Edgar Filing: APACHE CORP

Form 10-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

[X]

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

For the fiscal year ended December 31, 2011

[ ]

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

For the transition period from to

Commission file number 1-4300

APACHE CORPORATION

(Exact name of registrant as specified in its charter)


Delaware		41-0747868
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

One Post Oak Central, 2000 Post Oak Boulevard, Suite 100, Houston, Texas 77056-4400

(Address of principal executive offices)

Registrant’s telephone number, including area code (713) 296-6000

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


Title of each class		Name of each exchange on which registered

Common Stock, $0.625 par value		New York Stock Exchange, Chicago Stock Exchange
		and NASDAQ National Market

Preferred Stock Purchase Rights		New York Stock Exchange and Chicago Stock Exchange

Apache Finance Canada Corporation		New York Stock Exchange
7.75% Notes Due 2029
Irrevocably and Unconditionally
Guaranteed by Apache Corporation

Depositary Shares Representing a 1/20^th Interest in a Share of 6.00% Mandatory Convertible Preferred Stock, Series D		New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: Common Stock, $0.625 par value

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

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Yes [ ] No [X]

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes [X] No [ ]

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

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 [X] Accelerated filer [ ] Non-accelerated filer [ ] Smaller reporting company [ ]

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act): Yes [ ] No [X]


Aggregate market value of the voting and non-voting common equity held by non-affiliates of registrant as of June 30, 2011	$	47,361,451,733
Number of shares of registrant’s common stock outstanding as of January 31, 2012		384,321,970

Documents Incorporated By Reference

Portions of registrant’s proxy statement relating to registrant’s 2012 annual meeting of stockholders have been incorporated by reference in Part II and Part III of this annual report on Form 10-K.

TABLE OF CONTENTS

DESCRIPTION


Item		Page
	PART I

1.	BUSINESS		1
1A.	RISK FACTORS		23
1B.	UNRESOLVED STAFF COMMENTS		34
2.	PROPERTIES		1
3.	LEGAL PROCEEDINGS		34
4.	MINE SAFETY DISCLOSURES		34

	PART II

5.	MARKET FOR THE REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES		35
6.	SELECTED FINANCIAL DATA		37
7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		38
7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		68
8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA		71
9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE		71
9A.	CONTROLS AND PROCEDURES		71
9B.	OTHER INFORMATION		71

	PART III

10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE		72
11.	EXECUTIVE COMPENSATION		72
12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS		72
13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE		72
14.	PRINCIPAL ACCOUNTING FEES AND SERVICES		72

	PART IV

15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES		73

DEFINITIONS

All defined terms under Rule 4-10(a) of Regulation S-X shall have their statutorily prescribed meanings when used in this report. As used in this document:

“3-D” means three-dimensional.

“4-D” means four-dimensional.

“b/d” means barrels of oil or natural gas liquids per day.

“bbl” or “bbls” means barrel or barrels of oil.

“bcf” means billion cubic feet.

“boe” means barrel of oil equivalent, determined by using the ratio of one barrel of oil or NGLs to six Mcf of gas.

“boe/d” means boe per day.

“Btu” means a British thermal unit, a measure of heating value.

“LIBOR” means London Interbank Offered Rate.

“LNG” means liquefied natural gas.

“Mb/d” means Mbbls per day.

“Mbbls” means thousand barrels of oil.

“Mboe” means thousand boe.

“Mboe/d” means Mboe per day.

“Mcf” means thousand cubic feet of natural gas.

“Mcf/d” means Mcf per day.

“MMbbls” means million barrels of oil.

“MMboe” means million boe.

“MMBtu” means million Btu.

“MMBtu/d” means MMBtu per day.

“MMcf” means million cubic feet of natural gas.

“MMcf/d” means MMcf per day.

“NGL” or “NGLs” means natural gas liquids, which are expressed in barrels.

“NYMEX” means New York Mercantile Exchange.

“oil” includes crude oil and condensate.

“PUD” means proved undeveloped.

“SEC” means United States Securities and Exchange Commission.

“Tcf” means trillion cubic feet.

“U.K.” means United Kingdom.

“U.S.” means United States.

With respect to information relating to our working interest in wells or acreage, “net” oil and gas wells or acreage is determined by multiplying gross wells or acreage by our working interest therein. Unless otherwise specified, all references to wells and acres are gross.

PART I

ITEMS 1 AND 2. BUSINESS AND PROPERTIES

This Annual Report on Form 10-K and the documents incorporated herein by reference contain forward-looking statements based on expectations, estimates, and projections as of the date of this filing. These statements by their nature are subject to risks, uncertainties, and assumptions and are influenced by various factors. As a consequence, actual results may differ materially from those expressed in the forward-looking statements. See Part II, Item 7A—Quantitative and Qualitative Disclosures About Market Risk—Forward-Looking Statements and Risk of this Form 10-K.

General

Apache Corporation, a Delaware corporation formed in 1954, is an independent energy company that explores for, develops, and produces natural gas, crude oil, and natural gas liquids. We currently have exploration and production interests in six countries: the U.S., Canada, Egypt, Australia, offshore the U.K. in the North Sea (North Sea), and Argentina. Apache also pursues exploration interests in other countries that may over time result in reportable discoveries and development opportunities. We treat all operations as one line of business.

Our common stock, par value $0.625 per share, has been listed on the New York Stock Exchange (NYSE) since 1969, on the Chicago Stock Exchange (CHX) since 1960, and on the NASDAQ National Market (NASDAQ) since 2004. On May 20, 2011, we filed certifications of our compliance with the listing standards of the NYSE and the NASDAQ, including our principal executive officer’s certification of compliance with the NYSE standards. Through our website, www.apachecorp.com, you can access, free of charge, electronic copies of the charters of the committees of our Board of Directors, other documents related to our corporate governance (including our Code of Business Conduct and Governance Principles) and documents we file with the SEC, including our annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, as well as any amendments to these reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934. Included in our annual and quarterly reports are the certifications of our principal executive officer and our principal financial officer that are required by applicable laws and regulations. Access to these electronic filings is available as soon as reasonably practicable after we file such material with, or furnish it to, the SEC. You may also request printed copies of our committee charters or other governance documents free of charge by writing to our corporate secretary at the address on the cover of this report. Our reports filed with the SEC are also made available to read and copy at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C., 20549. You may obtain information about the Public Reference Room by contacting the SEC at 1-800-SEC-0330. Reports filed with the SEC are also made available on its website at www.sec.gov. From time to time, we also post announcements, updates, and investor information on our website in addition to copies of all recent press releases.

Properties to which we refer in this document may be held by subsidiaries of Apache Corporation. References to “Apache” or the “Company” include Apache Corporation and its consolidated subsidiaries unless otherwise specifically stated.

Growth Strategy

Apache’s mission is to grow a profitable global exploration and production company in a safe and environmentally responsible manner for the long-term benefit of our shareholders. Apache’s long-term perspective has many dimensions, which are centered on the following core strategic components:

•

balanced portfolio of core assets

•

conservative capital structure

•

rate of return focus

Throughout the cycles of our industry, these strategies have underpinned our ability to deliver long-term production and reserve growth and achieve competitive returns on invested capital for the benefit of our shareholders. We have increased reserves 23 out of the last 26 years and production 31 out of the past 33 years, a testament to our consistency over the long-term.

Apache pursues opportunities for growth through exploration and development drilling, supplemented by strategic acquisitions. In 2011, we generated approximately $10 billion of cash flows from operations, which enabled us to deliver on an aggressive capital budget investing approximately $8 billion across all of our regions, while paying down nearly $1 billion in debt. Approximately one-quarter of our global capital was spent on leasehold acreage, seismic data, gathering and processing facilities, long-lead development projects, and front-end engineering and design (FEED) studies tied to our LNG projects. Coupled with an active drilling program and an increasing new venture exploration effort, these longer-term investments secure a platform for continued long-term profitable growth.

We have also been significantly active in the acquisition market for the past two years, having identified several opportunities that met our criteria for risk, reward, rate of return, and growth potential. As we head into 2012, Apache continues to be active with recent acquisition announcements in Australia and the Anadarko basin of the central U.S. Each of our acquisitions fit well with our long-term strategy of maintaining a balanced portfolio of core assets by adding high-quality properties with a diversity of geologic and geographic risk, product mix, and reserve life to nearly all of our regions. The properties are strategically positioned with our existing infrastructure and play to the strengths that come with our operating experience.

2012 Acquisitions

Australian Burrup Holdings Limited acquisition On January 31, 2012, a subsidiary of Apache Energy Limited completed the acquisition of a 49-percent interest in Burrup Holdings Limited (BHL) for $439 million, including working capital adjustments. BHL is the owner of an ammonia fertilizer plant on the Burrup Peninsula of Western Australia.

Central Anadarko basin acquisition Apache announced in January 2012 that we agreed to acquire Cordillera Energy Partners III LLC (Cordillera), a privately held company, for $2.2 billion in cash and approximately 6.3 million shares of Apache common stock. The merger is expected to close in the second quarter of 2012.

2011 Acquisitions

North Sea acquisition On December 30, 2011, Apache completed the acquisition of Mobil North Sea Limited (Mobil North Sea) from Exxon Mobil Corporation with cash consideration of $1.25 billion.

2010 Acquisitions

Gulf of Mexico Shelf acquisition On June 9, 2010, Apache completed the acquisition of oil and gas assets in the Gulf of Mexico shelf from Devon Energy Corporation for $1.05 billion.

Mariner merger On November 10, 2010, Apache completed the acquisition of Mariner Energy, Inc. (Mariner) for stock and cash consideration totaling $2.7 billion. We also assumed approximately $1.7 billion of Mariner’s debt with the merger.

Permian acquisition On August 10, 2010, we completed the acquisition of BP plc’s (BP) oil and gas operations, acreage, and infrastructure in the Permian Basin for $2.5 billion, net of preferential rights to purchase.

Canadian acquisition On October 8, 2010, we completed the acquisition of substantially all of BP’s upstream natural gas business in western Alberta and British Columbia for $3.25 billion.

Egyptian acquisition On November 4, 2010, we completed the acquisition of BP’s assets in Egypt’s Western Desert for $650 million.

In the midst of our heightened exploration, development drilling, and acquisition activity, we have remained committed to our core strategies of maintaining a balanced portfolio, conservative capital structure, and rate of return focus.

Balanced Portfolio of Core Assets

A cornerstone of our long-term strategy is balancing our portfolio of assets through diversity of geologic risk, geographic risk, hydrocarbon mix (crude oil versus natural gas), and reserve life in order to achieve consistency in results. Our portfolio of geographic locations provides variation of all of these factors. We have exploration and production operations in six countries, through ten distinct regions: the Gulf of Mexico Shelf, Gulf of Mexico Deepwater, Gulf Coast Onshore, Permian, and Central regions of the U.S., Canada, Egypt, the U.K. North Sea, Australia, and Argentina.

Each of our regions has achieved an economy of scale providing a vehicle for cost-effective base production and a combination of low- and medium-risk drilling opportunities. The net cash provided by operating activities (cash flows) generated by our current production base funds our worldwide exploitation and drilling program and development capital for prior exploration discoveries. In addition, a portion of our cash flows generated each year is allocated to pursue new exploration targets over our 28 million gross undeveloped acres and new areas around the globe. Our continued diligence on allocating capital across multiple regions and various projects has produced a balanced portfolio of assets that consistently delivers positive cash flows and has become a foundation for future growth opportunities.

In 2011:

•

No single region contributed more than 22 percent of our equivalent production or 29 percent of revenue.

•

No single region held more than 26 percent of our year-end estimated proved reserves.

•

The mixture of reserve life (estimated reserves divided by annual production) in our regions, which offers a balance in timing of investment returns, ranges from five years to 22 years.

•

Our balanced product mix provides a measure of protection against price deterioration in a given product while retaining upside potential in the event of a significant increase in the commodity price for either product. In 2011, crude oil and liquids provided 50 percent of our production and 79 percent of our revenue.

•

International Dated Brent crudes and sweet crude from the Gulf Coast, which represent 76 percent of our crude oil production, continue to be priced at a significant premium to West Texas Intermediate (WTI)-based prices.

•

Our international gas portfolio, which accounted for 34 percent of our 2011 worldwide natural gas production, positions us to take advantage of increasing prices in Argentina and Australia while North American gas prices continue to languish.

Conservative Capital Structure

Maintaining a strong balance sheet and the financial flexibility it provides is a core component of our long-term strategy and we believe one of our most important strategic assets. This approach underpins our ability to weather commodity price volatility and has enabled us to deliver long-term production and reserves growth throughout the cycles of our industry. It is also key in positioning us to pursue value-creating acquisitions when opportunities arise.

During 2011, we met our objectives to fund our exploration and development capital with operating cash flows and to reduce the Company’s debt to $7.2 billion. Specifically, we exited the year with a debt-to-capitalization ratio of 20 percent, down from 25 percent at year-end 2010. In addition, as of December 31, 2011, we had access to $3.3 billion of available committed borrowing capacity, up from $2.4 billion at year-end 2010.

Rate of Return Focus

Another core component to our long-term strategy is focusing on rate of return. We do so through centralized management and incentive systems, decentralized decision making, cost control focus, and the creative application of technology.

Our centralized management and incentive systems provide a uniform process of measuring success across Apache and has instilled a rate-of-return focus into our culture. Our organizational structure incentivizes high rate-of-return activities but allows for appropriate risk-taking to drive future growth and monetize reserves. Results of operations and rate of return on invested capital are measured monthly, reviewed with management quarterly, and utilized to determine annual performance awards. We review capital allocations, at least quarterly, utilizing estimates of internally generated cash flows. We do this through a disciplined and focused process that includes analyzing current economic conditions, projected rate of return on internally generated drilling prospects, opportunities for tactical acquisitions, land positions with additional drilling prospects and occasionally, new core areas that could enhance our portfolio.

We also use technology to reduce risk, decrease time and costs, and maximize recoveries from reservoirs. Apache scientists and engineers have been granted numerous patents for a range of inventions, from systems used for interpreting seismic data and processing well logs to improvements in drilling and completion techniques.

For a more in-depth discussion of our 2011 results and the Company’s capital resources and liquidity, please see Part II, Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations of this Form 10-K.

Geographic Area Overviews

We currently have exploration and production interests in six countries: the U.S., Canada, Egypt, Australia, offshore the U.K. in the North Sea, and Argentina.

The following table sets out a brief comparative summary of certain key 2011 data for each of our operating areas. Additional data and discussion is provided in Part II, Item 7 of this Form 10-K.


	2011 Production		Percentage of Total 2011 Production		2011 Production Revenue		12/31/11 Estimated Proved Reserves		Percentage of Total Estimated Proved Reserves		2011 Gross Wells Drilled		2011 Gross Productive Wells Drilled
	(In MMboe)				(In millions)		(In MMboe)
United States		104.3		38%	$	6,104		1,290		43%		702		671
Canada		45.9		17		1,617		764		26		143		131

Total North America		150.2		55		7,721		2,054		69		845		802


Egypt		60.2		22		4,791		292		10		177		147
Australia		25.2		9		1,734		330		11		9		5
North Sea		20.0		7		2,091		197		6		14		11
Argentina		17.5		7		473		117		4		42		40

Total International		122.9		45		9,089		936		31		242		203

Total		273.1		100%	$	16,810		2,990		100%		1,087		1,005

North America

Apache’s North American asset base primarily comprises operations in the Permian Basin, the central U.S., the Gulf Coast areas of the U.S. and operations in Western Canada. In 2011, our North America assets contributed 55 percent of our production and 46 percent of our oil and gas production revenues. At year-end 2011, 69 percent of our estimated proved reserves were located in North America.

