significant decline in economic conditions. In accordance with the design of the awards, these awards were cancelled. This is the second consecutive year the performance-based RSUs were not earned. This resulted in each NEO losing a significant portion of pay that was targeted for 2007-2009 and 2008-2010.
 
It is important to note that the Summary Compensation Table displays a value for equity awards on the date of grant. This approach does not reflect the actual realized value associated with equity award grants. While the grant date values make it appear that NEOs’ pay has been fairly consistent in recent years, the value realized by the NEOs has significantly declined in recent years due to Williams’ pay for performance philosophy.


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Historically, Williams sets performance targets for its Annual Incentive Program (“AIP”) during the first quarter. The targets established in 2010 anticipated an improving economic environment and required significantly improved performance over 2009. While EVA® performance exceeded 2009 levels, the 2010 AIP results paid less than 2009 due to higher 2010 performance targets.
 
With respect to base salary, Mr. Malcolm did not receive a base pay increase in 2009 or 2010. The remaining NEOs did not receive a base pay increase in 2009 and received a two percent base pay increase in 2010, other than Ms. Ewing who received a 3.5% increase in 2010.
 
Williams’ Plan Design Decisions
 
The Committee regularly reviews Williams’ existing pay programs to ensure Williams’ ability to attract and retain the talent needed to deliver the strong financial and operating performance necessary to create stockholder value while ensuring its program effectively links pay to the performance of Williams. As part of this process in 2010, the Committee reached several important decisions. The Committee decided to continue awarding a significant portion of long-term incentive awards in the form of performance-based restricted stock units (“RSUs”). The metric for these awards utilizes absolute and relative TSR. NEOs will earn their targeted performance-based RSUs for the 2010 to 2012 period only if Williams delivers positive absolute TSR and also achieves solid TSR in relation to the Williams’ comparator group of companies. The Committee believes it is important to include both relative and absolute TSR to ensure that results are impacted by the absolute TSR actually delivered to stockholders, as well as the company’s performance relative to comparator companies. Williams’ commitment to these awards combined with the utilization of both relative and absolute TSR metrics demonstrates the emphasis on linking pay to long-term performance and aligning its pay programs with the interest of stockholders.
 
Williams continues to deliver a significant portion of equity in performance-based awards and stock options because these awards have the strongest alignment to stockholders. Shown below is the long-term incentive mix for the NEOs under Williams’ compensation program for 2010.
 
                 
    Mr. Malcolm     Other NEOs  
 
Performance-Based RSUs
    50 %     35 %
Stock Options
    50 %     30 %
Time-Based RSUs
    0 %     35 %
 
As to Williams’ AIP, EVA® improvement remained the performance metric in 2010. The difficult economic and commodity price environment made establishing a target level of performance very challenging. In anticipation of an improving economic environment, the Committee approved a 2010 EVA® performance target that was substantially higher than targets established for 2009. The Committee also continued a decision reached in 2009 to require that the AIP performance necessary to move from threshold to target was doubled from 2008 levels. Likewise, the performance required to move from target to stretch was doubled from 2008 levels. This design attempts to keep the AIP as a meaningful performance incentive throughout the year while ensuring a payout significantly above target only occurs if Williams significantly exceeds established performance targets.
 
Mitigating Risk
 
After a thorough review and analysis, it was determined that the risks arising from Williams’ compensation policies and practices are not reasonably likely to have a material adverse effect on Williams.
 
Williams’ Compensation Recommendation and Decision Process
 
Role of Williams’ Management
 
In order to make pay recommendations, management provides the Williams CEO with data from the annual proxy statements of companies in Williams’ comparator group along with pay information compiled from nationally recognized executive and industry related compensation surveys. The survey data is used to confirm that pay practices among companies in the comparator group are aligned with the market as a whole.


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Role of Williams’ CEO
 
Before recommending base pay adjustments and long-term incentive awards to the Committee, Williams’ CEO reviews the competitive market information related to each of Williams other named executive officers while also considering internal equity and individual performance.
 
For the annual cash incentive program, the Williams CEO’s recommendation is based on EVA® attainment with a potential adjustment for individual performance. Individual performance includes business unit EVA® results for the business unit leaders, achievement of business goals and demonstrated key leadership competencies (for more on leadership competencies, see the section entitled “Base Pay” in this Compensation Discussion and Analysis). The modifications made are fairly modest. For 2010 the adjustments made to the NEOs’ annual cash incentive awards were in total less than 5%.
 
Role of the Other NEOs
 
The NEOs, and Williams’ other named executive officers, have no role in setting compensation for any of the NEOs.
 
Role of Williams’ Compensation Committee
 
For all NEOs, except the Williams CEO, the Committee reviews the Williams CEO’s recommendations, supporting market data and individual performance assessments. In addition, the Committee’s independent compensation consultant, Frederic W. Cook & Co., Inc., reviews all of the data and advises on the reasonableness of the Williams CEO’s pay recommendations.
 
For the Williams CEO, the Williams board of directors meets in executive session without management present to review the Williams CEO’s performance. In this session, the Williams board of directors reviewed:
 
  •  Evaluations of the Williams CEO completed by the board members and the executive officers (excluding the Williams CEO);
 
  •  The Williams CEO’s written assessment of his/her own performance compared with the stated goals; and
 
  •  EVA® performance of the Company relative to established targets as well as the financial and safety metrics presented as a supplement to EVA® performance.
 
The Committee uses these evaluations and competitive market information provided by its independent compensation consultant to determine the Williams CEO’s long-term incentive amounts, annual cash incentive target, base pay and any performance adjustments to be made to the Williams CEO’s annual cash incentive payment.
 
Role of the Independent Compensation Consultant
 
Frederic W. Cook & Co., Inc. assists the Committee in determining or approving the compensation for Williams’ executive officers. Frederick W. Cook & Co., Inc. will serve as the independent compensation consultant to the Committee as the Committee provides input and analyzes and approves our compensation and benefit plans and policies until our compensation committee is formed.
 
To assist the Committee in discussions and decisions about compensation for the NEOs, the Committee’s independent compensation consultant presents competitive market data that includes proxy data from the approved Williams’ comparator group and published compensation data, using the same surveys and methodology used for the other NEOs (described in the “Role of Management” section in this Compensation Discussion and Analysis). The Williams comparator group is developed by the Committee’s independent compensation consultant, with input from management, and is approved by the Committee.


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


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    Williams’ 2010
    Our
 
    Comparator
    Comparator
 
    Company
    Company
 
Company Name
  Group     Group  
 
Newfield Exploration Co. 
            X  
NiSource Inc. 
    X          
Noble Energy Inc. 
    X       X  
Oneok Inc. 
    X          
Petrohawk Energy Corp. 
            X  
Pioneer Natural Resources Co. 
            X  
Plains All American Pipeline
    X          
QEP Resources Inc. 
            X  
Questar Corp. 
    X          
Range Resources Corp. 
            X  
Sandridge Energy Inc. 
            X  
Sempra Energy
    X          
SM Energy Co. 
            X  
Southern Union Co. 
    X          
Southwestern Energy Co. 
            X  
Spectra Energy Corp
    X          
Ultra Petroleum Corp. 
            X  
XTO Energy Inc. (acquired by ExxonMobil—removed)
    X          
 
Characteristics of Our Comparator Group
 
Our comparator group focuses on companies that work in the same industry segment and reflect where we compete for business and talent. Companies in the comparator group have a range of revenues, assets and market capitalization as well as a range of operational measures such as production and reserves. Our comparator group is appropriately scaled and these companies’ primary business is similar to ours and is subject to similar economic circumstances.
 
Williams’ Pay Setting Process
 
Setting pay for our NEOs historically has been an annual process that occurs during the first quarter of the year. The Committee completes a review to ensure that pay is competitive, equitable and encourages and rewards performance.
 
The compensation data of Williams’ comparator group disclosed in proxy statements is the primary market data used when benchmarking the competitive pay of the NEOs. Aggregate market data obtained from recognized third-party executive compensation survey companies (e.g. Towers Watson, Mercer, AonHewitt) is used to supplement and validate Williams’ comparator group market data for these executive officers. Typically, the Committee is presented with a range of annual revenues of the companies whose data is included in the aggregate analysis provided by the third party survey, but does not know the identities of the specific companies included.
 
Although the Committee reviews relevant data as it designs compensation packages, setting pay is not an exact science. Since market data alone does not reflect the strategic competitive value of various roles within Williams, internal pay equity is also considered when making pay decisions. Because Williams applies an enterprise-wide perspective to promote collaboration and ensure overall success, paying the executive officers equitably is important. Other considerations when making pay decisions for the NEOs include historical pay and tally sheets that include annual pay and benefit amounts, wealth accumulated over the past five years and the total aggregate value of the NEOs’ equity awards and holdings.

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When setting pay, Williams determines a target pay mix (distribution of pay among long-term incentives, annual incentives, base pay and other forms of compensation) for the NEOs. Consistent with Williams’ pay-for-performance philosophy, the actual amounts paid, excluding benefits, are determined based on Williams’ and individual performance. The following table provides the 2010 target pay mix by NEO.
 
                                 
    2010 Target Pay Mix by NEO  
    Base
    Annual
    Long-Term
       
    Salary     Incentive     Incentive     Total  
 
Mr. Malcolm
    14 %     14 %     72 %     100 %
Mr. Chappel
    20 %     15 %     65 %     100 %
Mr. Hill
    19 %     13 %     68 %     100 %
Mr. Bender
    23 %     15 %     62 %     100 %
Mrs. Ewing
    22 %     14 %     64 %     100 %
 
Game Plan for Growth
 
Williams’ goal for 2010 was to grow the natural gas-based businesses in order to generate superior value for investors in Williams and Williams Partners. The performance of the NEOs and other employees is measured by progress made towards the Game Plan for Growth goals. Individual adjustments within Williams’ annual cash incentive program are based on each NEO’s contributions to the Game Plan for Growth. The goals defined in the Game Plan for Growth include:
 
Invest in Growth
 
  •  Enhance Williams’ relationships with customers so that Williams continues to grow its competitive advantage and earn recognition for the reliable service and value that is essential to their success.
 
  •  Invest in Williams’ businesses in ways that grow EVA®, earnings and cash flows for Williams and Williams Partners; meet Williams’ customers’ needs; and enhance Williams’ competitive position.
 
  •  Pursue additional investment opportunities in new and emerging basins to capture significant, strategic, long-lived growth.
 
  •  Expand Williams’ intellectual, operational and leadership capacities so that Williams can successfully grow and develop high-performing employees and businesses.
 
Support Williams’ Growth
 
  •  Comply with applicable laws and regulations.
 
  •  Continuously improve Williams’ safety and environmental compliance performance in all of Williams’ operations.
 
  •  Assess and manage risks effectively; take appropriate, well-considered risks in order to create value. Exercise financial discipline so that Williams’ and Williams Partners’ financial condition is strong and credit ratings are investment-grade.
 
Deliver the Growth
 
  •  Achieve or exceed Williams’ EVA®, earnings and cash flow goals. Also achieve attractive growth in value for Williams and Williams Partners investors.
 
  •  Openly engage with communities, vendors and other stakeholders crucial to Williams’ success so that Williams grows the competitive advantage we enjoy as a preferred partner.
 
  •  Operate the business in a way that grows Williams’ reputation as a leader in environmental stewardship.


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During 2010, Williams made significant strides toward achieving Williams’ Game Plan for Growth. The following are some of the most impactful 2010 accomplishments:
 
  •  Completed the transformation of Williams Partners to a large diversified master limited partnership with reliable access to capital markets. This was accomplished through:
 
  •  Strategic asset drop-downs from Williams to Williams Partners; and
 
  •  The merger of Williams Partners and Williams Pipeline Partners L.P.
 
  •  Completed significant asset acquisitions in the Marcellus Shale. All of Williams’ businesses have a strategic presence in the Marcellus Shale allowing Williams to leverage the strengths of each business unit;
 
  •  Invested $2.8 billion in drilling activity and acquisitions in Williams’ Exploration & Production business. This included $1.7 billion related to acquisitions in the Bakken and Marcellus Shale areas. The Bakken Shale transaction creates more diversification in Williams’ Exploration and Production business by expanding the long-term crude oil portfolio;
 
  •  Invested $1 billion in capital and investment expenditures in the midstream businesses and invested $473 million in capital expenditures in Williams’ gas pipelines business in 2010;
 
  •  Expanded ownership of the Overland Pass Pipeline;
 
  •  Maintained Williams’ investment grade credit rating while achieving an upgrade of Williams Partners to an investment grade credit rating; and
 
  •  In addition to continuing to expand Williams’ natural gas businesses and drive stockholder value, Williams was recognized for its efforts to make Williams a great place to work for its employees;
 
  •  The Houston Business Journal recognized Williams as a Best Place to Work in Houston among companies not based in Houston. This was the third year in a row Williams was recognized on the Best Place to Work in Houston list;
 
  •  Utah Business magazine named Williams as a finalist in its Best Companies to Work for program, where Williams was recognized as one of the four best medium-sized companies in Utah for the second year in a row;
 
  •  OKCBiz magazine recognized Williams on its Best Places to Work in Oklahoma list for the third year in a row; and
 
  •  Tulsa Business Journal’s Economic Development Impact Awards recognized Williams as a finalist for the Best Workplace for Young Professionals.
 
How Williams Determines the Amount for Each Type of Pay
 
Long-term incentives, annual cash incentives, base pay and benefits accomplish different objectives.
 
Long-Term Incentives
 
Williams awards long-term incentives to reward performance and align NEOs with long-term stockholder interests by providing NEOs with an ownership stake in Williams, encouraging sustained long-term performance and providing an important retention element to their compensation program. Long-term incentives are provided in the form of equity and may include performance based RSUs, stock options and time-based RSUs.
 
To determine the value for long-term incentives granted to an NEO each year, Williams considers the following factors:
 
  •  the proportion of long-term incentives relative to base pay;
 
  •  the NEO’s impact on Williams’ performance and ability to create value;


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  •  long-term business objectives;
 
  •  awards made to NEOs in similar positions within Williams’ comparator group of companies
 
  •  the market demand for the NEO’s particular skills and experience;
 
  •  the amount granted to other NEOs in comparable positions at Williams;
 
  •  the NEO’s demonstrated performance over the past few years; and
 
  •  the NEO’s leadership performance.
 
The allocation of the long-term incentive program for 2010 is shown on page 105. The long-term incentive mix for the NEOs is shown on page 101.
 
The primary objectives for each type of equity awarded are shown below. The size of the circles in the chart indicates how closely each equity type aligns with each objective.
 
                 
            Drives operating
   
    Stockholder
      and financial
  Retention
Equity type and Performance Drivers   alignment   Stock ownership   performance   Incentive
 
Performance-Based RSUs
Absolute and Relative TSR
  l   l   l    
Stock Options
Stock Price Appreciation
  l   l   l    
Time-Based RSUs
Stock Price Appreciation
  l   l       l
 
2010 Performance-Based RSUs
 
Performance-based RSU awards further strengthen the relationship between pay and performance and over time will more closely link the long-term pay of the NEOs to the experience of Williams’ long-term stockholders.
 
Williams believes it is important to measure TSR on both an absolute and a relative basis. In absolute terms, Williams wants to ensure it is delivering a responsible return to stockholders. Additionally, Williams believes awards should be influenced by how TSR compares to the TSR of companies in Williams’ comparator group. Shown in the chart below are the absolute and relative TSR targets for the performance-based restricted stock unit awards for the 2010 to 2012 performance period and the continuum that will determine the resulting potential payout level:
 
 
2008 Performance-Based RSUs
 
The performance cycle for Williams’ 2008 performance-based RSUs ended in 2010. As discussed earlier, Williams did not attain threshold performance during the three-year period as a result of the global economic crisis. No performance-based RSU awards that were granted in 2008 were paid out under this plan. This resulted in each NEO losing a significant portion of pay that was targeted for 2008-2010. The performance goals for this award were set during a less volatile time based on market guidance and expectations for


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Williams’ performance at that time. The following is a chart of the threshold, target and stretch goals that were established in early 2008.
 
     
EVA®
  Payout Level as a % of Target
(Millions)
  (Attainment %)
 
    Threshold
$191
  (where incentives start to be earned)
$299
  100%
$407
  200%
 
Stock Option Awards
 
For recipients, stock options have value only to the extent the price of the common stock is higher on the date the options are exercised than it was on the date the options were granted.
 
Time-Based RSUs
 
Williams uses this type of equity to retain executives and to facilitate stock ownership. The use of time-based RSUs is also consistent with the practices of Williams’ comparator group of companies.
 
Grant Practices
 
Historically, the Committee typically approves the annual equity grant in February or early March of each year shortly after the annual earnings release. The grant date for awards is on or after the date of such approval to ensure the market has time to absorb material information disclosed in the earnings release and reflect that information in the stock price.
 
The grant date for off-cycle grants for individuals who are not Williams’ executive officers, for reasons such as retention or new hires, is the first business day of the month following the approval of the grant. By using this consistent approach, Williams removes grant timing from the influence of the release of material information.
 
Looking Forward—We intend to establish an equity plan prior to completion of this offering. The design of the plan and the form, terms and conditions of future long-term incentive awards available for grant thereunder have not been determined at this time.
 
Annual Cash Incentives
 
Williams provides annual cash incentives to encourage and reward NEOs for making decisions that improve Williams’ performance as measured by EVA®. EVA® measures the value created by a company. Simply stated, it is the financial return in a given period less the capital charge for that period. The calculation used is as follows:
 
                 
EVA®
  =   Adjusted Net Operating
Profits after Taxes
(NOPAT)
  Less   Adjusted Capital Charge (the amount
of capital invested by Williams
multiplied by the cost of capital)
 
Generating profits in excess of both operating and capital costs (debt and equity) creates EVA®. If EVA® improves, value has been created. The objectives of the EVA® -based incentive program are to:
 
  •  Motivate and incent management to choose strategies and investments that maximize long-term stockholder value;
 
  •  Offer sufficient incentive compensation to motivate management to put forth extra effort, take prudent risks and make tough decisions to maximize stockholder value;
 
  •  Provide sufficient total compensation to retain management; and


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  •  Limit the cost of compensation to levels that will maximize the wealth of current stockholders without compromising the other objectives.
 
The EVA® Calculation
 
EVA® is first calculated as NOPAT less Capital Charge. Williams’ incentive program allows for the Committee to make adjustments to EVA® calculations to reflect certain business events. After studying companies that utilize EVA® as an incentive measure, Williams determined that it is standard practice to make adjustments to EVA® calculations to create better alignment with stockholders.
 
When determining which adjustments are appropriate, Williams is guided by the principle that incentive payments should not result in unearned windfalls or impose undue penalties. In other words, Williams makes adjustments to ensure NEOs are not rewarded for positive results they did not facilitate nor are they penalized for certain unusual circumstances outside their control. Williams believes the adjustments improve the alignment of incentives with stockholder value creation and ensure EVA® is an incentive measure that effectively encourages NEOs to take actions to create value for stockholders. The categories of potential adjustments to the EVA® calculation are:
 
  •  Gains, losses and impairments;
 
  •  Mark-to-market, commodity price collar and construction work-in-progress; and
 
  •  Other unusual items that could result in unearned windfalls or undue penalties to NEOs such as certain litigation matters and natural disasters.
 
Williams’ management regularly reviews with the Committee a supplemental scorecard reflecting Williams’ segment profit, earnings per share, cash flow from operations and safety to provide updates regarding Williams’ performance as well as to ensure alignment between these measures and EVA®. This scorecard provides the Committee with additional data to assist in determining final AIP awards. There is strong correlation between Williams’ EVA® performance and other metrics included on the supplemental scorecard.
 
The Committee’s independent compensation consultant annually compares Williams’ relative performance on various measures, including total stockholder return, earnings per share and cash flow, with Williams’ comparator group of companies. The Committee also uses this analysis to validate the reasonableness of the EVA® results.
 
Annual Cash Incentives—Target
 
The starting point to determine annual cash incentive targets (expressed as a percent of base pay) is competitive market information, which gives Williams an idea of what other companies target to pay in annual cash incentives for similar jobs. Williams also considers the internal value of each job—i.e., how important the job is to executing its strategy compared to other jobs in Williams—before the target is set for the year. The annual cash incentive targets as a percentage of base pay for the NEOs in 2010 were as follows:
 
         
Mr. Malcolm
    100 %
Mr. Chappel
    75 %
Other NEOs
    65 %
 
Annual Cash Incentives—Actual
 
For NEOs, the annual cash incentive program is funded when Williams attains an established level of EVA® performance. Applying EVA® measurement to this annual cash incentive process encourages management to make business decisions that help drive long-term stockholder value. To determine the funding of the annual cash incentive, Williams uses the following calculation for each NEO:
 
                 
Base Pay received in 2010
  X   Incentive Target %   X   EVA® Goal Attainment %


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Actual payments may be adjusted upwards to recognize individual performance that exceeded expectations, such as success toward the Game Plan for Growth and individual goals and successful demonstration of the leadership competencies discussed in the Base Pay section on page 111. Payments may also be adjusted downwards if performance warrants.
 
How Williams Sets the EVA® Goals
 
Setting the EVA® goals for the annual cash incentive program begins with internal budgeting and planning. This rigorous process includes an evaluation of the challenges and opportunities for Williams and each of its business units. The key steps are as follows:
 
  •  Business and financial plans are submitted by the business units and consolidated by the corporate planning department.
 
  •  The business and financial plans are reviewed and analyzed by Williams’ chief executive officer, chief financial officer and other named executive officers.
 
  •  Using the plan guidance, Williams’ management establishes the EVA® goal and recommends it to the Committee.
 
  •  The Committee reviews, discusses and makes adjustments as necessary to management’s recommendations and sets the goal at the beginning of each fiscal year.
 
  •  Thereafter, progress toward the goal is regularly monitored and reported to the Committee throughout the year.
 
2010 EVA® Goal for the Annual Cash Incentive Program
 
The attainment percentage of EVA® goals results in payment of annual cash incentives along a continuum between threshold and stretch levels, which corresponds to 0% through 250% of the NEO’s annual cash incentive target. The chart below shows the EVA® improvement goals for the 2010 annual cash incentive and the resulting payout level. It is important to note that setting the EVA® goal for 2010 was again challenging considering the uncertain economic and commodity price environment. The EVA® goal established in 2010 was more challenging than the 2009 EVA® goal, reflecting an anticipated improvement in economic conditions.
 
     
EVA®
  Payout Level as a % of Target
(Millions)
  (Attainment %)
 
    Threshold
($563)
  (where incentives start to be earned)
($347)
  100%
($131)
  200%
 
As noted, EVA® considers both financial earnings and a cost of capital in measuring performance. The two main components of EVA® are NOPAT and a charge for the cost of capital. EVA®, like other performance metrics, has been impacted by the economic environment. NOPAT improved from 2009, but fell slightly below the 2010 plan while the 2010 charge for the cost of capital was better than 2009 and better than plan. As a result of the NOPAT and capital charge changes, total EVA® improved significantly from 2009 but was only modestly above the 2010 plan target.
 
Based on EVA® performance relative to the established goals, the Committee certified performance results of ($337) million in EVA® and approved payment of the annual cash incentive program at 105% of target.
 
Looking Forward—We intend to establish an annual cash incentive program to reward our executive officers. At this time, the design of the program, including the target opportunity and the performance metric(s), has not been determined.


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Base Pay
 
Base pay compensates NEOs for carrying out the duties of their jobs, and serves as the foundation of Williams’ pay program. Most other major components of pay are set based on a relationship to base pay, including annual and long-term incentives and retirement benefits.
 
Base pay for NEOs is set considering the market median, with potential individual variation from the median due to experience, skills and sustained performance of the individual as part of Williams’ pay-for-performance philosophy. Performance is measured in two ways: through the “Right Results” obtained in the “Right Way.” Right Results considers the NEOs’ success in attaining their annual goals as they relate to the Game Plan for Growth, business unit strategies and personal development plans. Right Way reflects the NEOs’ behavior as exhibited through Williams’ leadership competencies. The following table contains these competencies grouped within Williams’ five leadership areas.
 
                 
    INSPIRE A
          OPTIMIZE
MODEL THE
  SHARED
  CHAMPION
  LEVERAGE
  BUSINESS
WAY
 
VISION
 
INNOVATION
 
TALENT
 
PERFORMANCE
 
Caring About People   Enterprise Perspective   Change Leadership   Building Effective Teams   Business Acumen
Integrity
  Vision and Strategic Perspective   Entrepreneurial Spirit   Communication   Customer and Market Focus
Loyalty and Commitment       Promoting Diversity and Creativity   Developing People Resources   Decision Making
        Willingness to Take Risks   Empowering Others   Drive for Results
            Managerial Courage   Functional/Technical Skills
            Motivating and Inspiring Others    
 
Looking Forward—Our pay philosophy and comparator company group has been determined. This philosophy along with comparator company pay information will influence the base pay decisions of our executive officers. We currently expect this to be applied beginning in 2012.
 
Benefits
 
Consistent with Williams’ philosophy to emphasize pay for performance, NEOs receive very few perquisites (perks) or supplemental benefits. They are as follows:
 
  •  Retirement Restoration Benefits.   All NEOs participate in Williams’ qualified retirement program on the same terms as other Williams’ employees. Williams offers a retirement restoration plan to NEOs to maintain a proportional level of pension benefits to officers as provided to other employees. The Code limits qualified pension benefits based on an annual compensation limit. For 2010, the limit was $245,000. Any reduction in an NEO’s pension benefit in the tax-qualified pension plan due to this limit is made up for (subject to a cap) in the unfunded restoration retirement plan. Benefits for NEOs are calculated using the same benefit formula as that used to calculate benefits for all employees in the qualified pension plan. The value of pay in the form of stock option or other equity is not used in the formula to calculate benefits under the pension plan or restoration plan for NEOs, which is consistent with the treatment for all employees. Additionally, Williams does not provide a nonqualified benefit related to the qualified 401(k) defined contribution retirement plan.
 
  •  Financial Planning Allowance.  Williams offers financial planning to the NEOs to provide expertise on current tax laws with personal financial planning and preparations for contingencies such as death and disability. In addition, by working with a financial planner, executive officers gain a better understanding of and appreciation for the programs Williams provides, which helps to maximize the retention and engagement aspects of the dollars Williams spends on these programs.


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  •  Home Security.  Williams paid 2010 home security system and monitoring fees for its former CEO, Mr. Malcolm.
 
  •  Personal Use of Williams’ Company Aircraft.  Williams provides limited personal use of Williams’ company aircraft at the Williams CEO’s discretion. There was limited personal use of Williams’ company aircraft by the NEOs in 2010 and the details are provided in the footnote to the Summary Compensation Table.
 
  •  Event Center.  Williams has a suite and club seats at an event center that were purchased for business purposes. If it is not being used for business purposes, Williams makes them available to all employees, including the NEOs, as a form of reward and recognition.
 
  •  Executive Physicals.  The Committee approved physicals for the NEOs beginning in 2009. Executive officer physicals align with Williams’ wellness initiative as well as assist Williams in mitigating risk. These physicals reduce vacancy succession risk because they help to identify and prevent issues that would leave a role vacated unexpectedly.
 
Looking Forward—Our pay philosophy has been determined. This information and competitive market information will influence the design of our benefits program. The form of these designed benefit programs will influence the offering of any supplemental benefits. Any perquisites to be offered have not been defined at this time.
 
Additional Components of Williams’ Executive Compensation Program
 
In addition to establishing the pay elements described above, Williams has adopted a number of policies to further the goals of the executive compensation program, particularly with respect to strengthening the alignment of NEOs’ interests with stockholder long-term interests.
 
Recoupment Policy
 
In 2008, the Committee approved a recoupment policy to allow Williams to recover incentive-based compensation from executive officers in the event Williams is required to restate the financial statements due to fraud or intentional misconduct. The policy provides the Board discretion to determine situations where recovery of incentive pay is appropriate.
 
Stock Ownership Guidelines
 
All NEOs must hold an equity interest in Williams.  The chart below shows the NEO stock ownership guidelines, which have been in effect since 2005:
 
                         
    Holding Requirement as
       
    a multiple of Base Pay     Time Frame for
 
Position
  2010     2011     Compliance  
 
Mr. Malcolm
    5       6       5 Years  
Other NEOs
    3       3       5 Years  
 
Annually the Committee reviews the guidelines for competitiveness and alignment with best practice and monitors the NEOs’ progress toward compliance. The Committee increased the Williams CEO’s ownership guideline from five times base pay to six times base pay beginning in 2011. Shares owned outright and unvested performance-based and time-based RSUs count as owned for purposes of the program. Stock options are not included. The Committee maintains discretion to modify the guidelines in special circumstances of financial hardship such as illness of the NEO or a family member.
 
Derivative Transactions
 
Williams’ insider trading policy applies to transactions in positions or interests whose value is based on the performance or price of the common stock. Because of the inherent potential for abuse, Williams prohibits


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


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notice required by the NEOs’ change in control agreements in order to effect the change in 2012. After this provision is implemented, Williams will no longer provide additional compensation to address excise taxes. The Committee continues to believe that offering a change in control program is appropriate and critical to attracting and retaining executive talent and keeping them aligned with Williams’ stockholder interests in the event of a change in control of Williams.
 
The following chart details the benefits received if an NEO were to be terminated or resigned for a defined good reason following a change in control as well as an analysis of those benefits as it relates to Williams, stockholders and the NEO. Please also see the “Change in Control Agreements” section below for further discussion of Williams’ change in control program.
 
         
    What does the
   
    benefit provide to
  What does the
Change in Control
  Williams and
  benefit provide to
Benefit
 
stockholders?
 
the NEO?
 
Multiple of 3x base pay plus annual cash incentive at target   Encourages NEOs to remain engaged and stay focused on successfully closing the transaction.   Financial security for the NEO equivalent to three years of continued employment.
         
