sv1

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

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


(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.

Subject to Completion, dated April 29, 2011

PROSPECTUS

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

TABLE OF CONTENTS


	Page

CERTAIN DEFINITIONS		iii
PROSPECTUS SUMMARY		1
RISK FACTORS		17
FORWARD-LOOKING STATEMENTS		44
USE OF PROCEEDS		46
DIVIDEND POLICY		47
CAPITALIZATION		48
DILUTION		49
SELECTED HISTORICAL COMBINED FINANCIAL DATA		50
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		51
BUSINESS		70
MANAGEMENT		96
EXECUTIVE COMPENSATION		99
PRINCIPAL STOCKHOLDER		126
ARRANGEMENTS BETWEEN WILLIAMS AND OUR COMPANY		127
OTHER RELATED PARTY TRANSACTIONS		134
DESCRIPTION OF OUR CONCURRENT FINANCING TRANSACTIONS		136
DESCRIPTION OF CAPITAL STOCK		137
SHARES ELIGIBLE FOR FUTURE SALE		144
CERTAIN U.S. FEDERAL INCOME TAX CONSIDERATIONS		146
UNDERWRITING		150
LEGAL MATTERS		157
EXPERTS		157
WHERE YOU CAN FIND MORE INFORMATION		157
INDEX TO FINANCIAL STATEMENTS		F-1
EX-23.2
EX-23.3
EX-23.4
EX-23.5
EX-99.1
EX-99.2
EX-99.3

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.

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.

iii

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


		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.

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.

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.

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

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.


	•	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.

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.”

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.


	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.


	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.

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.

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

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

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;


	•	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.

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

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.

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

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.

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.

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

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.

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


	•	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,

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

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

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.

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

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

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

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;


	•	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.

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

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.

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

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;


	•	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.


	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.

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

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.

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;


	•	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.”

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.

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.”

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.

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.

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

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

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.

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

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.

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.

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.

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.


	•	$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

$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.

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.

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.

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

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

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.

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

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

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

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.

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.

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.


(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


	•	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.

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.

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


		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.

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

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

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.

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.

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.

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.

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

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.

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

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.


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.”


	•	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.