United States

Overview We have 10.3 million gross acres across the U.S., approximately half of which is undeveloped. As a result of recent acquisitions and a diversity of growth and opportunity profiles, we divided our U.S. assets into five regions: Permian, Central, Gulf of Mexico Shelf, Gulf of Mexico Deepwater, and Gulf Coast Onshore. We also have leasehold acreage holdings in Alaska. Our holdings in the U.S. provide a balance of hydrocarbon mix and reserve life and an opportunity for continued exploration. In 2011, 50 percent of our U.S. production and 62 percent of our U.S. year-end reserves were oil and liquids. In addition, the reserve life of our U.S. regions ranged from five to 22 years with the Gulf of Mexico offshore region’s shorter-lived reserves balancing longer-lived reserves in the Central and Permian regions. In 2011, 38 percent of Apache’s equivalent production and 43 percent of Apache’s total year-end reserves were in the U.S.

Gulf Coast Regions Our Gulf Coast assets are primarily located in and along the Gulf of Mexico, in the areas onshore and offshore Texas, Louisiana, Alabama, and Mississippi. Recent acquisitions have significantly increased Apache’s presence in the area and have bolstered an already deep inventory of projects with additional development and exploration opportunities for multiple years. The area is divided into three regions, which include the Gulf of Mexico Shelf, Gulf of Mexico Deepwater, and Gulf Coast Onshore.

In water less than 500 feet deep, which constitutes most of our Gulf of Mexico Shelf region, Apache is currently the largest producer and has been the largest offshore held-by-production acreage owner since 2004. The Gulf of Mexico Shelf region has approximately 3 million gross acres covering 622 offshore blocks with nearly 80 percent of the blocks held-by-production. The region contributed 14 percent of our worldwide production and 15 percent of worldwide revenue during 2011. With prolific wells, strong cash flows, and a strategic position near the petrochemical-industrial complex on the U.S. Gulf Coast, the region has consistently generated high rates of return allowing the region to play a vital role in funding investments in other regions. Although regulations issued in 2010 have slowed the issuance of drilling permits for all operators, during 2011 the region drilled or participated in 35 wells with a 71-percent success rate. We drilled 36 wells in 2010 and 20 wells in 2009.

In water greater than 500 feet deep, the Gulf of Mexico Deepwater region is a relatively underexplored and oil prone area that provides exposure to significant reserve and production potential. Apache’s strategic presence in the area was gained through the 2010 Mariner merger, and the Company now owns approximately 750,000 gross acres across 148 blocks as of the end of 2011. The Deepwater region contributed approximately two percent of Apache’s worldwide production; however, there are multiple projects underway. The Bushwood, Wide Berth, and Mandy development projects are projected to begin production in the second quarter of 2012 with combined net initial production of 12 Mboe/d. In addition, the larger scale non-operated Lucius project was sanctioned in the fourth quarter of 2011. Apache has an 11.7-percent working interest in this development with first production projected for 2014. The region is also increasing its exploration activity, having recently been awarded four deepwater exploration plans. We expect to drill or participate in drilling nine wells during 2012 compared to two wells drilled in the current year.

Apache’s Gulf Coast Onshore region was established in August 2010 to more fully exploit the opportunities built over the years in onshore areas of Texas, Louisiana, and Mississippi. The region has a significant acreage position of approximately 1.4 million gross acres, including 330,000 mineral fee acres. During the year, the region focused on drilling shallow and moderate depth targets, increasing acreage holdings, and expanding our

regional 3-D seismic databases. We are also evaluating several unconventional resource opportunities. The region drilled or participated in drilling 50 wells during 2011 and projects drilling approximately 40 wells in 2012, including increased activity in unconventional and deeper exploitation.

In 2012, the Company plans to invest approximately $1.0 billion, $500 million, and $350 million in the Gulf of Mexico Shelf, Gulf of Mexico Deepwater, and Gulf Coast Onshore regions, respectively. The capital will be spent on drilling, recompletion, and development projects, equipment upgrades, production enhancement projects, seismic acquisitions, and plugging and abandonment of wells and platforms. We spent $363 million on abandonment activities in 2011 over the entire Gulf Coast area.

Central Region The Central region includes more than 2,500 producing wells and controls over one million gross acres primarily in western Oklahoma and the Texas panhandle. Most of the region’s acreage is held-by-production. The region’s reserves and production are primarily natural gas; however, a transformation from vertical to horizontal drilling has evolved over the last two years, and the region is now targeting oil and liquids-rich gas plays given the continued price disparity between oil and gas. The result of focusing on oil and liquid plays was evident during 2011 with oil production nearly doubling and NGL production up 244 percent compared to the prior year. Total region production was up 14 percent as we drilled or participated in drilling 108 wells, 94 percent being completed as producers. The region’s year-end 2011 estimated proved reserves represented five percent of Apache’s worldwide total.

The primary target for the region’s liquids-focused objective has been in the Anadarko basin’s Granite Wash play, with 50 wells brought on production during 2011. Thirty-three of these were operated wells that had average 30-day gross rates of approximately 500 b/d and 4.5 MMcf/d. The Granite Wash consists of a series of thick, multi-layered formations of low-permeability and liquids-rich sandstones. We have operated in this area for 50 years drilling vertical wells, but the play has recently re-emerged as a horizontal drilling play with multi-staged fracturing technology. We drilled our first operated horizontal well in the Granite Wash in 2009 and have continued to pursue cost efficiencies and reduce drilling time.

The region has also increased its focus on oil plays in the Anadarko shelf Cherokee formation and the Texas Panhandle Cleveland formation. In 2011, we drilled 12 wells in the Cherokee formation and 10 wells in the Cleveland formation with an average 30-day gross production rate of 350 b/d and 500 Mcf/d.

With its growing success in oil and liquids-rich gas plays, the region has been active on the acquisition and divestiture front. In March 2011, Apache acquired 92,400 net acres in the Whittenburg basin of Oldham County, Texas, which is emerging as a potential new oil play for Apache. The acreage is immediately south of the Panhandle Dolomite field and directly north of two 25-well Canyon Wash fields. For 2012, the region plans to increase its Whittenburg activity level to include horizontal drilling and has recently completed the acquisition of 244 square miles of 3-D seismic data. Separately, in 2011 the region divested its natural gas properties in east Texas. The divestiture, which was completed in December 2011, included dry gas wells that were producing approximately 31 MMcf/d net to Apache.

In January 2012, the Company announced entry into a merger agreement to acquire Cordillera, a privately held company with approximately 254,000 net acres in the Granite Wash play, nearly 18 Mboe/d of current production, and estimated proved reserves of 71.5 MMboe. This doubles Apache’s acreage in the Granite Wash area and adds a robust drilling inventory that will be immediately integrated into our existing plans. The merger is expected to be completed in the second quarter of 2012 and allows for Cordillera to acquire up to $100 million in additional leasehold acreage in the Granite Wash and other plays through closing.

With the recent completed and pending acquisitions, the region plans to double its activity in 2012. The region plans to invest approximately $800 million in drilling, recompletions, equipment upgrades, production enhancement projects, and lease acquisitions.

Permian Region Our Permian region controls over three million gross acres with exposure across the Permian Basin. The region’s property and acreage base increased substantially after completing the 2010 BP acquisition and Mariner merger, and integrating these assets was a key focus during 2011. Apache is now one of the largest operators in the Permian Basin, operating more than 12,000 wells in 152 fields, including 45 waterfloods and six CO2 floods. Total region production was up over 38 percent sequentially as a result of the prior-year acquisitions and a drilling program that is continuing to ramp up. We averaged running 25 rigs during the year, drilling or participating in 507 wells. Only two dry holes were drilled, including a non-operated well. The Permian region’s year-end 2011 estimated proved reserves were 751 MMboe and represent 25 percent of Apache’s total proved reserves.

The key focus areas of our activity during the year continued to be the horizontal redevelopment of legacy waterflood units and the multi-zone development of the Deadwood area. Deadwood is the most active of our plays in the Permian Basin where we ran an average of 11 rigs and drilled 195 wells. Gross oil production in Deadwood exceeded 8 Mb/d and 17 MMcf/d at the end of the year, which compares with 2 Mb/d and 6 MMcf/d at the beginning of the year. Our gas volumes plateaued in this area in the fourth quarter because of midstream constraints. In order to increase capacity in 2012, the region began construction in the third-quarter 2011 on a natural gas processing facility in a 50-percent joint venture with Crosstex Energy, L.P. We expect to drill over 300 wells in Deadwood during 2012, and we have an inventory of approximately 1,000 additional vertical locations across multiple formations and stacked pay zones on 20-acre spacing.

Apache continued horizontal redevelopment of its waterflood units during 2011 with the drilling of 38 operated horizontal wells. Seven fields were tested with a 100-percent success rate. Three of these fields are under full horizontal development with the remaining fields in the testing phase. The region has identified an additional 23 major waterflood units and fields to be developed horizontally.

The Permian region is building a large inventory of other horizontal opportunities based on success achieved during 2011 along with the continued integration of the prior year BP acquisition and Mariner merger. As we head into 2012, the Company continues to advance several plays, including Bone Springs, Wolfcamp Shale, Cline Shale, and off-structure Grayburg formations. Given a current inventory of over 10,000 locations, the region has a strong portfolio of drilling opportunities for multiple years. For 2012, the Permian region plans to invest approximately $1.7 billion in drilling, recompletion projects, equipment upgrades, expansion of existing facilities and equipment, and leasing new acreage.

U.S. Marketing In general, most of our U.S. gas is sold at either monthly or daily market prices. Our natural gas is sold primarily to local distribution companies (LDCs), utilities, end-users, and integrated major oil companies. We maintain a diverse client portfolio, which is intended to reduce the concentration of credit risk.

Apache primarily markets its U.S. crude oil to integrated major oil companies, marketing and transportation companies, and refiners. The objective is to maximize the value of crude oil sold by identifying the best markets and most economical transportation routes available to move the product. Sales contracts are generally 30-day evergreen contracts that renew automatically until canceled by either party. These contracts provide for sales that are priced daily at prevailing market prices.

Apache’s NGL production is sold under contracts with prices based on market indices, less the costs for transportation and fractionation, or on a weighted-average sales price received by the purchaser.

Canada

Overview Apache has 7.5 million gross acres across the provinces of British Columbia, Alberta, and Saskatchewan. Our acreage base provides a significant inventory of both low-risk development drilling opportunities in and around a number of Apache fields and higher-risk, higher-reward exploration opportunities. At year-end 2011, our Canadian region represented approximately 26 percent of our estimated proved reserves. In 2011, we drilled or participated in 143 wells in Canada.

Our conventional oil assets comprise a wide variety of opportunities from Southeast Saskatchewan to Northwest Alberta. An increased focus on these assets during 2011 resulted in drilling 70 wells, enabling us to take advantage of current strong oil price realizations. We utilized advanced reservoir modeling and horizontal drilling technology to identify and exploit unswept oil in existing waterflood projects in the House Mountain, Leduc, Snipe Lake, and Provost areas. Additionally, we continued efforts on our enhanced oil recovery project at Midale with expansion of CO2 injection and assessment of new seismic data.

In the Kaybob and West 5 areas, the region continues to have success in the development of liquids-rich natural gas plays. These areas have focused primarily on the Bluesky, Montney, and Glauconite formations through horizontal drilling and multi-stage fracture completions. In addition, drilling costs have been driven down throughout the year. Horizontal oil plays in the Viking, Dunvegan, and Cardium formations are emerging, and we expect to further develop these opportunities as part of our 2012 drilling program.

The region’s near-term natural gas drilling activity will likely be focused in three large growth plays in British Colombia: shale gas in the Horn River basin, Cadomin conglomerates and sands in the Noel area, and fractured reservoirs in the Ojay area. Drilling activity focused on natural gas will be driven by investment decisions surrounding Apache’s ownership in the Kitimat LNG facility. Apache Canada Ltd., Encana Corporation, and EOG Resources Canada, Inc. plan to build the Kitimat LNG facility on Bish Cove near the Port of Kitimat, 400 miles north of Vancouver, British Columbia. The facility is planned for an initial minimum capacity of 700 MMcf/d, or approximately five million metric tons of LNG per year, of which Apache has reserved 40 percent. A proposed 287-mile pipeline will also be constructed that will originate in Summit Lake, British Columbia, and is designed to link the Kitimat LNG facility to the pipeline system currently servicing western Canada’s natural gas producing regions. Significant progress was made throughout the year to advance the LNG project. In October 2011, Apache and its partners in the Kitimat LNG project announced that the National Energy Board granted the project a 20-year export license to ship LNG from Canada to international markets. This export approval represents a major milestone for Kitimat LNG and its partners. In addition, the Company progressed with the FEED study and continued efforts to secure firm sales commitments and required permits necessary to make a final investment decision on the LNG project.

In 2012, the Canadian region plans to drill 170 wells, investing approximately $700 million in drilling and development projects, equipment upgrades, production enhancement projects, and seismic acquisition.

Marketing Our Canadian natural gas marketing activities focus on sales to LDCs, utilities, end-users, integrated major oil companies, supply aggregators, and marketers. We maintain a diverse client portfolio, which is intended to reduce our concentration of credit risk in our portfolio. To diversify our market exposure, we transport natural gas via firm transportation contracts to California and the Chicago area. We sell the majority of our Canadian gas on a monthly basis at either first-of-the-month or daily prices.

Canadian crude oil production is sold to integrated major companies, refiners, and marketing companies based on a WTI price, adjusted for quality, transportation, and a market-reflective negotiated differential. We maximize the value of our condensate and heavier crudes by determining whether to blend the condensate into our own crude production or sell it in the market as a segregated product. The crude is transported from Western Canada to the market hubs in Alberta and Manitoba, which allows for a more diversified group of purchasers and a higher netback price.

The region’s NGL production is sold under contracts with prices based on market indices, less the costs for transportation and fractionation, or on a weighted-average sales price received by the purchaser.

International

Apache’s international assets are located in Egypt, Australia, offshore the U.K. in the North Sea, and Argentina. In 2011, international assets contributed 45 percent of our production and 54 percent of our oil and gas revenues. At year-end 2011, 31 percent of our estimated proved reserves were located outside North America.

Egypt

Overview Our commitment to Egypt began in 1994 with our first Qarun discovery well. Today we control 9.7 million gross acres making Apache the largest acreage holder in Egypt’s Western Desert. Only 18 percent of our gross acreage in Egypt has been developed, with gross production of 217 Mb/d and 865 MMcf/d in 2011, or 104 Mb/d and 365 MMcf/d net to Apache. We believe this makes Apache the largest producer of liquid hydrocarbons and natural gas in the Western Desert and the third largest in all of Egypt. The remaining 82 percent of our acreage is undeveloped, providing us with considerable exploration and development opportunities for the future. We have 3-D seismic covering over 12,000 square miles, or 78 percent of our acreage. In 2011, the region contributed 29 percent of Apache’s worldwide production revenue, 22 percent of our worldwide production, and 10 percent of our year-end 2011 estimated proved reserves. Our estimated proved reserves in Egypt are reported under the economic interest method and exclude the host country share reserves.

Our operations in Egypt are conducted pursuant to production-sharing agreements in 24 separate concessions, under which the contractor partner pays all operating and capital expenditure costs for exploration and development. Development leases within concessions generally have a 25-year life, with extensions possible for additional commercial discoveries or on a negotiated basis, and currently have expiration dates ranging from five to 25 years. A percentage of the production on development leases, usually up to 40 percent, is available to the contractor partners to recover operating and capital expenditure costs, with the balance generally allocated between the contractor partners and Egyptian General Petroleum Corporation (EGPC) on a contractually defined basis.

Apache’s Egyptian operations continue to expand further into the Western Desert and achieved a record for annual production in 2011. Compared to the prior year, gross daily production was up 12 percent, and net daily production was up two percent. Throughout 2011, we maintained an active drilling and development program, drilling 221 exploration, development, and injector wells, resulting in 33 new field discoveries. Most notably, we drilled the first Paleozoic discovery at Tayim West, which test-flowed at 3,600 b/d. This Paleozoic discovery opens a new play deeper than previous discoveries in the Western Desert and provides for continued exploration opportunities. We also made our first discovery in the Siwa Concession, our westernmost concession in Egypt, with the Siwa D-1X well that test-flowed at 4,490 b/d and 8 MMcf/d.