Accelerated vesting of stock awards   An incentive to stay during and after a change in control. If there is risk of forfeiture, NEOs may be less inclined to stay or to support the transaction.   The NEOs are kept whole, if they have a separation from service following a change in control.
         
Up to 18 months of medical or health coverage through COBRA   This is a minimal cost to Williams that creates a competitive benefit.   Access to health coverage.
         
3x the previous year’s retirement restoration allocation   This is a minimal cost to Williams that creates a competitive benefit.   May allow those NEOs who are nearing retirement to receive a cash payment to make up for lost allocations due to a change in control.
         
Reimbursement of legal fees to enforce benefit   Keeps NEOs focused on Williams and not concerned about whether the acquiring company will honor commitments after a change in control.   Security during a non-stable period of time.
         
Outplacement assistance   Keeps NEOs focused on supporting the transaction and less concerned about trying to secure another position.   Assists NEOs in finding a comparable executive position.
 
Looking Forward—We have yet to determine the extent to which any of these programs may be provided to our executive officers.


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Executive Compensation and Other Information
 
2010 Summary Compensation Table
 
The following table sets forth certain information with respect to the compensation of the NEOs earned during fiscal years 2010, 2009 and 2008.
 
                                                                         
                                        Change in
             
                                        Pension
             
                                        Value and
             
                                        Nonqualified
             
                                  Non-Equity
    Deferred
             
Name and Principal
                    Stock
    Option
    Incentive Plan
    Compensation
    All Other
       
Position(1)
  Year     Salary(2)     Bonus     Awards(3)     Awards(4)     Compensation(5)     Earnings(6)     Compensation(7)     Total  
 
                                                                         
Steven J. Malcolm
    2010     $ 1,100,000     $     $ 2,936,283     $ 1,902,806     $ 1,276,378     $ 744,426     $ 43,805     $ 8,003,698  
Former Chairman, President &
    2009       1,142,308             2,116,863       2,846,407       1,903,360       1,399,796       71,100       9,479,835  
Chief Executive Officer
    2008       1,094,231             2,906,309       2,789,127       2,000,000       1,201,514       56,134       10,047,315  
of Williams
                                                                       
                                                                         
                                                                         
Donald R. Chappel
    2010       610,154             1,436,882       407,743       559,052       225,539       16,320       3,255,690  
Chief Financial Officer
    2009       623,077             1,242,734       618,783       765,047       383,380       16,320       3,649,341  
of Williams
    2008       597,115             2,114,349       651,405       780,008       330,531       15,744       4,489,152  
                                                                         
                                                                         
Ralph A. Hill
    2010       493,208             1,257,287       356,777       384,479       315,626       16,304       2,823,681  
Senior Vice President —
    2009       503,654             1,056,319       525,969       566,473       427,867       37,786       3,118,068  
Exploration & Production of Williams
    2008       480,962             1,606,867       495,071       579,633       363,151       30,371       3,556,055  
                                                                         
                                                                         
James J. Bender
    2010       477,954             933,975       265,033       359,122       188,427       33,900       2,258,411  
Senior Vice President and General
    2009       488,077             807,773       402,209       522,119       250,679       26,647       2,497,504  
Counsel of Williams
    2008       466,538             1,271,209       390,840       533,132       216,799       30,323       2,908,842  
                                                                         
                                                                         
Robyn L. Ewing
    2010       442,692             933,975       265,033       328,364       233,254       35,579       2,238,897  
Senior Vice President and Chief
    2009       446,538             745,640       371,269       485,362       304,374       31,093       2,384,277  
Administrative Officer of
    2008       370,198             299,757       118,485       435,072       248,784       30,096       1,502,392  
Williams
                                                                       
 
 
(1) Name and Principal Position. On January 3, 2011 Mr. Malcolm retired as Chairman, President and Chief Executive Officer of Williams.
 
(2) Salary. All NEOs did not receive a salary increase in 2009. The increase in the reported 2009 salary was due to a payroll timing issue resulting in a 27th bi-weekly paycheck being issued in the calendar year.
 
(3) Stock Awards. Awards were granted under the terms of Williams’ 2007 Incentive Plan and include time-based and performance-based RSUs. Amounts shown are the grant date fair value of awards computed in accordance with FASB ASC Topic 718. The assumptions used to value the stock awards can be found in Williams’ Annual Report on Form 10-K for the year-ended December 31, 2010.
 
The potential maximum values of the performance-based RSUs, subject to changes in performance outcomes, are as follows:
 
         
    2010 Performance-Based RSU
 
    Maximum potential  
 
Steven J. Malcolm
  $ 5,872,566  
Donald R. Chappel
    1,468,141  
Ralph A. Hill
    1,284,639  
James J. Bender
    954,294  
Robyn L. Ewing
    954,294  
 
(4) Option Awards. Awards are granted under the terms of Williams’ 2007 Incentive Plan and include non-qualified stock options. Amounts shown are the grant date fair value of awards computed in accordance with FASB ASC Topic 718. The assumptions used to value the option awards can be found in our Annual Report on Form 10-K for the year-ended December 31, 2010.
 
(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.


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The annual cash incentive and reserve amounts paid in 2011 as it relates to 2010 performance are as follows:
 
                                 
                Amount of
    Total AIP plus
 
    Reserve
    AIP
    Reserve
    Reserve
 
    Balance     for 2010     Paid in 2011     for 2010  
 
Steven J. Malcolm
  $ 242,756     $ 1,155,000     $ 121,378     $ 1,276,378  
Donald R. Chappel
    60,103       529,000       30,052       559,052  
Ralph A. Hill
    72,958       348,000       36,479       384,479  
James J. Bender
    44,244       337,000       22,122       359,122  
Robyn L. Ewing
    20,728       318,000       10,364       328,364  
 
(6) Change in Pension Value and Nonqualified Deferred Compensation Earnings. The amount shown is the aggregate change from December 31, 2009 to December 31, 2010 in the actuarial present value of the accrued benefit under the qualified pension and supplemental plan sponsored by Williams. Please refer to the “Pension Benefits” table for further details of the present value of the accrued benefit. The underlying benefit programs have been consistent during the time period displayed. The primary reason for the fluctuation in the change in present value during this time is due to the use of updated discount rates and conversion rates.
 
(7) All Other Compensation. Amounts shown represent payments by Williams made on behalf of the NEOs and includes life insurance premium, a 401(k) matching contribution and perquisites (if applicable). Perquisites include financial planning services, mandated annual physical exam, home security monitoring for the CEO and personal use of Williams’ company aircraft. The incremental cost method was used to calculate the personal use of the Company aircraft. The incremental cost calculation includes such items as fuel, maintenance, weather and airport services, pilot meals, pilot overnight expenses, aircraft telephone and catering. The amounts of perquisites for Mr. Malcolm, Mr. Bender and Ms. Ewing are included because the aggregate amounts exceed $10,000.
 
                                 
                      Company
 
          Annual
          Aircraft
 
    Financial
    Physical
    Home
    Personal
 
    Planning     Exam     Security     Usage  
 
Steven J. Malcolm
  $ 15,000     $ 0     $ 438     $ 12,047  
James J. Bender
    15,000       2,646       0       0  
Robyn L. Ewing
    15,000       4,437       0       0  


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2010 Grants of Williams’ Plan Based Awards
 
The following table sets forth certain information with respect to the grant of stock options to acquire Williams’ stock, RSUs with respect to Williams’ stock and awards payable under Williams’ annual cash incentive program during the fiscal year 2010 to the NEOs.
 
                                                                                         
                                              All Other
                   
                                              Stock
    All Other
             
                                              Awards:
    Option
          Grant
 
                                              Number
    Awards
    Exercise
    Date Fair
 
                                              of Shares
    Number of
    or Base
    Value of
 
          Equity Future Payouts Under
    Estimated Future Payouts Under
    of Stock
    Securities
    Price of
    Stock and
 
    Grant
    Non-Equity Incentive Plan Awards(1)     Equity Incentive Plan Awards     or
    Underlying
    Option
    Option
 
Name
  Date     Threshold     Target     Maximum     Threshold     Target(2)     Maximum     Units(3)     Options(4)     Awards     Awards  
 
Steven J. Malcolm
    2/23/2010     $ 121,378     $ 1,221,378     $ 2,871,378                                       271,055     $ 21.22     $ 1,902,806  
      2/23/2010                                     140,492       280,984                               2,936,283  
                                                                                         
Donald R. Chappel
    2/23/2010       30,052       487,667       1,174,090                                       58,083       21.22       407,743  
      2/23/2010                                     35,123       70,246                               734,071  
      2/23/2010                                                       35,123                       702,811  
                                                                                         
                                                                                         
Ralph A. Hill
    2/23/2010       36,479       357,064       837,941                                       50,823       21.22       356,777  
      2/23/2010                                     30,733       61,466                               642,320  
      2/23/2010                                                       30,733                       614,967  
                                                                                         
James J. Bender
    2/23/2010       22,122       332,792       798,797                                       37,754       21.22       265,033  
      2/23/2010                                     22,830       45,660                               477,147  
      2/23/2010                                                       22,830                       456,828  
                                                                                         
                                                                                         
Robyn L. Ewing
    2/23/2010       10,364       298,114       729,739                                       37,754       21.22       265,033  
      2/23/2010                                     22,830       45,660                               477,147  
      2/23/2010                                                       22,830                       456,828  
 
 
(1) Non-Equity Incentive Awards. Awards from Williams’ 2010 AIP are shown.
 
  •   Threshold: Because one-half of the AIP reserve balance from prior years is payable in 2011 upon meeting threshold performance, one-half of the reserve balance is shown.
 
  •   Target: The amount shown is based upon an EVA® attainment of 100%, plus one-half of the existing AIP reserve balance.
 
  •   Maximum: The maximum amount the NEOs can receive is 250% of their AIP target, plus one-half of the AIP reserve balance.
 
(2) Represents performance-based RSUs granted under Williams’ 2007 Incentive Plan. Performance-based RSUs can be earned over a three-year period only if the established performance target is met and the NEO is employed on the certification date, subject to certain exceptions such as the executive’s death or disability. These shares will be distributed no earlier than the third anniversary of the grant other than due to a termination upon a change in control. If performance plan goals are exceeded, the NEO can receive up to 200% of target. If plan goals are not met, the NEO can receive as little as 0% of target.
 
(3) Represents time-based RSUs granted under Williams’ 2007 Incentive Plan. Time-based units vest three years from the grant date of 2/23/2010 on 2/23/2013.
 
(4) Represents stock options granted under Williams’ 2007 Incentive Plan. Stock options granted in 2010 become exercisable in three equal annual installments beginning one year after the grant date. One-third of the options vested on 2/23/2011. Another one-third will vest on 2/23/2012, with the final one-third vesting on 2/23/2013. Once vested, stock options are exercisable for a period of 10 years from the grant date.


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


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Grant Date
 
Vesting Schedule
  Vesting Dates
 
2/23/2010
  One-third vests each year for three years     2/23/2011, 2/23/2012, 2/23/2013  
2/23/2009
  One-third vests each year for three years     2/23/2010, 2/23/2011, 2/23/2012  
2/25/2008
  One-third vests each year for three years     2/25/2009, 2/25/2010, 2/25/2011  
 
Stock Awards
 
(2) The following table reflects the vesting dates for associated time-based restricted stock unit award grant dates.
 
             
Grant Date
 
Vesting Schedule
  Vesting Dates
 
2/23/2010
  100% vests in three years     2/23/2013  
2/23/2009
  100% vests in three years     2/23/2012  
2/25/2008
  100% vests in three years     2/25/2011  
 
(3) All performance-based RSUs are subject to attainment of performance targets established by the Committee. These awards will vest no earlier than the end of the performance period and therefore do not have a specific vesting date. The awards included on the table are outstanding as of December 31, 2010.
 
(4) Values are based on a closing stock price for Williams of $24.72 on December 31, 2010.
 
2010 Williams’ Option Exercises and Stock Vested
 
The following table sets forth certain information with respect to options to acquire the stock of Williams exercised by the NEO and stock that vested during fiscal year 2010.
 
                                 
    Option Awards   Stock Awards
    Number of Shares
      Number of Shares
   
    Acquired on
  Value Realized
  Acquired on
  Value Realized
Name
  Exercise   on Exercise   Vesting   on Vesting
 
Steven J. Malcolm
    475,000     $ 10,096,083           $  
Donald R. Chappel
                19,069       410,746  
Ralph A. Hill
                17,162       369,669  
James J. Bender
                11,442       246,461  
Robyn L. Ewing
                4,005       86,268  
 
The Committee determines pay based on a target total compensation amount. While the Committee reviews tally sheets and wealth accumulation information on each NEO, thus far amounts realized from previous equity grants have not been a material factor when the Committee determines pay. How much compensation the NEOs actually receive is significantly impacted by the stock market performance of Williams’ shares.
 
Retirement Plan
 
The retirement plan for Williams’ executives consists of two plans: the pension plan and the retirement restoration plan as described below. Together these plans provide the same level of benefits to our executives as the pension plan provides to all other employees of Williams. The retirement restoration plan was implemented to address the annual compensation limit of the Code.
 
Pension Plan
 
Williams’ executives who have completed one year of service participate in Williams’ pension plan on the same terms as other Williams’ employees. The pension plan is a noncontributory, tax qualified defined benefit plan (with a cash balance design) subject to the Employee Retirement Income Security Act of 1974, as amended.

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Each year, participants earn compensation credits that are posted to their cash balance account. The annual compensation credits are equal to the sum of a percentage of eligible pay (base pay and certain bonuses) and a percentage of eligible pay greater than the social security wage base. The percentage credited is based upon the participant’s age as shown in the following table.
 
                     
    Percentage of
      Percent of Eligible Pay Greater
Age
  Eligible Pay       than the Social Security Wage Base
 
Less than 30
    4.5 %     +     from 1% to 1.2%
30-39
    6 %     +     2%
40-49
    8 %     +     3%
50 or over
    10 %     +     5%
 
For participants who were active employees and participants under the plan on March 31, 1998, and April 1, 1998, the percentage of eligible pay is increased by 0.3% multiplied by the participant’s total years of benefit service earned as of March 31, 1998.
 
In addition, interest is credited to account balances quarterly at a rate determined annually in accordance with the terms of the plan.
 
The monthly annuity available to those who take normal retirement is based on the participant’s account balance as of the date of retirement. Normal retirement age is 65. Early retirement eligibility begins at 55. At retirement, participants may choose to receive a single-life annuity (for single participants) or a qualified joint and survivor annuity (for married participants) or they may choose one of several other forms of payment having an actuarial value equal to that of the relevant annuity.
 
Retirement Restoration Plan
 
The Code limits pension benefits based on the annual compensation limit that can be accrued in tax-qualified defined benefit plans, such as Williams’ pension plan. Any reduction in an executive’s pension benefit accrual due to these limits will be compensated, subject to a cap, under an unfunded top hat plan—Williams’ retirement restoration plan.
 
The elements of compensation that are included in applying the payment and benefit formula for the retirement restoration plan are the same elements that are used, except for application of a cap, in the base pension plan for all Williams’ employees. The elements of pay included in that definition are total base pay, including any overtime, base pay-reduction amounts and cash bonus awards, if paid (unless specifically excluded under a written bonus or incentive-pay arrangement). Specifically excluded from the definition are severance pay, cost-of-living pay, housing pay, relocation pay (including mortgage interest differential), taxable and non-taxable fringe benefits and all other extraordinary pay, including any amounts received from equity compensation awards.
 
With respect to bonuses, annual cash incentives are considered in determining eligible pay under the pension plan. Long-term equity compensation incentives are not considered.


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2010 Williams’ Pension Benefits
 
The following table sets forth certain information with respect to the actuarial present value of the accrued benefit as of December 31, 2010 under Williams’ qualified pension plan and retirement restoration plan.
 
                             
        Number of
      Payments
        Years Credited
  Present Value of
  During Last
Name
 
Plan Name
  Services   Accrued Benefit(1)   Fiscal Year
 
Steven J. Malcolm(2)(3)
  Pension Plan     27     $ 829,307        
    Retirement Restoration Plan     27       5,497,857        
Donald R. Chappel(2)
  Pension Plan     8       245,359        
    Retirement Restoration Plan     8       1,319,741        
Ralph A. Hill(3)
  Pension Plan     27       586,869        
    Retirement Restoration Plan     27       1,321,013        
James J. Bender
  Pension Plan     8       216,010        
    Retirement Restoration Plan     8       799,037        
Robyn L. Ewing(2)
  Pension Plan     30       598,781        
    Retirement Restoration Plan     30       723,095        
 
 
(1) The primary actuarial assumptions used to determine the present values include an annual interest credit to normal retirement age equal to 5% and a discount rate equal to 5.29% for the pension plan and discount rate equal to 5.1% for the retirement restoration plan.
 
(2) Mr. Malcolm, Mr. Chappel and Ms. Ewing are the only NEOs eligible to retire as of December 31, 2010.
 
(3) Williams’ pension plan includes a Rule of 55 benefit that is a transition benefit that was provided to all employees meeting the eligibility criteria at the time Williams’ pension plan was converted from a final average pay formula to a cash balance formula. To be eligible for the Rule of 55 enhancement an employee’s age and years of service at the time of the cash balance conversion in 1998 must have totaled 55. Mr. Malcolm and Mr. Hill are the only NEOs that met the eligibility criteria for the Rule of 55 transitional benefit.
 
Nonqualified Deferred Compensation
 
Williams does not provide nonqualified deferred compensation for any NEOs or other employees.
 
Change in Control Agreements
 
Williams has entered into change in control agreements with certain officers, including each of the NEOs, to facilitate continuity of management if there is a change in control of Williams. These arrangements do not provide for the payment of any benefits in the event of a future change in control of the ownership of WPX Energy. The provisions of such agreements are described below. The definitions of words in quotations are also provided below.
 
If during the term of a change in control agreement, a “change in control” occurs and (i) the employment of any NEO is terminated other than for “cause,” “disability,” death or a “disqualification disaggregation” or (ii) an NEO resigns for “good reason,” such NEO is entitled to the following:
 
  •   Within 10 business days after the termination date:
 
  •   Accrued but unpaid base salary, accrued earned but unpaid cash incentive, accrued but unpaid paid time off and any other amounts or benefits due but not paid (lump sum payment);


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  •   On the first business day following six months after the termination date:
 
  •   Prorated annual bonus for the year of separation through the termination date (lump sum payment);
 
  •   A severance amount equal to three times his/her base salary for the NEO as of the termination date plus an annual bonus amount equal to his/her target percentage multiplied by his/her base salary in effect at the termination date as if performance goals were achieved at 100% (lump sum payment);
 
  •   An amount equal to three times for the total allocations made by Williams for the NEOs in the preceding calendar year under our retirement restoration plan (lump sum payment);
 
  •   An amount equal to the sum of the value of the unvested portion of the NEO’s accounts or accrued benefits under Williams’ 401(k) plan that would have otherwise been forfeited (lump sum payment);
 
  •   Continued participation in Williams’ medical benefit plans for so long as the NEO elects coverage or 18 months from the termination, whichever is less, in the same manner and at the same cost as similarly situated active employees;
 
  •   All restrictions on stock options held by the NEO will lapse, and the options will vest and become immediately exercisable;
 
  •   All restricted stock will vest and will be paid out only in accordance with the terms of the respective award agreements;
 
  •   Continued participation in Williams’ directors’ and officers’ liability insurance for six years or any longer known applicable statute of limitations period;
 
  •   Indemnification as set forth under Williams’ bylaws; and
 
  •   Outplacement benefits for six months at a cost not exceeding $25,000.
 
In addition, each NEO is generally entitled to receive a gross-up payment in an amount sufficient to make him/her whole for any federal excise tax on excess parachute payments imposed under Section 280G and 4999 of the Code or any similar tax under any state, local, foreign or other law (other than Section 409A of the Code). However, in reviewing the change in control agreements in 2010 and 2011, the Committee approved eliminating this excise tax gross-up provision. The Committee opted to provide a ‘best net’ provision providing the NEOs with the better of their after-tax benefit capped at the safe harbor amount or their benefit paid in full subjecting them to possible excise tax payments. Therefore, in 2011 Williams will provide the one year notice required by the NEOs’ change in control agreements in order to effect the change in 2012. After this change is implemented, Williams will no longer provide additional compensation to address excise taxes.
 
If an NEO’s employment is terminated for “cause” during the period beginning upon a change of control and continuing for two years or until the termination of the agreement, whichever happens first, the NEO is entitled to accrued but unpaid base salary, accrued earned but unpaid cash incentive, accrued but unpaid paid time off and any other amounts or benefits due but not paid (lump sum payment).
 
The agreements with our NEOs use the following definitions:
 
“Cause” means an NEO’s
 
  •   conviction of or a plea of nolo contendere to a felony or a crime involving fraud, dishonesty or moral turpitude;
 
  •   willful or reckless material misconduct in the performance of his/her duties that has an adverse effect on Williams or any of its subsidiaries or affiliates;
 
  •   willful or reckless violation or disregard of the code of business conduct of Williams or the policies of Williams or its subsidiaries; or


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  •   habitual or gross neglect of his/her duties.
 
Cause generally does not include bad judgment or negligence (other than habitual neglect or gross negligence); acts or omissions made in good faith after reasonable investigation by the NEO or acts or omissions with respect to which Williams’ board of directors could determine that the NEO had satisfied the standards of conduct for indemnification or reimbursement under Williams’ bylaws, indemnification agreement or applicable law; or failure (despite good faith efforts) to meet performance goals, objectives or measures for a period beginning upon a change of control and continuing for two years or until the termination of the agreement, whichever happens first. An NEO’s act or failure to act (except as relates to a conviction or plea of nolo contendere described above), when done in good faith and with a reasonable belief after reasonable investigation that such action or non-action was in the best interest of Williams or its affiliate or required by law shall not be Cause if the NEO cures the action or non-action within 10 days of notice. Furthermore, no act or failure to act will be Cause if the NEO acted under the advice of Williams’ counsel or required by the legal process.
 
“Change in control” means:
 
  •   Any person or group (other than an affiliate of Williams or an employee benefit plan sponsored by Williams or its affiliates) becomes a beneficial owner, as such term is defined under the Exchange Act, of 20% or more of the common stock of Williams or 20% or more of the combined voting power of all securities entitled to vote generally in the election of directors of Williams (“Voting Securities”), unless such person owned both more than 75% of common stock and Voting Securities, directly or indirectly, in substantially the same proportion immediately before such acquisition;
 
  •   Williams’ directors as of a date of the agreement (“Existing Directors”) and directors approved after that date by at least two-thirds of the Existing Directors cease to constitute a majority of the directors of Williams;
 
  •   Consummation of any merger, reorganization, recapitalization consolidation or similar transaction (“Reorganization Transaction”), other than a Reorganization Transaction that results in the person who was the direct or indirect owner of outstanding common stock and Voting Securities of Williams prior to the transaction becoming, immediately after the transaction, the owner of at least 65% of the then outstanding common stock and Voting Securities representing 65% of the combined voting power of the then outstanding Voting Securities of the surviving corporation in substantially the same respective proportion as that person’s ownership immediately before such Reorganization Transaction; or
 
  •   approval by the stockholders of Williams of the sale or other disposition of all or substantially all of the consolidated assets of Williams or the complete liquidation of Williams other than a transaction that would result in (i) a related party owning more than 50% of the assets that were owned by Williams immediately prior to the transaction or (ii) the persons who were the direct or indirect owners of outstanding Williams common stock and Voting Securities prior to the transaction continuing to own, directly or indirectly, 50% or more of the assets that were owned by Williams immediately prior to the transaction.
 
A change in control will not occur if:
 
  •   the NEO agrees in writing prior to an event that such an event will not be a change in control; or
 
  •   Williams’ board of directors determines that a liquidation, sale or other disposition approved by the stockholders, as described in the fourth bullet above, will not occur, except to the extent termination occurred prior to such determination.
 
“Disability” means a physical or mental infirmity that impairs the NEO’s ability to substantially perform his/her duties for twelve months or more and for which he/she is receiving income replacement benefits from a Williams’ plan for not less than three months.


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“Disqualification disaggregation” means:
 
  •   the termination of an NEO’s employment from Williams or an affiliate before a change in control for any reason; or
 
  •   the termination of an NEO’s employment by a successor (during the period beginning upon a change of control and continuing for two years or until the termination of the agreement, whichever happens first), if the NEO is employed in substantially the same position and the successor has assumed the Williams’ change in control agreement.
 
“Good reason” means, generally, a material adverse change in the NEO’s title, position or responsibilities, a reduction in the NEO’s base salary, a reduction in the NEO’s annual bonus, required relocation, a material reduction in the level of aggregate compensation or benefits not applicable to Williams’ peers, a successor company’s failure to honor the agreement or the failure of Williams’ board of directors to provide written notice of the act or omission constituting “cause.”
 
Termination Scenarios
 
The following table sets forth circumstances that provide for payments by Williams to the NEOs following or in connection with a change in control of Williams or an NEO’s termination of employment for cause, upon retirement, upon death and disability or not for cause, all while employed by Williams. NEOs are generally eligible to retire at the earlier of age 55 and completion of 3 years of service or age 65.
 
All values are based on a hypothetical termination date of December 31, 2010 and a closing stock price for Williams’ common stock of $24.72 on such date. The values shown are intended to provide reasonable estimates of the potential benefits the NEOs would receive upon termination. The values are based on various assumptions and may not represent the actual amount an NEO would receive. In addition to the amounts disclosed in the following table, a departing NEO would retain the amounts he/she has earned over the course of his/her employment prior to the termination event, including accrued retirement benefits and previously vested stock options and RSUs.
 
                                             
        For
          Death &
    Not for
       
Name
 
Payment
  Cause(1)     Retirement(2)     Disability(3)     Cause(4)     CIC(5)  
 
Malcolm, Steven J
  AIP Reserve         $ 242,756     $ 242,756     $ 242,756     $ 242,756  
    Stock options           5,645,264       5,645,264             5,645,264  
    Stock awards           7,240,399       7,240,399       7,240,399       12,634,022  
    Cash Severance                             6,600,000  
    Outplacement                             25,000  
    Health & Welfare                             18,170  
    Retirement Restoration                                        
    Plan                             2,207,808  
    Enhancement                                        
    Tax Gross Up                             8,649,197  
                                             
    Total         $ 13,128,419     $ 13,128,419     $ 7,483,155     $ 36,022,217  
                                             
                                             
Chappel, Donald R
  AIP Reserve         $ 60,103     $ 60,103     $ 60,103     $ 60,103  
    Stock options           1,224,287       1,224,287             1,224,287  
    Stock awards           4,086,877       5,444,451       5,444,451       6,829,365  
    Cash Severance                             3,213,000  
    Outplacement                             25,000  
    Health & Welfare                             26,699  
    Retirement Restoration Plan                                
    Enhancement                                     646,557  
    Tax Gross Up                             2,966,960  
                                             
    Total         $ 5,371,267     $ 6,728,841     $ 5,504,554     $ 14,991,971  
                                             


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        For
          Death &
    Not for
       
Name
 
Payment
  Cause(1)     Retirement(2)     Disability(3)     Cause(4)     CIC(5)  
 
Hill, Ralph A
  AIP Reserve         $ 72,958     $ 72,958     $ 72,958     $ 72,958  
    Stock options           1,045,738       1,045,738             1,045,738  
    Stock awards           3,360,366       4,527,523       4,527,523       5,715,453  
    Cash Severance                             2,448,765  
    Outplacement                             25,000  
    Health & Welfare                             26,346  
    Retirement Restoration Plan                                
    Enhancement                                     636,018  
    Tax Gross Up                              
                                             
    Total         $ 4,479,062     $ 5,646,219     $ 4,600,481     $ 9,970,278  
                                             
                                             
Bender, James J
  AIP Reserve         $ 44,244     $ 44,244     $ 44,244     $ 44,244  
    Stock options           795,784       795,784             795,784  
    Stock awards           2,586,716       3,467,769       3,467,769       4,365,230  
    Cash Severance                             2,373,030  
    Outplacement                             25,000  
    Health & Welfare                             26,346  
    Retirement Restoration Plan                                
    Enhancement                                     423,896  
    Tax Gross Up                             2,217,566  
                                             
    Total         $ 3,426,744     $ 4,307,797     $ 3,512,013     $ 10,271,096  
                                             
                                             
Ewing, Robyn L
  AIP Reserve         $ 20,728     $ 20,728     $ 20,728     $ 20,728  
    Stock options           744,737       744,737             744,737  
    Stock awards           1,836,807       2,671,273       2,671,273       3,507,393  
    Cash Severance                             2,202,750  
    Outplacement                             25,000  
    Health & Welfare                             26,346  
    Retirement Restoration Plan                                
    Enhancement                                     437,948  
    Tax Gross Up                             1,861,484  
                                             
    Total         $ 2,602,272     $ 3,436,738     $ 2,692,001     $ 8,826,386  
                                             
 
(1) If an NEO is terminated for cause or leaves Williams voluntarily, no additional benefits will be received.
 
(2) If an NEO retires from Williams, then all unvested stock options will fully accelerate. A pro-rated portion of the unvested time based RSUs will accelerate and a pro-rated portion of any performance-based RSUs will vest on the original vesting date if the Committee certifies that the performance measures were met.
 
(3) If an NEO dies or becomes disabled, then all unvested stock options will fully accelerate. All unvested time-based RSUs will fully accelerate, and a pro-rated portion of any performance-based RSUs will vest if the Committee certifies that the performance measures were met.
 
(4) For an NEO who is involuntarily terminated who receives severance or for an NEO whose job is outsourced with no comparable internal offer, all unvested time-based RSUs will fully accelerate and a pro-rated portion of any performance-based RSUs will vest if the Committee certifies that the performance measures were met. However all unvested stock options cancel.
 
(5) See “Change In Control Agreements” above.
 
Please note that we make no assumptions as to the achievement of performance goals as it relates to the performance based RSUs. If an award is covered by Section 409A of the Code, lump sum payments and distributions occurring from these events will occur six months after the triggering event as required by the Code and our award agreements.

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PRINCIPAL STOCKHOLDER
 
All outstanding shares of our common stock are owned beneficially and of record by Williams. The following table sets forth information with respect to the beneficial ownership of our common stock immediately after the completion of this offering by:
 
  •  each person who is an executive officer;
 
  •  each person who is a director;
 
  •  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).
 
Prior to the completion of this offering, we intend to appoint additional persons to serve as our executive officers and directors.
 
Beneficial ownership has been determined in accordance with the rules of the SEC and includes the power to vote or direct the voting of securities, or to dispose or direct the disposition thereof, or the right to acquire such powers within 60 days. Except as otherwise indicated, the persons or entities listed below have sole voting and investment power with respect to all shares of our common stock beneficially owned by them. The address for Williams is One Williams Center, Tulsa, Oklahoma 74172-0172. Unless otherwise indicated, the address for each director and executive officer listed is: c/o WPX Energy, Inc., One Williams Center, Tulsa, Oklahoma 74172-0172.
 
                                 
    Number of Class A
      Number of Class B
   
    Shares Beneficially
  Percentage
  Shares Beneficially
  Percentage
Name of Beneficial Owner
  Owned   of Class   Owned   of Class
 
The Williams Companies, Inc.
                               
Alan S. Armstrong
                               
Ralph A. Hill
                               
Donald R. Chappel
                               
Ted T. Timmermans
                               
James J. Bender
                               
Robyn L. Ewing
                               
Rodney J. Sailor
                               
All executive officers and directors as a group (seven persons)
                               
Total
                               


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


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Contractual Restrictions.  For so long as Williams owns at least 50% of the total voting power of our outstanding stock generally entitled to elect our directors, we will not (without Williams’ prior written consent):
 
  •   take any action that would limit the ability of Williams to transfer its shares of our common stock or limit the rights of any transferee of Williams as a holder of our common stock;
 
  •   issue any shares of our capital stock, or any rights, warrants or options to acquire our capital stock, if the issuance would cause Williams to own less than 50% of the total value of all classes of our outstanding capital stock, 80% of the total voting power of all classes of our outstanding capital stock generally entitled to elect our directors, 80% of any class of outstanding capital stock not entitled to vote or 80% of the total value of all classes of our outstanding capital stock; 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.
 
In addition, for so long as Williams is required to consolidate our results of operations and financial position, we will agree not to incur any additional indebtedness (excluding the Credit Facility and the Notes) without the consent of Williams.
 
During the term of the administrative services agreement and the transition services agreement, and for one year thereafter, neither we nor Williams will be permitted to solicit each other’s employees for employment without the other’s consent.
 
Financial Reporting.  We will agree, for so long as Williams is required to consolidate our results of operations and financial position, to:
 
  •   comply with all requirements under applicable law regarding disclosure controls and procedures and internal control over financial reporting;
 
  •   maintain internal systems and procedures that will provide Williams with reasonable assurance that our financial statements and other publicly reported information is reliable and timely prepared in accordance with GAAP and any other applicable law;
 
  •   provide Williams with financial reports, including consolidated financial statements (and notes thereto) and discussion and analysis by management of our financial condition and liquidity, in the form, and in accordance with the dates, specified by Williams;
 
  •   unless required by law, use the auditors (and lead audit partners) directed by Williams; and
 
  •   unless required by law, to the extent requested by Williams, keep our accounting practices and principles consistent with those of Williams.
 
Releases.  Except as otherwise provided in the separation and distribution agreement, each of Williams and us will release and discharge the other and their respective subsidiaries and other affiliates from all liabilities existing or arising from any acts or events occurring or failing to occur or alleged to have occurred or to have failed to occur or any conditions existing or alleged to have existed on or before the separation from Williams. The releases will not extend to obligations or liabilities under any agreements between Williams and us that remain in effect following the separation, which agreements include, but are not limited to, the separation and distribution agreement, the administrative services agreement, the transition services agreement, the registration rights agreement and the tax sharing agreement.
 
Confidentiality.  Each party will agree to treat as confidential and not disclose confidential information of the other party except in specific circumstances identified in the separation and distribution agreement.
 
Further Assurances.  Each party will agree to use its reasonable best efforts to take or cause to be taken all actions, and to do or cause be done all things reasonably necessary, proper or advisable under applicable law, regulations and agreements to consummate and make effective the transactions contemplated by the separation and distribution agreement and the ancillary agreements.


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Indemnification.  The separation and distribution agreement will provide that we will indemnify, defend and hold harmless Williams, its subsidiaries, and each of their respective current, former and future directors, officers and employees, and each of the heirs, executors, successors and assigns of any of the foregoing for any losses arising out of or resulting from:
 
  •   the liabilities being assumed by us pursuant to the separation and distribution agreement;
 
  •   the operation of our business;
 
  •   any breach by us of the separation and distribution agreement or the ancillary agreements; and
 
  •   any untrue statement or alleged untrue statement of a material fact or omission or alleged omission to state a material fact required to be stated therein or necessary to make the statements therein not misleading, with respect to all information (i) contained in the registration statement of which this prospectus is a part or in this prospectus, (ii) contained in any public filings made by us with the SEC following the separation; and (iii) provided by us to Williams specifically for inclusion in Williams’ annual or quarterly reports following the separation.
 
Williams will indemnify, defend and hold harmless us, our subsidiaries, and each of our and their respective current, former and future directors, officers and employees, and each of the heirs, executors, successors and assigns of any of the foregoing for any losses arising out of or resulting from:
 
  •   the liabilities being retained by Williams pursuant to the separation and distribution agreement;
 
  •   the operation of Williams’ business;
 
  •   any breach by Williams of the separation and distribution agreement or the ancillary agreements; and
 
  •   certain pending or threatened litigation related to the 2000-2001 California Energy Crisis and the reporting of certain natural gas-related information to trade publications.
 
The separation and distribution agreement will also specify procedures with respect to claims subject to indemnification and related matters.
 
Termination.  The separation and distribution agreement will be terminable before the separation in the sole discretion of Williams. In the event of such a termination, no party will have any liability or further obligation with respect to the separation and distribution agreement.
 
Dispute Resolution.  In the event of a dispute relating to the separation and distribution agreement between us and our subsidiaries and other affiliates, on the one hand, and Williams and its other subsidiaries and other affiliates, on the other hand, the separation and distribution agreement will provide for the following procedures:
 
  •   first, the parties will use commercially reasonable efforts to resolve the dispute through negotiations between our representatives and Williams’ representatives;
 
  •   if negotiations fail, then the parties will attempt to resolve the dispute through non-binding mediation; and
 
  •   if mediation fails, then the parties may seek relief in any court of competent jurisdiction.
 
Expenses.  Except as expressly set forth in the separation and distribution agreement or in any other ancillary agreement, all fees and expenses incurred in connection with our separation from Williams will be paid by the party incurring such fees or expenses.
 
Administrative Services and Transition Services Agreements
 
We will enter into an administrative services agreement and a transition services agreement with Williams under which Williams will provide to us, on an interim basis, various corporate support services. These


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services will consist generally of the services that have been provided to WPX on an intercompany basis prior to this offering. These services relate to:
 
  •   cash management and treasury administration;
 
  •   finance and accounting;
 
  •   tax;
 
  •   internal audit;
 
  •   investor relations;
 
  •   payroll and human resource administration;
 
  •   information technology;
 
  •   legal and government affairs;
 
  •   insurance and claims administration;
 
  •   records management;
 
  •   real estate and facilities management;
 
  •   sourcing and procurement; and
 
  •   mail, print and other office services.
 
Pursuant to the administrative services agreement, Williams will provide these services to us for the period beginning on the date this offering is completed and ending on the earlier of (i) the date immediately prior to the distribution date or (ii) sixty days’ notice by Williams if it determines that the provision of such services involves certain conflicts of interest between Williams and us or would cause Williams to violate applicable law. Williams will provide the services and we will pay Williams’ costs, including Williams’ direct and indirect administrative and overhead charges allocated in accordance with Williams’ regular and consistent accounting practices. Pursuant to the transition services agreement, Williams will provide certain services for up to one year after the distribution date. The transition services agreement may be terminated by either us or Williams upon 60 days notice after the distribution date. In addition, Williams may immediately terminate any of the services it provides under the transition services agreement if it determines that the provision of such services involves certain conflicts of interest between Williams and us or would cause Williams to violate applicable law.
 
Williams may decline to provide certain services under these agreements if the provision of such services causes Williams to violate applicable law, creates a conflict of interest, requires Williams to retain additional employees or other resources or the provision of such services become impracticable due to reasons outside the control of Williams. Williams will charge us for its full salary and benefits costs associated with individuals providing the services as well as any out-of-pocket expenses incurred by Williams in the provision of the services, plus an administrative fee.
 
In both cases, Williams will provide these services with the same general degree of care, at the same general volumes and at the same general degree of accuracy and responsiveness, as when the services were performed prior to the separation.
 
Registration Rights Agreement
 
The registration rights agreement provides Williams with rights relating to the shares of our Class B common stock held by Williams. Under the registration rights agreement, Williams has the right, subject to the terms of its lock-up agreement with the underwriters, to require us to register for offer and sale all or a portion of the shares of our Class B common stock covered by the agreement.
 
Shares Covered.  The registration rights agreement covers those shares of our Class B common stock that are held by Williams or a transferee of Williams.


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Demand Registration.  Williams may request registration under the Securities Act of all or any portion of our shares covered by the registration rights agreement, and we will be obligated, subject to limited exceptions, to register such shares as requested by Williams. The maximum number of registrations Williams may require us to effect is five. Williams has the right to designate the terms of each offering it requests.
 
We are not required to undertake any demand registration requested by Williams within 90 days after completion of a previously-requested demand registration other than pursuant to a shelf registration statement. In addition, we have the right, which may be exercised once in any 12-month period, to postpone the filing or effectiveness of any demand registration if we determine in the good faith judgment of our general counsel, confirmed by our board of directors, that such registration would reasonably be expected to require the disclosure of material information that we have a business purpose to keep confidential and the disclosure of which would have a material adverse effect on any then-active proposals to engage in certain material transactions until the earlier of (i) 15 business days after the date of disclosure of such material information, or (ii) 75 days after we make such determination.
 
Piggy-Back Registration.  If we at any time intend to file on our behalf or on behalf of any of our other security holders a registration statement in connection with a public offering of any of our securities on a form and in a manner that would permit the registration for offer and sale of the shares of our Class B common stock, Williams has the right to have those shares included in that offering.
 
Registration Expenses.  We are responsible for all registration expenses incurred in connection with the performance of our obligations under the registration rights agreement. Williams is responsible for all of the fees and expenses of counsel to Williams, any applicable underwriting discounts or commissions, and any registration or filing fees incurred with respect to shares of our Class B common stock being sold under the registration rights agreement.
 
Indemnification.  The registration rights agreement contains indemnification and contribution provisions by us for the benefit of Williams and its affiliates and representatives and, in limited situations, by Williams for the benefit of us and any underwriters with respect to information included in any registration statement, prospectus or related documents.
 
Transfer.  Williams may transfer shares covered by the registration rights agreement and the holders of such transferred shares will be entitled to the benefits of the registration rights agreement, provided that each such transferee agrees to be bound by the terms of the registration rights agreement.
 
Duration.  The registration rights under the registration rights agreement will remain in effect with respect to any shares of Class B common stock covered by the agreement until:
 
  •   such shares have been sold pursuant to an effective registration statement under the Securities Act;
 
  •   such shares have been sold to the public pursuant to Rule 144 under the Securities Act;
 
  •   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; or
 
  •   such shares have ceased to be outstanding.
 
Tax Sharing Agreement
 
In connection with this offering, we will enter into a tax sharing agreement with Williams. The tax sharing agreement will govern the respective rights, responsibilities, and obligations of Williams and us with respect to the payment of taxes, filing of tax returns, reimbursements of taxes, control of audits and other tax proceedings, liability for taxes that may be triggered as a result of the spin-off of our stock to Williams’ stockholders and other matters regarding taxes. The tax sharing agreement will remain in effect until the parties agree in writing to its termination.


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Tax Returns and Taxes.  Williams will be responsible for the preparation and filing of all consolidated, combined, or unitary income tax returns in which we (or our subsidiaries) are included, and the payment of all taxes that relate to such returns. Williams will be entitled to make all decisions regarding the preparation of such tax returns, including the making of any tax elections, and we will be bound by such decisions. We will be responsible for the preparation, filing, and payment of all returns other than those described above that are required to be filed with respect to us or any of our subsidiaries; however, Williams may, in its discretion, assist us in preparing any such returns.
 
Pro Forma Returns and Reimbursements.  For each tax period in which we or any of our subsidiaries are consolidated or combined with Williams for purposes of any tax return, Williams will prepare a pro forma tax return for us as if we filed our own consolidated, combined, or unitary return. Such pro forma returns will take into account all elections and methods of accounting reflected on the true returns; will only include current income, deductions, credits and losses from us (with certain exceptions); will not include any carryovers or carrybacks of any items from us for prior or subsequent periods; and will not take into account the federal Alternative Minimum Tax. For any periods shorter than a full taxable year, the pro forma return computations will be made based on a hypothetical closing of the books for us and our subsidiaries. We will reimburse Williams for any taxes shown on the pro forma tax returns, and Williams will reimburse us for any current losses or credits we recognize based on the pro forma tax returns.
 
Redeterminations.  In the case of any tax audit adjustments, all pro forma returns and associated tax reimbursement obligations will be recomputed to give effect to such adjustments, but only for adjustments that originate from a federal audit.
 
Spin-off.  Williams and we expect that the spin-off of our stock to Williams’ stockholders and any related restructuring transaction, taken together, will qualify for U.S. federal income tax purposes as a tax-free transaction under section 355 and section 368(a)(1)(D) of the Code. Williams intends to seek a private letter ruling from the IRS and an opinion from its outside tax advisor to such effect. In connection with the private letter ruling and the opinion, we will be required to make certain factual statements and representations regarding our company and our business, and Williams will be required to make certain representations regarding itself and its business. In the tax sharing agreement, we will represent and warrant that any factual statements and representations relating to our company and business made in connection with the private letter ruling and tax opinion are true, correct, and complete, and that we have no plan or intention of taking any actions nor know of any circumstances that could cause such factual statements or representations (or any factual statements or representations in the tax sharing agreement or separation and distribution agreement) to be untrue. We will also represent and warrant that, for a period leading up to the completion of the spin-off, and for the two-year period beginning on the date of the closing of the spin-off, there was no agreement or arrangement by any of our officers or directors (or by any person with permission of our officers or directors) regarding an acquisition of our stock or assets. In addition, we and Williams will each covenant not to take any actions that would (i) be inconsistent with any factual statement or representation made in the tax sharing agreement, the separation and distribution agreement, or in connection with the private letter ruling or tax opinion, (ii) create a material risk that the spin-off or any related restructuring transaction would fail to qualify as tax-free, or (iii) create a material risk that section 355(d) or section 355(e) of the Code would apply to the spin-off. We and Williams will also agree to notify each other if we or they become aware of a transaction that could affect the status of the spin-off or any related restructuring transaction under section 355 or section 368(a)(1)(D) of the Code, and to take reasonable action or reasonably refrain from taking action to ensure the qualification of the spin-off as tax free, unless the IRS has issued a private letter ruling or other guidance conclusively establishing that such matter or transaction does not adversely affect the tax-free nature of the spin-off. Last, we will agree that our officers and directors will not discuss any acquisitions of our stock or the stock of any of our subsidiaries during the two-year period beginning after the spin-off without permission from Williams, and that we will not take any position in a tax return that is inconsistent with the tax-free treatment of the spin-off or any related restructuring transaction under section 355 or section 368(a)(1)(D) of the Code.
 
Indemnities.  If Williams (or any of its subsidiaries) becomes liable for any taxes because of a failure of the spin-off or any related restructuring transaction to be wholly-tax free under section 355 or section 368(a)(1)(D) of the Code, we will indemnify Williams for such taxes to the extent caused by our breach of any representations or


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covenants made in the tax sharing agreement, the separation and distribution agreement, or made in connection with the private letter ruling or tax opinion. Williams will indemnify us for all taxes arising from the failure of the spin-off or any related restructuring transaction to be tax-free except for those caused by us as described above.
 
Proceedings and Cooperation.  Williams will have the right to control any tax proceedings or disputes and to make any decisions regarding taxes, payments and settlements relating to consolidated, combined, or unitary returns that include us or our subsidiaries. If a proceeding or dispute could require us to pay taxes arising from the spin-off, Williams will agree to consult with us and give us an opportunity to comment and participate in the proceeding. However, Williams retains sole discretion over all the positions taken in such proceedings, except that we will have consent rights, which have to be exercised reasonably, to approve any settlement. We and Williams will cooperate with each other in good faith regarding all provisions of the tax sharing agreement, and will retain books and records relating to the filing of returns in the agreement for 10 years.


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OTHER RELATED PARTY TRANSACTIONS
 
In addition to the related party transactions described in “Arrangements Between Williams and Our Company” above, this section discusses other transactions and relationships with related persons during the past three fiscal years.
 
Reimbursement of Expenses of Williams
 
Williams charges us for the payroll and benefit costs associated with operations employees (referred to as direct employees) and carries the obligations for many employee-related benefits in its financial statements, including the liabilities related to employee retirement and medical plans. Our share of those costs is charged to us through affiliate billings and reflected in lease and facility operating and general and administrative within costs and expenses in the accompanying Combined Statement of Operations. These costs totaled $128 million, $126 million and $115 million for the years ended December 31, 2010, 2009 and 2008, respectively.
 
In addition, Williams charges us for certain employees of Williams who provide general and administrative services on our behalf (referred to as indirect employees). These charges are either directly identifiable or allocated to our operations. Direct charges include goods and services provided by Williams at our request. Allocated general corporate costs are based on our relative use of the service or on a three-factor formula, which considers revenues; properties and equipment; and payroll. Our share of direct general and administrative expenses and our share of allocated general corporate expenses is reflected in general and administrative expense in the Combined Statement of Operations. These costs totaled $134 million, $136 million and $128 million for the years ended December 31, 2010, 2009 and 2008, respectively. In our management’s estimation, the allocation methodologies used are reasonable and result in a reasonable allocation to us of their costs of doing business incurred by Williams.
 
Commodity Sales Contracts
 
We procure and sell natural gas for shrink replacement and fuel to Williams Partners and other Williams affiliates. We sell substantially all of the NGLs related to our production to Williams Partners. We conduct these transactions at market prices at the time of purchase. Revenues from these sales totaled $786 million, $547 million and $1,078 million for the years ended December 31, 2010, 2009 and 2008, respectively.
 
In addition, through an agency agreement, we manage the jurisdictional merchant gas sales for Transcontinental Gas Pipe Line Company LLC (“Transco”), an indirect, wholly owned subsidiary of Williams Partners. We are authorized to make gas sales on Transco’s behalf in order to manage its gas purchase obligations. Although there is no exchange of payments between us and Transco for these transactions, we receive all margins associated with jurisdictional merchant gas sales business and, as Transco’s agent, assume all market and credit risk associated with such sales.
 
Gathering, Processing and Treating Contracts
 
We purchase gathering, processing and treating services from Williams Partners, primarily in the San Juan and Piceance Basins, under several contracts. We paid $163 million, $72 million and $44 million under these contracts for the years ended December 31, 2010, 2009 and 2008, respectively. The rates Williams Partners charges us to provide these services are comparable to those that Williams Partners charges to similarly-situated nonaffiliated customers.
 
Transportation Contracts
 
We purchase natural gas transportation services from Williams Partners. Costs for these purchases were $25 million, $28 million and $34 million for the years ended December 31, 2010, 2009 and 2008, respectively. The rates Williams Partners charges us to provide these services are comparable to those that Williams Partners charges to similarly-situated nonaffiliated customers.


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We have executed a capacity commitment of 135,000 MMBtu/d on Williams Partners’ Transco Northeast Supply Link, which is scheduled to be in-service in the fourth quarter of 2013. Construction of the Northeast Supply Link remains subject to regulatory approvals. The transportation rate for this firm capacity commitment is $0.59/MMbtu and represents a demand payment obligation of $436MM over the 15 year life of the project. The receipt point is Transco Station 517 and the delivery point is the New York City market area.
 
We manage a transportation capacity contract for Williams Partners. To the extent the transportation is not fully utilized or does not recover full-rate demand expense, Williams Partners reimburses us for these transportation costs. These reimbursements to us totaled approximately $9.8 million, $9.1 million and $10.9 million for the years ended December 31, 2010, 2009 and 2008, respectively.
 
Derivative Contracts
 
We periodically enter into derivative contracts with Williams Partners to hedge Williams Partners’ forecasted NGL sales and natural gas purchases. The revenues for these contracts were $14 million and $6 million for the years ended December 31, 2010 and 2009, respectively, and an expense of $3 million for the year ended December 31, 2008. We enter into offsetting derivative contracts with third parties at equivalent pricing and volumes.
 
Agreements Related to the Piceance Disposition
 
We entered into a contribution agreement and certain other agreements with Williams Partners that effected our sale to Williams Partners of certain gathering and processing assets in Colorado’s Piceance Basin (the “Piceance Disposition”). These agreements were the result of arm’s-length negotiations between Williams and the Conflicts Committee of the board of directors of the general partner Williams Partners, which is composed solely of independent directors unaffiliated with Williams.
 
Contribution Agreement.  On November 19, 2010, we closed the Piceance Disposition as contemplated by the contribution agreement. The Piceance Disposition was made in exchange for consideration of $702 million in cash and 1,849,138 Williams Partners common units. In March 2011, the Williams Partners common units we received in this transaction were distributed to Williams in a dividend.
 
Conveyance, Contribution, and Assumption Agreement.  In connection with the closing of the Piceance Disposition, the parties to the contribution agreement entered into a conveyance, contribution, and assumption agreement. This conveyance, contribution, and assumption agreement effected the contribution of the contributed interests from us to Williams Partners.
 
Piceance Omnibus Agreement.  Under an omnibus agreement entered into in connection with the Piceance Disposition, we are obligated to reimburse Williams Partners for (i) amounts incurred by Williams Partners for any costs required to complete the pipeline and compression projects known collectively as the Ryan Gulch Expansion Project, (ii) amounts incurred by Williams Partners prior to January 31, 2011 related to the development of a cryogenic processing arrangement with a subsidiary of ours, up to $20 million, and (iii) amounts incurred by Williams Partners for notice of violation or enforcement actions related to compression station land use permits or other losses, costs and expenses related certain surface lease use agreements. As of December 31, 2010, we paid obligations of Williams Partners related to the Ryan Gulch Expansion Project of $2.9 million. Williams Partners is obligated to reimburse us for any costs related to the pipeline and compression projects known collectively as the Kokopelli Expansion irrespective of whether those costs were incurred prior to the effective date of the Piceance Disposition. We received $432,000 in reimbursements for the Kokopelli Expansion for the year ended December 31, 2010.
 
Transition Services Agreement.  We provide transition services to Williams Partners related to the Piceance Disposition. As of December 31, 2010, we incurred expenses of $3 million for which we were reimbursed by Williams Partners pursuant to this agreement.
 
Meter Agency Agreements.  We have agreed to provide for the operation, calibration and maintenance of certain meters for the benefit of Williams Partners. It is anticipated that payments under these agreements will be approximately $275,000 in 2011.


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DESCRIPTION OF OUR CONCURRENT FINANCING TRANSACTIONS
 
Concurrent with or shortly following this offering, we expect that we will issue up to $1.5 billion in aggregate principal amount of senior unsecured notes and we will enter into a senior unsecured credit facility. The following summary is a description of the principal terms of the Notes and the Credit Facility. This offering of our Class A common stock is not contingent upon the entry into the Credit Facility or the completion of the Notes Offering. The actual terms and provisions of the Notes and our Credit Facility may be different than our current expectations. We cannot assure you that we will obtain terms consistent in all respects with our description below.
 
Notes
 
We expect to offer and sell the Notes only to qualified institutional buyers in reliance on Rule 144A under the Securities Act and to certain non-U.S. persons in transactions outside the United States in reliance on Regulation S under the Securities Act. We do not expect to register the offer and sale of the Notes under the Securities Act and, as a result, the Notes may not be offered and sold in the United States absent registration or an applicable exemption from registration requirements. This prospectus shall not be deemed to be an offer to sell or a solicitation of an offer to buy the Notes.
 
We expect the Notes will bear interest at a fixed rate agreed to by us and the initial purchasers in the Notes Offering. In connection with the Notes Offering, we expect to enter into a registration rights agreement that will obligate us to file an exchange offer registration statement for the exchange of the Notes for a new issue of substantially identical debt securities, the issuance of which has been registered under the Securities Act, as evidence of the same underlying obligation of indebtedness.
 
Credit Facility
 
We expect to enter into a $1.5 billion, five year senior unsecured credit facility. The Credit Facility may, under certain conditions, be increased by an additional $300 million. Funds may be borrowed under two methods of calculating interest: a fluctuating base rate equal to the lender’s base rate plus an applicable margin, or a periodic base rate equal to LIBOR plus an applicable margin. We expect the applicable margin and the commitment fee to be based on our senior unsecured long-term debt ratings. The Credit Facility will contain various covenants consistent with like companies’ unsecured credit facilities, with similar credit ratings in the industry. We expect these covenants to limit, among other things, our and our subsidiaries’ ability to incur indebtedness, grant certain liens supporting indebtedness, merge or consolidate, sell all or substantially all of our assets, enter into certain affiliate transactions and allow any material change in the nature of our or our subsidiaries’ businesses. Significant financial covenants under the Credit Facility will likely include:
 
  •   a ratio of Debt to Capitalization (as such terms will be defined in the Credit Facility) no greater than 60% for us and our consolidated subsidiaries as calculated at the end of each fiscal quarter; and
 
  •   if our senior unsecured debt rating at the time of this offering is below investment grade with a stable outlook, an additional covenant will require a minimum ratio of Net Present Value of Projected Future Cash Flows from Proved Reserves to Debt (as defined in the Credit Facility) for us and our consolidated subsidiaries as calculated at the end of each fiscal quarter. This covenant would fall away if and when an investment grade rating with a stable outlook is received.
 
The Credit Facility will include customary events of default. If an event of default occurs under the Credit Facility, the lenders will be able to terminate the commitments and accelerate the maturity of any loans under the Credit Facility and exercise other rights and remedies.


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DESCRIPTION OF CAPITAL STOCK
 
The following is a description of the material terms of our capital stock as to be provided in our amended and restated certificate of incorporation and amended and restated bylaws, as each is anticipated to be in effect upon the completion of this offering. We also refer you to our amended and restated certificate of incorporation and amended and restated bylaws, copies of which are filed as exhibits to the registration statement of which this prospectus forms a part.
 
Authorized Capitalization
 
Following completion of this offering, our authorized capital stock will consist of (i)      shares of Class A common stock, par value $      per share, (ii)      shares of Class B common stock, par value $      per share and (iii)      shares of preferred stock, par value $      per share.
 
Authorized but unissued shares of our capital stock may be used for a variety of corporate purposes, including future public offerings, to raise additional capital or to facilitate acquisitions. The Delaware General Corporation Law does not require stockholder approval for any issuance of authorized shares. However, the listing requirements of the NYSE, which would apply so long as our Class A common stock is listed on the NYSE, require stockholder approval of certain issuances equal to or exceeding 20% of the then outstanding voting power or then outstanding number of shares of Class A common stock.
 
Common Stock
 
Voting Rights
 
The holders of Class A common stock and Class B common stock generally have identical rights, except that holders of Class A common stock are entitled to one vote per share while holders of Class B common stock are entitled to ten votes per share on all matters to be voted on by stockholders. Holders of shares of Class A common stock and Class B common stock are not entitled to cumulate their votes in the election of directors. Generally, except as discussed in “—Anti-Takeover Effects of Certificate of Incorporation and Bylaws Provisions,” all matters to be voted on by stockholders must be approved by a majority of the votes entitled to be cast by the holders of Class A common stock and Class B common stock present in person or represented by proxy, voting together as a single class, subject to any voting rights granted to holders of any preferred stock. Except as otherwise provided by law or in the amended and restated certificate of incorporation (as further discussed in “—Anti-Takeover Effects of Certificate of Incorporation and Bylaws Provisions”), and subject to any voting rights granted to holders of any outstanding preferred stock, amendments to the amended and restated certificate of incorporation must be approved by a majority of the votes entitled to be cast by the holders of Class A common stock and Class B common stock, voting together as a single class. Any provision for the voluntary, mandatory and other conversion or exchange of the Class B common stock into or for Class A common stock on a one-for-one basis, whether by amendment to the amended and restated certificate of incorporation, will be deemed not to affect adversely the rights of the Class A common stock.
 
Dividends
 
Holders of Class A common stock and Class B common stock will share equally on a per share basis in any dividend declared by our board of directors, subject to any preferential rights of any outstanding shares of preferred stock. Dividends payable in shares of common stock may be paid only as follows:
 
  •   shares of Class A common stock may be paid only to holders of Class A common stock, and
 
  •   shares of Class B common stock may be paid only to holders of Class B common stock.
 
The number of shares so paid will be equal on a per share basis with respect to each outstanding share of Class A common stock and Class B common stock.
 
We may not reclassify, subdivide or combine shares of either class of common stock without at the same time proportionally reclassifying, subdividing or combining shares of the other class.


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Conversion
 
Each share of Class B common stock is convertible while beneficially owned by Williams or any of its affiliates at the option of the holder thereof into one share of Class A common stock. Williams has indicated that it intends to convert its Class B common shares to Class A common shares immediately prior to a spin-off of our common stock to Williams’ stockholders, assuming such conversion would not jeopardize the ability to consummate the tax-free spin-off or the tax-free treatment of any related restructuring transaction undertaken by Williams. In the event that Williams does not convert its Class B common shares to Class A common shares prior to such spin-off, then following any distribution of Class B common stock to Williams common stockholders in a transaction (including any distribution in exchange for Williams shares or securities) intended to qualify as a tax-free distribution under section 355 of the Code, or any corresponding provision of any successor statute (a “Tax-Free Spin-Off”), shares of Class B common stock will no longer be convertible into shares of Class A common stock.
 