Building on prior year discoveries, we continued our drilling success in the Faghur basin having ten new field discoveries in the year that tested in aggregate over 33 Mb/d and 25 MMcf/d. These wells are the most recent in a series of oil discoveries in the Alam El Buieb (AEB), Safa, and now Paleozoic reservoirs that support the multi-pay potential of the oil prone basin. We also started to actively drill on acreage acquired in the 2010 BP acquisition. We drilled 21 successful wells on this acreage and have increased gross production by over 7 Mb/d and 39 MMcf/d. In addition to the increased drilling activity, we continue to assess opportunities to leverage existing processing and transportation infrastructure at the BP-acquired Abu Gharadig field complex and expand our processing facilities in the Faghur and Matruh basins. Maintaining and increasing infrastructure capacity is a critical component to our growth goals in the Western Desert.

Heading into 2012, the region plans to invest approximately $1.0 billion for drilling, recompletion projects, development projects, equipment upgrades, production enhancement projects, and seismic acquisition. Our drilling program includes a combination of development and exploration wells with current plans to drill approximately 20 percent more wells than in 2011.

Egypt political unrest In February 2011, former Egyptian president Hosni Mubarak stepped down, and the Egyptian Supreme Council of the Armed Forces took power. In November 2011, Egypt held its first round of parliamentary elections. Despite the Muslim Brotherhood’s Freedom and Justice Party’s victory in the parliamentary elections, Egypt remains under martial law. Although Egypt’s first post-revolutionary parliament convened on January 23, 2012, the new Parliament remains subordinate to the Egyptian Supreme Council of the Armed Forces, which has stated its intention to turn over power to civilians following the presidential election

expected in June 2012. Apache’s operations, located in remote locations in the Western Desert, have continued uninterrupted; however, a deterioration in the political, economic, and social conditions or other relevant policies of the Egyptian government, such as changes in laws or regulations, export restrictions, expropriation of our assets or resource nationalization, and/or forced renegotiation or modification of our existing contracts with EGPC could materially and adversely affect our business, financial condition, and results of operations.

Apache purchases multi-year political risk insurance from the Overseas Private Investment Corporation (OPIC) and other highly rated international insurers covering its investments in Egypt. In the aggregate, these policies, subject to the policy terms and conditions, provide approximately $1 billion of coverage to Apache for losses arising from confiscation, nationalization, and expropriation risks, with a $237.5 million sub-limit for currency inconvertibility. In addition, the Company has a separate policy with OPIC, which provides $225 million of coverage, including a self-insured retention of $37.5 million, for losses arising from (1) non-payment by EGPC of arbitral awards covering amounts owed Apache on past due invoices and (2) expropriation of exportable petroleum when actions taken by the government of Egypt prevent Apache from exporting our share of production.

Marketing Our gas production is sold to EGPC primarily under an industry-pricing formula, a sliding scale based on Dated Brent crude oil with a minimum of $1.50 per MMBtu and a maximum of $2.65 per MMBtu, which corresponds to a Dated Brent price of $21.00 per barrel. Generally, this industry-pricing formula applies to all new gas discovered and produced. In exchange for extension of the Khalda Concession lease in July 2004, Apache agreed to accept the industry-pricing formula on a majority of gas sold, but retained the previous gas-price formula (without an oil price cap) until the end of 2012 for up to 100 MMcf/d gross. The region averaged $4.66 per Mcf in 2011.

Oil from the Khalda Concession, the Qarun Concession and other nearby Western Desert blocks is sold primarily to third parties in the Mediterranean market or to EGPC when called upon to supply domestic demand. Oil sales are made either directly into the Egyptian oil pipeline grid, sold to non-governmental third parties including those supplying the Middle East Oil Refinery located in northern Egypt, or exported from or sold at one of two terminals on the northern coast of Egypt. Oil production that is presently sold to EGPC is sold on a spot basis priced at Brent with a monthly EGPC official differential applied.

Australia

Overview Apache’s holdings in Australia are focused offshore Western Australia in the Carnarvon basin, where we have operated since acquiring the gas processing facilities on Varanus Island and adjacent producing properties in 1993, in the Exmouth basin and in the Browse basin. Production operations are located in the Carnarvon and Exmouth basins. In total, we control approximately 8.8 million gross acres in Australia through 35 exploration permits, 16 production licenses, and 10 retention leases. Approximately 90 percent of our acreage is undeveloped.

During 2011, the region had net production of 38 Mb/d of oil and 185 MMcf/d of natural gas, contributing 10 percent of Apache’s worldwide production revenue, 9 percent of worldwide production and 11 percent of year-end estimated proved reserves. Production compared to the prior year was 13 percent lower as a result of numerous tropical cyclones, repairs to the Floating Production Storage and Offloading vessel (FPSO) that services our Van Gogh oil field, and natural decline in the Pyrenees and Van Gogh oil fields.

Offsetting production declines was the start-up of two new developments offshore Western Australia. In June 2011, Apache’s Halyard-1 gas discovery well commenced production into the domestic gas market. The Halyard development, which largely utilized existing Apache-operated pipelines and facilities, was completed ahead of schedule and set the stage for further development of our nearby Spar field. The region also completed development of the Reindeer gas field and construction of the Devil Creek Gas Plant in December. This plant is

Western Australia’s third domestic natural gas processing hub and the first new hub to be constructed in more than 15 years. Gas from the development has been sold to a number of customers in Western Australia’s growing mining and minerals processing sectors at prices significantly higher than current realizations.

The region also drilled several significant exploration and development wells in 2011. We participated in drilling nine wells during 2011, of which five were productive. Ongoing exploration activity at Apache’s Julimar and Brunello complex resulted in the discovery of a deeper Mungaroo gas pool encountering 362 feet of net pay. This 65-percent working interest Balnaves Deep well is associated with continuing field development efforts and augments previous discoveries. Separately, the Zola-1 natural gas discovery logged 410 feet of net pay and is on trend with the Gorgon gas field 16 miles to the north and near both existing and developing infrastructure. The evaluation of this 30-percent working interest discovery, including the planning of future appraisal drilling, is currently underway.

In addition, the region has a pipeline of projects that are expected to contribute to production growth as they are brought on-stream over coming years.

The 2010 Spar-2 discovery is projected to commence production in 2013 through an extension of the Halyard subsea infrastructure, which will also allow for the tie-in of future wells.

First production is also projected in 2013 from four completed gas wells in the Macedon gas field. We have a 29-percent non-operating working interest in the field. Gas will be delivered via a 60-mile pipeline to a 200 MMcf/d gas plant to be built at Ashburton North in Western Australia. The project, approved in 2010, is currently underway. Apache has successfully marketed nearly all of its proved reserves in the Macedon field under long-term contracts.

In 2011, the Coniston oil field project, which lies just north of the Van Gogh field, was sanctioned for development. First production is projected for 2013. The field will be produced via subsea completions tied back to the FPSO at Van Gogh. To more effectively control the Van Gogh and Coniston field operations, development, and maintenance efforts, this FPSO (the Ningaloo Vision) was purchased from the lessor in January 2012.

The region will also proceed with development of the offshore Balnaves field, an oil accumulation located near the Brunello gas field offshore Western Australia. The project is expected to deliver initial gross production of 30 Mb/d in 2014 utilizing a leased FPSO vessel. Apache has a 65-percent working interest in the project.

During 2011, the Company and its partners announced they will proceed with the Chevron-operated Wheatstone LNG development project (Wheatstone) in Western Australia. The first phase of the Wheatstone project will comprise two LNG processing trains with a combined capacity of approximately 8.9 million metric tons per annum (mtpa), a domestic gas plant, and associated infrastructure. Apache has a 13-percent interest in the project and expects to invest approximately $4 billion over five years for the field and LNG facility development. Apache will supply gas to Wheatstone from its operated Julimar and Brunello complex. The 65-percent interest Julimar development project is expected to generate average net sales to Apache of approximately 140 MMcf/d of gas (equivalent to 1.07 million mtpa of LNG) at prices pegged to world oil markets, 22 MMcf/d of sales gas into the domestic market, and 3,250 barrels of condensate per day. First production is projected for 2016.

These development projects require significant capital investments above traditional drilling programs. During 2012, the region plans to invest approximately $1.8 billion for drilling, recompletion projects, development projects, equipment upgrades, production enhancement projects, and seismic acquisition. Approximately 75 percent of the 2012 investment will be for development and processing facilities in connection with the projects discussed above.

In February 2012, a subsidiary closed on the acquisition of a 49-percent interest in Burrup Holdings Limited, which owns an ammonia plant on the Burrup Peninsula of Western Australia. Apache has been supplying natural gas to this plant since it commenced operations in 2006. This acquisition allowed Apache to stabilize the overall plant project, which was in receivership. The plant, which has been rebranded Yara Pilbara, has a production capacity of 760,000 mtpa and is one of the world’s largest ammonia production facilities.

Marketing Western Australia has historically had a local market for natural gas with a limited number of buyers and sellers resulting in sales under mostly long-term, fixed-price contracts, many of which contain periodic price revision clauses based on either the Australian consumer price index or a commodity linkage. As of December 31, 2011, Apache had 22 active gas contracts in Australia with expiration dates ranging from November 2012 to December 2026. Recent increases in demand and higher development costs have increased the supply prices required from the local market in order to support the development of new supplies. As a result, market prices negotiated on recent contracts are substantially higher than historical levels.

We directly market all of our Australian crude oil production into Australian domestic and international markets at prices generally indexed to Dated Brent benchmark crude oil prices plus premiums, which typically result in sales well above NYMEX oil prices.

North Sea

Overview Apache entered the North Sea in 2003 after acquiring an approximate 97-percent working interest in the Forties field (Forties). Since acquiring Forties, Apache has actively invested in the region having produced and sold oil volumes in excess of the proved reserves initially recorded. Forties, which Apache acquired with 45 producing wells, now has 75 producing wells with a substantial inventory of future drilling locations.

In 2011, the North Sea region produced 20 MMboe of which approximately 99 percent was crude oil. The region represents seven percent of our total worldwide production and 13 percent of Apache’s oil and gas production revenues. In 2011, the region’s production decreased four percent compared to the prior year as natural well decline and unplanned maintenance downtime exceeded gains from drilling. The drilling program, however, was successful and benefited greatly from a new 4-D seismic interpretation derived from the latest 3-D seismic survey acquired over Forties in 2010. The data highlighted many areas of bypassed oil in the reservoir and provided better definition of existing targets. In 2011, 14 wells were drilled in Forties, of which 11 were productive. Two of the highest producing wells were the Charlie 4-3 well, which commenced production in June at a rate of 12.6 Mb/d, and the Charlie 2-2 well, which was completed in March with an initial rate of 11.9 Mb/d. These rates were some of the highest in the Forties since 1990.

In addition, the region acquired an 11.5 percent non-operated interest in the Nelson field in early 2011, and on December 30, 2011, closed on the acquisition of Mobil North Sea Limited from Exxon Mobil Corporation. The assets acquired include operated interests in the Beryl, Nevis, Nevis South, Skene, and Buckland fields; operated interest in the Beryl/Brae gas pipeline and the SAGE gas plant; non-operated interests in the Maclure, Scott, and Telford fields; and Benbecula (west of Shetlands) exploration acreage. These major legacy assets bring the region quality reservoirs with significant remaining reserve life, high production efficiency, and a portfolio of low-risk exploitation projects. Beginning in 2012, production from the former Mobil North Sea fields will add to the percentage of Apache’s current output that is indexed to the premium Brent crude oil benchmark price. These acquisitions expand Apache’s presence in the North Sea and increase its portfolio of future drilling locations.

Estimated proved reserves recorded at the end of the year for the acquired properties totaled 61 MMboe, bringing Apache’s total estimated proved reserves at year-end 2011 to 197 MMbbls of crude oil in this region, or approximately seven percent of our worldwide year-end estimated proved reserves.

In 2012, the region will invest approximately $950 million on a diverse set of capital projects. Forties will see another year of active drilling with two platform rigs operating the entire year along with a partial year of jack-up drilling at the Echo platform. Construction of the Forties Alpha Satellite Platform is underway and is projected to be complete by the third quarter of 2012. This platform will sit adjacent to the main Alpha platform and provide an additional 18 drilling slots along with power generation, fluid separation, gas lift compression, and oil export pumping. The region will also work to integrate the acquired Mobil North Sea properties and plans to drill three wells on these properties during the year along with well recompletions and workovers.

Marketing We have traditionally sold our Forties crude under both term contracts and spot cargoes. The term sales are composed of a market-based index prices plus a premium, which reflects the higher market value for term arrangements. The prices received for spot cargoes are market driven and can trade at a premium or discount to the market-based index. All 2012 production from Forties will be sold under a term contract with a per-barrel premium to the Dated Brent index. Production from the former Mobil North Sea fields will also be indexed to the premium Brent crude oil benchmark price.

Argentina

Overview We have had a continuous presence in Argentina since 2001, which was expanded substantially by two acquisitions in 2006. We currently have operations in the Provinces of Neuquén, Rio Negro, Tierra del Fuego, and Mendoza. We have interests in 34 concessions, exploration permits, and other interests totaling 3.7 million gross acres in four of the main Argentine hydrocarbon basins: Neuquén, Austral, Cuyo, and Noroeste. Our concessions have varying expiration dates ranging from three years to over 15 years remaining, subject to potential extensions. In 2011, Argentina produced six percent of our worldwide production and held four percent of our estimated proved reserves at year-end.

In 2011, the region achieved record production of 48 Mboe/d and drilled 36 gross wells pursuant to a development drilling program that achieved a 97 percent success rate by focusing on unconventional premium gas and shallow oil targets. Our exploration program included drilling six gross wells in 2011. We are continuing to test two vertical wells targeting the Vaca Muerta formation in the Huacalera and Cortadera areas and are targeting oil in two recent exploration wells drilled in the Cuyo basin.

During the year, Apache’s first horizontal well in the Anticlinal Campamento field in the Neuquén basin began producing at a rate over 10 MMcf/d. The well was a test of horizontal drilling and multi-stage hydraulic fracturing in the low-permeability pre-Cuyo formation. In the third quarter, we completed the first horizontal multi-stage hydraulically fractured shale gas well drilled and completed in South America. The region will continue to evaluate the use of horizontal drilling techniques on tight and unconventional gas resources in the pre-Cuyo, Los Molles, and Vaca Muerta formations of the Neuquén basin, as these formations receive the benefit of higher gas prices under the Gas Plus program, as defined below.

Apache added acreage during the year in the Neuquén and Noroeste basins, increasing the region’s unconventional oil and gas potential. We also began negotiations for extensions of concessions in the Tierra del Fuego and Rio Negro Provinces, which are scheduled to expire between 2015 and 2017. Future investment by Apache in the Tierra del Fuego and Rio Negro Provinces will be significantly influenced by the ability to extend the present concessions.

During 2012, the region plans to invest approximately $250 million for drilling, recompletion projects, development projects, equipment upgrades, production enhancement projects, and seismic acquisition.

Marketing

Natural Gas Apache sells its natural gas through three pricing structures:

•

Gas Plus program: This program was instituted by the Argentine government in 2008 to encourage new gas supplies through the development of conventional and unconventional (tight sands) reserves. Under this program, Apache is allowed to sell gas from qualifying projects at prices that are above the regulated rates. During 2011, the average Gas Plus volume sold by Apache was 55.1 MMcf/d at an average price of $4.89 per Mcf. In addition, Apache signed or extended Gas Plus contracts with industrial consumers totaling gross rates of 15.5 MMcf/d at $4.28 per Mcf through December 31, 2012.

•

Government-regulated pricing: The volumes we are required to sell at regulated prices are set by the Argentine government and vary with seasonal factors and industry category. During 2011, we realized an average price of $1.06 per Mcf on government-regulated sales.