Prior to a Tax-Free Spin-Off, any shares of Class B common stock transferred to a person other than Williams or any of its affiliates will be converted automatically into shares of Class A common stock upon such transfer. To the extent that Williams does not convert its Class B common shares to Class A common shares prior to a Tax-Free Spin-Off, shares of Class B common stock transferred to stockholders of Williams in such Tax-Free Spin-Off will not be converted into shares of Class A common stock and, following a Tax-Free Spin-Off, shares of Class B common stock will be transferable as Class B common stock, subject to applicable laws.
 
All shares of Class B common stock will be converted automatically into Class A common stock if a Tax-Free Spin-Off has not occurred and the number of outstanding shares of Class B common stock beneficially owned by Williams and its affiliates falls below 50% of the aggregate number of outstanding shares of our common stock. This automatic conversion of Class B common stock into Class A common stock will prevent Williams from decreasing its economic interest in our company to less than 50% while still retaining control of more than 80% of our voting power. All conversions will be effected on a one-for-one basis.
 
Other Rights
 
Unless approved by 75% of the votes entitled to be cast by the holders of each class of our common stock, voting separately as a class, in the event of any reorganization or consolidation of WPX with one or more corporations or a merger of WPX with another corporation in which shares of common stock are converted into or exchangeable for shares of stock, other securities or property (including cash), all holders of our common stock, regardless of class, will be entitled to receive the same kind and amount of shares of stock and other securities and property (including cash).
 
On liquidation, dissolution or winding up of WPX, after payment in full of the amounts required to be paid to holders of preferred stock, if any, all holders of common stock, regardless of class, are entitled to receive the same amount per share with respect to any distribution of assets to holders of shares of common stock.
 
No shares of either class of common stock are subject to redemption or have preemptive rights to purchase additional shares of our common stock or other securities.
 
Upon completion of this offering, all the outstanding shares of Class A common stock and Class B common stock will be validly issued, fully paid and nonassessable.
 
Preferred Stock
 
Our amended and restated certificate of incorporation authorizes our board of directors to establish one or more series of preferred stock. Unless required by law or by any stock exchange on which our common stock is listed, the authorized shares of preferred stock will be available for issuance without further action by you.


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Our board of directors is able to determine, with respect to any series of preferred stock, the terms and rights of that series, including the following:
 
  •   the designation of the series;
 
  •   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 be convertible into shares of any other class or series, or any other security, of our company or any other corporation, and, if so, the specification of the other class or series or other security, the conversion price or prices or rate or rates, any rate adjustments, the date or dates as of which the shares will be convertible and all other terms and conditions upon which the conversion may be made;
 
  •   restrictions on the issuance of shares of the same series or of any other class or series; and
 
  •   the voting rights, if any, of the holders of the series.
 
Provisions of Amended and Restated Certificate of Incorporation Governing Corporate Opportunities
 
After the completion of this offering, Williams will remain a substantial stockholder of ours until it completes the spin-off of our stock to Williams’ stockholders or otherwise disposes of our common stock that it owns. We and Williams are engaged in similar activities or lines of business and have an interest in the same areas of corporate opportunities. Williams will not have a duty to refrain from engaging directly or indirectly in the same or similar business activities or lines of business as us, and to the fullest extent permitted by law, neither Williams nor any of its directors or officers will be liable to us or our stockholders for breach of any fiduciary duty, by reason of any such activities. Additionally, if Williams acquires knowledge of a potential transaction or matter that may be a corporate opportunity for Williams and us, to the fullest extent permitted by law, Williams will have no duty to communicate or offer such corporate opportunity to us and will not be liable to us or our stockholders for breach of any duty (fiduciary or otherwise) if Williams pursues or acquires such corporate opportunity for itself or directs such corporate opportunity to its affiliates. If any director or officer of Williams who is also one of our officers or directors becomes aware of a potential business opportunity, transaction or other matter (other than one expressly offered to that director or officer in writing solely in his or her capacity as our director or officer), that director or officer will have no duty to communicate or offer that opportunity to us, and will be permitted to communicate or offer that opportunity to Williams (or its affiliates) and that director or officer will not to the fullest extent permitted by law, be deemed to have (1) breached or acted in a manner inconsistent with or opposed to his or her fiduciary or other duties to us regarding the opportunity or (2) acted in bad faith or in a manner inconsistent with the best interests of our company or our stockholders. See “Risk Factors—Risks Related to Our Relationship with Williams—Pursuant to the terms of our amended and restated certificate of incorporation, Williams is not required to offer corporate opportunities to us, and certain of our directors and officers are permitted to offer certain corporate opportunities to Williams before us.”
 
The provisions in our amended and restated certificate of incorporation governing corporate opportunities between Williams and us will automatically terminate, expire and have no further force and effect once (1) Williams and its subsidiaries (excluding us and our subsidiaries) cease to beneficially own shares of capital


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stock representing 50% or more of the voting power of all then outstanding shares of our capital stock entitled to vote generally in the election of directors and (2) no person who is a director or officer of Williams is also a director or officer of ours. At that point, any such activities will be governed by Delaware law generally.
 
Anti-Takeover Effects of Certificate of Incorporation and Bylaws Provisions
 
Some provisions of our amended and restated certificate of incorporation and amended and restated bylaws could make the following more difficult, although they have little significance while we are controlled by Williams:
 
  •   acquisition of us by means of a tender offer or merger;
 
  •   acquisition of us by means of a proxy contest or otherwise; or
 
  •   removal of our incumbent officers and directors.
 
These provisions, summarized below, are expected to discourage coercive takeover practices and inadequate takeover bids. These provisions also are designed to encourage persons seeking to acquire control of us to first negotiate with our board of directors. We believe that the benefits of the potential ability to negotiate with the proponent of an unfriendly or unsolicited proposal to acquire or restructure our company outweigh the disadvantages of discouraging those proposals because negotiation of them could result in an improvement of their terms.
 
Classified Board
 
Our amended and restated certificate of incorporation provides that our board of directors is divided into three classes. The term of the first class of directors expires at our 2012 annual meeting of stockholders, the term of the second class of directors expires at our 2013 annual meeting of stockholders and the term of the third class of directors expires at our 2014 annual meeting of stockholders. At each of our annual meetings of stockholders, the successors of the class of directors whose term expires at that meeting of stockholders will be elected for a three-year term, one class being elected each year by our stockholders. This system of electing and removing directors may discourage a third party from making a tender offer or otherwise attempting to obtain control of us if Williams no longer controls us because it generally makes it more difficult for stockholders to replace a majority of our directors.
 
Election and Removal of Directors
 
Directors may be removed, with or without cause, by the affirmative vote of shares representing a majority of the votes entitled to be cast by the outstanding capital stock in the election of our board of directors as long as Williams owns shares representing at least a majority of the votes entitled to be cast by the outstanding capital stock in the election of our board of directors. Once Williams ceases to own shares representing at least a majority of the votes entitled to be cast by the outstanding capital stock in the election of our board of directors, our amended and restated certificate of incorporation requires that directors may only be removed for cause and only by the affirmative vote of not less than 75% of votes entitled to be cast by the outstanding capital stock in the election of our board of directors.
 
Size of Board and Vacancies
 
Our amended and restated certificate of incorporation provides that the number of directors on our board of directors will be fixed exclusively by our board of directors. Newly created directorships resulting from any increase in our authorized number of directors will be filled solely by the vote of our remaining directors in office. Any vacancies in our board of directors resulting from death, resignation, retirement, disqualification, removal from office or other cause will be filled solely by the vote of our remaining directors in office; provided, however, that as long as Williams continues to beneficially own shares representing at least a majority of the votes entitled to be cast by the outstanding capital stock in the election of our board of directors and such vacancy was caused by the action of stockholders, then such vacancy also may be filled by


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


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No Cumulative Voting
 
Our amended and restated certificate of incorporation and amended and restated bylaws do not provide for cumulative voting in the election of directors.
 
Undesignated Preferred Stock
 
The authorization of our undesignated preferred stock makes it possible for our board of directors to issue our preferred stock with voting or other rights or preferences that could impede the success of any attempt to change control of us. These and other provisions may have the effect of deferring hostile takeovers or delaying changes of control of our management.
 
Delaware Anti-Takeover Statute
 
We are subject to Section 203 of the Delaware General Corporation Law. Subject to specific exceptions, Section 203 prohibits a publicly held Delaware corporation from engaging in a “business combination” with an “interested stockholder” for a period of three years after the date of the transaction in which the person became an interested stockholder, unless:
 
  •   the “business combination,” or the transaction in which the stockholder became an “interested stockholder” is approved by the board of directors prior to the date the “interested stockholder” attained that status;
 
  •   upon completion of the transaction that resulted in the stockholder becoming an “interested stockholder,” the “interested stockholder” owned at least 85% of the voting stock of the corporation outstanding at the time the transaction commenced (excluding for purposes of determining the voting stock outstanding and not outstanding, voting stock owned by the interested stockholder, those shares owned by persons who are directors and also officers, and employee stock plans in which employee participants do not have the right to determine confidentiality whether shares held subject to the plan will be tendered in a tender or exchange offer); or
 
  •   on or subsequent to the date a person became an “interested stockholder,” the “business combination” is approved by the board of directors and authorized at an annual or special meeting of stockholders by the affirmative vote of at least two-thirds of the outstanding voting stock that is not owned by the “interested stockholder.”
 
“Business combinations” include mergers, asset sales and other transactions resulting in a financial benefit to the “interested stockholder.” Subject to various exceptions, an “interested stockholder” is a person who, together with his or her affiliates and associates, owns, or within the previous three years did own, 15% or more of the corporation’s outstanding voting stock. These restrictions could prohibit or delay the accomplishment of mergers or other takeover or change in control attempts with respect to us and, therefore, may discourage attempts to acquire us.
 
Limitations on Liability and Indemnification of Officers and Directors
 
The Delaware General Corporation Law authorizes corporations to limit or eliminate the personal liability of directors to corporations and their stockholders for monetary damages for breaches of directors’ fiduciary duties. Under our amended and restated certificate of incorporation, subject to limitations imposed by the Delaware General Corporation Law, no director shall be personally liable to us or our stockholders for monetary damages for breach of fiduciary duty as a director, except for liability:
 
  •   for any breach of the director’s duty of loyalty to the corporation or its stockholders;
 
  •   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


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  •   for any transaction from which a director derived an improper personal benefit.
 
Our amended and restated bylaws provide that we must indemnify our directors and officers to the fullest extent authorized by the Delaware General Corporation Law. We are also expressly authorized to advance certain expenses (including attorneys’ fees and disbursements and court costs) and carry directors’ and officers’ insurance providing indemnification for our directors, officers and certain employees for some liabilities. We believe that these indemnification provisions and insurance are useful to attract and retain qualified directors and executive officers. There is currently no pending material litigation or proceeding involving any of our directors, officers or employees for which indemnification is sought.
 
Transfer Agent and Registrar
 
Computershare Trust Company, N.A. will be the transfer agent and registrar for our Class A and Class B common stock.
 
Listing
 
We intend to apply to have our Class A common stock listed on the NYSE under the symbol “WPX.”


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SHARES ELIGIBLE FOR FUTURE SALE
 
Prior to this offering, there has not been any public market for our Class A common stock, and a significant public market for our Class A common stock may not develop or be sustained after this offering. We cannot predict what effect, if any, sales of shares of our Class A common stock or the availability of shares of our Class A common stock for sale will have on the prevailing market price of our Class A common stock from time to time. The number of shares of our Class A common stock available for future sale into the public markets is subject to legal and contractual restrictions, some of which are described below. The expiration of these restrictions will permit sales of substantial amounts of our Class A common stock in the public market or could create the perception that these sales could occur, which could adversely affect the market price for our Class A common stock and could make it more difficult for us to raise capital through the sale of our equity or equity-related securities at a time and price that we deem acceptable.
 
Upon the completion of this offering, we expect to have a total of           shares of our Class A common stock outstanding (           if the underwriters exercise their option to purchase additional Class A common shares in full). All of the shares of our Class A common stock sold in this offering will be freely tradable without restriction or further registration under the Securities Act, except for “restricted” shares held by persons who may be deemed our “affiliates,” as that term is defined under Rule 144 of the Securities Act. An “affiliate” is a person that directly, or indirectly through one or more intermediaries, controls or is controlled by us or is under common control with us.
 
Rule 144
 
In general, pursuant to Rule 144 under the Securities Act in effect on the date of this prospectus, once we have been subject to public company reporting requirements for at least 90 days, a person who is not one of our affiliates at any time during the 90 days preceding a sale and who has beneficially owned the shares of our Class A common stock to be sold for at least six months, including the holding period of any prior owner other than our affiliates, would be entitled to sell those shares without complying with the manner of sale, volume limitation or notice provisions of Rule 144, subject to compliance with the public information requirements of Rule 144. In addition, under Rule 144, a person who is not one of our affiliates at any time during the 90 days preceding a sale, and who has beneficially owned the shares of our Class A common stock to be sold for at least one year, including the holding period of any prior owner other than our affiliates, would be entitled to sell those shares without regard to the requirements of Rule 144. Our affiliates or persons selling on behalf of our affiliates are entitled to sell, upon expiration of the lock-up agreements described below, within any three-month period beginning 90 days after the date of this prospectus, a number of shares that does not exceed the greater of:
 
  •   1.0% of the number of shares of Class A common stock then outstanding, which is approximately           (           if the underwriters exercise their option to purchase additional Class A common shares in full) shares of Class A common stock upon the completion of this offering; and
 
  •   the average weekly trading volume of our Class A common stock on the NYSE during the four calendar weeks preceding each such sale, subject to certain restrictions.
 
Sales under Rule 144 by our affiliates or persons selling on behalf of our affiliates are also subject to manner of sale provisions and notice requirements and to the availability of current public information about us. Rule 144 also provides that affiliates relying on Rule 144 to sell shares of our Class A common stock that are not restricted shares must nonetheless comply with the same restrictions applicable to restricted shares, other than the holding period requirement.
 
Lock-up Agreements
 
We, our directors, certain of our officers and Williams have agreed with the underwriters not to sell or otherwise transfer or dispose of any shares of our common stock, subject to specified exceptions, during the period from the date of this prospectus continuing through the date that is 180 days after the date of this prospectus, subject to an extension in certain circumstances, except with the prior written consent of Barclays


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


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


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


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foreign corporations” or “passive foreign investment companies.” Such entities should consult their own tax advisors to determine the U.S. federal, state, local and other tax consequences that may be relevant to them.
 
Distributions
 
Any dividends paid to a non-U.S. holder with respect to the shares of our Class A common stock will be subject to withholding tax at a 30% rate or such lower rate as specified by an applicable income tax treaty. However, dividends that are effectively connected with the conduct of a trade or business within the United States and, where an applicable tax treaty so provides, are attributable to a U.S. permanent establishment, are not subject to the withholding tax, but instead are subject to U.S. federal income tax on a net income basis at applicable graduated individual or corporate rates. Certain certification and disclosure requirements must be complied with in order for effectively connected income to be exempt from withholding. Any such effectively connected dividends received by a foreign corporation may, under certain circumstances, be subject to an additional branch profits tax at a 30% rate or such lower rate as specified by an applicable income tax treaty.
 
A non-U.S. holder of shares of our Class A common stock who wishes to claim the benefit of an applicable treaty rate is required to satisfy applicable certification and other requirements. If a non-U.S. holder is eligible for a reduced rate of U.S. withholding tax pursuant to an income tax treaty, the holder may obtain a refund of any excess amounts withheld by timely filing an appropriate claim for refund with the IRS.
 
Sale, Exchange, Redemption or Other Taxable Disposition of our Class A Common Stock
 
Any gain realized by a non-U.S. holder upon the sale, exchange, redemption (provided the redemption is treated as a sale or exchange) or other taxable disposition of shares of our Class A common stock will not be subject to U.S. federal income tax with respect to such gain unless:
 
  •   that gain is effectively connected with the conduct of a trade or business in the United States (and, if required by an applicable income tax treaty, is attributable to a U.S. permanent establishment);
 
  •   the non-U.S. holder is an individual who is present in the United States for 183 days or more in the taxable year of that disposition, and certain other conditions are met; or
 
  •   our Class A common stock constitutes a U.S. real property interest by reason of our status as a “U.S. real property holding corporation” (a “USRPHC”) for U.S. federal income tax purposes at any time within the shorter of the five-year period preceding the disposition or the period that the non-U.S. holder held our Class A common stock.
 
A non-U.S. holder described in the first bullet point above will be subject to U.S. federal income tax on the net gain derived from the sale in the same manner as a U.S. holder. If a non-U.S. holder is eligible for the benefits of a tax treaty between the United States and its country of residence, any such gain will be subject to U.S. federal income tax in the manner specified by the treaty. To claim the benefit of a treaty, a non-U.S. holder must properly submit an IRS Form W-8BEN (or suitable successor or substitute form). A non-U.S. holder that is a foreign corporation and is described in the first bullet point above will be subject to tax on gain under regular graduated U.S. federal income tax rates and, in addition, may be subject to a branch profits tax at a 30% rate or a lower rate if so specified by an applicable income tax treaty. An individual non-U.S. holder described in the second bullet point above will be subject to a flat 30% U.S. federal income tax on the gain derived from the sale, which may be offset by U.S. source capital losses.
 
With regard to the third bullet point above, generally, a corporation is a USRPHC if the fair market value of its United States real property interests equals or exceeds 50% of the sum of the fair market value of its worldwide real property interests and its other assets used or held for use in a trade or business. We expect to be a USRPHC for U.S. federal income tax purposes. However, even if we are or become a USRPHC, our Class A common stock will be treated as a U.S. real property interest only if the non-U.S. holder actually or constructively holds more than 5% of our Class A common stock at any time during the holding period described above, provided that our Class A common stock does not cease to be regularly traded on an established securities market prior to the year in which the sale occurs. Any taxable gain generally would be taxed in the same manner as gain that is effectively connected with the conduct of a trade or business in the


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


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UNDERWRITING
 
Barclays Capital Inc., Citigroup Global Markets Inc. and J.P. Morgan Securities LLC are acting as representatives of the underwriters and joint book-running managers of this offering. Under the terms of an underwriting agreement, which will be filed as an exhibit to the registration statement, each of the underwriters named below has severally agreed to purchase from us the respective number of Class A common stock shown opposite its name below:
 
         
    Number of
 
Underwriters
  Shares  
 
Barclays Capital Inc. 
       
Citigroup Global Markets Inc.
       
J.P. Morgan Securities LLC
             
         
Total
       
         
 
The underwriting agreement provides that the underwriters’ obligation to purchase shares of Class A common stock depends on the satisfaction of the conditions contained in the underwriting agreement including:
 
  •   the obligation to purchase all of the shares of Class A common stock offered hereby (other than those shares of Class A common stock covered by their option to purchase additional shares as described below), if any of the shares are purchased;
 
  •   the representations and warranties made by us to the underwriters are true;
 
  •   there is no material change in our business or the financial markets; and
 
  •   we deliver customary closing documents to the underwriters.
 
Commissions and Expenses
 
The following table summarizes the underwriting discounts and commissions we will pay to the underwriters. These amounts are shown assuming both no exercise and full exercise of the underwriters’ option to purchase additional shares. The underwriting fee is the difference between the initial price to the public and the amount the underwriters pay to us for the shares.
 
                 
   
No Exercise
   
Full Exercise
 
 
Per share
               
                 
Total
                           
                 
 
The representatives of the underwriters have advised us that the underwriters propose to offer the shares of Class A common stock directly to the public at the public offering price on the cover of this prospectus and to selected dealers, which may include the underwriters, at such offering price less a selling concession not in excess of $      per share. After the offering, the representatives may change the offering price and other selling terms. Sales of shares made outside of the United States may be made by affiliates of the underwriters.
 
The expenses of the offering that are payable by us are estimated to be $           (excluding underwriting discounts and commissions).
 
Option to Purchase Additional Shares
 
We have granted the underwriters an option exercisable for 30 days after the date of the underwriting agreement, to purchase, from time to time, in whole or in part, up to an aggregate of           shares at the public offering price less underwriting discounts and commissions. This option may be exercised if the underwriters sell more than           shares in connection with this offering. To the extent that this option is exercised, each underwriter will be obligated, subject to certain conditions, to purchase its pro rata portion of


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these additional shares based on the underwriter’s underwriting commitment in the offering as indicated in the table at the beginning of this Underwriting section.
 
Lock-Up Agreements
 
We, our directors, certain of our officers and Williams have agreed that, subject to certain exceptions, without the prior written consent of Barclays Capital Inc., we and they will not directly or indirectly, (1) offer for sale, sell, pledge, or otherwise dispose of (or enter into any transaction or device that is designed to, or could be expected to, result in the disposition by any person at any time in the future of) any shares of Class A common stock (including, without limitation, shares of Class A common stock that may be deemed to be beneficially owned by us or them in accordance with the rules and regulations of the SEC and shares of Class A common stock that may be issued upon exercise of any options or warrants) or securities convertible into or exercisable or exchangeable for Class A common stock, (2) enter into any swap or other derivatives transaction that transfers to another, in whole or in part, any of the economic consequences of ownership of the Class A common stock, (3) make any demand for or exercise any right or file or cause to be filed a registration statement, including any amendments thereto, with respect to the registration of any shares of Class A common stock or securities convertible, exercisable or exchangeable into Class A common stock or any of our other securities, or (4) publicly disclose the intention to do any of the foregoing for a period of 180 days after the date of this prospectus, except that 120 days after the date of this prospectus, Williams will be permitted to spin-off all of our shares of common stock that it owns to its stockholders.
 
The 180-day restricted period described in the preceding paragraph will be extended if:
 
  •   during the last 17 days of the 180-day restricted period we issue an earnings release or material news or a material event relating to us occurs; or
 
  •   prior to the expiration of the 180-day restricted period, we announce that we will release earnings results during the 16-day period beginning on the last day of the 180-day period,
 
in which case the restrictions described in the preceding paragraph will continue to apply until the expiration of the 18-day period beginning on the issuance of the earnings release or the announcement of the material news or occurrence of a material event, unless such extension is waived in writing by Barclays Capital Inc.
 
Barclays Capital Inc., in its sole discretion, may release the Class A common stock and other securities subject to the lock-up agreements described above in whole or in part at any time with or without notice. When determining whether or not to release Class A common stock and other securities from lock-up agreements, Barclays Capital Inc. will consider, among other factors, the holder’s reasons for requesting the release, the number of shares of Class A common stock and other securities for which the release is being requested and market conditions at the time.
 
Offering Price Determination
 
Prior to this offering, there has been no public market for our Class A common stock. The initial public offering price will be negotiated between the representatives and us. In determining the initial public offering price of our Class A common stock, the representatives will consider:
 
  •   the history and prospects for the industry in which we compete;
 
  •   our financial information;
 
  •   the ability of our management and our business potential and earning prospects;
 
  •   the prevailing securities markets at the time of this offering; and
 
  •   the recent market prices of, and the demand for, publicly traded shares of generally comparable companies.


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Indemnification
 
We have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act, and to contribute to payments that the underwriters may be required to make for these liabilities.
 
Stabilization, Short Positions and Penalty Bids
 
The representatives may engage in stabilizing transactions, short sales and purchases to cover positions created by short sales, and penalty bids or purchases for the purpose of pegging, fixing or maintaining the price of the Class A common stock, in accordance with Regulation M under the Exchange Act:
 
  •   Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum.
 
  •   A short position involves a sale by the underwriters of shares in excess of the number of shares the underwriters are obligated to purchase in the offering, which creates the syndicate short position. This short position may be either a covered short position or a naked short position. In a covered short position, the number of shares involved in the sales made by the underwriters in excess of the number of shares they are obligated to purchase is not greater than the number of shares that they may purchase by exercising their option to purchase additional shares. In a naked short position, the number of shares involved is greater than the number of shares in their option to purchase additional shares. The underwriters may close out any short position by either exercising their option to purchase additional shares and/or purchasing shares in the open market. In determining the source of shares to close out the short position, the underwriters will consider, among other things, the price of shares available for purchase in the open market as compared to the price at which they may purchase shares through their option to purchase additional shares. A naked short position is more likely to be created if the underwriters are concerned that there could be downward pressure on the price of the shares in the open market after pricing that could adversely affect investors who purchase in the offering.
 
  •   Syndicate covering transactions involve purchases of the Class A common stock in the open market after the distribution has been completed in order to cover syndicate short positions.
 
  •   Penalty bids permit the representatives to reclaim a selling concession from a syndicate member when the Class A common stock originally sold by the syndicate member is purchased in a stabilizing or syndicate covering transaction to cover syndicate short positions.
 
These stabilizing transactions, syndicate covering transactions and penalty bids may have the effect of raising or maintaining the market price of our Class A common stock or preventing or retarding a decline in the market price of the Class A common stock. As a result, the price of the Class A common stock may be higher than the price that might otherwise exist in the open market. These transactions may be effected on the NYSE or otherwise and, if commenced, may be discontinued at any time.
 
Neither we nor any of the underwriters make any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of the Class A common stock. In addition, neither we nor any of the underwriters make representation that the representatives will engage in these stabilizing transactions or that any transaction, once commenced, will not be discontinued without notice.
 
Electronic Distribution
 
A prospectus in electronic format may be made available on the Internet sites or through other online services maintained by one or more of the underwriters and/or selling group members participating in this offering, or by their affiliates. In those cases, prospective investors may view offering terms online and, depending upon the particular underwriter or selling group member, prospective investors may be allowed to place orders online. The underwriters may agree with us to allocate a specific number of shares for sale to online


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brokerage account holders. Any such allocation for online distributions will be made by the representatives on the same basis as other allocations.
 
Other than the prospectus in electronic format, the information on any underwriter’s or selling group member’s web site and any information contained in any other web site maintained by an underwriter or selling group member is not part of the prospectus or the registration statement of which this prospectus forms a part, has not been approved and/or endorsed by us or any underwriter or selling group member in its capacity as underwriter or selling group member and should not be relied upon by investors.
 
New York Stock Exchange
 
We intend to apply to list our shares of Class A common stock for quotation on the NYSE under the symbol “WPX.” In connection with that listing, the underwriters will undertake to sell the minimum number of Class A common shares to the minimum number of beneficial owners necessary to meet the NYSE listing requirements.
 
Discretionary Sales
 
The underwriters have informed us that they do not intend to confirm sales to discretionary accounts that exceed 5% of the total number of shares offered by them.
 
Stamp Taxes
 
If you purchase shares of Class A common stock offered in this prospectus, you may be required to pay stamp taxes and other charges under the laws and practices of the country of purchase, in addition to the offering price listed on the cover page of this prospectus.
 
Relationships
 
Certain of the underwriters and/or their affiliates have engaged, and may in the future engage, in investment banking transactions with us in the ordinary course of their business. They have received, and expect to receive, customary compensation and expense reimbursement for these investment banking transactions.
 
Selling Restrictions
 
European Economic Area
 
In relation to each member state of the European Economic Area which has implemented the Prospectus Directive (each, a “Relevant Member State”), including each Relevant Member State that has implemented the 2010 PD Amending Directive with regard to persons to whom an offer of securities is addressed and the denomination per unit of the offer of securities (each, an “Early Implementing Member State”), with effect from and including the date on which the Prospectus Directive is implemented in that Relevant Member State (the “Relevant Implementation Date”), no offer of shares will be made to the public in that Relevant Member State (other than offers (the “Permitted Public Offers”) where a prospectus will be published in relation to the shares that has been approved by the competent authority in a Relevant Member State or, where appropriate, approved in another Relevant Member State and notified to the competent authority in that Relevant Member State, all in accordance with the Prospectus Directive), except that with effect from and including that Relevant Implementation Date, offers of shares may be made to the public in that Relevant Member State at any time:
 
  (a)   to “qualified investors” as defined in the Prospectus Directive, including:
 
  (i)   (in the case of Relevant Member States other than Early Implementing Member States), legal entities which are authorized or regulated to operate in the financial markets or, if not so authorized or regulated, whose corporate purpose is solely to invest in securities, or any legal entity which has two or more of (i) an average of at least 250 employees during the last


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  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,
 
provided that no such offer of shares shall result in a requirement for the publication of a prospectus pursuant to Article 3 of the Prospectus Directive or of a supplement to a prospectus pursuant to Article 16 of the Prospectus Directive.
 
Each person in a Relevant Member State (other than a Relevant Member State where there is a Permitted Public Offer) who initially acquires any shares or to whom any offer is made will be deemed to have represented, acknowledged and agreed that (A) it is a “qualified investor”, and (B) in the case of any shares acquired by it as a financial intermediary, as that term is used in Article 3(2) of the Prospectus Directive, (x) the shares acquired by it in the offering have not been acquired on behalf of, nor have they been acquired with a view to their offer or resale to, persons in any Relevant Member State other than “qualified investors” as defined in the Prospectus Directive, or in circumstances in which the prior consent of the Subscribers has been given to the offer or resale, or (y) where shares have been acquired by it on behalf of persons in any Relevant Member State other than “qualified investors” as defined in the Prospectus Directive, the offer of those shares to it is not treated under the Prospectus Directive as having been made to such persons.
 
For the purpose of the above provisions, the expression “an offer to the public” in relation to any shares in any Relevant Member State means the communication in any form and by any means of sufficient information on the terms of the offer of any shares to be offered so as to enable an investor to decide to purchase any shares, as the same may be varied in the Relevant Member State by any measure implementing the Prospectus Directive in the Relevant Member State and the expression “Prospectus Directive” means Directive 2003/71 EC (including the 2010 PD Amending Directive, in the case of Early Implementing Member States) and includes any relevant implementing measure in each Relevant Member State and the expression “2010 PD Amending Directive” means Directive 2010/73/EU.
 