•

Unregulated market: The majority of our remaining volumes are sold into the unregulated market. In 2011, realizations averaged $3.14 per Mcf.

Crude Oil Our crude oil is subject to an export tax, which effectively limits the prices buyers are willing to pay for domestic sales. Domestic oil prices are currently based on $42 per barrel, plus quality adjustments and local premiums, and producers realize a gradual increase or decrease as market prices deviate from the base price. In Tierra del Fuego, similar pricing formulas exist; however, Apache retains the value-added tax collected from buyers, effectively increasing realized prices by 21 percent. As a result, 2011 oil prices realized from Tierra del Fuego oil production averaged $76.51 per barrel as compared to our Neuquén basin production, which averaged $64.16 per barrel.

Other Exploration

New Ventures

Apache continues to pursue numerous exploration opportunities in new areas across the globe. In Cook Inlet, Alaska, where we are currently the largest acreage holder with approximately 800,000 gross acres, we plan to conduct a seismic survey and drill a well within the next 12 months. During 2012, we also plan to drill a well in deepwater Kenya, where we hold a 50-percent working interest and are the operator. In the East Coast basin of New Zealand, where we have entered into a farm-in agreement to explore and potentially develop about 1.7 million gross acres, we expect to commence seismic operations and drill our first four wells targeting new onshore unconventional oil plays during 2012. Apache will earn a 50-percent interest in the New Zealand exploration permits upon completing the seismic and drilling program planned for the next four years.

During 2012, we plan to invest approximately $450 million to pursue exploration opportunities in new areas where Apache has yet to establish an operating region.

Chile

In November 2007, Apache was awarded exploration rights on two blocks comprising approximately one million net acres on the Chilean side of Tierra del Fuego. Upon careful evaluation of the exploration potential and economics of the blocks, we determined that these blocks are no longer prospective to Apache. As such, in the fourth quarter of 2011, we relinquished this acreage and recorded a $60 million non-cash write-off of the carrying value of our oil and gas property balance in Chile.

Major Customers

In 2011, 2010, and 2009, purchases by Royal Dutch Shell plc and its subsidiaries accounted for 11 percent, 15 percent, and 18 percent, respectively, of the Company’s worldwide oil and gas production revenues. In 2011, purchases by the Vitol Group accounted for 13 percent of the Company’s worldwide oil and gas production revenues.

Drilling Statistics

Worldwide in 2011 we participated in drilling 1,087 gross wells, with 1,005 (92 percent) completed as producers. Historically, our drilling activities in the U.S. have generally concentrated on exploitation and extension of existing producing fields rather than exploration. As a general matter, our operations outside of the U.S. focus on a mix of exploration and exploitation wells. In addition to our completed wells, at year-end several wells had not yet reached completion: 39 in the U.S. (28.44 net); 50 in Canada (42.69 net); 23 in Egypt (21.75 net); 6 in the North Sea (4.91 net); 1 in Australia (0.33 net); and 3 in Argentina (3.00 net).

The following table shows the results of the oil and gas wells drilled and completed for each of the last three fiscal years:


	Net Exploratory						Net Development						Total Net Wells
	Productive		Dry		Total		Productive		Dry		Total		Productive		Dry		Total
2011
United States		12.4		5.0		17.4		522.0		17.0		539.0		534.4		22.0		556.4
Canada		4.0		5.0		9.0		77.2		5.0		82.2		81.2		10.0		91.2
Egypt		28.2		19.8		48.0		112.6		6.0		118.6		140.8		25.8		166.6
Australia		1.0		2.3		3.3		1.0		0.0		1.0		2.0		2.3		4.3
North Sea		0.0		0.3		0.3		10.7		1.9		12.6		10.7		2.2		12.9
Argentina		4.0		1.0		5.0		29.4		0.3		29.7		33.4		1.3		34.7

Total		49.6		33.4		83.0		752.9		30.2		783.1		802.5		63.6		866.1

2010
United States		3.7		2.2		5.9		309.2		12.7		321.9		312.9		14.9		327.8
Canada		6.5		1.5		8.0		122.3		5.7		128.0		128.8		7.2		136.0
Egypt		19.4		18.5		37.9		144.8		5.5		150.3		164.2		24.0		188.2
Australia		5.5		3.4		8.9		4.5		1.3		5.8		10.0		4.7		14.7
North Sea		1.0		1.2		2.2		10.7		5.8		16.5		11.7		7.0		18.7
Argentina		1.8		2.7		4.5		43.3		0.3		43.6		45.1		3.0		48.1

Total		37.9		29.5		67.4		634.8		31.3		666.1		672.7		60.8		733.5

2009
United States		5.6		2.5		8.1		107.6		8.5		116.1		113.2		11.0		124.2
Canada		3.0		–		3.0		136.8		12.8		149.6		139.8		12.8		152.6
Egypt		8.6		10.4		19.0		126.4		4.0		130.4		135.0		14.4		149.4
Australia		6.9		3.8		10.7		4.7		–		4.7		11.6		3.8		15.4
North Sea		1.0		–		1.0		12.6		2.9		15.5		13.6		2.9		16.5
Argentina		3.4		0.7		4.1		25.5		–		25.5		28.9		0.7		29.6
Other International		2.0		–		2.0		–		–		–		2.0		–		2.0

Total		30.5		17.4		47.9		413.6		28.2		441.8		444.1		45.6		489.7

Productive Oil and Gas Wells

The number of productive oil and gas wells, operated and non-operated, in which we had an interest as of December 31, 2011, is set forth below:


	Oil				Gas				Total
	Gross		Net		Gross		Net		Gross		Net
United States		12,667		8,465		4,936		2,899		17,603		11,364
Canada		2,210		1,015		9,390		8,015		11,600		9,030
Egypt		880		839		80		76		960		915
Australia		44		20		12		7		56		27
North Sea		147		97		24		11		171		108
Argentina		465		390		470		440		935		830

Total		16,413		10,826		14,912		11,448		31,325		22,274

Gross natural gas and crude oil wells include 1,675 wells with multiple completions.

Production, Pricing, and Lease Operating Cost Data

The following table describes, for each of the last three fiscal years, oil, NGL, and gas production volumes, average lease operating expenses per boe (including transportation costs but excluding severance and other taxes), and average sales prices for each of the countries where we have operations:


	Production						Average Lease Operating Cost per Boe		Average Sales Price
Year Ended December 31,	Oil (MMbbls)		NGLs (MMbbls)		Gas (Bcf)		Average Lease Operating Cost per Boe		Oil (Per bbl)		NGLs (Per bbl)		Gas (Per Mcf)
2011
United States		43.6		8.1		315.6	$	11.80	$	95.51	$	48.42	$	4.91
Canada		5.2		2.2		230.9		13.86		93.19		45.72		4.47
Egypt		37.9		–		133.4		7.19		109.92		66.36		4.66
Australia		14.0		–		67.6		7.80		111.22		65.45		2.69
North Sea		19.9		–		0.8		11.61		104.09		–		22.25
Argentina		3.5		1.1		77.5		9.83		68.02		27.90		2.64

Total		124.1		11.4		825.8		10.62		102.19		45.95		4.37

2010
United States		35.3		5.0		266.8	$	11.40	$	76.13	$	41.45	$	5.28
Canada		5.3		1.1		144.5		13.46		72.83		36.61		4.48
Egypt		36.2		–		136.8		5.56		79.45		69.75		3.62
Australia		16.7		–		72.9		6.41		77.32		–		2.24
North Sea		20.8		–		0.9		9.23		76.66		–		18.64
Argentina		3.6		1.2		67.5		7.97		57.47		27.08		1.96

Total		117.9		7.3		689.4		9.20		76.69		38.58		4.15

2009
United States		32.5		2.2		243.1	$	10.59	$	59.06	$	33.02	$	4.34
Canada		5.5		0.8		131.1		11.46		56.16		25.54		4.17
Egypt		33.6		–		132.3		5.17		61.34		–		3.70
Australia		3.6		–		67.0		6.84		64.42		–		1.99
North Sea		22.3		–		1.0		8.19		60.91		–		13.15
Argentina		4.2		1.2		67.4		6.78		49.42		18.76		1.96

Total		101.7		4.2		641.9		8.48		59.85		27.63		3.69

Gross and Net Undeveloped and Developed Acreage

The following table sets out our gross and net acreage position in each country where we have operations:


	Undeveloped Acreage				Developed Acreage
	Gross Acres		Net Acres		Gross Acres		Net Acres
United States		5,323,494		3,057,334		4,975,556		2,555,355
Canada		3,084,789		2,640,389		4,433,557		3,355,367
Egypt		7,944,459		5,151,927		1,784,630		1,661,556
Australia		7,945,004		4,684,742		861,400		488,470
North Sea		598,091		251,525		187,462		85,904
Argentina		3,519,906		2,872,880		220,840		188,226

Total		28,415,743		18,658,797		12,463,445		8,334,878

As of December 31, 2011, we had 4,198,666, 3,772,074, and 1,885,448 net acres scheduled to expire by December 31, 2012, 2013, and 2014, respectively, if production is not established or we take no other action to extend the terms. We plan to continue the terms of many of these licenses and concession areas through operational or administrative actions and do not project a significant portion of our net acreage position to expire before such actions occur.

As of December 31, 2011, 34 percent of U.S. net undeveloped acreage and 40 percent of Canadian undeveloped acreage was held by production.

Estimated Proved Reserves and Future Net Cash Flows

Proved oil and gas reserves are the estimated quantities of natural gas, crude oil, condensate, and NGLs that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing conditions, operating conditions, and government regulations. Estimated proved developed oil and gas reserves can be expected to be recovered through existing wells with existing equipment and operating methods. The Company reports all estimated proved reserves held under production-sharing arrangements utilizing the “economic interest” method, which excludes the host country’s share of reserves.

Estimated reserves that can be produced economically through application of improved recovery techniques are included in the “proved” classification when successful testing by a pilot project or the operation of an active, improved recovery program using reliable technology establishes the reasonable certainty for the engineering analysis on which the project or program is based. Economically producible means a resource that generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. Reasonable certainty means a high degree of confidence that the quantities will be recovered. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field-tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. In estimating its proved reserves, Apache uses several different traditional methods that can be classified in three general categories: 1) performance-based methods; 2) volumetric-based methods; and 3) analogy with similar properties. Apache will, at times, utilize additional technical analysis, such as computer reservoir models, petrophysical techniques, and proprietary 3-D seismic interpretation methods, to provide additional support for more complex reservoirs. Information from this additional analysis is combined with traditional methods outlined above to enhance the certainty of our reserve estimates.

PUD reserves include those reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Undeveloped reserves may be classified as proved reserves on undrilled acreage directly offsetting development areas that are reasonably certain of production when drilled, or where reliable technology provides reasonable certainty of economic producibility. Undrilled locations may be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless specific circumstances justify a longer time period.

The following table shows proved oil, NGL, and gas reserves as of December 31, 2011, based on average commodity prices in effect on the first day of each month in 2011, held flat for the life of the production, except where future oil and gas sales are covered by physical contract terms. This table shows reserves on a boe basis in which natural gas is converted to an equivalent barrel of oil based on a 6:1 energy equivalent ratio. This ratio is not reflective of the current price ratio between the two products.


	Oil (MMbbls)		NGL (MMbbls)		Gas (Bcf)		Total (MMboe)
Proved Developed:
United States		428		107		2,216		905
Canada		82		23		2,109		457
Egypt		106		–		701		223
Australia		36		–		676		148
North Sea		137		9		105		163
Argentina		16		6		447		96
Proved Undeveloped:
United States		206		53		760		385
Canada		60		8		1,439		308
Egypt		22		–		282		69
Australia		32		–		894		181
North Sea		32		1		3		34
Argentina		5		1		90		21

TOTAL PROVED		1,162		208		9,722		2,990

As of December 31, 2011, Apache had total estimated proved reserves of 1,370 MMbbls of crude oil, condensate, and NGLs and 9.7 Tcf of natural gas. Combined, these total estimated proved reserves are the energy equivalent of 3.0 billion barrels of oil or 17.9 Tcf of natural gas, of which oil represents 39 percent. As of December 31, 2011, the Company’s proved developed reserves totaled 1,992 MMboe and estimated PUD reserves totaled 998 MMboe, or approximately 33 percent of worldwide total proved reserves. Apache has elected not to disclose probable or possible reserves in this filing.

The Company’s estimates of proved reserves, proved developed reserves and PUD reserves as of December 31, 2011, 2010, and 2009, changes in estimated proved reserves during the last three years, and estimates of future net cash flows from proved reserves are contained in Note 14—Supplemental Oil and Gas Disclosures in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K. Estimated future net cash flows as of December 31, 2011 and 2010, were calculated using a discount rate of 10 percent per annum, end of period costs, and an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months, held flat for the life of the production, except where prices are defined by contractual arrangements.

Proved Undeveloped Reserves

The Company’s total estimated PUD reserves of 998 MMboe as of December 31, 2011, increased by 30 MMboe over the 968 MMboe of PUD reserves estimated at the end of 2010. During the year, Apache converted 106 MMboe of PUD reserves to proved developed reserves through development drilling activity. In North America, we converted 78 MMboe, with the remaining 28 MMboe in our international areas. We divested 12 MMboe of PUD reserves during the year primarily associated with our East Texas sales package. We acquired 6 MMboe of PUD reserves during the year. We added 179 MMboe of new PUD reserves through extensions and discoveries and had revisions of (37) MMboe associated with changes in product prices and revised development plans.

During the year, a total of approximately $2.6 billion was spent on projects associated with reserves that were carried as PUD reserves at the end of 2010. A portion of our costs incurred each year relate to development projects that will be converted to proved developed reserves in future years. We spent $1.4 billion on PUD reserve development activity in North America and $1.2 billion in the international areas. Other than our Julimar/Brunello development project, which is tied to the construction schedule of the Wheatstone LNG project with projected first production in 2016, we had no material amounts of PUD reserves that have remained undeveloped for five years or more after they were initially disclosed as PUD reserves and no material amounts of PUD reserves which are scheduled to be developed beyond five years from December 31, 2011.

Preparation of Oil and Gas Reserve Information

Apache emphasizes that its reported reserves are reasonably certain estimates which, by their very nature, are subject to revision. These estimates are reviewed throughout the year and revised either upward or downward, as warranted.

Apache’s proved reserves are estimated at the property level and compiled for reporting purposes by a centralized group of experienced reservoir engineers that is independent of the operating groups. These engineers interact with engineering and geoscience personnel in each of Apache’s operating areas and with accounting and marketing employees to obtain the necessary data for projecting future production, costs, net revenues, and ultimate recoverable reserves. All relevant data is compiled in a computer database application, to which only authorized personnel are given security access rights consistent with their assigned job function. Reserves are reviewed internally with senior management and presented to Apache’s Board of Directors in summary form on a quarterly basis. Annually, each property is reviewed in detail by our centralized and operating region engineers to ensure forecasts of operating expenses, netback prices, production trends, and development timing are reasonable.

Apache’s Executive Vice President of Corporate Reservoir Engineering is the person primarily responsible for overseeing the preparation of our internal reserve estimates and for coordinating any reserves audits conducted by a third-party engineering firm. He has a Bachelor of Science degree in Petroleum Engineering and over 30 years of industry experience with positions of increasing responsibility within Apache’s corporate reservoir engineering department. The Executive Vice President of Corporate Reservoir Engineering reports directly to our Chairman and Chief Executive Officer.