United Kingdom
 
This prospectus is only being distributed to, and is only directed at, persons in the United Kingdom that are qualified investors within the meaning of Article 2(1)(e) of the Prospectus Directive (“Qualified Investors”) that are also (i) investment professionals falling within Article 19(5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005 (the “Order”) or (ii) high net worth entities, and other persons to whom it may lawfully be communicated, falling within Article 49(2)(a) to (d) of the Order (all such persons together being referred to as “relevant persons”). This prospectus and its contents are confidential and should not be distributed, published or reproduced (in whole or in part) or disclosed by recipients to any other persons in the United Kingdom. Any person in the United Kingdom that is not a relevant persons should not act or rely on this document or any of its contents.
 
Australia
 
No prospectus or other disclosure document (as defined in the Corporations Act 2001 (Cth) of Australia (“Corporations Act”)) in relation to the shares has been or will be lodged with the Australian Securities &


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Investments Commission (“ASIC”). This document has not been lodged with ASIC and is only directed to certain categories of exempt persons. Accordingly, if you receive this document in Australia:
 
  (a)   you confirm and warrant that you are either:
 
  (i)      a “sophisticated investor” under section 708(8)(a) or (b) of the Corporations Act;
 
  (ii)     a “sophisticated investor” under section 708(8)(c) or (d) of the Corporations Act and that you have provided an accountant’s certificate to us which complies with the requirements of section 708(8)(c)(i) or (ii) of the Corporations Act and related regulations before the offer has been made;
 
  (iii)    a person associated with the Company under section 708(12) of the Corporations Act; or
 
  (iv)    a “professional investor” within the meaning of section 708(11)(a) or (b) of the Corporations Act,
 
and to the extent that you are unable to confirm or warrant that you are an exempt sophisticated investor, associated person or professional investor under the Corporations Act any offer made to you under this document is void and incapable of acceptance; and
 
  (b)   you warrant and agree that you will not offer any of the shares for resale in Australia within 12 months of those shares being issued unless any such resale offer is exempt from the requirement to issue a disclosure document under section 708 of the Corporations Act.
 
Hong Kong
 
The shares may not be offered or sold in Hong Kong, by means of any document, other than (a) to “professional investors” as defined in the Securities and Futures Ordinance (Cap. 571, Laws of Hong Kong) and any rules made under that Ordinance or (b) in other circumstances which do not result in the document being a “prospectus” as defined in the Companies Ordinance (Cap. 32, Laws of Hong Kong) or which do not constitute an offer to the public within the meaning of that Ordinance. No advertisement, invitation or document relating to the shares may be issued or may be in the possession of any person for the purpose of the issue, whether in Hong Kong or elsewhere, which is directed at, or the contents of which are likely to be read by, the public in Hong Kong (except if permitted to do so under the laws of Hong Kong) other than with respect to the shares which are intended to be disposed of only to persons outside Hong Kong or only to “professional investors” as defined in the Securities and Futures Ordinance (Cap. 571, Laws of Hong Kong) or any rules made under that Ordinance.
 
India
 
This prospectus has not been and will not be registered as a prospectus with the Registrar of Companies in India or with the Securities and Exchange Board of India. This prospectus or any other material relating to these securities is for information purposes only and may not be circulated or distributed, directly or indirectly, to the public or any members of the public in India and in any event to not more than 50 persons in India. Further, persons into whose possession this prospectus comes are required to inform themselves about and to observe any such restrictions. Each prospective investor is advised to consult its advisors about the particular consequences to it of an investment in these securities. Each prospective investor is also advised that any investment in these securities by it is subject to the regulations prescribed by the Reserve Bank of India and the Foreign Exchange Management Act and any regulations framed thereunder.
 
Japan
 
No securities registration statement (“SRS”) has been filed under Article 4, Paragraph 1 of the Financial Instruments and Exchange Law of Japan (Law No. 25 of 1948, as amended) (“FIEL”) in relation to the shares. The shares are being offered in a private placement to “qualified institutional investors” (tekikaku-kikan-toshika) under Article 10 of the Cabinet Office Ordinance concerning Definitions provided in Article 2 of the FIEL (the


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Ministry of Finance Ordinance No. 14, as amended) (“QIIs”), under Article 2, Paragraph 3, Item 2 i of the FIEL. Any QII acquiring the shares in this offer may not transfer or resell those shares except to other QIIs.
 
Korea
 
The shares may not be offered, sold and delivered directly or indirectly, or offered or sold to any person for reoffering or resale, directly or indirectly, in Korea or to any resident of Korea except pursuant to the applicable laws and regulations of Korea, including the Korea Securities and Exchange Act and the Foreign Exchange Transaction Law and the decrees and regulations thereunder. The shares have not been registered with the Financial Services Commission of Korea for public offering in Korea. Furthermore, the shares may not be resold to Korean residents unless the purchaser of the shares complies with all applicable regulatory requirements (including but not limited to government approval requirements under the Foreign Exchange Transaction Law and its subordinate decrees and regulations) in connection with the purchase of the shares.
 
Singapore
 
This prospectus has not been registered as a prospectus with the Monetary Authority of Singapore. Accordingly, this prospectus and any other document or material in connection with the offer or sale, or invitation for subscription or purchase, of the shares may not be circulated or distributed, nor may the shares be offered or sold, or be made the subject of an invitation for subscription or purchase, whether directly or indirectly, to persons in Singapore other than (i) to an institutional investor under Section 274 of the Securities and Future Act, Chapter 289 of Singapore (the “SFA”), (ii) to a “relevant person” as defined in Section 275(2) of the SFA, or any person pursuant to Section 275 (1A), and in accordance with the conditions, specified in Section 275 of the SFA or (iii) otherwise pursuant to, and in accordance with the conditions of, any other applicable provision of the SFA.
 
Where the shares are subscribed and purchased under Section 275 of the SFA by a relevant person which is:
 
  (a)   a corporation (which is not an accredited investor (as defined in Section 4A of the SFA)) the sole business of which is to hold investments and the entire share capital of which is owned by one or more individuals, each of whom is an accredited investor; or
 
  (b)   a trust (where the trustee is not an accredited investor (as defined in Section 4A of the SFA)) whose sole whole purpose is to hold investments and each beneficiary is an accredited investor, shares, debentures and units of shares and debentures of that corporation or the beneficiaries’ rights and interest (howsoever described) in that trust shall not be transferable within six months after that corporation or that trust has acquired the shares under Section 275 of the SFA except:
 
  (i)      to an institutional investor under Section 274 of the SFA or to a relevant person (as defined in Section 275(2) of the SFA) and in accordance with the conditions, specified in Section 275 of the SFA;
 
  (ii)     (in the case of a corporation) where the transfer arises from an offer referred to in Section 275(1A) of the SFA, or (in the case of a trust) where the transfer arises from an offer that is made on terms that such rights or interests are acquired at a consideration of not less than S$200,000 (or its equivalent in a foreign currency) for each transaction, whether such amount is to be paid for in cash or by exchange of securities or other assets;
 
  (iii)    where no consideration is or will be given for the transfer; or
 
  (iv)    where the transfer is by operation of law.
 
By accepting this prospectus, the recipient hereof represents and warrants that he is entitled to receive it in accordance with the restrictions set forth above and agrees to be bound by limitations contained herein. Any failure to comply with these limitations may constitute a violation of law.


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


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


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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
  $ 2,243     $ 2,183     $ 2,917  
Gas management, including affiliate
    1,742       1,456       3,244  
Hedge ineffectiveness and mark to market gains and losses
    27       18       29  
Other
    41       43       36  
                         
Total revenues
    4,053       3,700       6,226  
Costs and expenses:
                       
Lease and facility operating, including affiliate
    295       273       284  
Gathering, processing and transportation, including affiliate
    324       270       225  
Taxes other than income
    125       94       255  
Gas management (including charges for unutilized pipeline capacity)
    1,774       1,496       3,248  
Exploration
    76       56       38  
Depreciation, depletion and amortization
    881       894       758  
Impairment of producing properties and costs of acquired unproved reserves
    678       15       148  
Goodwill impairment
    1,003              
General and administrative, including affiliate
    252       251       253  
Gain on sale of contractual right to international production payment
                (148 )
Other — net
    (15 )     33       7  
                         
Total costs and expenses
    5,393       3,382       5,068  
                         
Operating income (loss)
    (1,340 )     318       1,158  
Interest expense, including affiliate
    (124 )     (100 )     (74 )
Interest capitalized
    16       18       20  
Investment income and other
    21       7       22  
                         
Income (loss) before income taxes
    (1,427 )     243       1,126  
Provision (benefit) for income taxes
    (151 )     94       400  
                         
Income (loss) from continuing operations
    (1,276 )     149       726  
Income (loss) from discontinued operations
    (3 )     (3 )     10  
                         
Net income (loss)
    (1,279 )     146       736  
Less: Net income attributable to noncontrolling interests
    8       6       8  
                         
Net income (loss) attributable to WPX Energy
  $ (1,287 )   $ 140     $ 728  
                         
 
See accompanying notes.


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WPX Energy
(Note 1)

Combined Balance Sheet
 
                 
    December 31,  
    2010     2009  
    (Dollars in millions)  
 
Assets
               
Current assets:
               
Cash and cash equivalents
  $ 37     $ 34  
Accounts receivable:
               
Trade, net of allowance for doubtful accounts of $15 and $19 as of December 31, 2010 and 2009, respectively
    362       361  
Affiliate
    60       54  
Derivative assets
    400       650  
Inventories
    78       62  
Other
    21       40  
                 
Total current assets
    958       1,201  
Investments
    105       95  
Properties and equipment, net (successful efforts method of accounting)
    8,501       7,724  
Derivative assets
    173       444  
Goodwill, net
          1,003  
Other noncurrent assets
    110       88  
                 
Total assets
  $ 9,847     $ 10,555  
                 
Liabilities and Equity
               
Current liabilities:
               
Accounts payable:
               
Trade
  $ 446     $ 460  
Affiliates
    64       37  
Accrued and other current liabilities
    144       220  
Deferred income taxes
    87       28  
Notes payable to Williams
    2,261       1,216  
Derivative liabilities
    146       578  
                 
Total current liabilities
    3,148       2,539  
Deferred income taxes
    1,629       1,841  
Derivative liabilities
    143       428  
Asset retirement obligations
    287       238  
Other noncurrent liabilities
    120       89  
Contingent liabilities and commitments (Note 9)
               
Equity:
               
Owner’s net equity:
               
Owner’s net investment
    4,280       5,284  
Accumulated other comprehensive income
    168       72  
                 
Total owner’s net equity
    4,448       5,356  
Noncontrolling interests in combined subsidiaries
    72       64  
                 
Total equity
    4,520       5,420  
                 
Total liabilities and equity
  $ 9,847     $ 10,555  
                 
 
See accompanying notes.


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WPX Energy
(Note 1)

Combined Statement of Equity
 
                                         
          Accumulated Other
                   
    Owner’s Net
    Comprehensive
    Total Owner’s Net
    Noncontrolling
       
    Investment     Income (Loss)*     Equity     Interest**     Total  
    (Dollars in millions)  
 
Balance at December 31, 2007
  $ 4,462     $ (161 )   $ 4,301     $ 55     $ 4,356  
Comprehensive income:
                                       
Net income
    728             728       8       736  
Other comprehensive income:
                                       
Change in fair value of cash flow hedges (net of $260 of income tax)
          454       454             454  
Net reclassifications into earnings of net cash flow hedge losses (net of $3 income tax benefit)
          5       5             5  
                                         
Total other comprehensive income
                                    459  
                                         
Total comprehensive income
                                    1,195  
                                         
Net transfers with Williams
    (32 )           (32 )           (32 )
Dividends to noncontrolling interests
                      (4 )     (4 )
                                         
Balance at December 31, 2008
    5,158       298       5,456       59       5,515  
                                         
Comprehensive income:
                                       
Net income
    140             140       6       146  
Other comprehensive income:
                                       
Change in fair value of net cash flow hedges (net of $97 of income tax)
          169       169             169  
Net reclassifications into earnings of cash flow hedge gain (net of $226 income tax provision)
          (395 )     (395 )           (395 )
                                         
Total other comprehensive loss
                                    (226 )
                                         
Total comprehensive income
                                    (80 )
                                         
Net transfers with Williams
    (14 )           (14 )           (14 )
Dividends to noncontrolling interests
                      (1 )     (1 )
                                         
Balance at December 31, 2009
    5,284       72       5,356       64       5,420  
                                         
Comprehensive income:
                                       
Net loss
    (1,287 )           (1,287 )     8       (1,279 )
Other comprehensive income:
                                       
Change in fair value of net cash flow hedges (net of $184 of income tax)
          321       321             321  
Net reclassifications into earnings of cash flow hedge gains (net of $129 income tax provision)
          (225 )     (225 )           (225 )
                                         
Total other comprehensive income
                                    96  
                                         
Total comprehensive loss
                                    (1,183 )
                                         
Cash proceeds in excess of historical book value related to assets sold to an affiliate
    244             244             244  
Net transfers with Williams
    39             39             39  
Dividends to noncontrolling interests
                             
                                         
Balance at December 31, 2010
  $ 4,280     $ 168     $ 4,448     $ 72     $ 4,520  
                                         
 
 
Accumulated other Comprehensive income (loss) is comprised primarily of unrealized gains relating to natural gas hedges totaling $169 million (net of $97 million for income taxes), $74 million (net of $42 million for income taxes) and $299 million (net of $172 million for income taxes) as of December 31, 2010, 2009 and 2008, respectively.
 
** Represents the 31 percent interest in Apco Oil and Gas International Inc. owned by others.
 
See accompanying notes.


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WPX Energy
(Note 1)

Combined Statement of Cash Flows
 
                         
    Years Ended December 31,  
    2010     2009     2008  
    (Dollars in millions)  
 
Operating Activities
                       
Net income (loss)
  $ (1,279 )   $ 146     $ 736  
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
                       
Depreciation, depletion and amortization
    881       894       758  
Deferred income tax provision (benefit)
    (167 )     106       456  
Provision for impairment of goodwill and properties and equipment (including certain exploration expenses)
    1,734       38       173  
Provision for loss on cost-based investment
          11        
Gain on sale of contractual right to international production payment
                (148 )
(Gain) loss on sales of other assets
    (22 )     1       1  
Cash provided (used) by operating assets and liabilities:
                       
Accounts receivable and payable — affiliate
    21       (71 )     20  
Accounts receivable — trade
    9       103       124  
Other current assets
    19       (17 )     (11 )
Inventories
    (16 )     24       (32 )
Margin deposits and customer margin deposit payable
    (1 )     4       87  
Accounts payable — trade
    (54 )     (17 )     (91 )
Accrued and other current liabilities
    (68 )     (116 )     21  
Changes in current and noncurrent derivative assets and liabilities
    (45 )     38       (119 )
Other, including changes in other noncurrent assets and liabilities
    42       35       31  
                         
Net cash provided by operating activities
    1,054       1,179       2,006  
                         
Investing Activities
                       
Capital expenditures*
    (1,856 )     (1,434 )     (2,467 )
Purchase of business
    (949 )            
Proceeds from sale of contractual right to international production payment
                148  
Proceeds from sales of assets
    493             72  
Purchases of investments
    (7 )     (1 )     (5 )
Other
    (18 )            
                         
Net cash used in investing activities
    (2,337 )     (1,435 )     (2,252 )
                         
Financing Activities
                       
Net changes in notes payable to parent
    1,045       270       269  
Net changes in owner’s net investment
    243       (14 )     (35 )
Other
    (2 )     2       (6 )
                         
Net cash provided by financing activities
    1,286       258       228  
                         
Net change in cash and cash equivalents
    3       2       (18 )
Cash and cash equivalents at beginning of period
    34       32       50  
                         
Cash and cash equivalents at end of period
  $ 37     $ 34     $ 32  
                         
                       
* Increase to properties and equipment
  $ (1,891 )   $ (1,291 )   $ (2,520 )
Changes in related accounts payable
    35       (143 )     53  
                         
Capital expenditures
  $ (1,856 )   $ (1,434 )   $ (2,467 )
                         
 
See accompanying notes.


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WPX Energy
 
Notes to Combined Financial Statements
 
1.   Description of Business, Basis of Presentation and Summary of Significant Accounting Policies
 
Description of Business
 
The combined businesses represented herein as WPX Energy (also referred to herein as the “Company”) comprise substantially all of the exploration and production operating segment of The Williams Companies, Inc. (“Williams”). In these notes, WPX Energy is at times referred to in the first person as “we”, “us” or “our”.
 
On February 16, 2011, Williams announced that its Board of Directors approved pursuing a plan to separate Williams’ businesses into two stand-alone, publicly traded companies. The plan first calls for Williams to separate its exploration and production business via an initial public offering (the “Offering”) of up to 20 percent of its interest. As a result, WPX Energy, Inc. is to be formed to effect the separation. Prior to the close of the Offering, Williams will contribute and transfer to the Company its investment in certain subsidiaries related to its exploration and production business, including its wholly-owned subsidiaries Williams Production Holdings, LLC, Williams Production Company, LLC and its 69 percent ownership interest in Apco Oil and Gas International (“Apco”, NASDAQ listed: APAGF), as well as all on-going operations of Williams Gas Marketing Services, Inc. (collectively referred to as the “Contribution”).
 
WPX Energy includes natural gas development, production and gas management activities located in the Rocky Mountain (primarily Colorado, New Mexico, and Wyoming), Mid-Continent (Oklahoma and Texas), and Appalachian regions of the United States and oil and natural gas interests in South America. We specialize in natural gas production from tight-sands and shale formations and coal bed methane reserves in the Piceance, San Juan, Powder River, Arkoma, Green River, Fort Worth, and Appalachian basins. During 2010, we acquired a company with a significant acreage position in the Williston Basin (Bakken Shale) in North Dakota, which is primarily comprised of crude oil reserves. We also have international oil and gas interests which represented approximately two percent of combined revenues and approximately six percent of proved reserves for the year ended December 31, 2010. These international interests primarily consist of our ownership in Apco, an oil and gas exploration and production company with operations in South America.
 
Basis of Presentation
 
These financial statements are prepared on a combined, rather than a consolidated basis. The combined financial statements have been derived from the financial statements and accounting records of Williams using the historical results of operations and historical basis of the assets and liabilities of the companies that are to be part of the Contribution to WPX Energy.
 
Management believes the assumptions underlying the financial statements are reasonable. However, the financial statements included herein may not necessarily reflect the Company’s results of operations, financial position and cash flows in the future or what its results of operations, financial position and cash flows would have been had the Company been a stand-alone company during the periods presented. Because a direct ownership relationship did not exist among the various entities that will comprise the Company, Williams’ net investment in the Company, excluding notes payable to Williams, is shown as owner’s net investment in lieu of stockholder’s equity in the combined financial statements. Transactions between the Company and Williams which are not part of the notes payable have been identified in the Combined Statements of Equity as net transfers with Williams (see Note 2). Transactions with Williams’ other operating businesses, which generally settle monthly, are shown as accounts receivable-affiliate or accounts payable-affiliate (see Note 2). The accompanying combined financial statements do not reflect any changes that will occur upon the Contribution and recapitalization of the Company, or may occur in the capitalization and operations of the Company as a result of, or after, any spin-off of the Company.
 
During fourth quarter 2010, the Company sold certain gathering and processing assets in Colorado’s Piceance basin (the “Piceance Sale”) with a net book value of $458 million to Williams Partners L.P.


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WPX Energy
 
Notes to Combined Financial Statements—(Continued)
 
(“WPZ”), an entity under the common control of Williams, in exchange for $702 million in cash and 1.8 million WPZ limited partner units. As the Company and WPZ are under common control, no gain was recognized on this transaction in the Combined Statement of Operations. Accordingly, the $244 million difference between the cash consideration received and the historical net book value of the assets has been reflected in the Combined Statement of Equity for the year ended December 31, 2010. Since the WPZ units received in this transaction by the Company were intended to be (and now have been, as described below) distributed through a dividend to Williams, these units (as well as the tax effects associated with these units of $42 million) have been presented net within equity and are included in net transfers with Williams in 2010. Further, as a result of the limitations on the Company’s ability to sell these units and the subsequent dividend to Williams, no gains on the value of the common units during the holding period have been recognized in the Combined Statement of Operations. In conjunction with the Piceance Sale, we entered into long-term contracts with WPZ for gathering and processing of our natural gas production in the area. Due to the continuation of significant direct cash flows related to these assets, historical operating results of these assets continue to be presented in the Combined Statement of Operations as continuing operations for all periods presented. In March, 2011, the 1.8 million WPZ units and related tax basis were distributed via dividend to Williams.
 
Discontinued operations
 
The accompanying combined financial statements and notes include the results of operations of Williams’ former power business most of which was disposed in 2007 as discontinued operations. The discontinued operations have been included in these combined financial statements because contingent obligations related to this former business directly relate to Williams Gas Marketing Services, resulting in the potential of charges or benefits to the Company in periods subsequent to the exit from this business. See Note 9 for a discussion of contingencies related to this discontinued power business.
 
Unless indicated otherwise, the information in the Notes to Combined Financial Statements relates to continuing operations.
 
Summary of Significant Accounting Policies
 
Basis of combination
 
The combined financial statements include the accounts of the combined entities as set forth in Description of Business and Basis of Presentation above. Companies in which WPX Energy entities own 20 percent to 50 percent of the voting common stock, or otherwise exercise significant influence over operating and financial policies of the company, are accounted for under the equity method. All material intercompany transactions have been eliminated.
 
Use of estimates
 
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the combined financial statements and accompanying notes. Actual results could differ from those estimates.
 
Significant estimates and assumptions which impact these financials include:
 
  •   Impairment assessments of long-lived assets and goodwill;
 
  •   Assessments of litigation-related contingencies;
 
  •   Valuations of derivatives;
 
  •   Hedge accounting correlations and probability;
 
  •   Estimation of oil and natural gas reserves.


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WPX Energy
 
Notes to Combined Financial Statements—(Continued)
 
 
These estimates are discussed further throughout these notes.
 
Cash and cash equivalents
 
Our cash and cash equivalents relate primarily to our international operations. We consider all investments with a maturity of three months or less when acquired to be cash equivalents.
 
Additionally, our domestic businesses currently participate in the Williams’ cash management program (see Note 2) rather than maintaining cash and cash equivalent balances.
 
Restricted cash
 
Restricted cash primarily consists of approximately $19 million in both 2010 and 2009 related to escrow accounts established as part of the settlement agreement with certain California utilities (see Note 9) and is included in noncurrent other assets.
 
Accounts receivable
 
Accounts receivable are carried on a gross basis, with no discounting, less the allowance for doubtful accounts. We estimate the allowance for doubtful accounts based on existing economic conditions, the financial conditions of the customers and the amount and age of past due accounts. Receivables are considered past due if full payment is not received by the contractual due date. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted. A portion of our receivables are from joint interest owners of properties we operate. Thus, we may have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings.
 
Inventories
 
All inventories are stated at the lower of cost or market. Our inventories consist primarily of tubular goods and production equipment for future transfer to wells of $47 million in 2010 and $35 million in 2009. Additionally, we have natural gas in storage of $31 million in 2010 and $27 million in 2009 primarily related to our gas management activities. Inventory is recorded and relieved using the weighted average cost method except for production equipment which is on the specific identification method. We recorded lower of cost or market writedowns on natural gas in storage of $2 million in 2010, $7 million in 2009 and $35 million in 2008.
 
Properties and equipment
 
Oil and gas exploration and production activities are accounted for under the successful efforts method. Costs incurred in connection with the drilling and equipping of exploratory wells are capitalized as incurred. If proved reserves are not found, such costs are charged to exploration expense. Other exploration costs, including geological and geophysical costs and lease rentals are charged to expense as incurred. All costs related to development wells, including related production equipment and lease acquisition costs, are capitalized when incurred whether productive or nonproductive.
 
Unproved properties include lease acquisition costs and costs of acquired unproved reserves. Individually significant lease acquisition costs are assessed annually, or as conditions warrant, for impairment considering our future drilling plans, the remaining lease term and recent drilling results. Lease acquisition costs that are not individually significant are aggregated by prospect or geographically, and the portion of such costs estimated to be nonproductive prior to lease expiration is amortized over the average holding period. The estimate of what could be nonproductive is based on our historical experience or other information, including current drilling plans and existing geological data. Impairment and amortization of lease acquisition costs are included in exploration expense in the Combined Statement of Operations. A majority of the costs of acquired unproved reserves are associated with areas to which we or other producers have identified significant proved developed


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


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Table of Contents

WPX Energy
 
Notes to Combined Financial Statements—(Continued)
 
development and production, expected future commodity prices, capital expenditures, production costs and appropriate discount rates.
 
Asset retirement obligations
 
We record an asset and a liability upon incurrence equal to the present value of each expected future asset retirement obligation (“ARO”). These estimates include, as a component of future expected costs, an estimate of the price that a third party would demand, and could expect to receive, for bearing the uncertainties inherent in the obligations, sometimes referred to as a market risk premium. The ARO asset is depreciated in a manner consistent with the depreciation of the underlying physical asset. We measure changes in the liability due to passage of time by applying an interest method of allocation. This amount is recognized as an increase in the carrying amount of the liability and as a corresponding accretion expense in lease and facility operating expense included in costs and expenses.
 
Goodwill
 
Goodwill represents the excess of cost over fair value of the assets of businesses acquired. It is evaluated at least annually (in the fourth quarter) for impairment by first comparing our management’s estimate of the fair value of a reporting unit with its carrying value, including goodwill. If the carrying value of the reporting unit exceeds its fair value, a computation of the implied fair value of the goodwill is compared with its related carrying value. If the carrying value of the reporting unit’s goodwill exceeds the implied fair value of that goodwill, an impairment loss is recognized in the amount of the excess.
 
As a result of significant declines in forward natural gas prices during third quarter of 2010, we performed an interim impairment assessment of our goodwill related to our domestic production reporting unit. As a result of that assessment, we recorded an impairment of goodwill of approximately $1 billion (see Note 4).
 
Judgments and assumptions are inherent in our management’s estimate of future cash flows used to determine the estimate of the reporting unit’s fair value.
 
Derivative instruments and hedging activities
 
We utilize derivatives to manage our commodity price risk. These instruments consist primarily of futures contracts, swap agreements, option contracts, and forward contracts involving short- and long-term purchases and sales of a physical energy commodity.
 
We report the fair value of derivatives, except for those for which the normal purchases and normal sales exception has been elected, on the Combined Balance Sheet in derivative assets and derivative liabilities as either current or noncurrent. We determine the current and noncurrent classification based on the timing of expected future cash flows of individual trades. We report these amounts on a gross basis. Additionally, we report cash collateral receivables and payables with our counterparties on a gross basis.
 
The accounting for the changes in fair value of a commodity derivative can be summarized as follows:
 
     
Derivative Treatment
 
Accounting Method
 
Normal purchases and normal sales exception
  Accrual accounting
Designated in a qualifying hedging relationship
  Hedge accounting
All other derivatives
  Mark-to-market accounting
 
We may elect the normal purchases and normal sales exception for certain short- and long-term purchases and sales of a physical energy commodity. Under accrual accounting, any change in the fair value of these derivatives is not reflected on the balance sheet after the initial election of the exception.


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WPX Energy
 
Notes to Combined Financial Statements—(Continued)
 
We have also designated a hedging relationship for certain commodity derivatives. For a derivative to qualify for designation in a hedging relationship, it must meet specific criteria and we must maintain appropriate documentation. We establish hedging relationships pursuant to our risk management policies. We evaluate the hedging relationships at the inception of the hedge and on an ongoing basis to determine whether the hedging relationship is, and is expected to remain, highly effective in achieving offsetting changes in fair value or cash flows attributable to the underlying risk being hedged. We also regularly assess whether the hedged forecasted transaction is probable of occurring. If a derivative ceases to be or is no longer expected to be highly effective, or if we believe the likelihood of occurrence of the hedged forecasted transaction is no longer probable, hedge accounting is discontinued prospectively, and future changes in the fair value of the derivative are recognized currently in revenues or costs and operating expenses dependent upon the underlying hedge transaction.
 
For commodity derivatives designated as a cash flow hedge, the effective portion of the change in fair value of the derivative is reported in accumulated other comprehensive income (loss) (“AOCI”) and reclassified into earnings in the period in which the hedged item affects earnings. Any ineffective portion of the derivative’s change in fair value is recognized currently in revenues. Gains or losses deferred in AOCI associated with terminated derivatives, derivatives that cease to be highly effective hedges, derivatives for which the forecasted transaction is reasonably possible but no longer probable of occurring, and cash flow hedges that have been otherwise discontinued remain in AOCI until the hedged item affects earnings. If it becomes probable that the forecasted transaction designated as the hedged item in a cash flow hedge will not occur, any gain or loss deferred in AOCI is recognized in revenues at that time. The change in likelihood is a judgmental decision that includes qualitative assessments made by management.
 
For commodity derivatives that are not designated in a hedging relationship, and for which we have not elected the normal purchases and normal sales exception, we report changes in fair value currently in revenues dependent upon the underlying of the hedged transaction.
 
Certain gains and losses on derivative instruments included in the Combined Statement of Operations are netted together to a single net gain or loss, while other gains and losses are reported on a gross basis. Gains and losses recorded on a net basis include:
 
  •   Unrealized gains and losses on all derivatives that are not designated as hedges and for which we have not elected the normal purchases and normal sales exception;
 
  •   The ineffective portion of unrealized gains and losses on derivatives that are designated as cash flow hedges;
 
  •   Realized gains and losses on all derivatives that settle financially;
 
  •   Realized gains and losses on derivatives held for trading purposes; and
 
  •   Realized gains and losses on derivatives entered into as a pre-contemplated buy/sell arrangement.
 