The estimate of reserves disclosed in this Annual Report on Form 10-K is prepared by the Company’s internal staff, and the Company is responsible for the adequacy and accuracy of those estimates. However, the Company engages Ryder Scott Company, L.P. Petroleum Consultants (Ryder Scott) to review our processes and the reasonableness of our estimates of proved hydrocarbon liquid and gas reserves. Apache selects the properties for review by Ryder Scott based primarily on relative reserve value. We also consider other factors such as geographic location, new wells drilled during the year and reserves volume. During 2011, the properties selected for each country ranged from 57 to 100 percent of the total future net cash flows discounted at 10 percent. These properties also accounted for over 81 percent of the reserves value of our international proved reserves and of the new wells drilled in each country. In addition, all fields containing five percent or more of the Company’s total proved reserves volume were included in Ryder Scott’s review. The review covered 70 percent of total proved reserves, including 76 percent of proved developed reserves and 59 percent of PUD reserves. Properties with PUD reserves generally have an associated capital expenditure required to develop those reserves included in their net present value calculation, reducing their value relative to proved developed reserves. For this reason those properties are less likely to be selected for the audit, resulting in a higher percentage review coverage for proved developed reserves.

During 2011, 2010, and 2009, Ryder Scott’s review covered 81, 72, and 79 percent, respectively, of the Company’s worldwide estimated proved reserves value and 70, 63, and 69 percent, respectively, of the Company’s total proved reserves volume. Ryder Scott’s review of 2011 covered 68 percent of U.S., 69 percent of Canada, 58 percent of Argentina, 99 percent of Australia, 62 percent of Egypt, and 61 percent of the U.K.’s total proved reserves. Ryder Scott’s review of 2010 covered 59 percent of U.S., 42 percent of Canada, 64 percent of Argentina, 99 percent of Australia, 83 percent of Egypt, and 83 percent of the U.K.’s total proved reserves. Ryder Scott’s review of 2009 covered 66 percent of U.S., 48 percent of Canada, 63 percent of Argentina, 96 percent of Australia, 86 percent of Egypt, and 80 percent of the U.K.’s total proved reserves. We have filed Ryder Scott’s independent report as an exhibit to this Form 10-K.

According to Ryder Scott’s opinion, based on their review, including the data, technical processes, and interpretations presented by Apache, the overall procedures and methodologies utilized by Apache in determining the proved reserves comply with the current SEC regulations, and the overall proved reserves for the reviewed properties as estimated by Apache are, in aggregate, reasonable within the established audit tolerance guidelines as set forth in the Society of Petroleum Engineers auditing standards.

Employees

On December 31, 2011, we had 5,299 employees.

Offices

Our principal executive offices are located at One Post Oak Central, 2000 Post Oak Boulevard, Suite 100, Houston, Texas 77056-4400. At year-end 2011, we maintained regional exploration and/or production offices in Tulsa, Oklahoma; Houston, Texas; Midland, Texas; Calgary, Alberta; Cairo, Egypt; Perth, Western Australia; Aberdeen, Scotland; and Buenos Aires, Argentina. Apache leases all of its primary office space. The current lease on our principal executive offices runs through December 31, 2018. For information regarding the Company’s obligations under its office leases, please see Part II, Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity—Contractual Obligations and Note 8—Commitments and Contingencies in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.

Title to Interests

As is customary in our industry, a preliminary review of title records, which may include opinions or reports of appropriate professionals or counsel, is made at the time we acquire properties. We believe that our title to all of the various interests set forth above is satisfactory and consistent with the standards generally accepted in the oil and gas industry, subject only to immaterial exceptions that do not detract substantially from the value of the interests or materially interfere with their use in our operations. The interests owned by us may be subject to one or more royalty, overriding royalty, or other outstanding interests (including disputes related to such interests) customary in the industry. The interests may additionally be subject to obligations or duties under applicable laws, ordinances, rules, regulations, and orders of arbitral or governmental authorities. In addition, the interests may be subject to burdens such as production payments, net profits interests, liens incident to operating agreements and current taxes, development obligations under oil and gas leases, and other encumbrances, easements, and restrictions, none of which detract substantially from the value of the interests or materially interfere with their use in our operations.

Additional Information about Apache

In this section, references to “we,” “us,” “our,” and “Apache” include Apache Corporation and its consolidated subsidiaries, unless otherwise specifically stated.

Remediation Plans and Procedures

Apache and its wholly owned subsidiary, Apache Deepwater LLC (ADW), adopted certain Region Spill Response Plans (the Plans) for their respective Gulf of Mexico operations to ensure rapid and effective responses to spill events that may occur on such entities’ operated properties. Periodically, drills are conducted to measure and maintain the effectiveness of the Plans. These drills include the participation of spill response contractors, representatives of the Clean Gulf Associates (CGA, described below), and representatives of governmental agencies. The primary association available to Apache and ADW in the event of a spill is CGA. Apache and ADW have received approval for the Plans from the Bureau of Ocean Energy Management (BOEM). Apache and ADW personnel each review their respective Plan annually and update where necessary.

Both Apache and ADW are members of, and Apache has an employee representative on the executive committee of, CGA, a not-for-profit association of producing and pipeline companies operating in the Gulf of Mexico. CGA was created to provide a means of effectively staging response equipment and providing immediate spill response for its member companies’ operations in the Gulf of Mexico. To this end, CGA has bareboat chartered (an arrangement for the hiring of a boat with no crew or provisions included) its marine equipment to the Marine Spill Response Corporation (MSRC), a national, private, not-for-profit marine spill response organization, which is funded by grants from the Marine Preservation Association. MSRC maintains CGA’s equipment (currently including 13 shallow water skimmers, four fast response vessels with skimming capabilities, nine fast response containment-skimming units, a large skimming containment barge, numerous containment systems, wildlife cleaning and rehabilitation facilities, and dispersant inventory) at various staging points around the Gulf of Mexico in its ready state, and in the event of a spill, MSRC stands ready to mobilize all of this equipment to CGA members. MSRC also handles the maintenance and mobilization of CGA non-marine equipment. In addition, CGA maintains a contract with Airborne Support Inc., which provides aircraft and dispersant capabilities for CGA member companies. In 2011, we incurred charges for CGA of approximately $300,000: $12,800 per member and a fee based on annual production.

In the event that CGA resources are already being utilized, other associations are available to Apache. Apache is a member of Oil Spill Response Limited, which entitles any Apache entity worldwide to access their service. Oil Spill Response Limited has access to resources from the Global Response Network, a collaboration of seven major oil industry funded spill response organizations worldwide. Oil Spill Response Limited has equipment stockpiles in Bahrain, Singapore, and Southampton that currently include approximately 153

skimmers, booms (of approximately 12,000 meters), two Hercules aircraft for equipment deployment and aerial dispersant spraying, two additional aircraft, dispersant spray systems and dispersant, floating storage tanks, all-terrain vehicles, and various other equipment. If necessary, Oil Spill Response Limited’s resources may be, and have been, deployed to areas across the globe, such as the Gulf of Mexico. In addition, in February 2012, ADW became a member of MSRC and National Response Corporation (NRC), and such resources are available to ADW for its deepwater Gulf of Mexico operations along with the spill response resources of other organizations, each of which are available to both Apache and ADW as non-members, albeit at a higher cost. MSRC has an extensive inventory of oil spill response equipment, independent of and in addition to CGA’s equipment, currently including 19 oil spill response barges with storage capacities between 12,000 and 68,000 barrels, 68 shallow water barges, over 290 skimming systems, approximately 50 self-propelled skimming vessels, seven mobile communication suites with internet and telephone connections, as well as marine and aviation communication capabilities, various small crafts and shallow water vessels, 22,500 feet of fire boom, and 6 dispersant aircraft. MSRC has contracts in place with over 100 environmental contractors around the country, in addition to hundreds of other companies that provide support services during spill response. In the event of a spill, MSRC will activate these contractors as necessary to provide additional resources or support services requested by its customers. NRC owns a variety of equipment, currently including shallow water portable barges, boom, high capacity skimming systems, inland workboats, vacuum transfer units, and mobile communication centers. NRC has access to a vessel fleet of more than 328 offshore vessels and supply boats worldwide, as well as access to hundreds of tugs and oil barges from its tug and barge clients. The equipment and resources available to these companies changes from time to time, and current information is generally available on each of the companies’ websites.

In 2011, ADW retained the Helix Well Containment Group (HWCG) in conjunction with its CGA membership. HWCG is a consortium of 24 deepwater operators in the Gulf of Mexico that have worked on expanding capabilities to rapidly respond to subsea well incidents like the Deepwater Horizon incident. In June 2011, HWCG announced that it is now capable of responding to a subsea well containment incident in water depths of up to 10,000 feet. Each HWCG member company has entered into a mutual aid agreement, allowing any member to draw upon the technical expertise and resources of the group in the event of an incident. ADW’s 2011 membership dues for the two-year service agreement were approximately $1.4 million.

In 2011, ADW also became a member of the Marine Well Containment Company (MWCC) to fulfill the government permit requirements for containment and oil spill response plans in deepwater Gulf of Mexico operations. MWCC is a not-for-profit, stand-alone organization whose goal is to improve capabilities for containing an underwater well control incident in the U.S. Gulf of Mexico. MWCC is currently developing a billion-dollar expanded containment system, which is expected to be available in 2012. The MWCC owns and maintains an interim containment system, which became available for use in February 2011. The interim containment system includes a subsea capping stack with the ability to shut in oil flow or to flow the oil via flexible pipes and risers to surface vessels. The system also includes subsea dispersant injection equipment, manifolds, and, through mutual aid among members, capture vessels to provide surface processing and storage. The interim system is designed to meet the BOEM requirements. The system is designed to operate in 10,000 feet of water and process up to 100,000 b/d and 200 MMcf/d. The current interim system can operate in water depths up to 8,000 feet and has storage and processing capacity for up to 60,000 b/d. Membership in MWCC is open to all companies operating in the U.S. Gulf of Mexico. Members have access to the interim containment system, as well as the expanded system once construction is completed. Non-members will also have access to the systems through a service agreement and fee. In 2011, ADW paid $40 million to MWCC, which represents our initial capital investment.

Apache also participates in a number of industry-wide task forces that are studying ways to better access and control blowouts in subsea environments and increase containment and recovery methods. Two such task forces are the Subsea Well Control and Containment Task Force and the Offshore Operating Procedures Task Force.

Competitive Conditions

The oil and gas business is highly competitive in the exploration for and acquisitions of reserves, the acquisition of oil and gas leases, equipment and personnel required to find and produce reserves, and in the gathering and marketing of oil, gas, and natural gas liquids. Our competitors include national oil companies, major integrated oil and gas companies, other independent oil and gas companies, and participants in other industries supplying energy and fuel to industrial, commercial, and individual consumers.

Certain of our competitors may possess financial or other resources substantially larger than we possess or have established strategic long-term positions and maintain strong governmental relationships in countries in which we may seek new entry. As a consequence, we may be at a competitive disadvantage in bidding for leases or drilling rights.

However, we believe our diversified portfolio of core assets, which comprises large acreage positions and well-established production bases across six countries, and our balanced production mix between oil and gas, our management and incentive systems, and our experienced personnel give us a strong competitive position relative to many of our competitors who do not possess similar political, geographic, and production diversity. Our global position provides a large inventory of geologic and geographic opportunities in the six countries in which we have producing operations to which we can reallocate capital investments in response to changes in local business environments and markets. It also reduces the risk that we will be materially impacted by an event in a specific area or country.

Environmental Compliance

As an owner or lessee and operator of oil and gas properties, we are subject to numerous federal, provincial, state, local, and foreign country laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution clean-up resulting from operations, subject the lessee to liability for pollution damages and require suspension or cessation of operations in affected areas. Although environmental requirements have a substantial impact upon the energy industry, as a whole, we do not believe that these requirements affect us differently, to any material degree, than other companies in our industry.

We have made and will continue to make expenditures in our efforts to comply with these requirements, which we believe are necessary business costs in the oil and gas industry. We have established policies for continuing compliance with environmental laws and regulations, including regulations applicable to our operations in all countries in which we do business. We have established operating procedures and training programs designed to limit the environmental impact of our field facilities and identify and comply with changes in existing laws and regulations. The costs incurred under these policies and procedures are inextricably connected to normal operating expenses such that we are unable to separate expenses related to environmental matters; however, we do not believe expenses related to training and compliance with regulations and laws that have been adopted or enacted to regulate the discharge of materials into the environment will have a material impact on our capital expenditures, earnings, or competitive position.

Changes to existing, or additions of, laws, regulations, enforcement policies or requirements in one or more of the countries or regions in which we operate could require us to make additional capital expenditures. While the events in the U.S. Gulf of Mexico in 2010 have resulted in the enactment of, and may result in the enactment of additional, laws or requirements regulating the discharge of materials into the environment, we do not believe that any such regulations or laws enacted or adopted as of this date will have a material adverse impact on our cost of operations, earnings, or competitive position.

ITEM 1A.

RISK FACTORS

Our business activities and the value of our securities are subject to significant hazards and risks, including those described below. If any of such events should occur, our business, financial condition, liquidity, and/or results of operations could be materially harmed, and holders and purchasers of our securities could lose part or all of their investments. Additional risks relating to our securities may be included in the prospectuses for securities we issue in the future.

Future economic conditions in the U.S. and key international markets may materially adversely impact our operating results.

The U.S. and other world economies are slowly recovering from a global financial crisis and recession that began in 2008. Growth has resumed but is modest and at an unsteady rate. There are likely to be significant long-term effects resulting from the recession and credit market crisis, including a future global economic growth rate that is slower than in the years leading up to the crisis, and more volatility may occur before a sustainable, yet lower, growth rate is achieved. Global economic growth drives demand for energy from all sources, including fossil fuels. A lower future economic growth rate could result in decreased demand growth for our crude oil and natural gas production as well as lower commodity prices, which would reduce our cash flows from operations and our profitability.

In addition, the Organisation for Economic Co-operation and Development (OECD) has encouraged countries with large federal budget deficits to initiate deficit reduction measures. As a result of the European sovereign debt crisis, certain European countries have initiated austerity measures. Such deficit reduction measures, if they are undertaken too rapidly, could further undermine economic recovery and slow growth by reducing demand.

Crude oil and natural gas prices are volatile, and a substantial reduction in these prices could adversely affect our results and the price of our common stock.

Our revenues, operating results and future rate of growth depend highly upon the prices we receive for our crude oil and natural gas production. Historically, the markets for crude oil and natural gas have been volatile and are likely to continue to be volatile in the future. For example, the NYMEX daily settlement price for the prompt month oil contract in 2011 ranged from a high of $113.93 per barrel to a low of $75.67 per barrel. The NYMEX daily settlement price for the prompt month natural gas contract in 2011 ranged from a high of $4.85 per MMBtu to a low of $2.99 per MMBtu. The market prices for crude oil and natural gas depend on factors beyond our control. These factors include demand for crude oil and natural gas, which fluctuates with changes in market and economic conditions, and other factors, including:

•

worldwide and domestic supplies of crude oil and natural gas;

•

actions taken by foreign oil and gas producing nations;

•

political conditions and events (including instability, changes in governments, or armed conflict) in crude oil or natural gas producing regions;

•

the level of global crude oil and natural gas inventories;

•

the price and level of imported foreign crude oil and natural gas;

•

the price and availability of alternative fuels, including coal and biofuels;

•

the availability of pipeline capacity and infrastructure;

•

the availability of crude oil transportation and refining capacity;

•

weather conditions;

•

electricity generation;

•

domestic and foreign governmental regulations and taxes; and

•

the overall economic environment.

Significant declines in crude oil and natural gas prices for an extended period may have the following effects on our business:

•

limiting our financial condition, liquidity, and/or ability to fund planned capital expenditures and operations;

•

reducing the amount of crude oil and natural gas that we can produce economically;

•

causing us to delay or postpone some of our capital projects;

•

reducing our revenues, operating income, and cash flows;

•

limiting our access to sources of capital, such as equity and long-term debt;

•

a reduction in the carrying value of our crude oil and natural gas properties; or

•

a reduction in the carrying value of goodwill.

Our ability to sell natural gas or oil and/or receive market prices for our natural gas or oil may be adversely affected by pipeline and gathering system capacity constraints and various transportation interruptions.

A portion of our natural gas and oil production in any region may be interrupted, or shut in, from time to time for numerous reasons, including as a result of weather conditions, accidents, loss of pipeline or gathering system access, field labor issues or strikes, or capital constraints that limit the ability of third parties to construct gathering systems, processing facilities, or interstate pipelines to transport our production, or we might voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted at the same time, it could temporarily adversely affect our cash flows.

Weather and climate may have a significant adverse impact on our revenues and productivity.

Demand for oil and natural gas are, to a significant degree, dependent on weather and climate, which impact the price we receive for the commodities we produce. In addition, our exploration and development activities and equipment can be adversely affected by severe weather, such as hurricanes in the Gulf of Mexico or cyclones offshore Australia, which may cause a loss of production from temporary cessation of activity or lost or damaged equipment. Our planning for normal climatic variation, insurance programs, and emergency recovery plans may inadequately mitigate the effects of such weather conditions, and not all such effects can be predicted, eliminated, or insured against.

Our operations involve a high degree of operational risk, particularly risk of personal injury, damage, or loss of equipment, and environmental accidents.

Our operations are subject to hazards and risks inherent in the drilling, production, and transportation of crude oil and natural gas, including:

•

drilling well blowouts, explosions, and cratering;

•

pipeline ruptures and spills;

•

fires;

•

formations with abnormal pressures;

•

equipment malfunctions; and

•

hurricanes and/or cyclones, which could affect our operations in areas such as on- and offshore the Gulf Coast and Australia, and other natural disasters.

Failure or loss of equipment, as the result of equipment malfunctions, cyber-attacks, or natural disasters such as hurricanes, could result in property damages, personal injury, environmental pollution and other damages for which we could be liable. Litigation arising from a catastrophic occurrence, such as a well blowout, explosion, or fire at a location where our equipment and services are used, may result in substantial claims for damages. Ineffective containment of a drilling well blowout or pipeline rupture could result in extensive environmental pollution and substantial remediation expenses. If a significant amount of our production is interrupted, our containment efforts prove to be ineffective or litigation arises as the result of a catastrophic occurrence, our cash flows, and, in turn, our results of operations could be materially and adversely affected.

The Devon and Mariner transactions have increased our exposure to Gulf of Mexico operations.

Our 2010 acquisitions of oil and gas assets in offshore Gulf of Mexico from Devon Energy Corporation and Mariner Energy, Inc. have increased our exposure to offshore Gulf of Mexico operations. Greater offshore concentration proportionately increases risks from delays or higher costs common to offshore activity, including severe weather, availability of specialized equipment and compliance with environmental and other laws and regulations.

In addition, regulatory changes in the Gulf of Mexico after the Deepwater Horizon incident and the increased demand for drilling rigs and oilfield services since the resumption of activities in the Gulf may lead to higher costs and reduced availability of such rigs and services, making satisfactory returns on our investments in that region more difficult to achieve.

The additional deepwater drilling laws and regulations, delays in the processing and approval of permits and other related developments in the Gulf of Mexico as well as our other locations resulting from the Deepwater Horizon incident could adversely affect Apache’s business.

In response to the Deepwater Horizon incident in the U.S. Gulf of Mexico in April 2010, and as directed by the Secretary of the US Department of the Interior, the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE), now split into the Bureau of Ocean Energy Management (BOEM) and the Bureau of Safety and Environmental Enforcement (BSEE), issued new guidelines and regulations regarding safety, environmental matters, drilling equipment, and decommissioning applicable to drilling in the Gulf of Mexico. These new requirements applicable to drilling activities in the Gulf of Mexico, have imposed additional requirements with respect to development and production activities in the Gulf of Mexico and have delayed the approval of applications to drill in both deepwater and shallow-water areas. In addition, the U.S. Department of the Interior (or BOEM/BSEE) requires that operators demonstrate their compliance with new regulations before they resume deepwater drilling. While certain new drilling plans and drilling permits have been approved during 2011, we cannot predict when development and production activities will return to previous levels of activity in the Gulf of Mexico.

Further, at this time, we cannot predict with any certainty what further impact, if any, the Deepwater Horizon incident may have on the regulation of offshore oil and gas exploration and development activity, or on

the cost or availability of insurance coverage to cover the risks of such operations. The enactment of new or stricter regulations in the United States and other countries and increased liability for companies operating in this sector could adversely affect Apache’s operations in the U.S. Gulf of Mexico as well as in our other locations.

Our commodity price risk management and trading activities may prevent us from benefiting fully from price increases and may expose us to other risks.

To the extent that we engage in price risk management activities to protect ourselves from commodity price declines, we may be prevented from realizing the full benefits of price increases above the levels of the derivative instruments used to manage price risk. In addition, our hedging arrangements may expose us to the risk of financial loss in certain circumstances, including instances in which:

•

our production falls short of the hedged volumes;

•

there is a widening of price-basis differentials between delivery points for our production and the delivery point assumed in the hedge arrangement;

•

the counterparties to our hedging or other price risk management contracts fail to perform under those arrangements; or

•

a sudden unexpected event materially impacts oil and natural gas prices.

The credit risk of financial institutions could adversely affect us.

We have exposure to different counterparties, and we have entered into transactions with counterparties in the financial services industry, including commercial banks, investment banks, insurance companies, other investment funds, and other institutions. These transactions expose us to credit risk in the event of default of our counterparty. Deterioration in the credit markets may impact the credit ratings of our current and potential counterparties and affect their ability to fulfill their existing obligations to us and their willingness to enter into future transactions with us. We have exposure to financial institutions in the form of derivative transactions in connection with our hedges and insurance companies in the form of claims under our policies. In addition, if any lender under our credit facility is unable to fund its commitment, our liquidity will be reduced by an amount up to the aggregate amount of such lender’s commitment under our credit facility.

We are exposed to counterparty credit risk as a result of our receivables.

We are exposed to risk of financial loss from trade, joint venture, joint interest billing, and other receivables. We sell our crude oil, natural gas, and NGLs to a variety of purchasers. As operator, we pay expenses and bill our non-operating partners for their respective shares of costs. Some of our purchasers and non-operating partners may experience liquidity problems and may not be able to meet their financial obligations. Nonperformance by a trade creditor or non-operating partner could result in significant financial losses.

A downgrade in our credit rating could negatively impact our cost of and ability to access capital.

We receive debt ratings from the major credit rating agencies in the United States. Factors that may impact our credit ratings include debt levels, planned asset purchases or sales, and near-term and long-term production growth opportunities. Liquidity, asset quality, cost structure, product mix, and commodity pricing levels and others are also considered by the rating agencies. A ratings downgrade could adversely impact our ability to access debt markets in the future, increase the cost of future debt, and potentially require the Company to post letters of credit for certain obligations.

Market conditions may restrict our ability to obtain funds for future development and working capital needs, which may limit our financial flexibility.

While the credit markets have recovered in the wake of the global financial crises, they remain vulnerable to unpredictable shocks. We have a significant development project inventory and an extensive exploration portfolio, which will require substantial future investment. We and/or our partners may need to seek financing in order to fund these or other future activities. Our future access to capital, as well as that of our partners and contractors, could be limited if the debt or equity markets are constrained. This could significantly delay development of our property interests.

Our ability to declare and pay dividends is subject to limitations.

The payment of future dividends on our capital stock is subject to the discretion of our board of directors, which considers, among other factors, our operating results, overall financial condition, credit-risk considerations, and capital requirements, as well as general business and market conditions. Our board of directors is not required to declare dividends on our common stock and may decide not to declare dividends.

Any indentures and other financing agreements that we enter into in the future may limit our ability to pay cash dividends on our capital stock, including common stock. In the event that any of our indentures or other financing agreements in the future restrict our ability to pay dividends in cash on the mandatory convertible preferred stock, we may be unable to pay dividends in cash on the common stock unless we can refinance amounts outstanding under those agreements. In addition, under Delaware law, dividends on capital stock may only be paid from “surplus,” which is defined as the amount by which our total assets exceeds the sum of our total liabilities, including contingent liabilities, and the amount of our capital; if there is no surplus, cash dividends on capital stock may only be paid from our net profits for the then current and/or the preceding fiscal year. Further, even if we are permitted under our contractual obligations and Delaware law to pay cash dividends on common stock, we may not have sufficient cash to pay dividends in cash on our common stock.

Discoveries or acquisitions of additional reserves are needed to avoid a material decline in reserves and production.

The production rate from oil and gas properties generally declines as reserves are depleted, while related per-unit production costs generally increase as a result of decreasing reservoir pressures and other factors. Therefore, unless we add reserves through exploration and development activities or, through engineering studies, identify additional behind-pipe zones, secondary recovery reserves, or tertiary recovery reserves, or acquire additional properties containing proved reserves, our estimated proved reserves will decline materially as reserves are produced. Future oil and gas production is, therefore, highly dependent upon our level of success in acquiring or finding additional reserves on an economic basis. Furthermore, if oil or gas prices increase, our cost for additional reserves could also increase.

We may not realize an adequate return on wells that we drill.

Drilling for oil and gas involves numerous risks, including the risk that we will not encounter commercially productive oil or gas reservoirs. The wells we drill or participate in may not be productive, and we may not recover all or any portion of our investment in those wells. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that crude or natural gas is present or may be produced economically. The costs of drilling, completing, and operating wells are often uncertain, and drilling operations may be curtailed, delayed, or canceled as a result of a variety of factors including, but not limited to:

•

unexpected drilling conditions;

•

pressure or irregularities in formations;

•

equipment failures or accidents;

•

fires, explosions, blowouts, and surface cratering;

•

marine risks such as capsizing, collisions, and hurricanes;

•

other adverse weather conditions; and

•

increase in the cost of, or shortages or delays in the availability of, drilling rigs and equipment.

Future drilling activities may not be successful, and, if unsuccessful, this failure could have an adverse effect on our future results of operations and financial condition. While all drilling, whether developmental or exploratory, involves these risks, exploratory drilling involves greater risks of dry holes or failure to find commercial quantities of hydrocarbons.

Material differences between the estimated and actual timing of critical events may affect the completion and commencement of production from development projects.

We are involved in several large development projects the completion of which may be delayed beyond our anticipated completion dates. Our projects may be delayed by project approvals from joint venture partners, timely issuances of permits and licenses by governmental agencies, weather conditions, manufacturing and delivery schedules of critical equipment, and other unforeseen events. Delays and differences between estimated and actual timing of critical events may adversely affect our large development projects and our ability to participate in large-scale development projects in the future.

We may fail to fully identify potential problems related to acquired reserves or to properly estimate those reserves.

Although we perform a review of properties that we acquire that we believe is consistent with industry practices, such reviews are inherently incomplete. It generally is not feasible to review in depth every individual property involved in each acquisition. Ordinarily, we will focus our review efforts on the higher-value properties and will sample the remainder. However, even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit us as a buyer to become sufficiently familiar with the properties to assess fully and accurately their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, we often assume certain environmental and other risks and liabilities in connection with acquired properties. There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and future production rates and costs with respect to acquired properties, and actual results may vary substantially from those assumed in the estimates. In addition, there can be no assurance that acquisitions will not have an adverse effect upon our operating results, particularly during the periods in which the operations of acquired businesses are being integrated into our ongoing operations.

Several significant matters in the BP Acquisition were not resolved before closing.

Because of the relatively short time period between signing the BP Purchase Agreements and the closing of the acquisition of the BP properties, several significant matters commonly resolved prior to closing such an acquisition were reserved for after closing. We did not have sufficient time before closing on the BP Properties to conduct a full environmental assessment. We may discover adverse environmental or other conditions after closing and after the time periods specified in the BP Purchase Agreements during which we may be able to seek, in certain cases, indemnification from or cure of the defect or adverse condition by BP for such matters. For example, Apache Canada Ltd. has asserted a claim against BP Canada arising from the acquisition of certain

Canadian properties under the BP Purchase Agreements. The dispute centers on Apache Canada Ltd.’s identification of Alleged Adverse Conditions, as that term is defined in the BP Purchase Agreements, and more specifically, the contention that liabilities associated with such conditions were retained by BP Canada as seller. There can be no assurance that we will prevail on this or any future claim against BP.

The BP Acquisition and/or our liabilities could be adversely affected in the event one or more of the BP entities become the subject of a bankruptcy case.

In light of the extensive costs and liabilities related to the oil spill in the Gulf of Mexico in 2010, there was public speculation as to whether one or more of the BP entities could become the subject of a case or proceeding under Title 11 of the United States Code or any other relevant insolvency law or similar law (which we collectively refer to as “Insolvency Laws”). In the event that one or more of the BP entities were to become the subject of such a case or proceeding, a court may find that the BP Purchase Agreements are executory contracts, in which case such BP entities may, subject to relevant Insolvency Laws, have the right to reject the agreements and refuse to perform their future obligations under them. In this event, our ability to enforce our rights under the BP Purchase Agreements could be adversely affected.

Additionally, in a case or proceeding under relevant Insolvency Laws, a court may find that the sale of the BP Properties constitutes a constructive fraudulent conveyance that should be set aside. While the tests for determining whether a transfer of assets constitutes a constructive fraudulent conveyance vary among jurisdictions, such a determination generally requires that the seller received less than a reasonably equivalent value in exchange for such transfer or obligation and the seller was insolvent at the time of the transaction, or was rendered insolvent or left with unreasonably small capital to meet its anticipated business needs as a result of the transaction. The applicable time periods for such a finding also vary among jurisdictions, but generally range from two to six years. If a court were to make such a determination in a proceeding under relevant Insolvency Laws, our rights under the BP Purchase Agreements, and our rights to the BP Properties, could be adversely affected.

Crude oil and natural gas reserves are estimates, and actual recoveries may vary significantly.

There are numerous uncertainties inherent in estimating crude oil and natural gas reserves and their value. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact manner. Because of the high degree of judgment involved, the accuracy of any reserve estimate is inherently imprecise, and a function of the quality of available data and the engineering and geological interpretation. Our reserves estimates are based on 12-month average prices, except where contractual arrangements exist; therefore, reserves quantities will change when actual prices increase or decrease. In addition, results of drilling, testing, and production may substantially change the reserve estimates for a given reservoir over time. The estimates of our proved reserves and estimated future net revenues also depend on a number of factors and assumptions that may vary considerably from actual results, including:

•

historical production from the area compared with production from other areas;

•

the effects of regulations by governmental agencies, including changes to severance and excise taxes;

•

future operating costs and capital expenditures; and

•

workover and remediation costs.

For these reasons, estimates of the economically recoverable quantities of crude oil and natural gas attributable to any particular group of properties, classifications of those reserves and estimates of the future net cash flows expected from them prepared by different engineers or by the same engineers but at different times

may vary substantially. Accordingly, reserves estimates may be subject to upward or downward adjustment, and actual production, revenue and expenditures with respect to our reserves likely will vary, possibly materially, from estimates.

Additionally, because some of our reserves estimates are calculated using volumetric analysis, those estimates are less reliable than the estimates based on a lengthy production history. Volumetric analysis involves estimating the volume of a reservoir based on the net feet of pay of the structure and an estimation of the area covered by the structure. In addition, realization or recognition of proved undeveloped reserves will depend on our development schedule and plans. A change in future development plans for proved undeveloped reserves could cause the discontinuation of the classification of these reserves as proved.

Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage.

A sizeable portion of our acreage is currently undeveloped. Unless production in paying quantities is established on units containing certain of these leases during their terms, the leases will expire. If our leases expire, 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, oil and natural gas prices, the availability and cost of capital, drilling, and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints, and regulatory approvals.

We may incur significant costs related to environmental matters.

As an owner or lessee and operator of oil and gas properties, we are subject to various federal, provincial, state, local, and foreign country laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution clean-up resulting from operations, subject the lessee to liability for pollution damages and require suspension or cessation of operations in affected areas. Our efforts to limit our exposure to such liability and cost may prove inadequate and result in significant adverse effect on our results of operations. In addition, it is possible that the increasingly strict requirements imposed by environmental laws and enforcement policies could require us to make significant capital expenditures. Such capital expenditures could adversely impact our cash flows and our financial condition.