Realized gains and losses on derivatives that require physical delivery, as well as natural gas derivatives which are not held for trading purposes nor were entered into as a pre-contemplated buy/sell arrangement, are recorded on a gross basis. In reaching our conclusions on this presentation, we considered whether we act as principal in the transaction; whether we have the risks and rewards of ownership, including credit risk; and whether we have latitude in establishing prices.
 
Oil and gas sales revenues
 
Revenues for sales of natural gas, oil and condensate and natural gas liquids are recognized when the product is sold and delivered. Revenues from the production of natural gas in properties for which we have an interest with other producers are recognized based on the actual volumes sold during the period. Any


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Table of Contents

WPX Energy
 
Notes to Combined Financial Statements—(Continued)
 
differences between volumes sold and entitlement volumes, based on our net working interest, that are determined to be nonrecoverable through remaining production are recognized as accounts receivable or accounts payable, as appropriate. Our cumulative net natural gas imbalance position based on market prices as of December 31, 2010 and 2009 was insignificant. Additionally, oil and gas sales revenues include hedge gains realized on production sold of $333 million in 2010, $615 million in 2009 and $34 million in 2008.
 
Gas management revenues and expenses
 
Revenues for sales related to gas management activities are recognized when the product is sold and physically delivered. Our gas management activities to date include purchases and subsequent sales to WPZ for fuel and shrink gas (see Note 2). Additionally, gas management activities include the managing of various natural gas related contracts such as transportation, storage and related hedges. The Company also sells natural gas purchased from working interest owners in operated wells and other area third party producers. The revenues and expenses related to these marketing activities are reported on a gross basis as part of gas management revenues and costs and expenses.
 
Charges for unutilized transportation capacity included in gas management expenses were $48 million in 2010, $21 million in 2009 and $8 million in 2008.
 
Capitalization of interest
 
We capitalize interest during construction on projects with construction periods of at least three months or a total estimated project cost in excess of $1 million. The interest rate used is the rate charged to us by Williams, based on Williams’ average quarterly interest rate on its debt.
 
Income taxes
 
The Company’s domestic operations are included in the consolidated federal and state income tax returns for Williams, except for certain separate state filings. The income tax provision for the Company has been calculated on a separate return basis, except for certain state and federal tax attributes (primarily minimum tax credit carry-forwards) for which the actual allocation (if any) cannot be determined until the consolidated tax returns are complete for the year in which an income tax deconsolidation event occurs. This allocation methodology results in the recognition of deferred assets and liabilities for the differences between the financial statement carrying amounts and their respective tax basis, except to the extent of deferred taxes on income considered to be permanently reinvested in foreign jurisdictions. Deferred tax assets and liabilities are measured using enacted tax rates for the years in which those temporary differences are expected to be recovered or settled. In addition, Williams manages its tax position based upon its entire portfolio which may not be indicative of tax planning strategies available to us if we were operating as an independent company.
 
Employee stock-based compensation
 
Certain employees providing direct service to the Company participate in Williams’ common-stock-based awards plans. The plans provide for Williams common-stock-based awards to both employees and Williams’ non-management directors. The plans permit the granting of various types of awards including, but not limited to, stock options and restricted stock units. Awards may be granted for no consideration other than prior and future services or based on certain financial performance targets.
 
Williams charges us for compensation expense related to stock-based compensation awards granted to our direct employees. Stock based compensation is also a component of allocated amounts charged to us by Williams for general and administrative personnel providing services on our behalf.


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Table of Contents

WPX Energy
 
Notes to Combined Financial Statements—(Continued)
 
Foreign exchange
 
Translation gains and losses that arise from exchange rate fluctuations applicable to transactions denominated in a currency other than the United States dollar are included in the results of operations as incurred.
 
Earnings (loss) per share
 
Historical earnings per share are not presented since the Company’s common stock was not part of the capital structure of Williams for the periods presented.
 
2.   Related Party Transactions
 
Transactions with Williams and Other Affiliated Entities
 
Our employees are also employees of Williams. Williams charges us for the payroll and benefit costs associated with operations employees (referred to as direct employees) and carries the obligations for many employee-related benefits in its financial statements, including the liabilities related to employee retirement and medical plans. Our share of those costs is charged to us through affiliate billings and reflected in lease and facility operating and general and administrative within costs and expenses in the accompanying Combined Statement of Operations.
 
In addition, Williams charges us for certain employees of Williams who provide general and administrative services on our behalf (referred to as indirect employees). These charges are either directly identifiable or allocated to our operations. Direct charges include goods and services provided by Williams at our request. Allocated general corporate costs are based on our relative usage of the service or on a three-factor formula, which considers revenues; properties and equipment; and payroll. Our share of direct general and administrative expenses and our share of allocated general corporate expenses is reflected in general and administrative expense in the accompanying Combined Statement of Operations. In management’s estimation, the allocation methodologies used are reasonable and result in a reasonable allocation to us of our costs of doing business incurred by Williams. We also have operating activities with WPZ and another Williams subsidiary. Our revenues include revenues from the following types of transactions:
 
  •   Sales of natural gas liquids (NGLs) related to our production to WPZ at market prices at the time of sale and included within our oil and gas sales revenues; and
 
  •   Sale to WPZ and another Williams subsidiary of natural gas procured by Williams Gas Marketing Services for those companies’ fuel and shrink replacement at market prices at the time of sale and included in our gas management revenues.
 
Our costs and operating expenses include the following services provided by WPZ:
 
  •   Gathering, treating and processing services under several contracts for our production primarily in the San Juan and Piceance basins; and
 
  •   Pipeline transportation for both our oil and gas sales and gas management activities which includes commitments totaling $442 million (see Note 9 for capacity commitments with affiliates).
 
In addition, through an agency agreement, we manage the jurisdictional merchant gas sales for Transcontinental Gas Pipe Line Company LLC (“Transco”), an indirect, wholly owned subsidiary of WPZ. We are authorized to make gas sales on Transco’s behalf in order to manage its gas purchase obligations. Although there is no exchange of payments between us and Transco for these transactions, we receive all margins associated with jurisdictional merchant gas sales business and, as Transco’s agent, assume all market and credit risk associated with such sales.


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Table of Contents

WPX Energy
 
Notes to Combined Financial Statements—(Continued)
 
We manage a transportation capacity contract for WPZ. To the extent the transportation is not fully utilized or does not recover full-rate demand expense, WPZ reimburses us for these transportation costs. These reimbursements to us totaled approximately $10 million, $9 million and $11 million for the years ended December 31, 2010, 2009 and 2008, respectively, and are included in gas management revenues.
 
WPZ periodically enters into derivative contracts with us to hedge their forecasted NGL sales and natural gas purchases. We enter into offsetting derivative contracts with third parties at equivalent pricing and volumes. These contracts are included in derivative assets and liabilities on the Combined Balance Sheet (see Note 13).
 
Williams utilizes a centralized approach to cash management and the financing of its businesses. Cash receipts from the Company’s domestic operations are transferred to Williams on a regular basis and cleared through unsecured promissory note agreements with Williams. Cash expenditures for property operating and development costs and expenses are also cleared through these unsecured promissory note agreements with Williams. The amounts receivable or due under the note agreements are due on demand, however, Williams has agreed to not make demand on these notes payable prior to the completion of the Offering. Williams has also agreed to forgive or contribute any amounts outstanding on these note agreements prior to or concurrent with the Contribution. The notes bear interest based on Williams’ weighted average cost of debt and such interest is added monthly to the note principal. The interest rate for the notes payable to Williams was 8.08% and 8.01% at December 31, 2010 and 2009, respectively. As of December 31, 2010 and 2009, our net amounts due to Williams are reflected as notes payable to Williams. None of Williams’ cash or debt at the Williams corporate level has been allocated to the Company in the financial statements. Changes in the notes represent any funding required from Williams for working capital, acquisitions or capital expenditures and after giving effect to the Company’s transfers to Williams from its cash flows from operations or proceeds from sales of assets. Concurrently with or shortly following the consummation of the Offering, we expect to issue up to $1.5 billion aggregate principal amount of senior unsecured notes. Furthermore, we expect to distribute the net proceeds from the Offering and the issuance of the notes in excess of approximately $500 million to Williams.
 
Under Williams’ cash-management system, certain cash accounts reflect negative balances to the extent checks written have not been presented for payment. These negative amounts represent obligations and have been reclassified to accounts payable-affiliate. Accounts payable-affiliate includes approximately $38 million and $26 million of these negative balances at December 31, 2010 and 2009, respectively.


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Table of Contents

WPX Energy
 
Notes to Combined Financial Statements—(Continued)
 
Below is a summary of the related party transactions discussed above:
 
                         
    2010     2009     2008  
    (Millions)  
 
Oil and gas sales revenues—sales of NGLs to WPZ
  $ 277     $ 116     $ 36  
Gas management revenues—sales of natural gas for fuel and shrink to WPZ and another Williams subsidiary
    509       431       1,042  
Lease and facility operating expenses from Williams-direct employee salary and benefit costs
    25       25       21  
Gathering, processing and transportation expense from
                       
WPZ:
                       
Gathering and processing
    163       72       44  
Transportation
    25       28       34  
General and administrative from Williams:
                       
Direct employee salary and benefit costs
    103       101       94  
Charges for general and administrative services
    58       60       60  
Allocated general corporate costs
    64       63       56  
Other
    12       13       12  
Interest expense on notes payable to Williams
    119       92       64  
 
In addition, the current amount due to or from affiliates consists of normal course receivables and payables resulting from the sale of products to and cost of gathering services provided by WPZ. Below is a summary of these payables and receivables which are settled monthly:
 
                 
    December 31,  
    2010     2009  
    (Millions)  
 
Current:
               
Accounts receivable:
               
Due from WPZ and another Williams subsidiary
  $ 60     $ 54  
                 
Accounts payable:
               
Due to WPZ
  $ 12     $ 2  
Due to Williams for cash overdraft. 
    38       26  
Due to Williams for accrued payroll and benefits
    14       9  
                 
    $ 64     $ 37  
                 
 
As discussed in Note 1, the Company sold certain gathering and processing assets in Colorado’s Piceance basin to WPZ. Under an Omnibus Agreement entered into in connection with this transaction, we are obligated to reimburse WPZ for (i) amounts incurred by WPZ or its subsidiaries for any costs required to complete the pipeline and compression projects known collectively as the Ryan Gulch Expansion Project, (ii) amounts incurred by WPZ or its subsidiaries prior to January 31, 2011, related to the development of a cryogenic processing arrangement with a subsidiary of Williams, up to $20 million, and (iii) amounts incurred by WPZ or its subsidiaries for notice of violation or enforcement actions related to compression station land use permits or other losses, costs and expenses related to certain surface lease use agreements. In addition, WPZ is obligated to reimburse us for any costs related to the pipeline and compression projects known collectively as the Kokopelli Expansion irrespective of whether those costs were incurred prior to the effective date of the transaction. Estimated amounts for these obligations were recorded at the time of the sale and were less than


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Table of Contents

WPX Energy
 
Notes to Combined Financial Statements—(Continued)
 
$5 million. Differences in the estimated amounts and actual payments will be reflected within Owner’s Net Investment consistent with the treatment of the difference in the net book value and proceeds from sale.
 
3.   Investment income and other
 
Investment income and other for the years ended December 31, 2010, 2009 and 2008, is as follows:
 
                         
    Years Ended December 31,  
    2010     2009     2008  
    (Millions)  
 
Equity earnings
  $ 20     $ 18     $ 20  
Impairment of cost-based investment
          (11 )      
Other
    1             2  
                         
Total investment income and other
  $ 21     $ 7     $ 22  
                         
 
Impairment of cost-based investment in 2009 reflects an $11 million full impairment of our 4 percent interest in a Venezuelan corporation that owns and operates oil and gas activities in Venezuela.
 
Investments
 
Investment balance as of December 31, 2010 and 2009 is as follows:
 
                 
    December 31,  
    2010     2009  
    (Millions)  
 
Petrolera Entre Lomas S.A.—40.8%
  $ 82     $ 81  
Other
    23       14  
                 
    $ 105     $ 95  
                 
 
Dividends and distributions received from companies accounted for by the equity method were $19 million in 2010, $9 million in 2009 and $11 million in 2008.
 
4.   Asset sales, impairments, exploration expenses and other accruals
 
The following table presents a summary of significant gains or losses reflected in impairment of producing properties and costs of acquired unproved reserves, goodwill impairment and other—net within costs and expenses:
 
                         
    Years Ended December 31,  
    2010     2009     2008  
    (Millions)  
 
Goodwill impairment
  $ 1,003     $     $  
Impairment of producing properties and costs of acquired unproved reserves*
    678       15       148  
Penalties from early release of drilling rigs included in other (income) expense—net
          32        
Gain on sale of contractual right to an international production payment
                (148 )
(Gain) loss on sales of other assets
    (22 )     1       1  
 
 
* Excludes unproved leasehold property impairment, amortization and expiration included in exploration expenses.


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WPX Energy
 
Notes to Combined Financial Statements—(Continued)
 
 
As a result of significant declines in forward natural gas prices during 2010, we performed an interim impairment assessment of our capitalized costs related to goodwill and domestic producing properties. As a result of these assessments, we recorded an impairment of goodwill, as noted above, and impairments of our capitalized costs of certain natural gas producing properties in the Barnett Shale of $503 million and capitalized costs of certain acquired unproved reserves in the Piceance Highlands acquired in 2008 of $175 million (see Note 12).
 
Based on a comparison of the estimated fair value to the carrying value, we recorded a $15 million impairment in 2009 related to costs of acquired unproved reserves resulting from a 2008 acquisition in the Fort Worth basin (see Note 12). Additionally, we recorded an impairment charge of $148 million in 2008 related to properties in the Arkoma basin.
 
Our impairment analyses included an assessment of undiscounted (except for the costs of acquired unproved reserves) and discounted future cash flows, which considered information obtained from drilling, other activities, and natural gas reserve quantities.
 
In July 2010, we sold a portion of our gathering and processing facilities in the Piceance basin to a third party for cash proceeds of $30 million resulting in a gain of $12 million. The remaining portion of the facilities was part of the Piceance Sale (see Note 1). Also in 2010, we exchanged undeveloped leasehold acreage in different areas with a third party resulting in a $7 million gain.
 
In January 2008, we sold a contractual right to a production payment on certain future international hydrocarbon production for $148 million. We obtained this interest (for which we allocated no value) through the acquisition of Barrett Resources Corporation in 2001 and there were no operations associated with this interest. As a result of the contract termination, we have no further interests associated with the crude oil concession which is located in Peru.
 
The following presents a summary of exploration expenses:
 
                         
    Years Ended December 31  
    2010     2009     2008  
    (Millions)  
 
Geologic and geophysical costs
  $ 22     $ 33     $ 13  
Dry hole costs
    17       11       16  
Unproved leasehold property impairment, amortization and expiration
    37       12       9  
                         
Total exploration expense
  $ 76     $ 56     $ 38  
                         
 
Additional Items
 
Production and ad valorem taxes in 2008 include a $34 million accrual (which was reduced by $5 million in 2009) for additional Wyoming severance and ad valorem taxes associated with our initial estimate for settlement of an assessment initially for production years 2000 through 2002, but expanded through 2008 by the Wyoming Department of Audit (DOA), of additional severance tax and interest and notification of an increase in the taxable value of our interests for ad valorem tax purposes. Associated with this charge is an interest expense accrual of $4 million. All matters related to this issue have been settled with the State and respective counties for the amounts accrued.


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Table of Contents

WPX Energy
 
Notes to Combined Financial Statements—(Continued)
 
5.   Properties and Equipment
 
Properties and equipment is carried at cost and consists of the following:
 
                         
    Estimated
             
    Useful Life(a)
    December 31,  
    (Years)     2010     2009  
          (Millions)  
 
Proved properties
    (b)     $ 9,871     $ 8,833  
Unproved properties
    (c)       1,902       931  
Gathering, processing and other facilities
    15-25       130       798  
Construction in progress
    (c)       604       574  
Other
    3-25       127       123  
                         
Total properties and equipment, at cost
            12,634       11,259  
Accumulated depreciation, depletion and amortization
            (4,133 )     (3,535 )
                         
Properties and equipment—net
          $ 8,501     $ 7,724  
                         
 
 
(a) Estimated useful lives are presented as of December 31, 2010.
 
(b) Proved properties are depreciated, depleted and amortized using the units-of-production method (see Note 1).
 
(c) Unproved properties and construction in progress are not yet subject to depreciation and depletion.
 
Unproved properties consist primarily of non-producing leasehold in the Williston basin (Bakken Shale) and the Appalachian basin (Marcellus Shale) and acquired unproved reserves in the Powder River and Piceance basins.
 
On December 21, 2010, we closed the acquisition of 100 percent of the equity of Dakota-3 E&P Company LLC for $949 million, including closing adjustments. This company holds approximately 85,800 net acres on the Fort Berthold Indian Reservation in the Williston basin of North Dakota. Approximately 85% of the acreage is undeveloped. Approximately $400 million of the purchase price was recorded as proved properties, $542 million as unproved properties within properties and equipment and $5 million of prepaid drilling costs (no significant working capital was acquired). Revenues and earnings for the acquired company were nominal and thus insignificant to us for the three years ended December 31, 2010, 2009 and 2008; accordingly, pro forma operating results would be substantially similar to those reflected on our historical Combined Statement of Operations.
 
As discussed in Notes 1 and 2, the Company sold certain gathering and processing assets in Colorado’s Piceance basin with a net book value of $458 million to WPZ.
 
In May 2010, we entered into a purchase agreement consisting primarily of non-producing leasehold acreage in the Appalachian basin and a 5 percent overriding royalty interest associated with the acreage position for $599 million. We also acquired additional non-producing leasehold acreage in the Appalachian basin for $164 million during the year.
 
Construction in progress includes $142 million in 2010 and $136 million in 2009 related to wells located in Powder River. In order to produce gas from the coal seams, an extended period of dewatering is required prior to natural gas production.
 
In 2009, we adopted Accounting Standards Update No. 2010-03, which aligned oil and gas reserve estimation and disclosure requirements to those in the Securities and Exchange Commission’s final rule related thereto. Accordingly, our fourth quarter 2009 depreciation, depletion and amortization expense was approximately $17 million more than had it been computed under the prior requirements.


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Table of Contents

WPX Energy
 
Notes to Combined Financial Statements—(Continued)
 
Asset Retirement Obligations
 
Our asset retirement obligations relate to producing wells, gas gathering well connections and related facilities. At the end of the useful life of each respective asset, we are legally obligated to plug producing wells and remove any related surface equipment and to cap gathering well connections at the wellhead and remove any related facility surface equipment.
 
A rollforward of our asset retirement obligation for the years ended 2010 and 2009 is presented below.
 
                 
    2010     2009  
    (Millions)  
 
Balance, January 1
  $ 245     $ 197  
Liabilities incurred during the period
    43       18  
Liabilities settled during the period
    (2 )     (1 )
Liabilities associated with assets sold
    (22 )      
Estimate revisions
    5       15  
Accretion expense*
    21       16  
                 
Balance, December 31
  $ 290     $ 245  
                 
Amount reflected as current
  $ 3     $ 7  
                 
 
 
Accretion expense is included in lease and facility operating expense on the Combined Statement of Operations.
 
6.   Accrued and other current liabilities
 
Accrued and other current liabilities as of December 31, 2010 and 2009 is as follows:
 
                 
    December 31,  
    2010     2009  
    (Millions)  
 
Taxes other than income taxes
  $ 76     $ 126  
Customer margin deposit payable
    25       31  
Other
    43       63  
                 
    $ 144     $ 220  
                 
 
7.   Unsecured Credit Agreement
 
We have an unsecured credit agreement with certain banks in order to reduce margin requirements related to our hedging activities as well as lower transaction fees. In July 2010, the term of this facility was extended from December 2013 to December 2015. Under the credit agreement, we are not required to post collateral as long as the value of our domestic natural gas reserves, as determined under the provisions of the agreement, exceeds by a specified amount certain of our obligations including any outstanding debt and the aggregate out-of-the-money positions on hedges entered into under the credit agreement. We are subject to additional covenants under the credit agreement including restrictions on hedge limits (70% of annual forecasted production as defined in the agreement), the creation of liens, the incurrence of debt, the sale of assets and properties, and making certain payments during an event of default, such as dividends. In December 2010, a waiver with the same terms and restrictions as the original agreement, was executed that will allow us to also hedge up to 70% of annual forecasted oil production, as defined in the agreement.


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Table of Contents

WPX Energy
 
Notes to Combined Financial Statements—(Continued)
 
8.   Income Taxes
 
The Company’s domestic operations are included in the consolidated federal and state income tax returns for Williams, except for certain separate state filings. The income tax provision for the Company has been calculated on a separate return basis, except for certain state and federal tax attributes (primarily minimum tax credit carry-forwards) for which the actual allocation (if any) cannot be determined until the consolidated tax returns are complete for the year in which an income tax deconsolidation event occurs. If the income tax deconsolidation event had occurred December 31, 2010, the Company’s allocated share of minimum tax credit carry-forwards are estimated to be in the range of $35 to $45 million. This estimate of potential tax attributes has not been included in these financial statements. The valuation allowance at December 31, 2010 and 2009 serves to reduce the recognized tax assets of $22 million associated with state losses, net of federal benefit, to an amount that will more likely than not be realized by the Company. There have been no significant effects on the income tax provision associated with changes in the valuation allowance for the years ended December 31, 2010, 2009 and 2008. Williams manages its tax position based upon its entire portfolio which may not be indicative of tax planning strategies available to us if we were operating as an independent company.
 
The provision (benefit) for income taxes from continuing operations includes:
 
                         
    Years Ended December 31,  
    2010     2009     2008  
    (Millions)  
 
Provision (benefit):
                       
Current:
                       
Federal
  $ 5     $ (20 )   $ (60 )
State
          (1 )     (4 )
Foreign
    11       9       8  
                         
      16       (12 )     (56 )
                         
Deferred:
                       
Federal
    (157 )     100       429  
State
    (10 )     6       28  
Foreign
                (1 )
                         
      (167 )     106       456  
                         
Total provision (benefit)
  $ (151 )   $ 94     $ 400  
                         
 
Reconciliations from the provision (benefit) for income taxes from continuing operations at the federal statutory rate to the realized provision (benefit) for income taxes are as follows:
 
                         
    Years Ended December 31,  
    2010     2009     2008  
    (Millions)  
 
Provision (benefit) at statutory rate
  $ (499 )   $ 85     $ 394  
Increases (decreases) in taxes resulting from:
                       
State income taxes (net of federal benefit)
    (6 )     3       15  
Foreign operations—net
    3       5       (2 )
Goodwill impairment
    351              
Other—net
          1       (7 )
                         
Provision (benefit) for income taxes
  $ (151 )   $ 94     $ 400  
                         


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WPX Energy
 
Notes to Combined Financial Statements—(Continued)
 
Income (loss) from continuing operations before income taxes includes $36 million, $21 million, and $30 million of foreign income in 2010, 2009, and 2008, respectively.
 
Significant components of deferred tax liabilities and deferred tax assets are as follows:
 
                 
    December 31,  
    2010     2009  
    (Millions)  
 
Deferred tax liabilities:
               
Properties and equipment
  $ 1,723     $ 1,939  
Derivatives, net
    110       61  
                 
Total deferred tax liabilities
    1,833       2,000  
                 
Deferred tax assets:
               
Accrued liabilities and other
    117       131  
State loss carryovers
    22       22  
                 
Total deferred tax assets
    139       153  
Less: valuation allowance
    22       22  
                 
Total net deferred tax assets
    117       131  
                 
Net deferred tax liabilities
  $ 1,716     $ 1,869  
                 
 
Undistributed earnings of certain combined foreign subsidiaries at December 31, 2010, totaled approximately $109 million. No provision for deferred U.S. income taxes has been made for these subsidiaries because we intend to permanently reinvest such earnings in foreign operations.
 
The payments and receipts for domestic income taxes were made to or received from Williams via the notes payable to parent (see Note 2) in accordance with our historical tax allocation procedure. The cash payments for domestic income taxes (net of refunds) were $5 million in 2010. Cash receipts for domestic income taxes (net of payments) were $13 million and $44 million in 2009 and 2008, respectively. Additionally, payments made directly to international taxing authorities were $8 million, $4 million, and $8 million in 2010, 2009, and 2008, respectively.
 
We recognize related interest and penalties as a component of income tax expense. The amounts accrued for interest and penalties are insignificant.
 
As of December 31, 2010, the amount of unrecognized tax benefits is insignificant.
 
During the first quarter of 2011, Williams finalized settlements with the IRS for 1997 through 2008. These settlements will not have a material impact on our unrecognized tax benefits. The statute of limitations for most states expires one year after expiration of the IRS statute. Income tax returns for our Colombian (2008 through 2010), Venezuelan (2006 through 2010) and Argentine (2003 through 2010) entities are also open to audit.
 
During the next 12 months, we do not expect ultimate resolution of any uncertain tax position associated with a domestic or international matter will result in a significant increase or decrease of our unrecognized tax benefit.


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WPX Energy
 
Notes to Combined Financial Statements—(Continued)
 
9.   Contingent Liabilities and Commitments
 
Royalty litigation
 
In September 2006, royalty interest owners in Garfield County, Colorado, filed a class action suit in District Court, Garfield County Colorado, alleging we improperly calculated oil and gas royalty payments, failed to account for the proceeds that we received from the sale of natural gas and extracted products, improperly charged certain expenses and failed to refund amounts withheld in excess of ad valorem tax obligations. Plaintiffs sought to certify as a class of royalty interest owners, recover underpayment of royalties and obtain corrected payments resulting from calculation errors. We entered into a final partial settlement agreement. The partial settlement agreement defined the class members for class certification, reserved two claims for court resolution, resolved all other class claims relating to past calculation of royalty and overriding royalty payments, and established certain rules to govern future royalty and overriding royalty payments. This settlement resolved all claims relating to past withholding for ad valorem tax payments and established a procedure for refunds of any such excess withholding in the future. The first reserved claim is whether we are entitled to deduct in our calculation of royalty payments a portion of the costs we incur beyond the tailgates of the treating or processing plants for mainline pipeline transportation. We received a favorable ruling on our motion for summary judgment on the first reserved claim. Plaintiffs appealed that ruling and the Colorado Court of Appeals found in our favor in April 2011. We anticipate knowing later in 2011 whether plaintiffs will pursue any further appeal on the first reserved claim. The second reserved claim relates to whether we are required to have proportionately increased the value of natural gas by transporting that gas on mainline transmission lines and, if required, whether we did so and are thus entitled to deduct a proportionate share of transportation costs in calculating royalty payments. We anticipate trial on the second reserved claim following resolution of the first reserved claim. We believe our royalty calculations have been properly determined in accordance with the appropriate contractual arrangements and Colorado law. At this time, the plaintiffs have not provided us a sufficient framework to calculate an estimated range of exposure related to their claims. However, it is reasonably possible that the ultimate resolution of this item could result in a future charge that may be material to our results of operations.
 
Other producers have been in litigation or discussions with a federal regulatory agency and a state agency in New Mexico regarding certain deductions, comprised primarily of processing, treating and transportation costs, used in the calculation of royalties. Although we are not a party to these matters, we have monitored them to evaluate whether their resolution might have the potential for unfavorable impact on our results of operations. One of these matters involving federal litigation was decided on October 5, 2009. The resolution of this specific matter is not material to us. However, other related issues in these matters that could be material to us remain outstanding. We received notice from the U.S. Department of Interior Office of Natural Resources Revenue (ONRR) in the fourth quarter of 2010, intending to clarify the guidelines for calculating federal royalties on conventional gas production applicable to our federal leases in New Mexico. The ONRR’s guidance provides its view as to how much of a producer’s bundled fees for transportation and processing can be deducted from the royalty payment. We believe using these guidelines would not result in a material difference in determining our historical federal royalty payments for our leases in New Mexico. No similar specific guidance has been issued by ONRR for leases in other states, but such guidelines are expected in the future. However, the timing of receipt of the necessary guidelines is uncertain. In addition, these interpretive guidelines on the applicability of certain deductions in the calculation of federal royalties are extremely complex and will vary based upon the ONRR’s assessment of the configuration of processing, treating and transportation operations supporting each federal lease. From January 2004 through December 2010, our deductions used in the calculation of the royalty payments in states other than New Mexico associated with conventional gas production total approximately $55 million. Based on correspondence in 2009 with the ONRR’s predecessor, we believe our calculating assumptions have been consistent with the requirements. The issuance of similar guidelines in Colorado and other states could affect our previous royalty payments and the effect could be material to our results of operations.


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WPX Energy
 
Notes to Combined Financial Statements—(Continued)
 
Environmental matters
 
The EPA and various state regulatory agencies routinely promulgate and propose new rules, and issue updated guidance to existing rules. These new rules and rulemakings include, but are not limited to, rules for reciprocating internal combustion engine maximum achievable control technology, new air quality standards for ground level ozone, and one hour nitrogen dioxide emission limits. We are unable to estimate the costs of asset additions or modifications necessary to comply with these new regulations due to uncertainty created by the various legal challenges to these regulations and the need for further specific regulatory guidance.
 
Matters related to Williams’ former power business
 
California energy crisis
 
Our former power business was engaged in power marketing in various geographic areas, including California. Prices charged for power by us and other traders and generators in California and other western states in 2000 and 2001 were challenged in various proceedings, including those before the FERC. We have entered into settlements with the State of California (State Settlement), major California utilities (Utilities Settlement), and others that substantially resolved each of these issues with these parties.
 
Although the State Settlement and Utilities Settlement resolved a significant portion of the refund issues among the settling parties, we continue to have potential refund exposure to nonsettling parties, including various California end users that did not participate in the Utilities Settlement. We are currently in settlement negotiations with certain California utilities aimed at eliminating or substantially reducing this exposure. If successful, and subject to a final “true-up” mechanism, the settlement agreement would also resolve our collection of accrued interest from counterparties as well as our payment of accrued interest on refund amounts. Thus, as currently contemplated by the parties, the settlement agreement would resolve most, if not all, of our legal issues arising from the 2000-2001 California Energy Crisis. With respect to these matters, amounts accrued are not material to our financial position.
 