Our North American operations are subject to governmental risks that may impact our operations.

Our North American operations have been, and at times in the future may be, affected by political developments and by federal, state, provincial, and local laws and regulations such as restrictions on production, changes in taxes, royalties and other amounts payable to governments or governmental agencies, price or gathering rate controls, and environmental protection laws and regulations. New political developments, laws, and regulations may adversely impact our results on operations.

Pending regulations related to emissions and the impact of any changes in climate could adversely impact our business.

Several countries where Apache operates including Australia, Canada, and the United Kingdom either tax or assess some form of greenhouse gas (GHG) related fees on Company operations. Exposure has not been material to date, although under current regulations the rates and amounts of payments are expected to increase. Quantifying our total net financial exposure to GHG taxes in Australia awaits regulatory guidance and clarification, but we expect the value to be manageable within the context of our ongoing operations.

In the event the predictions for rising temperatures and sea levels suggested by reports of the United Nations Intergovernmental Panel on Climate Change do transpire, we do not believe those events by themselves are likely

to impact the Company’s assets or operations. However, any increase in severe weather could have a material adverse effect on our assets and operations.

The proposed U.S. federal budget for fiscal year 2013 includes certain provisions that, if passed as originally submitted, will have an adverse effect on our financial position, results of operations, and cash flows.

On February 13, 2012, the Office of Management and Budget released a summary of the proposed U.S. federal budget for fiscal year 2013. The proposed budget repeals many tax incentives and deductions that are currently used by U.S. oil and gas companies and imposes new taxes. The provisions include elimination of the ability to fully deduct intangible drilling costs in the year incurred; increases in the taxation of foreign source income; repeal of the manufacturing tax deduction for oil and natural gas companies; and an increase in the geological and geophysical amortization period for independent producers. Should some or all of these provisions become law, our taxes will increase, potentially significantly, which would have a negative impact on our net income and cash flows. This could also cause us to reduce our drilling activities in the U.S. Since none of these proposals have yet to be voted on or become law, we do not know the ultimate impact these proposed changes may have on our business.

Proposed federal, state, or local regulation regarding hydraulic fracturing could increase our operating and capital costs.

Several proposals are before the U.S. Congress that, if implemented, would either prohibit or restrict the practice of hydraulic fracturing or subject the process to regulation under the Safe Drinking Water Act. Several states are considering legislation to regulate hydraulic fracturing practices that could impose more stringent permitting, transparency, and well construction requirements on hydraulic-fracturing operations or otherwise seek to ban fracturing activities altogether. In addition, some municipalities have significantly limited or prohibited drilling activities and/or hydraulic fracturing, or are considering doing so. We routinely use fracturing techniques in the U.S. and other regions to expand the available space for natural gas and oil to migrate toward the wellbore. It is typically done at substantial depths in very tight formations.

Although it is not possible at this time to predict the final outcome of the legislation regarding hydraulic fracturing, any new federal, state, or local restrictions on hydraulic fracturing that may be imposed in areas in which we conduct business could result in increased compliance costs or additional operating restrictions in the U.S.

A deterioration of conditions in Egypt or changes in the economic and political environment in Egypt could have an adverse impact on our business.

In February 2011, the former Egyptian president Hosni Mubarak stepped down, and the Egyptian Supreme Council of the Armed Forces took power. In November 2011, Egypt held its first round of parliamentary elections. Despite the Muslim Brotherhood’s Freedom and Justice Party’s victory in the parliamentary elections, Egypt remains under martial law. The new Parliament remains subordinate to the Egyptian Supreme Council of the Armed Forces, which has stated its intention to turn over power to civilians following the presidential election expected in June 2012. Deterioration in the political, economic, and social conditions or other relevant policies of the Egyptian government, such as changes in laws or regulations, export restrictions, expropriation of our assets or resource nationalization, and/or forced renegotiation or modification of our existing contracts with EGPC could materially and adversely affect our business, financial condition, and results of operations. Our operations in Egypt contributed 22 percent of our 2011 production and accounted for 10 percent of our year-end estimated proved reserves. At year-end 2011, 17 percent of our estimated discounted future net cash flows and 7.5 percent of our net capitalized oil and gas property was attributable to Egypt.

International operations have uncertain political, economic, and other risks.

Our operations outside North America are based primarily in Egypt, Australia, the United Kingdom, and Argentina. On a barrel equivalent basis, approximately 45 percent of our 2011 production was outside North America, and approximately 31 percent of our estimated proved oil and gas reserves on December 31, 2011 were located outside North America. As a result, a significant portion of our production and resources are subject to the increased political and economic risks and other factors associated with international operations including, but not limited to:

•

general strikes and civil unrest;

•

the risk of war, acts of terrorism, expropriation and resource nationalization, forced renegotiation or modification of existing contracts;

•

import and export regulations;

•

taxation policies, including royalty and tax increases and retroactive tax claims, and investment restrictions;

•

price control;

•

transportation regulations and tariffs;

•

constrained natural gas markets dependent on demand in a single or limited geographical area;

•

exchange controls, currency fluctuations, devaluation, or other activities that limit or disrupt markets and restrict payments or the movement of funds;

•

laws and policies of the United States affecting foreign trade, including trade sanctions;

•

the possibility of being subject to exclusive jurisdiction of foreign courts in connection with legal disputes relating to licenses to operate and concession rights in countries where we currently operate;

•

the possible inability to subject foreign persons, especially foreign oil ministries and national oil companies, to the jurisdiction of courts in the United States; and

•

difficulties in enforcing our rights against a governmental agency because of the doctrine of sovereign immunity and foreign sovereignty over international operations.

Foreign countries have occasionally asserted rights to oil and gas properties through border disputes. If a country claims superior rights to oil and gas leases or concessions granted to us by another country, our interests could decrease in value or be lost. Even our smaller international assets may affect our overall business and results of operations by distracting management’s attention from our more significant assets. Various regions of the world in which we operate have a history of political and economic instability. This instability could result in new governments or the adoption of new policies that might result in a substantially more hostile attitude toward foreign investments such as ours. In an extreme case, such a change could result in termination of contract rights and expropriation of our assets. This could adversely affect our interests and our future profitability.

The impact that future terrorist attacks or regional hostilities may have on the oil and gas industry in general, and on our operations in particular, is not known at this time. Uncertainty surrounding military strikes or a sustained military campaign may affect operations in unpredictable ways, including disruptions of fuel supplies and markets, particularly oil, and the possibility that infrastructure facilities, including pipelines, production

facilities, processing plants, and refineries, could be direct targets of, or indirect casualties of, an act of terror or war. We may be required to incur significant costs in the future to safeguard our assets against terrorist activities.

In addition, continued regional conflict in the Middle East could have the following results, among others:

•

volatility in global crude prices, which could negatively impact the global economy, resulting in slower economic growth rates, which could reduce demand for our products;

•

negative impact on the world’s crude oil supply if transportation avenues are disrupted, leading to further commodity price volatility;

•

damage to or destruction of our wells, production facilities, receiving terminals, or other operating assets;

•

inability of our service equipment providers to deliver items necessary for us to conduct our operations in the Middle East;

•

lack of availability of drilling rigs, oilfield equipment, or services if third-party providers decide to exit the region.

Our operations are sensitive to currency rate fluctuations.

Our operations are sensitive to fluctuations in foreign currency exchange rates, particularly between the U.S. dollar and the Canadian dollar, the Australian dollar, and the British Pound. Our financial statements, presented in U.S. dollars, may be affected by foreign currency fluctuations through both translation risk and transaction risk. Volatility in exchange rates may adversely affect our results of operations, particularly through the weakening of the U.S. dollar relative to other currencies.

We face strong industry competition that may have a significant negative impact on our results of operations.

Strong competition exists in all sectors of the oil and gas exploration and production industry. We compete with major integrated and other independent oil and gas companies for acquisition of oil and gas leases, properties, and reserves, equipment, and labor required to explore, develop, and operate those properties, and marketing of oil and natural gas production. Crude oil and natural gas prices impact the costs of properties available for acquisition and the number of companies with the financial resources to pursue acquisition opportunities. Many of our competitors have financial and other resources substantially larger than we possess and have established strategic long-term positions and maintain strong governmental relationships in countries in which we may seek new entry. As a consequence, we may be at a competitive disadvantage in bidding for drilling rights. In addition, many of our larger competitors may have a competitive advantage when responding to factors that affect demand for oil and natural gas production, such as fluctuating worldwide commodity prices and levels of production, the cost and availability of alternative fuels, and the application of government regulations. We also compete in attracting and retaining personnel, including geologists, geophysicists, engineers, and other specialists. These competitive pressures may have a significant negative impact on our results of operations.

Our insurance policies do not cover all of the risks we face, which could result in significant financial exposure.

Exploration for and production of crude oil and natural gas can be hazardous, involving natural disasters and other events such as blowouts, cratering, fire and explosion and loss of well control, which can result in damage to or destruction of wells or production facilities, injury to persons, loss of life, or damage to property and the

environment. Our international operations are also subject to political risk. The insurance coverage that we maintain against certain losses or liabilities arising from our operations may be inadequate to cover any such resulting liability; moreover, insurance is not available to us against all operational risks.

ITEM 1B.

UNRESOLVED STAFF COMMENTS

As of December 31, 2011, we did not have any unresolved comments from the SEC staff that were received 180 or more days prior to year-end.

ITEM 3.

LEGAL PROCEEDINGS

The information set forth under “Legal Matters” and “Environmental Matters” in Note 8—Commitments and Contingencies in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K is incorporated herein by reference.

ITEM 4. MINE SAFETY DISCLOSURES

None.

PART II

ITEM 5.

MARKET FOR THE REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

During 2011, Apache common stock, par value $0.625 per share, was traded on the New York and Chicago Stock Exchanges and the NASDAQ National Market under the symbol “APA.” The table below provides certain information regarding our common stock for 2011 and 2010. Prices were obtained from The New York Stock Exchange, Inc. Composite Transactions Reporting System. Per-share prices and quarterly dividends shown below have been rounded to the indicated decimal place.


	2011								2010
	Price Range				Dividends Per Share				Price Range				Dividends Per Share
	High		Low		Declared		Paid		High		Low		Declared		Paid

First Quarter	$	132.50	$	110.29	$	0.15	$	0.15	$	108.92	$	95.15	$	0.15	$	0.15
Second Quarter		134.13		114.94		0.15		0.15		111.00		83.55		0.15		0.15
Third Quarter		129.26		80.05		0.15		0.15		99.09		81.94		0.15		0.15
Fourth Quarter		105.64		73.04		0.15		0.15		120.80		96.51		0.15		0.15

The closing price of our common stock, as reported on the New York Stock Exchange Composite Transactions Reporting System for January 31, 2012 (last trading day of the month), was $98.88 per share. As of January 31, 2012, there were 384,321,970 shares of our common stock outstanding held by approximately 5,600 stockholders of record and approximately 444,000 beneficial owners.

We have paid cash dividends on our common stock for 47 consecutive years through December 31, 2011. When, and if, declared by our Board of Directors, future dividend payments will depend upon our level of earnings, financial requirements, and other relevant factors.

In 1995, under our stockholder rights plan, each of our common stockholders received a dividend of one preferred stock purchase right (a “right”) for each 2.310 outstanding shares of common stock (adjusted for subsequent stock dividends and a two-for-one stock split) that the stockholder owned. These rights were originally scheduled to expire on January 31, 2006. Effective as of that date, the rights were reset to one right per share of common stock, and the expiration was extended to January 31, 2016. Unless the rights have been previously redeemed, all shares of Apache common stock are issued with rights, which trade automatically with our shares of common stock. For a description of the rights, please refer to Note 9—Capital Stock in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.

Information concerning securities authorized for issuance under equity compensation plans is set forth under the caption “Equity Compensation Plan Information” in the proxy statement relating to the Company’s 2012 annual meeting of stockholders, which is incorporated herein by reference.

The following stock price performance graph is intended to allow review of stockholder returns, expressed in terms of the appreciation of the Company’s common stock relative to two broad-based stock performance indices. The information is included for historical comparative purposes only and should not be considered indicative of future stock performance. The graph compares the yearly percentage change in the cumulative total stockholder return on the Company’s common stock with the cumulative total return of the Standard & Poor’s Composite 500 Stock Index and of the Dow Jones U.S. Exploration & Production Index (formerly Dow Jones Secondary Oil Stock Index) from December 31, 2006, through December 31, 2011. The stock performance graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall information be incorporated by reference into any future filing under the Securities Act of 1933 or Securities Exchange Act of 1934, each as amended, except to the extent that the Company specifically incorporates it by reference into such filing.

LOGO


	2006		2007		2008		2009		2010		2011
Apache Corporation	$	100.00	$	162.91	$	113.67	$	158.58	$	184.36	$	140.80
S & P’s Composite 500 Stock Index		100.00		105.49		66.46		84.05		96.71		98.76
DJ US Expl & Prod Index		100.00		143.67		86.02		120.92		141.16		135.25

ITEM 6.

SELECTED FINANCIAL DATA

The following table sets forth selected financial data of the Company and its consolidated subsidiaries over the five-year period ended December 31, 2011, which information has been derived from the Company’s audited financial statements. This information should be read in connection with, and is qualified in its entirety by, the more detailed information in the Company’s financial statements set forth in Part IV, Item 15 of this Form 10-K. As discussed in more detail under Item 15, the 2009 numbers in the following table reflect a $2.82 billion ($1.98 billion net of tax) non-cash write-down of the carrying value of the Company’s U.S. and Canadian proved oil and gas properties as of March 31, 2009, as a result of ceiling test limitations. The 2008 numbers reflect a $5.3 billion ($3.6 billion net of tax) non-cash write-down of the carrying value of the Company’s U.S., U.K. North Sea, Canadian, and Argentine proved oil and gas properties as of December 31, 2008.


	As of or for the Year Ended December 31,
	2011		2010		2009		2008		2007
	(In millions, except per share amounts)
Income Statement Data
Total revenues	$	16,888	$	12,092	$	8,615	$	12,390	$	9,999
Income (loss) attributable to common stock		4,508		3,000		(292)		706		2,807
Net income (loss) per common share:
Basic		11.75		8.53		(0.87)		2.11		8.45
Diluted		11.47		8.46		(0.87)		2.09		8.39
Cash dividends declared per common share		0.60		0.60		0.60		0.70		0.60

Balance Sheet Data
Total assets	$	52,051	$	43,425	$	28,186	$	29,186	$	28,635
Long-term debt		6,785		8,095		4,950		4,809		4,012
Shareholders’ equity		28,993		24,377		15,779		16,509		15,378
Common shares outstanding		384		382		336		335		333

For a discussion of significant acquisitions and divestitures, see Note 2—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Apache Corporation, a Delaware corporation formed in 1954, is an independent energy company that explores for, develops, and produces natural gas, crude oil, and natural gas liquids. We currently have exploration and production interests in six countries: the U.S., Canada, Egypt, Australia, offshore the United Kingdom in the North Sea, and Argentina. Apache also pursues exploration interests in other countries that may over time result in reportable discoveries and development opportunities.

The following discussion should be read together with the Consolidated Financial Statements and the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K, and the Risk Factors information set forth in Part I, Item 1A of this Form 10-K.

Executive Overview

Strategy

—

balanced portfolio of core assets

—

conservative capital structure

—

rate of return focus

A cornerstone of our strategy is balancing our portfolio through diversity of geologic risk, geographic risk, hydrocarbon mix (crude oil versus natural gas), and reserve life in order to achieve consistency in results. Continued volatility in the commodity price environment reinforces the importance of our balanced portfolio approach. Our 2011 results reflected the benefit of our product balance, as crude oil and liquids combined represented 50 percent of our production but provided 79 percent of our $16.8 billion of oil and gas revenues. Crude oil drove 92 percent of this combined crude and liquids production and 96 percent of the related revenues. International Dated Brent crudes and sweet crude from the Gulf Coast continue to be priced at a significant premium to West Texas Intermediate (WTI)-based prices. As a result of our geographic balance, we are receiving these premium prices on approximately 76 percent of our crude oil production. The advantage of our geographic balance is also reflected in our 2011 natural gas revenues. Over one-third of our natural gas is produced outside of North America, where 2011 prices averaged 27 percent higher than 2010. This balance allowed us to achieve record earnings and cash flow from operations for the year.