Certain other issues also remain open at the FERC and for other nonsettling parties.
 
Reporting of natural gas-related information to trade publications
 
Civil suits based on allegations of manipulating published gas price indices have been brought against us and others, in each case seeking an unspecified amount of damages. We are currently a defendant in class action litigation and other litigation originally filed in state court in Colorado, Kansas, Missouri and Wisconsin brought on behalf of direct and indirect purchasers of natural gas in those states. These cases were transferred to the federal court in Nevada. In 2008, the court granted summary judgment in the Colorado case in favor of us and most of the other defendants based on plaintiffs’ lack of standing. On January 8, 2009, the court denied the plaintiffs’ request for reconsideration of the Colorado dismissal and entered judgment in our favor. We expect that the Colorado plaintiffs will appeal, but the appeal cannot occur until the case against the remaining defendant is concluded.
 
In the other cases, our joint motions for summary judgment to preclude the plaintiffs’ state law claims based upon federal preemption have been pending since late 2009. If the motions are granted, we expect a final judgment in our favor which the plaintiffs could appeal. If the motions are denied, the current stay of activity would be lifted, class certification would be addressed, and discovery would be completed as the cases proceed towards trial. Because of the uncertainty around these current pending unresolved issues, including an insufficient description of the purported classes and other related matters, we cannot reasonably estimate a range of potential exposures at this time. However, it is reasonably possible that the ultimate resolution of these items could result in future charges that may be material to our results of operations.


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Table of Contents

WPX Energy
 
Notes to Combined Financial Statements—(Continued)
 
Other Divestiture Indemnifications
 
Pursuant to various purchase and sale agreements relating to divested businesses and assets, we have indemnified certain purchasers against liabilities that they may incur with respect to the businesses and assets acquired from us. The indemnities provided to the purchasers are customary in sale transactions and are contingent upon the purchasers incurring liabilities that are not otherwise recoverable from third parties. The indemnities generally relate to breach of warranties, tax, historic litigation, personal injury, environmental matters, right of way and other representations that we have provided.
 
At December 31, 2010, we do not expect any of the indemnities provided pursuant to the sales agreements to have a material impact on our future financial position. However, if a claim for indemnity is brought against us in the future, it may have a material adverse effect on our results of operations in the period in which the claim is made.
 
In addition to the foregoing, various other proceedings are pending against us which are incidental to our operations.
 
Summary
 
Litigation, arbitration, regulatory matters, and environmental matters are subject to inherent uncertainties. Were an unfavorable ruling to occur, there exists the possibility of a material adverse impact on the results of operations in the period in which the ruling occurs. As of December 31, 2010 and 2009, the Company had accrued approximately $21 million and $30 million, respectively, for loss contingencies associated with royalty litigation, reporting of natural gas information to trade publications and other contingencies. Management, including internal counsel, currently believes that the ultimate resolution of the foregoing matters, taken as a whole and after consideration of amounts accrued, insurance coverage, recovery from customers or other indemnification arrangements, is not expected to have a materially adverse effect upon our future liquidity or financial position; however, it could be material to our results of operations in any given year.
 
Commitments
 
As part of managing our commodity price risk, we utilize contracted pipeline capacity (including capacity on affiliates’ systems, resulting in a total of $442 million for all years) primarily to move our natural gas production to other locations in an attempt to obtain more favorable pricing differentials. Our commitments under these contracts are as follows:
 
         
    (Millions)  
 
2011
  $ 204  
2012
    208  
2013
    200  
2014
    174  
2015
    166  
Thereafter
    635  
         
Total
  $ 1,587  
         
 
We have certain commitments to an equity investee and others for natural gas gathering and treating services, which total $447 million over approximately eleven years.
 
We have a long-term obligation to deliver on a firm basis 200,000 MMBtu per day of natural gas to a buyer at the White River Hub (Greasewood-Meeker, Colorado), which is the major market hub exiting the Piceance Basin. This obligation expires in 2014.


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Table of Contents

WPX Energy
 
Notes to Combined Financial Statements—(Continued)
 
In connection with a gathering agreement entered into by WPZ with a third party in December 2010, we concurrently agreed to buy up to 200,000 MMBtu per day of natural gas at Transco Station 515 (Marcellus Basin) at market prices from the same third party. Purchases under the 12-year contract are expected to begin in the third quarter of 2011. We expect to sell this natural gas in the open market and may utilize available transportation capacity to facilitate the sales.
 
Future minimum annual rentals under noncancelable operating leases as of December 31, 2010, are payable as follows:
 
         
    (Millions)  
 
2011
  $ 14  
2012
    10  
2013
    9  
2014
    4  
2015
    3  
Thereafter
    15  
         
Total
  $ 55  
         
 
Total rent expense, excluding month-to-month rentals, was $15 million, $26 million and $26 million in 2010, 2009 and 2008, respectively. Rent charges incurred for drilling rig rentals are capitalized under the successful efforts method of accounting.
 
10.   Employee Benefit Plans
 
Certain benefit costs associated with direct employees who support our operations are determined based on a specific employee basis and are charged to us by Williams as described below. These pension and post retirement benefit costs include amounts associated with vested participants who are no longer employees. As described in Note 2, Williams also charges us for the allocated cost of certain indirect employees of Williams who provide general and administrative services on our behalf. Williams includes an allocation of the benefit costs associated with these Williams employees based upon a Williams’ determined benefit rate, not necessarily specific to the employees providing general and administrative services on our behalf. As a result, the information described below is limited to amounts associated with the direct employees supporting our operations.
 
For the periods presented, we were not the plan sponsor for these plans. Accordingly, our Combined Balance Sheet does not reflect any assets or liabilities related to these plans.
 
Pension plans
 
Williams is the sponsor of noncontributory defined benefit pension plans that provide pension benefits for its eligible employees. Pension expense charged to us by Williams for 2010, 2009 and 2008 totaled $7 million, $7 million and $3 million, respectively.
 
Other postretirement benefits
 
Williams is the sponsor of subsidized retiree medical and life insurance benefit plans (other postretirement benefits) that provides benefits to certain eligible participants, generally including employees hired on or before December 31, 1991, and other miscellaneous defined participant groups. The allocation of cost for the plan anticipates future cost-sharing changes to the plan that are consistent with Williams’ expressed intent to increase the retiree contribution level, generally in line with health care cost increases. Other postretirement


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Table of Contents

WPX Energy
 
Notes to Combined Financial Statements—(Continued)
 
benefit expense charged to us by Williams for 2010, 2009, and 2008 totaled less than $1 million for each period.
 
Defined contribution plan
 
Williams also is the sponsor of a defined contribution plan that provides benefits to certain eligible participants and thus has charged us compensation expense of $5 million, $5 million and $4 million in 2010, 2009 and 2008, respectively, for Williams’ matching contributions to this plan. Additionally, Apco maintains a defined contribution plan for its employees. Total annual compensation expense related to Apco’s plan was approximately $0.1 million for each period.
 
11.   Stock-Based Compensation
 
Certain of our direct employees participate in The Williams Companies, Inc. 2007 Incentive Plan, which provides for Williams common-stock-based awards to both employees and Williams’ nonmanagement directors. The plan permits the granting of various types of awards including, but not limited to, stock options and restricted stock units. Awards may be granted for no consideration other than prior and future services or based on certain financial performance targets. Additionally, certain of direct our employees participate in Williams’ Employee Stock Purchase Plan (ESPP). The ESPP enables eligible participants to purchase through payroll deductions a limited amount of Williams’ common stock at a discounted price.
 
We are charged by Williams for stock-based compensation expense related to our direct employees. Williams also charges us for the allocated costs of certain indirect employees of Williams (including stock-based compensation) who provide general and administrative services on our behalf and may become our employees in the future. However, information included in this note is limited to stock-based compensation associated with the direct employees (see Note 2 for total costs charged to us by Williams).
 
Total stock-based compensation expense included in general and administrative expense for the years ended December 31, 2010, 2009 and 2008 was $14 million, $13 million, and $11 million, respectively.
 
Employee stock-based awards
 
Stock options are valued at the date of award, which does not precede the approval date, and compensation cost is recognized on a straight-line basis, net of estimated forfeitures, over the requisite service period. The purchase price per share for stock options may not be less than the market price of the underlying stock on the date of grant.
 
Stock options generally become exercisable over a three-year period from the date of grant and generally expire ten years after the grant.
 
Restricted stock units are generally valued at market value on the grant date and generally vest over three years. Restricted stock unit compensation cost, net of estimated forfeitures, is generally recognized over the vesting period on a straight-line basis.
 
Stock Options
 
The following summary reflects stock option activity and related information for the year ended December 31, 2010.
 


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Table of Contents

WPX Energy
 
Notes to Combined Financial Statements—(Continued)
 
                         
          Weighted-
       
          Average
    Aggregate
 
          Exercise
    Intrinsic
 
Stock Options
  Options     Price     Value  
    (Millions)           (Millions)  
 
Outstanding at December 31, 2009
    1.6     $ 17.47          
Granted
    0.2     $ 21.22          
Exercised
    (0.1 )   $ 7.65     $ 2  
                         
Expired
    (0.1 )   $ 42.29          
Forfeited
        $          
                         
Outstanding at December 31, 2010
    1.6     $ 18.23     $ 13  
                         
Exercisable at December 31, 2010
    1.2     $ 18.20     $ 10  
                         
 
The total intrinsic value of options exercised during the years ended December 31, 2010, 2009, and 2008 was $2 million, $0.2 million, and $7 million, respectively.
 
The following summary provides additional information about stock options that are outstanding and exercisable at December 31, 2010.
 
                                                 
    Stock Options Outstanding     Stock Options Exercisable  
                Weighted-
                Weighted-
 
          Weighted-
    Average
          Weighted-
    Average
 
          Average
    Remaining
          Average
    Remaining
 
          Exercise
    Contractual
          Exercise
    Contractual
 
Range of Exercise Prices
  Options     Price     Life     Options     Price     Life  
    (Millions)           (Years)     (Millions)           (Years)  
 
$2.58 to $11.84
    0.6     $ 8.79       4.9       0.5     $ 7.88       3.4  
$11.85 to 21.67
    0.6     $ 20.32       6.1       0.4     $ 19.79       4.3  
$21.68 to $33.65
    0.2     $ 27.84       6.0       0.2     $ 27.84       6.0  
$33.66 to $36.50
    0.2     $ 36.21       5.9       0.1     $ 36.09       5.5  
                                                 
Total
    1.6     $ 18.23       5.6       1.2     $ 18.20       4.4  
                                                 
 
The estimated fair value at date of grant of options for Williams common stock granted in each respective year, using the Black-Scholes option pricing model, is as follows:
 
                         
    2010     2009     2008  
 
Weighted-average grant date fair value of options granted
  $ 7.02     $ 5.60     $ 12.83  
                         
Weighted-average assumptions:
                       
Dividend yield
    2.6 %     1.6 %     1.2 %
Volatility
    39.0 %     60.8 %     33.4 %
Risk-free interest rate
    3.0 %     2.3 %     3.5 %
Expected life (years)
    6.5       6.5       6.5  
 
The expected dividend yield is based on the average annual dividend yield as of the grant date. Expected volatility is based on the historical volatility of Williams stock and the implied volatility of Williams stock based on traded options. In calculating historical volatility, returns during calendar year 2002 were excluded as the extreme volatility during that time is not reasonably expected to be repeated in the future. The risk-free interest rate is based on the U.S. Treasury Constant Maturity rates as of the grant date. The expected life of the option is based on historical exercise behavior and expected future experience.

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Table of Contents

WPX Energy
 
Notes to Combined Financial Statements—(Continued)
 
Nonvested Restricted Stock Units
 
The following summary reflects nonvested restricted stock unit activity and related information for the year ended December 31, 2010.
 
                 
          Weighted-
 
          Average
 
Restricted Stock Units
  Shares     Fair Value*  
    (Millions)        
 
Nonvested at December 31, 2009
    1.7     $ 18.24  
Granted
    0.6     $ 21.19  
Forfeited
    (0.1 )   $ 19.36  
Cancelled
    (0.1 )   $ 0.00  
Vested
    (0.3 )   $ 28.35  
                 
Nonvested at December 31, 2010
    1.8     $ 17.96  
                 
 
 
* Performance-based shares are primarily valued using the end-of-period market price until certification that the performance objectives have been completed, a value of zero once it has been determined that it is unlikely that performance objectives will be met, or a valuation pricing model. All other shares are valued at the grant-date market price.
 
Other restricted stock unit information
 
                         
    2010     2009     2008  
 
Weighted-average grant date fair value of restricted stock units granted during the year, per share
  $ 21.19     $ 10.53     $ 32.34  
                         
Total fair value of restricted stock units vested during the year ($’s in millions)
  $ 9     $ 8     $ 6  
                         
 
12.   Fair Value Measurements
 
Fair value is the amount received to sell an asset or the amount paid to transfer a liability in an orderly transaction between market participants (an exit price) at the measurement date. Fair value is a market-based measurement considered from the perspective of a market participant. We use market data or assumptions that we believe market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation. These inputs can be readily observable, market corroborated, or unobservable. We apply both market and income approaches for recurring fair value measurements using the best available information while utilizing valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.
 
The fair value hierarchy prioritizes the inputs used to measure fair value, giving the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). We classify fair value balances based on the observability of those inputs. The three levels of the fair value hierarchy are as follows:
 
  •   Level 1—Quoted prices for identical assets or liabilities in active markets that we have the ability to access. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 primarily consists of financial instruments that are exchange traded;
 
  •   Level 2—Inputs are other than quoted prices in active markets included in Level 1, that are either directly or indirectly observable. These inputs are either directly observable in the marketplace or


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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.
 
In valuing certain contracts, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. For disclosure purposes, assets and liabilities are classified in their entirety in the fair value hierarchy level based on the lowest level of input that is significant to the overall fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels.
 
The following table presents, by level within the fair value hierarchy, our assets and liabilities that are measured at fair value on a recurring basis.
 
Fair Value Measurements Using:
 
                                                                 
    December 31, 2010     December 31, 2009  
    Level 1     Level 2     Level 3     Total     Level 1     Level 2     Level 3     Total  
    (Millions)     (Millions)  
 
Energy derivative assets
  $ 97     $ 474     $ 2     $ 573     $ 178     $ 912     $ 4     $ 1,094  
Energy derivative liabilities
  $ 78     $ 210     $ 1     $ 289     $ 177     $ 826     $ 3     $ 1,006  
 
Energy derivatives include commodity based exchange-traded contracts and OTC contracts. Exchange-traded contracts include futures, swaps, and options. OTC contracts include forwards, swaps and options.
 
Many contracts have bid and ask prices that can be observed in the market. Our policy is to use a mid-market pricing (the mid-point price between bid and ask prices) convention to value individual positions and then adjust on a portfolio level to a point within the bid and ask range that represents our best estimate of fair value. For offsetting positions by location, the mid-market price is used to measure both the long and short positions.
 
The determination of fair value for our assets and liabilities also incorporates the time value of money and various credit risk factors which can include the credit standing of the counterparties involved, master netting arrangements, the impact of credit enhancements (such as cash collateral posted and letters of credit) and our nonperformance risk on our liabilities. The determination of the fair value of our liabilities does not consider noncash collateral credit enhancements.
 
Exchange-traded contracts include New York Mercantile Exchange and Intercontinental Exchange contracts and are valued based on quoted prices in these active markets and are classified within Level 1.
 
Forward, swap, and option contracts included in Level 2 are valued using an income approach including present value techniques and option pricing models. Option contracts, which hedge future sales of our production, are structured as costless collars and are financially settled. They are valued using an industry standard Black-Scholes option pricing model. Significant inputs into our Level 2 valuations include commodity


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WPX Energy
 
Notes to Combined Financial Statements—(Continued)
 
prices, implied volatility by location, and interest rates, as well as considering executed transactions or broker quotes corroborated by other market data. These broker quotes are based on observable market prices at which transactions could currently be executed. In certain instances where these inputs are not observable for all periods, relationships of observable market data and historical observations are used as a means to estimate fair value. Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2.
 
Our energy derivatives portfolio is largely comprised of exchange-traded products or like products and the tenure of our derivatives portfolio is relatively short with more than 99 percent of the value of our derivatives portfolio expiring in the next 24 months. Due to the nature of the products and tenure, we are consistently able to obtain market pricing. All pricing is reviewed on a daily basis and is formally validated with broker quotes and documented on a monthly basis.
 
Certain instruments trade with lower availability of pricing information. These instruments are valued with a present value technique using inputs that may not be readily observable or corroborated by other market data. These instruments are classified within Level 3 when these inputs have a significant impact on the measurement of fair value. The instruments included in Level 3 at December 31, 2010, consist primarily of natural gas index transactions that are used to manage our physical requirements.
 
Reclassifications of fair value between Level 1, Level 2, and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. No significant transfers in or out of Level 1 and Level 2 occurred during the year ended December 31, 2010. In 2009, certain options which hedge future sales of production were transferred from Level 3 to Level 2. These options were originally included in Level 3 because a significant input to the model, implied volatility by location, was considered unobservable. Due to increased transparency, this input was considered observable, and we transferred these options to Level 2.
 
The following tables present a reconciliation of changes in the fair value of our net energy derivatives and other assets classified as Level 3 in the fair value hierarchy.
 
Level 3 Fair Value Measurements Using Significant Unobservable Inputs
 
                         
    Year Ended December 31,  
    2010
    2009
    2008
 
    Net Energy
    Net Energy
    Net Energy
 
    Derivatives     Derivatives     Derivatives  
    (Millions)        
 
Beginning balance
  $ 1     $ 506     $ (5 )
Realized and unrealized gains (losses):
                       
Included in income (loss) from continuing operations
    1       476       96  
Included in other comprehensive income (loss)
          (329 )     478  
Purchases, issuances, and settlements
    (1 )     (479 )     (61 )
Transfers into Level 3
                3  
Transfers out of Level 3
          (173 )     (5 )
                         
Ending balance
  $ 1     $ 1     $ 506  
                         
Unrealized gains included in income from continuing operations relating to instruments held at December 31
  $     $     $  
                         
 
Realized and unrealized gains (losses) included in income (loss) from continuing operations for the above periods are reported in revenues in our Combined Statement of Operations.


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WPX Energy
 
Notes to Combined Financial Statements—(Continued)
 
The following table presents impairments associated with certain assets that have been measured at fair value on a nonrecurring basis within Level 3 of the fair value hierarchy.
 
Fair Value Measurements Using:
 
                 
    Total Losses for the Years
 
    Ended December 31,  
    2010     2009  
    (Millions)  
 
Impairments:
               
Goodwill (see Note 4)
  $ 1,003 (a)   $  
Producing properties and costs of acquired unproved reserves (see Note 4)
    678 (b)     15 (c)
Cost-based investment (see Note 3)
          11 (d)
                 
    $ 1,681     $ 26  
                 
 
 
(a) Due to a significant decline in forward natural gas prices across all future production periods during 2010, we determined that we had a trigger event and thus performed an interim impairment assessment of the approximate $1 billion of goodwill related to our domestic natural gas production operations (the reporting unit). Forward natural gas prices through 2025 as of September 30, 2010, used in our analysis declined more than 22 percent on average compared to the forward prices as of December 31, 2009. We estimated the fair value of the reporting unit on a stand-alone basis by valuing proved and unproved reserves, as well as estimating the fair values of other assets and liabilities which are identified to the reporting unit. We used an income approach (discounted cash flow) for valuing reserves. The significant inputs into the valuation of proved and unproved reserves included reserve quantities, forward natural gas prices, anticipated drilling and operating costs, anticipated production curves, income taxes, and appropriate discount rates. To estimate the fair value of the reporting unit and the implied fair value of goodwill under a hypothetical acquisition of the reporting unit, we assumed a tax structure where a buyer would obtain a step-up in the tax basis of the net assets acquired. Significant assumptions in valuing proved reserves included reserves quantities of more than 4.4 trillion cubic feet of gas equivalent; forward prices averaging approximately $4.65 per thousand cubic feet of gas equivalent (Mcfe) for natural gas (adjusted for locational differences), natural gas liquids and oil; and an after-tax discount rate of 11 percent. Unproved reserves (probable and possible) were valued using similar assumptions adjusted further for the uncertainty associated with these reserves by using after- tax discount rates of 13 percent and 15 percent, respectively, commensurate with our estimate of the risk of those reserves. In our assessment as of September 30, 2010, the carrying value of the reporting unit, including goodwill, exceeded its estimated fair value. We then determined that the implied fair value of the goodwill was zero. As a result of our analysis, we recognized a full $1 billion impairment charge related to this goodwill.
 
(b) As of September 30, 2010, we also believed we had a trigger event as a result of recent significant declines in forward natural gas prices and therefore, we assessed the carrying value of our natural gas-producing properties and costs of acquired unproved reserves for impairments. Our assessment utilized estimates of future cash flows. Significant judgments and assumptions in these assessments are similar to those used in the goodwill evaluation and include estimates of natural gas reserve quantities, estimates of future natural gas prices using a forward NYMEX curve adjusted for locational basis differentials, drilling plans, expected capital costs, and an applicable discount rate commensurate with risk of the underlying cash flow estimates. The assessment performed at September 30, 2010, identified certain properties with a carrying value in excess of their calculated fair values. As a result, we recorded a $678 million impairment charge in the


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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.
 
13.   Financial Instruments, Derivatives, Guarantees and Concentration of Credit Risk
 
We use the following methods and assumptions in estimating our fair-value disclosures for financial instruments:
 
Cash and cash equivalents and restricted cash:  The carrying amounts reported in the Combined Balance Sheet approximate fair value due to the nature of the instrument and/or the short-term maturity of these instruments.
 
Other:  Includes margin deposits and customer margin deposits payable for which the amounts reported in the combined Balance Sheet approximate fair value.
 
Energy derivatives:  Energy derivatives include futures, forwards, swaps, and options. These are carried at fair value in the Combined Balance Sheet. See Note 12 for a discussion of valuation of energy derivatives.
 
Carrying amounts and fair values of our financial instruments were as follows:
 
                                 
    December 31,  
    2010     2009  
    Carrying
    Fair
    Carrying
    Fair
 
Asset (Liability)
  Amount     Value     Amount     Value  
    (Millions)  
 
Cash and cash equivalents
  $ 37     $ 37     $ 34     $ 34  
Restricted cash
    24       24       19       19  
Other
    (25 )     (25 )     (26 )     (26 )
Net energy derivatives:
                               
Energy commodity cash flow hedges
    266       266       180       180  
Other energy derivatives
    18       18       (92 )     (92 )


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WPX Energy
 
Notes to Combined Financial Statements—(Continued)
 
Energy Commodity Derivatives
 
We are exposed to market risk from changes in energy commodity prices within our operations. We utilize derivatives to manage exposure to the variability in expected future cash flows from forecasted sales of natural gas attributable to commodity price risk. Certain of these derivatives utilized for risk management purposes have been designated as cash flow hedges, while other derivatives have not been designated as cash flow hedges or do not qualify for hedge accounting despite hedging our future cash flows on an economic basis.
 
We produce, buy and sell natural gas at different locations throughout the United States. To reduce exposure to a decrease in revenues from fluctuations in natural gas market prices, we enter into natural gas futures contracts, swap agreements, and financial option contracts to mitigate the price risk on forecasted sales of natural gas. We have also entered into basis swap agreements to reduce the locational price risk associated with our producing basins. These cash flow hedges are expected to be highly effective in offsetting cash flows attributable to the hedged risk during the term of the hedge. However, ineffectiveness may be recognized primarily as a result of locational differences between the hedging derivative and the hedged item. Our financial option contracts are either purchased options or a combination of options that comprise a net purchased option or a zero-cost collar. Our designation of the hedging relationship and method of assessing effectiveness for these option contracts are generally such that the hedging relationship is considered perfectly effective and no ineffectiveness is recognized in earnings.
 
The following table sets forth the derivative volumes designated as hedges of production volumes as of December 31, 2010:
 
                             
                        Weighted Average
                  Notional Volume
    Price
Commodity
  Period    
Contract Type
 
Location
  (MMbtu)     ($/MMbtu)
 
Natural Gas
    2011     Costless Collar   Rockies     16,425     $5.30 - $7.10
Natural Gas
    2011     Costless Collar   San Juan     32,850     $5.27 - $7.06
Natural Gas
    2011     Costless Collar   MidCon     29,200     $5.10 - $7.00
Natural Gas
    2011     Costless Collar   SoCal     10,950     $5.83 - $7.56
Natural Gas
    2011     Costless Collar   Appalachia     10,950     $6.50 - $8.14
Natural Gas
    2011     Location Swaps   Rockies     27,375     $5.57
Natural Gas
    2011     Location Swaps   San Juan     38,325     $5.14
Natural Gas
    2011     Location Swaps   MidCon     7,300     $5.22
Natural Gas
    2011     Location Swaps   SoCal     7,300     $5.34
Natural Gas
    2011     Location Swaps   Appalachia     23,725     $5.59
Natural Gas
    2012     Location Swaps   Rockies     25,620     $4.79
Natural Gas
    2012     Location Swaps   San Juan     26,535     $5.06
Natural Gas
    2012     Location Swaps   MidCon     14,640     $4.74
Natural Gas
    2012     Location Swaps   SoCal     9,150     $5.22
Natural Gas
    2012     Location Swaps   Appalachia     20,130     $5.93
 
We also enter into forward contracts to buy and sell natural gas to maximize the economic value of transportation agreements and storage capacity agreements. To reduce exposure to a decrease in margins from fluctuations in natural gas market prices, we may enter into futures contracts, swap agreements, and financial option contracts to mitigate the price risk associated with these contracts. Hedges for transportation contracts are designated as cash flow hedges and are expected to be highly effective in offsetting cash flows attributable to the hedged risk during the term of the hedge. However, ineffectiveness may be recognized primarily as a result of locational differences between the hedging derivative and the hedged item. Hedges for storage


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WPX Energy
 
Notes to Combined Financial Statements—(Continued)
 
contracts have not been designated as hedging instruments, despite economically hedging the expected cash flows generated by those agreements.
 
We also enter into commodity derivatives for other than risk management purposes, including managing certain remaining legacy natural gas contracts and positions from our former power business and providing services to third parties. These legacy natural gas contracts include substantially offsetting positions and have had an insignificant net impact on earnings.
 
The following table depicts the notional amounts of the net long (short) positions which we did not designate as hedges of our production in our commodity derivatives portfolio as of December 31, 2010. Natural gas is presented in millions of British Thermal Units (MMBtu). All of the Central hub risk realizes in 2011 and 99% of the basis risk realizes in 2011. The net index position includes contracts for the future sale of physical natural gas related to our production. Offsetting these sales are contracts for the future production of physical natural gas related to WPZ’s natural gas shrink requirements. These contracts result in minimal commodity price risk exposure and have a value of less than $1 million at December 31, 2010.
 
                                 
    Unit of
    Central Hub
    Basis
    Index
 
Derivative Notional Volumes
  Measure     Risk(a)     Risk(b)     Risk(c)  
 
Not Designated as Hedging Instruments
                               
Risk Management
    MMBtu       (9,077,499 )     (20,195,000 )     16,586,059  
Other
    MMBtu       150,400       (14,766,500 )        
 
 
(a) includes physical and financial derivative transactions that settle against the Henry Hub price;
 
(b) includes financial derivative transactions priced off the difference in value between the Central Hub and another specific delivery point;
 
(c) includes physical derivative transactions at an unknown future price, including purchases of 84,583,157 MMBtu primarily on behalf of WPZ and sales of 67,997,098 MMBtu.
 
Fair values and gains (losses)
 
The following table presents the fair value of energy commodity derivatives. Our derivatives are presented as separate line items in our Combined Balance Sheet as current and noncurrent derivative assets and liabilities. Derivatives are classified as current or noncurrent based on the contractual timing of expected future net cash flows of individual contracts. The expected future net cash flows for derivatives classified as current are expected to occur within the next 12 months. The fair value amounts are presented on a gross basis and do not reflect the netting of asset and liability positions permitted under the terms of our master netting arrangements. Further, the amounts below do not include cash held on deposit in margin accounts that we have received or remitted to collateralize certain derivative positions.
 
                                 
    December 31,  
    2010     2009  
    Assets     Liabilities     Assets     Liabilities  
    (Millions)  
 
Designated as hedging instruments
  $ 288     $ 22     $ 352     $ 172  
Not designated as hedging instruments:
                               
Legacy natural gas contracts from former power business
    186       187       505       526  
Hedges for storage contracts and other
    99       80       237       308  
                                 
Total derivatives not designated as hedging instruments
    285       267       742       834  
                                 
Total derivatives
  $ 573     $ 289     $ 1,094     $ 1,006  
                                 


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WPX Energy
 
Notes to Combined Financial Statements—(Continued)
 
The following table presents pre-tax gains and losses for our energy commodity derivatives designated as cash flow hedges, as recognized in accumulated other comprehensive income (AOCI) or revenues.
 
                         
    Years Ended December 31,        
    2010     2009     Classification  
    (Millions)        
 
Net gain recognized in other comprehensive income (loss) (effective portion)
  $ 505     $ 266       AOCI  
Net gain reclassified from accumulated other comprehensive income (loss) into income (effective portion)(1)
  $ 354     $ 621       Revenues  
Gain recognized in income (ineffective portion)
  $ 9     $ 4       Revenues  
 
 
(1) Gains reclassified from accumulated other comprehensive income (loss) primarily represent realized gains associated with our production reflected in oil and gas sales.
 
There were no gains or losses recognized in income as a result of excluding amounts from the assessment of hedge effectiveness.
 
The following table presents pre-tax gains and losses for our energy commodity derivatives not designated as hedging instruments.
 
                 
    Years Ended
 
    December 31, 2009  
    2010     2009  
    (Millions)  
 
Gas management revenues
  $ 47     $ 33  
Gas management expenses
    28       33  
                 
Net gain
  $ 19     $  
                 
 
The cash flow impact of our derivative activities is presented in the Combined Statement of Cash Flows as changes in current and noncurrent derivative assets and liabilities.
 
Credit-risk-related features
 
Certain of our derivative contracts contain credit-risk-related provisions that would require us, in certain circumstances, to post additional collateral in support of our net derivative liability positions. These credit-risk-related provisions require us to post collateral in the form of cash or letters of credit when our net liability positions exceed an established credit threshold. The credit thresholds are typically based on our senior unsecured debt ratings from Standard and Poor’s and/or Moody’s Investors Service. Under these contracts, a credit ratings decline would lower our credit thresholds, thus requiring us to post additional collateral. We also have contracts that contain adequate assurance provisions giving the counterparty the right to request collateral in an amount that corresponds to the outstanding net liability. Additionally, we have an unsecured credit agreement with certain banks related to hedging activities. We are not required to provide collateral support for net derivative liability positions under the credit agreement as long as the value of our domestic natural gas reserves, as determined under the provisions of the agreement, exceeds by a specified amount certain of its obligations including any outstanding debt and the aggregate out-of-the-money position on hedges entered into under the credit agreement.
 
As of December 31, 2010, we have collateral totaling $8 million, all of which is in the form of letters of credit, posted to derivative counterparties, to support the aggregate fair value of our net derivative liability position (reflecting master netting arrangements in place with certain counterparties) of $36 million, which


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WPX Energy
 
Notes to Combined Financial Statements—(Continued)
 
includes a reduction of less than $1 million to our liability balance for our own nonperformance risk. At December 31, 2009, we had collateral totaling $96 million posted to derivative counterparties, all of which was in the form of letters of credit, to support the aggregate fair value of our net derivative liabilities position (reflecting master netting arrangements in place with certain counterparties) of $164 million, which included a reduction of $3 million to our liability balance for our own nonperformance risk. The additional collateral that we would have been required to post, assuming our credit thresholds were eliminated and a call for adequate assurance under the credit risk provisions in our derivative contracts was triggered, was $29 million and $71 million at December 31, 2010 and December 31, 2009, respectively.
 
Cash flow hedges
 
Changes in the fair value of our cash flow hedges, to the extent effective, are deferred in other comprehensive income and reclassified into earnings in the same period or periods in which the hedged forecasted purchases or sales affect earnings, or when it is probable that the hedged forecasted transaction will not occur by the end of the originally specified time period. As of December 31, 2010, we have hedged portions of future cash flows associated with anticipated energy commodity purchases and sales for up to two years. Based on recorded values at December 31, 2010, $148 million of net gains (net of income tax provision of $88 million) will be reclassified into earnings within the next year. These recorded values are based on market prices of the commodities as of December 31, 2010. Due to the volatile nature of commodity prices and changes in the creditworthiness of counterparties, actual gains or losses realized within the next year will likely differ from these values. These gains or losses are expected to substantially offset net losses or gains that will be realized in earnings from previous unfavorable or favorable market movements associated with underlying hedged transactions.
 
Concentration of Credit Risk
 
Cash equivalents
 
Our cash equivalents are primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government.
 
Accounts receivable
 
The following table summarizes concentration of receivables (other than as relates to affiliates), net of allowances, by product or service as of December 31:
 
                 
    2010     2009  
    (Millions)  
 
Receivables by product or service:
               
Sale of natural gas and related products and services
  $ 272     $ 288  
Joint interest owners
    83       66  
Other
    7       7  
                 
Total
  $ 362     $ 361  
                 
 
Natural gas customers include pipelines, distribution companies, producers, gas marketers and industrial users primarily located in the eastern and northwestern United States, Rocky Mountains and Gulf Coast. As a general policy, collateral is not required for receivables, but customers’ financial condition and credit worthiness are evaluated regularly.


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WPX Energy
 
Notes to Combined Financial Statements—(Continued)
 
Derivative assets and liabilities
 
We have a risk of loss from counterparties not performing pursuant to the terms of their contractual obligations. Counterparty performance can be influenced by changes in the economy and regulatory issues, among other factors. Risk of loss is impacted by several factors, including credit considerations and the regulatory environment in which a counterparty transacts. We attempt to minimize credit-risk exposure to derivative counterparties and brokers through formal credit policies, consideration of credit ratings from public ratings agencies, monitoring procedures, master netting agreements and collateral support under certain circumstances. Collateral support could include letters of credit, payment under margin agreements, and guarantees of payment by credit worthy parties.
 
We also enter into master netting agreements to mitigate counterparty performance and credit risk. During 2010 and 2009, we did not incur any significant losses due to counterparty bankruptcy filings.
 
The gross credit exposure from our derivative contracts as of December 31, 2010, is summarized as follows.
 
                 
    Investment
       
Counterparty Type
  Grade*     Total  
    (Millions)  
 
Gas and electric utilities
  $ 7     $ 8  
Energy marketers and traders
          133  
Financial institutions
    432       432  
                 
    $ 439       573  
                 
Credit reserves
             
                 
Gross credit exposure from derivatives
          $ 573  
                 
 
We assess our credit exposure on a net basis to reflect master netting agreements in place with certain counterparties. We offset our credit exposure to each counterparty with amounts we owe the counterparty under derivative contracts. The net credit exposure from our derivatives as of December 31, 2010, excluding collateral support discussed below, is summarized as follows.
 
                 
    Investment
       
Counterparty Type
  Grade*     Total  
    (Millions)  
 
Gas and electric utilities
  $ 3     $ 3  
Financial institutions
    317       317  
                 
    $ 320       320  
                 
Credit reserves
             
                 
Net credit exposure from derivatives
          $ 320  
                 
 
 
* We determine investment grade primarily using publicly available credit ratings. We include counterparties with a minimum Standard & Poor’s rating of BBB- or Moody’s Investors Service rating of Baa3 in investment grade.
 
Our nine largest net counterparty positions represent approximately 99 percent of our net credit exposure from derivatives and are all with investment grade counterparties. Included within this group are eight counterparty positions, representing 81 percent of our net credit exposure from derivatives, associated with our hedging facility (see Note 8). Under certain conditions, the terms of this credit agreement may require the participating financial institutions to deliver collateral support to a designated collateral agent (which is


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Table of Contents

WPX Energy
 
Notes to Combined Financial Statements—(Continued)
 
another participating financial institution in the agreement). The level of collateral support required is dependent on whether the net position of the counterparty financial institution exceeds specified thresholds. The thresholds may be subject to prescribed reductions based on changes in the credit rating of the counterparty financial institution.
 
At December 31, 2010, the designated collateral agent holds $19 million of collateral support on our behalf under our hedging facility. In addition, we hold collateral support, which may include cash or letters of credit, of $15 million related to our other derivative positions.
 
Revenues
 
During 2010, BP Energy Company accounted for 13% of our combined revenues. During 2009, and 2008, there were no customers for which our sales exceeded 10 percent of our combined revenues. Management believes that the loss of any individual purchaser would not have a long-term material adverse impact on the financial position or results of operations of the Company.
 
Net Assets of Operations in Foreign Locations
 
Net assets of operations in Argentina were $231 million and $208 million as of December 31, 2010 and 2009, respectively.
 
14.   Subsequent Events
 
In March 2011, management of Williams approved the plan to sell our oil and gas properties and other related assets in the Arkoma basin of Oklahoma. As of March 31, 2011, these operations are considered held for sale. The net book value of the assets, revenues and operating costs represent less than a percent of our total assets, total revenues and operating costs in 2010. In 2008, we recorded an impairment charge of $148 million related to these properties as discussed in Note 4.


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WPX Energy
 
Supplemental Oil and Gas Disclosures
(Unaudited)
 
We have significant oil and gas producing activities primarily in the Rocky Mountain, Northeast and Mid-continent areas of the United States. Additionally, we have international oil and gas producing activities, primarily in Argentina. This information also excludes our gas management activities.
 
Capitalized Costs
 
                                 
    As of December 31, 2009  
                      Entity’s share of
 
                      international
 
                Consolidated
    equity method
 
    Domestic     International     Total     investee  
 
Proved Properties
  $ 9,176     $ 180     $ 9,356     $ 187  
Unproved properties
    945       3       948        
                                 
      10,121       183       10,304       187  
Accumulated depreciation, depletion and amortization and valuation provisions
    (3,213 )     (94 )     (3,307 )     (109 )
                                 
Net capitalized costs
  $ 6,908     $ 89     $ 6,997     $ 78  
                                 
 
                                 
    As of December 31, 2010  
                      Entity’s share of
 
                      international
 
                Consolidated
    equity method
 
    Domestic     International     Total     investee  
 
Proved Properties
  $ 9,854     $ 213     $ 10,067     $ 220  
Unproved properties
    2,094       3       2,097        
                                 
      11,948       216       12,164       220  
Accumulated depreciation, depletion and amortization and valuation provisions
    (3,866 )     (109 )     (3,975 )     (129 )
                                 
Net capitalized costs
  $ 8,082       107     $ 8,189     $ 91  
                                 
 
  •   Excluded from capitalized costs are equipment and facilities in support of oil and gas production of $312 million and $727 million, net, for 2010 and 2009, respectively.
 
  •   Proved properties include capitalized costs for oil and gas leaseholds holding proved reserves, development wells including uncompleted development well costs, and successful exploratory wells.
 
  •   Unproved properties consist primarily of unproved leasehold costs and costs for acquired unproven reserves.


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Table of Contents

WPX Energy
 
Supplemental Oil and Gas Disclosures—(Continued)
(Unaudited)
 
Cost Incurred
 
                         
                Entity’s share of
 
                international
 
                equity method
 
    Domestic     International     investee  
    (Millions)  
 
For the Year Ended December 31, 2008
                       
Acquisition
  $ 543     $     $  
Exploration
    38       9       7  
Development
    1,699       27       25  
                         
    $ 2,280     $ 36     $ 32  
                         
For the Year Ended December 31, 2009
                       
Acquisition
  $ 305     $ 3     $  
Exploration
    51       3       3  
Development
    878       19       21  
                         
    $ 1,234     $ 25     $ 24  
                         
For the Year Ended December 31, 2010
                       
Acquisition
  $ 1,731     $     $  
Exploration
    22       13       3  
Development
    988       27       25  
                         
    $ 2,741     $ 40     $ 28  
                         
 
  •   Costs incurred include capitalized and expensed items.
 
  •   Acquisition costs are as follows: The 2010 costs are primarily for additional leasehold in the Williston and Marcellus basins and include approximately $422 million of proved property values. The 2009 costs are primarily for additional leasehold and reserve acquisitions in the Piceance basin, and include $85 million of proved property values. The 2008 costs are primarily for additional leasehold and reserve acquisitions in the Piceance and Fort Worth basins. Included in the 2008 acquisition amounts is $140 million of proved property values and $71 million related to an interest in a portion of acquired assets that a third party subsequently exercised its contractual option to purchase from us, on the same terms and conditions.
 
  •   Exploration costs include the costs incurred for geological and geophysical activity, drilling and equipping exploratory wells, including costs incurred during the year for wells determined to be dry holes, exploratory lease acquisitions, and retaining undeveloped leaseholds.
 
  •   Development costs include costs incurred to gain access to and prepare well locations for drilling and to drill and equip wells in our development basins.
 
  •   We have classified our step-out drilling and site preparation costs in the Powder River Basin as development, although the immediate offsets are frequently in the dewatering stages in as much as it better reflects the low risk profile of the costs incurred.


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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, 2008
                       
Revenues:
                       
Oil and gas revenues
  $ 2,845     $ 72     $ 2,917  
Other revenues
    36             36  
                         
Total revenues
    2,881       72       2,953  
                         
Costs:
                       
Lease and facility operating
    267       17       284  
Gathering, processing & transportation
    225             225  
Taxes other than income
    243       12       255  
Exploration expenses
    32       6       38  
Depreciation, depletion & amortization
    744       14       758  
Impairment of certain natural gas properties in the Arkoma basin
    148             148  
General and administrative
    223       7       230  
Gain on sale of international production payment right
          (148 )     (148 )
Other (income) expense
    5       2       7  
                         
Total costs
    1,887       (90 )     1,797  
                         
Results of operations
    994       162       1,156  
(Provision) benefit for income taxes
    (362 )     (59 )     (421 )
                         
Exploration and production net income (loss)
  $ 632     $ 103     $ 735  
                         
 


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Table of Contents

WPX Energy
 
Supplemental Oil and Gas Disclosures—(Continued)
(Unaudited)
 
                         
    Domestic     International     Total  
    (Millions)  
 
For the Year Ended December 31, 2009
                       
Revenues:
                       
Oil and gas revenues
  $ 2,105     $ 78     $ 2,183  
Other revenues
    43             43  
                         
Total revenues
    2,148       78       2,226  
                         
Costs:
                       
Lease and facility operating
    257       16       273  
Gathering, processing & transportation
    270             270  
Taxes other than income
    81       13       94  
Exploration expenses
    54       2       56  
Depreciation, depletion & amortization
    877       17       894  
Impairment of costs of acquired unproved reserves
    15             15  
General and administrative
    221       9       230  
Other (income) expense
    33             33  
                         
Total costs
    1,808       57       1,865  
                         
Results of operations
    340       21       361  
(Provision) benefit for income taxes
    (124 )     (8 )     (132 )
                         
Exploration and production net income (loss)
  $ 216     $ 13     $ 229  
                         
 

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Table of Contents

WPX Energy
 
Supplemental Oil and Gas Disclosures—(Continued)
(Unaudited)
 
                         
    Domestic     International     Total  
    (Millions)  
 
For the Year Ended December 31, 2010
                       
Revenues:
                       
Oil and gas revenues
  $ 2,154     $ 89     $ 2,243  
Other revenues
    41             41  
                         
Total revenues
    2,195       89       2,284  
                         
Costs:
                       
Lease and facility operating
    276       19       295  
Gathering, processing & transportation
    324             324  
Taxes other than income
    109       16       125  
Exploration expenses
    70       6       76  
Depreciation, depletion & amortization
    864       17       881  
Impairment of certain natural gas properties in the Ft. Worth basin
    503             503  
Impairment of costs of acquired unproved reserves
    175             175  
Goodwill impairment
    1,003             1,003  
General and administrative
    224       9       233  
Other (income) expense
    (15 )           (15 )
                         
Total costs
    3,533       67       3,600  
                         
Results of operations
    (1,338 )     22       (1,316 )
(Provision) benefit for income taxes
    122       (8 )     114  
                         
Exploration and production net income (loss)
  $ (1,216 )   $ 14     $ (1,202 )
                         
 
  •   Amount for all years exclude the equity earnings from the international equity method investee. Equity earnings from this investee were $16 million, $14 million and $16 million in 2010, 2009 and 2008.
 
  •   Oil and gas revenues consist primarily of natural gas production sold and includes the impact of hedges.
 
  •   Other revenues consist of activities that are an indirect part of the producing activities. Other expenses in 2009 also include $32 million of expense related to penalties from the early release of drilling rigs.
 
  •   Exploration expenses include the costs of geological and geophysical activity, drilling and equipping exploratory wells determined to be dry holes, and the cost of retaining undeveloped leaseholds including lease amortization and impairments.
 
  •   Depreciation, depletion and amortization includes depreciation of support equipment. Additionally, 2009 includes $17 million additional depreciation, depletion and amortization as a result of our recalculation of fourth quarter depreciation, depletion and amortization utilizing our year-end reserves which were lower than 2008. The lower reserves are primarily a result of the application of new rules issued by the SEC.

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Table of Contents

WPX Energy
 
Supplemental Oil and Gas Disclosures—(Continued)
(Unaudited)
 
 
Proved Reserves
 
                                 
                Entity’s share of
       
                international
       
                equity method
       
    Domestic     International(1)     investee(2)     Combined  
    (Bcfe)     (MMBoe)     (MMBoe)     (Bcfe)  
 
For The Year Ended December 31, 2008
                               
Proved reserves at the beginning of period
    4,143       21       15       4,357  
Revisions
    (220 )     1             (208 )
Purchases
    31                   31  
Extensions and discoveries
    791       2       1       810  
Wellhead production
    (406 )     (2 )     (2 )     (434 )
                                 
Proved reserves at the end of period
    4,339       22       14       4,556  
                                 
Proved developed reserves at end of period
    2,456       15       10       2,607  
                                 
For the year ended December 31, 2009
                               
Proved reserves at the beginning of period
    4,339       22       14       4,556  
Revisions
    (859 )     2       1       (841 )
Purchases
    159                   159  
Extensions and discoveries
    1,051       5       7       1,123  
Wellhead production
    (435 )     (3 )     (2 )     (466 )
                                 
Proved reserves at the end of period
    4,255       26       20       4,531  
                                 
Proved developed reserves at end of period
    2,387       17       12       2,562  
                                 
For the year ended December 31, 2010
                               
Proved reserves at the beginning of period
    4,255       26       20       4,531  
Revisions
    (233 )     (2 )     1       (242 )
Purchases
    162                   162  
Extensions and discoveries
    508       4       4       557  
Wellhead production
    (420 )     (3 )     (2 )     (450 )
                                 
Proved reserves at the end of period
    4,272       25       23       4,558  
                                 
Proved developed reserves at end of period
    2,498       15       14       2,671  
                                 
 
 
(1) Reserves attributable to a consolidated subsidiary (Apco) in which there is a 31 percent noncontrolling interest.
 
(2) Represents Apco’s 40.8% interest in reserves of Petrolera Entre Lomas S.A.
 
  •   The SEC defines proved oil and gas reserves (Rule 4-10(a) of Regulation S-X) as those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is


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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
 
The following is based on the estimated quantities of proved reserves. In 2009, we adopted prescribed accounting revisions associated with oil and gas authoritative guidance. Those revisions include using the 12-month average price computed as an unweighted arithmetic average of the price as of the first day of each month, unless prices are defined by contractual arrangements. These revisions are reflected in our 2010 and 2009 amounts. For the years ended December 31, 2010 and 2009, the average domestic natural gas equivalent price used in the estimates was $3.78 and $2.76 per MMcfe, respectively. For the year ended December 31, 2008, the average domestic year-end natural gas equivalent price used in the estimates was $4.41 per MMcfe. Future income tax expenses have been computed considering applicable taxable cash flows and appropriate statutory tax rates. The discount rate of 10 percent is as prescribed by authoritative guidance. Continuation of year-end economic conditions also is assumed. The calculation is based on estimates of proved reserves, which are revised over time as new data becomes available. Probable or possible reserves, which may become proved in the future, are not considered. The calculation also requires assumptions as to the timing of future production of proved reserves, and the timing and amount of future development and production costs.
 
Numerous uncertainties are inherent in estimating volumes and the value of proved reserves and in projecting future production rates and timing of development expenditures. Such reserve estimates are subject


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Table of Contents

WPX Energy
 
Supplemental Oil and Gas Disclosures—(Continued)
(Unaudited)
 
to change as additional information becomes available. The reserves actually recovered and the timing of production may be substantially different from the reserve estimates.
 
Standardized Measure of Discounted Future Net Cash Flows
 
                         
                Entity’s share
 
                of international
 
                equity method
 
As of December 31, 2009
  Domestic     International(1)     investee(2)  
    (Millions)  
 
Future cash inflows
  $ 11,729     $ 664     $ 614  
Less:
                       
Future production costs
    3,990       227       228  
Future development costs
    2,833       83       91  
Future income tax provisions
    1,404       67       73  
                         
Future net cash flows
    3,502       287       222  
Less 10 percent annual discount for estimated timing of cash flows
    (1,789 )     (112 )     (93 )
                         
Standardized measure of discounted future net cash inflows
  $ 1,713     $ 175     $ 129  
                         
 
                         
                Entity’s share
 
                of international
 
                equity method
 
As of December 31, 2010
  Domestic     International(1)     investee(2)  
 
Future cash inflows
  $ 16,151     $ 779     $ 787  
Less:
                       
Future production costs
    4,927       273       278  
Future development costs
    2,960       89       92  
Future income tax provisions
    2,722       98       114  
                         
Future net cash flows
    5,542       319       303  
Less 10 percent annual discount for estimated timing of cash flows
    (2,728 )     (121 )     (117 )
                         
Standardized measure of discounted future net cash inflows
  $ 2,814     $ 198     $ 186  
                         
 
 
(1) Amounts attributable to a consolidated subsidiary (Apco) in which there is a 31 percent noncontrolling interest.
 
(2) Represents Apco’s 40.8% interest in Petrolera Entre Lomas S.A.


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


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Table of Contents

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

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Table of Contents

WPX Energy
 
Supplemental Oil and Gas Disclosures—(Continued)
(Unaudited)
 
                         
                Entity’s share
 
                of international
 
                equity method
 
For the Year Ended December 31, 2010
  Domestic     International(1)     investee(2)  
    (Millions)  
 
Standardized measure of discounted future net cash flows beginning of period
  $ 1,713     $ 175     $ 129  
Changes during the year:
                       
Sales of oil and gas produced, net of operating costs
    (1,446 )     (59 )     (55 )
Net change in prices and production costs
    1,921       34       43  
Extensions, discoveries and improved recovery, less estimated future costs
    724              
Development costs incurred during year
    633       26       25  
Changes in estimated future development costs
    (292 )     (12 )     (15 )
Purchase of reserves in place, less estimated future costs
    439       2        
Revisions of previous quantity estimates
    (332 )     26       63  
Accretion of discount
    220       22       17  
Net change in income taxes
    (758 )     (13 )     (20 )
Other
    (8 )     (3 )     (1 )
                         
Net changes
    1,101       23       57  
                         
Standardized measure of discounted future net cash flows end of period
  $ 2,814     $ 198     $ 186  
                         
 
 
(1) Amounts attributable to a consolidated subsidiary (Apco) in which there is a 31 percent noncontrolling interest.
 
(2) Represents Apco’s 40.8% interest in Petrolera Entre Lomas S.A.
 
In relation to the SEC rules adopted in 2009, we estimated that the domestic standardized measure of discounted future net cash flows in 2009 declined approximately $840 million on a before tax basis and excluding the overall price rule impact. The significant components of this decline included an estimated $640 million decrease included in revisions of previous quantity estimates and a related $430 million decrease included in the net change in prices and production costs, partially offset by a $210 million increase included in extensions, discoveries and improved recovery, less estimated future costs. Additionally, we estimated that a significant portion of the remaining net change in domestic price and production costs is due to the application of the new pricing rules which resulted in the use of lower prices at December 31, 2009, than would have resulted under the previous rules.

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Table of Contents

           Shares
WPX Energy, Inc.
Class A Common Stock
 
Prospectus
          , 2011
 
Barclays Capital
Citi
J.P. Morgan
 


Table of Contents

PART II
 
INFORMATION NOT REQUIRED IN PROSPECTUS
 
Item 13.   Other Expenses of Issuance and Distribution.
 
The following table sets forth the expenses (other than underwriting compensation expected to be incurred) in connection with this offering. All of such amounts (except the SEC registration fee and FINRA filing fee) are estimated.
 
                 
SEC registration fee
  $ 87,075          
FINRA filing fee
    75,500          
NYSE listing fee
    *          
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.
 
Our certificate of incorporation provides that a director will not be liable to the corporation or its stockholders for monetary damages for breach of fiduciary duty as a director to the fullest extent that the Delaware General Corporation Law (“DGCL”) or any other law of the State of Delaware permits. If the DGCL or any other law of the State of Delaware is amended to authorize the further elimination or limitation of the liability of directors, then the liability of a director will be limited to the fullest extent permitted by the amended DGCL or other law, as applicable.
 
We are empowered by Section 145 of the DGCL, subject to the procedures and limitations stated therein, to indemnify any person against expenses (including attorneys’ fees), judgments, fines, and amounts paid in settlement actually and reasonably incurred by them in connection with any threatened, pending, or completed action, suit, or proceeding in which such person is made party by reason of their being or having been a director, officer, employee, or agent of the Company. The statute provides that indemnification pursuant to its provisions is not exclusive of other rights of indemnification to which a person may be entitled under any bylaw, agreement, vote of stockholders or disinterested directors, or otherwise. Our bylaws provide for indemnification by us of our directors and officers to the fullest extent permitted by the DGCL.
 
We maintain policies of insurance under which our directors and officers are insured, within the limits and subject to the limitations of the policies, against certain expenses in connection with the defense of actions, suits, or proceedings, and certain liabilities which might be imposed as a result of such actions, suits or proceedings, to which they are parties by reason of being or having been such directors or officers.
 
Item 15.   Recent Sales of Unregistered Securities.
 
Except for the issuance of shares to Williams, we have not issued any securities in unregistered transactions. The issuance of shares to Williams was exempt from the registration requirements of the Securities Act pursuant to Section 4(2) thereof.


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Item 16.   Exhibits and Financial Statement Schedules.
 
  (a)  Exhibits
 
A list of exhibits filed as part of this registration statement is set forth in the Exhibit Index, which is incorporated herein by reference.
 
  (b)  Financial Statement Schedules
 
Schedule II—Valuation and Qualifying Accounts for the three years ended December 31, 2010, 2009 and 2008
 
SCHEDULE II—VALUATION AND QUALIFYING ACCOUNTS
 
                                         
          Charged
                   
          (Credited)
                   
    Beginning
    to Costs and
                Ending
 
    Balance     Expenses     Other     Deductions     Balance  
    (Millions)  
 
2010:
                                       
Allowance for doubtful accounts—accounts and notes receivable(a)
  $ 19     $ (4 )   $     $     $ 15  
Price-risk management credit
reserves—liabilities(b)
    (3 )     3 (d)                  
2009:
                                       
Allowance for doubtful accounts—accounts and notes receivable(a)
    25       3             (9 )(c)     19  
Price-risk management credit
reserves—assets(a)
    6       (3 )(d)     (3 )(e)            
Price-risk management credit
reserves—liabilities(b)
    (15 )     12 (d)                 (3 )
2008:
                                       
Allowance for doubtful accounts—accounts and notes receivable(a)
    14       12             (1 )(c)     25  
Price-risk management credit
reserves—assets(a)
    1       1 (d)     4 (e)           6  
Price-risk management credit reserves—liabilities(b)
          (16 )(d)     1 (e)           (15 )
 
 
(a) Deducted from related assets.
 
(b) Deducted from related liabilities.
 
(c) Represents recoveries of balances previously written off.
 
(d) Included in revenues.
 
(e) Included in accumulated other comprehensive income (loss).
 
Item 17.   Undertakings.
 
The undersigned registrant hereby undertakes that:
 
(1) The undersigned will provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.
 
(2) For purposes of determining any liability under the Securities Act of 1933, as amended, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1)


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


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Signatures
 
Pursuant to the requirements of the Securities Act of 1933, the registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Tulsa, State of Oklahoma, on April 29, 2011.
 
WPX ENERGY, INC.
(Registrant)
 
  By: 
/s/  Ralph A. Hill
Ralph A. Hill
Chief Executive Officer
 
KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears below hereby constitutes and appoints Ralph A. Hill and James. J. Bender, and each of them, his true and lawful attorney-in-fact and agent, with full power of substitution and resubstitution, for him and in his name, place, and stead in any and all capacities, to sign this registration statement on Form S-1 filed by WPX Energy, Inc. pursuant to the Securities Act of 1933, as amended (the “Securities Act”), and any and all amendments to this registration statement (including post-effective amendments and registration statements filed pursuant to Rule 462(b) under the Securities Act, and otherwise), and to file the same, with all exhibits thereto and all other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done to the end that such registration statement or registration statements shall comply with the Securities Act and the applicable rules and regulations adopted or issued pursuant thereto, as fully and to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them or their substitutes or resubstitutes, may lawfully do or cause to be done by virtue hereof.
 
Pursuant to the requirements of the Securities Act of 1933, this registration statement has been signed below by the following persons in the capacities and on the dates indicated:
 
             
         
Date: April 29, 2011
  By:  
/s/  Ralph A. Hill
Ralph A. Hill, Chief Executive Officer(Principal Executive Officer)
         
Date: April 29, 2011
  By:  
/s/  Donald R. Chappel
Donald R. Chappel, Chief Financial Officer
(Principal Financial Officer)
         
Date: April 29, 2011
  By:  
/s/  Ted T. Timmermans
Ted T. Timmermans, Chief Accounting Officer
(Principal Accounting Officer)
         
Date: April 29, 2011
  By:  
/s/  Alan S. Armstrong
Alan S. Armstrong, Chairman of the Board


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EXHIBIT INDEX
 
         
Exhibit No.
 
Description
 
  1 .1*   Form of Underwriting Agreement
  3 .1*   Form of Amended and Restated Certificate of Incorporation of WPX Energy, Inc.
  3 .2*   Form of Amended and Restated Bylaws of WPX Energy, Inc.
  4 .1*   Form of Specimen Class A Common Stock Certificate
  4 .2*   Form of Specimen Class B Common Stock Certificate
  5 .1*   Opinion of Gibson, Dunn & Crutcher LLP
  10 .1*   Form of Separation and Distribution Agreement
  10 .2*   Form of Administrative Services Agreement
  10 .3*   Form of Transition Services Agreement
  10 .4*   Form of Tax Sharing Agreement
  10 .5*   Form of Registration Rights Agreement
  10 .6*   Form of Credit Agreement
  21 .1*   List of Subsidiaries
  23 .1*   Consent of Gibson, Dunn & Crutcher LLP (included in Exhibit 5.1)
  23 .2   Consent of Ernst & Young LLP
  23 .3   Consent of Independent Petroleum Engineers and Geologists, Netherland, Sewell & Associates, Inc.
  23 .4   Consent of Independent Petroleum Engineers and Geologists, Miller and Lents, Ltd.
  23 .5   Consent of Independent Petroleum Engineers, Ralph E. Davis Associates, Inc.
  24 .1   Powers of Attorney (included on signature page to this 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.
 
 
* To be filed by amendment