Preserving financial flexibility is also important to our overall business philosophy. We believe our balance sheet, and the financial flexibility it provides, is one of our most important strategic assets. It is also key in positioning us to pursue value-creating acquisitions when opportunities arise. During 2011, we reduced debt to $7.2 billion and ended the year with a debt-to-capitalization ratio of 20 percent, down from 25 percent at the end of 2010, despite current-year capital investments of $8 billion and cash payments on acquisitions totaling nearly $2 billion. In addition, we have $3.3 billion of available committed borrowing capacity that provides additional flexibility to our business. Our balance sheet strength, financial flexibility, and record levels of cash flow from operations provide a solid foundation as we continue to integrate recent acquisitions and monetize opportunities in all of our regions.

Each of our operating regions has a significant producing asset base as well as large undeveloped acreage positions, which provide room for growth through sustainable lower-risk drilling opportunities, balanced by higher-risk, higher-reward exploration. We closely monitor drilling and acquisition cost trends in each of our

core areas relative to product prices and, when appropriate, adjust our budgets accordingly. We review capital allocations at least quarterly. We do this through a disciplined and focused process that includes analyzing current economic conditions, projected rate of return on internally-generated drilling prospects, opportunities for tactical acquisitions, land positions with additional drilling prospects, or, occasionally, new core areas that could enhance our portfolio. In addition, we actively seek to identify and pursue ways to maintain efficient levels of costs and expenses. Our overall approach to managing cash expenditures has enabled us to consistently deliver strong results with 2011 return on average capital employed and return on equity of 13 percent and 18 percent, respectively.

Throughout the cycles of our industry, these strategic principles have underpinned our ability to deliver production, reserve growth, and competitive returns on invested capital for the benefit of our shareholders. Delivering successful results under this strategy is bolstered by Apache’s unique culture. A strong sense of urgency, empowerment of our employees, effective incentive systems, and an independent mindset are at the heart of how we build value.

Financial and Operating Results

Apache’s steady commitment to our core strategies drove financial performance throughout 2011. For the 12-month period ending December 31, 2011, Apache reported record performances in several key metrics. Highlights for the year include:

—

Annual daily production of oil, natural gas, and natural gas liquids averaged a record 748 Mboe/d, up 14 percent compared with 2010. Production in fourth-quarter 2011 averaged 759 Mboe/d, an increase of four percent from the 729 Mboe/d averaged in the fourth quarter of 2010.

—

Oil and gas production revenues for 2011 increased 38 percent to $16.8 billion, up from $12.2 billion in 2010, well above our prior record of $12.3 billion achieved in 2008, when we also saw record prices.

—

Apache reported a record $4.5 billion in income attributable to common stock, an increase of over 50 percent compared to $3 billion in 2010. Net income per diluted common share was $11.47 in 2011, up from $8.46 in 2010. Apache’s reported adjusted earnings, which exclude certain items impacting the comparability of results, were $4.7 billion in 2011, an increase of 47 percent from $3.2 billion in 2010. Adjusted earnings per common diluted share were $11.83 in 2011, up from $8.94 in the prior year. Adjusted earnings is not a financial measure prepared in accordance with accounting principles generally accepted in the U.S. (GAAP). For a description of adjusted earnings and a reconciliation of adjusted earnings to income attributable to common stock, the most directly comparable GAAP financial measure, please see “Non-GAAP Measures” in this Item 7.

—

Net cash provided by operating activities (operating cash flows or cash flows) totaled $10.0 billion, up 48 percent from $6.7 billion in 2010.

2012 Outlook

As we head into 2012, we believe our inventory of exploration and development projects offers numerous growth opportunities. Recent drilling successes and continued acquisition of acreage positions in all of our operating regions has built a robust drilling inventory for the Company. Coupled with large-scale development projects currently in progress, our global allocation of capital is critical. Given the present price disparity between oil and natural gas, our near-term focus is exploiting the oil-prone and more liquids-rich properties in our portfolio. Our plan for 2012 also includes development of our gas resources in Australia and Canada to supply our LNG projects, which, if completed, would enable us to monetize these resources at prices more closely linked to crude oil. Rate of return will drive our decision making while we continue our focus on costs, operational efficiency, and integrating recently acquired assets.

Our current 2012 capital budget is approximately $9.5 billion. Nearly $5.3 billion is expected to be spent on projects in North America, with the remaining amount allocated across our international regions. While funds have been committed for certain 2012 exploration drilling, long-lead development projects, and front-end engineering and design (FEED) studies, the majority of our drilling and development projects are discretionary and subject to acceleration, deferral, or cancellation as conditions warrant. We closely monitor commodity prices, service cost levels, regulatory impacts, and numerous other industry factors, and we typically review and revise our exploration and development budgets based on changes to predicted operating cash flows on a quarterly basis.

Apache projects an increase in 2012 production between 7 percent and 13 percent from full-year 2011 production levels, after adjusting for 2011 divestitures. We generally do not budget for acquisitions because they are specific, discrete events whose occurrence and timing is unpredictable. Acquisitions may be funded from operating cash flows, credit facilities, new equity, debt issuances, or a combination thereof.

Operating Highlights

Apache pursues opportunities for growth through exploration, exploitation, and development drilling, supplemented by strategic acquisitions. In 2011, we generated $10 billion of cash flow from operations, which enabled us to deliver on a robust capital budget, investing approximately $8 billion in capital expenditures across all of our regions while paying down nearly $1 billion in debt. We have also been significantly active in the acquisition market for the past two years, having identified several opportunities that met our criteria for risk, reward, rate of return, and growth potential.

Merger and Acquisitions of Property and Acreage

During 2011 and 2010, we completed nearly $14 billion in acquisitions culminating in the purchase of Exxon Mobil Corporation’s North Sea subsidiary, Mobil North Sea Limited. As we head into 2012, Apache continues to be active with recent acquisition announcements in Australia and the Anadarko basin of the central U.S. Each of our acquisitions fits well with our long-term strategy of maintaining a balanced portfolio of core assets by adding high-quality properties with a diversity of geologic and geographic risk, product mix, and reserve life. The properties acquired impacted nine of our ten operating regions and are strategically positioned to benefit from our existing infrastructure and operating experience. For detailed information regarding our recent acquisitions, please see “Significant Acquisitions and Divestitures” in this Item 7 and Note 2—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.

2012 Acquisitions

Central Anadarko basin acquisition Apache announced in January 2012 that we agreed to acquire Cordillera Energy Partners III, LLC (Cordillera), a privately-held company, for approximately 6.3 million shares of Apache common stock and $2.2 billion in cash. The merger is expected to close during the second quarter of 2012.

2011 Acquisitions

North Sea acquisition On December 30, 2011, Apache completed the acquisition of Mobil North Sea Limited from Exxon Mobil Corporation with cash consideration of $1.25 billion.

2010 Acquisitions

Gulf of Mexico Shelf acquisition On June 9, 2010, Apache completed the acquisition of oil and gas assets in the Gulf of Mexico (GOM) shelf from Devon Energy Corporation (Devon) for $1.05 billion.

Canadian acquisition On October 8, 2010, we completed the acquisition of substantially all of BP’s upstream natural gas business in western Alberta and British Columbia for $3.25 billion.

Egyptian acquisition On November 4, 2010, we completed the acquisition of BP’s assets in Egypt’s Western Desert for $650 million.

Exploration, Exploitation and Development Activities

Our internally-generated exploration and drilling opportunities, multi-year development projects, and recent acquisitions provide the foundation for our growth in the near- and long-term. Highlights of our 2011 drilling successes, exploration discoveries, LNG project milestones, and other opportunities for continued growth include:

International Activities

North Sea Drilling and Exploitation New 4-D seismic interpretation derived from the latest 3-D seismic survey acquired over the Forties field in 2010 highlighted areas of bypassed oil. During 2011, we drilled 14 wells, of which 11 were productive. The Charlie 4-3 well commenced production in June at a rate of 12,567 b/d, and the Charlie 2-2 well was completed in March with an initial rate of 11,876 b/d. These wells represent some of the highest rates in the Forties field since the early 1990s.

North Sea Satellite Platform Project Construction of the Forties Alpha Satellite Platform is underway and is projected to be complete by the third quarter of 2012. This platform will sit adjacent to the main Alpha platform and will provide Apache with 18 new slots for drilling additional development wells to increase the ultimate recovery from the Forties field. The satellite platform will also expand critical utility services to the field, including power generation, produced fluid processing, high-pressure gas compression for artificial lift and dehydration.

Egypt Discoveries Apache’s Egyptian operations continue to expand further into the Western Desert and achieved a record for annual production in 2011. We maintained an active drilling and development program throughout 2011, drilling 221 exploration, development, and injector wells, resulting in 33 new field discoveries. Most notably, we drilled the first Paleozoic discovery at Tayim West, which test-flowed at 3,600 b/d. This Paleozoic discovery opens a new play deeper than previous discoveries in the Western Desert and provides for continued exploration opportunities. We also made our first discovery in the Siwa Concession, our western-most concession in Egypt, with the Siwa D-1X well that flowed at 4,490 b/d and 8 MMcf/d. In addition to increased drilling activity, we continue to assess opportunities to leverage existing processing and transportation infrastructure at the BP-acquired Abu Gharadig field complex and expand our processing facilities in the Faghur and Matruh basins.

Argentina Exploration Apache’s first horizontal well in the Anticlinal Campamento field in the Neuquén basin began producing at a rate over 10 MMcf/d. The well was a test of horizontal drilling and multi-stage hydraulic fracturing in the low-permeability Pre-Cuyo formation. Apache continues to evaluate the potential of tight and unconventional gas resources in the Pre-Cuyo, Los Molles, and Vaca Muerta formations of the Neuquén basin, which is supported by higher gas prices realized under the Gas Plus program. In 2011, the average Gas Plus volume sold by Apache was 55.1 MMcf/d at an average price of $4.89 per Mcf.

Australia Exploration Ongoing exploration activity at the Julimar and Brunello complex resulted in the discovery of a deeper Mungaroo gas formation encountering 362 feet of net pay. This 65-percent working interest Balnaves Deep well is associated with continuing field development efforts and augments previous discoveries. Separately, the Zola-1 natural gas discovery logged 410 feet of net pay and is on trend with the Gorgon gas field 16 miles to the north and near both existing and developing infrastructure. The evaluation of the 30-percent working interest discovery, including the planning of future appraisal drilling, is underway.

Australia Reindeer Field Development and Devil Creek Gas Plant Development of our Reindeer gas field and construction of the Devil Creek Gas Plant was completed in December 2011. Gas production from the Reindeer development has been sold to a number of customers in Western Australia’s growing mining and minerals processing sectors at prices significantly higher than current realizations. Apache owns a 55-percent interest in the field and is the operator.

Australia Halyard Field Development Initial production from our Halyard-1 discovery well commenced in June 2011 upon completion of the tie-in to the existing gas facilities on Varanus Island. The Halyard development was completed ahead of schedule and set the stage for further development of our nearby Spar field. The 2010 Spar-2 discovery is projected to commence production in 2013 through an extension of the Halyard subsea infrastructure that will also allow for the tie-in of future wells.

Australia Macedon Field Development First production is also projected in 2013 from four completed gas wells in the Macedon gas field. We have a 29-percent non-operating working interest in the field. Gas will be delivered via a 60-mile pipeline to a 200 MMcf/d gas plant to be built at Ashburton North in Western Australia. The project, approved in 2010, is currently underway.

Australia Coniston Oil Field Development The Coniston field is an oil accumulation near our Van Gogh field in Australia. The project was sanctioned for development in 2011 with first production projected in 2013. Apache operates the field with a 52.5-percent working interest and expects peak production to be approximately 30 Mb/d. The field will be produced via subsea completions tied back to the Ningaloo Vision floating production storage and offloading vessel (FPSO) that services Apache’s Van Gogh oil field. To more effectively control the Van Gogh and Coniston field operations, development, and maintenance efforts, this FPSO (the Ningaloo Vision) was purchased from the previous lessor in January 2012 for $185 million, $97 million net to Apache.

Australia Balnaves Oil Development In 2011, the Company announced that it will proceed with development of the offshore Balnaves field, an oil accumulation located in a separate reservoir within the large gas reservoirs of our Brunello gas fields. The project is expected to deliver initial gross production of 30 Mb/d in 2014 through a leased FPSO. Apache has a 65-percent working interest in the operated project.

Australia Wheatstone LNG Project During 2011, the Company and its partners announced they will proceed with the Chevron-operated Wheatstone LNG development project (Wheatstone) in Western Australia. The first phase of the Wheatstone project will comprise two LNG processing trains with a combined capacity of approximately 8.9 million metric tons per annum (mtpa), a domestic gas plant, and associated infrastructure. Apache has a 13-percent interest in the project and expects to invest approximately $4 billion over five years for the field and LNG facility development. Apache will supply gas to Wheatstone from its operated Julimar and Brunello complex, which was approved for development by the Australian government in September 2011. The 65-percent interest Julimar development project is expected to generate average net sales to Apache of

approximately 140 MMcf/d of gas (equivalent to 1.07 million mtpa of LNG) at prices pegged to world oil markets, 22 MMcf/d of sales gas into the domestic market, and 3,250 barrels of condensate per day. First production is projected for 2016.

North America Activities

Permian Basin Gas Plant Development During 2011, Apache agreed with Crosstex Energy, L.P. to jointly build an $85 million natural gas processing facility for our Deadwood development in the Permian Basin of west Texas. The plant, in which Apache has a 50-percent interest, is anticipated to become fully operational in the second quarter of 2012, with capacity of 50 MMcf/d. This infrastructure will enable Apache to continue its active development program targeting multiple stacked formations, including the Wolfcamp, Cline, Strawn, Atoka, and Fusselman.

North America Horizontal Drilling Apache continues to evaluate horizontal drilling potential across our acreage positions, in both conventional and unconventional reservoirs. In the Permian Basin, Apache is utilizing horizontal drilling to access bypassed, unswept oil zones in established waterfloods. The identification and development of significant resources in shale formations and other unconventional gas plays has also been the focus of drilling opportunities during 2011. Natural gas production growth in North America will likely be driven by our activity in three large unconventional plays: shale gas in British Columbia’s Horn River basin, tight sands in British Columbia’s Noel area, and the liquids-rich Granite Wash tight sands in the Anadarko basin of Oklahoma and the Texas Panhandle.

Kitimat LNG Project The time horizon and magnitude of Apache’s shale gas development will be impacted by North American gas prices and investment decisions surrounding our ownership in the Kitimat LNG facility and a related proposed pipeline. The project has the potential to open new markets linked to oil prices in the Asia-Pacific region for gas from Apache’s Canadian operations. In October 2011, Apache and its partners in the Kitimat LNG project announced that the National Energy Board granted the project a 20-year export license to ship LNG from Canada to international markets. This export approval represents a major milestone for Kitimat LNG and its partners. In addition, the Company progressed with the FEED study and continued efforts to secure firm sales commitments and required permits necessary to make a final investment decision on the LNG project.

Alaska Cook Inlet Acreage During 2011, Apache continued to accumulate acreage in Alaska’s Cook Inlet and was the successful bidder on approximately 515,000 acres of onshore and offshore state leases. The Company has now accumulated approximately 800,000 gross acres in the Cook Inlet. We have current plans to conduct a seismic survey for the area and drill a well within the next 12 months.

Gulf of Mexico Deepwater Exploration Apache’s strategic presence in the Gulf of Mexico deepwater portfolio was gained through the 2010 merger with Mariner Energy, Inc. At the end of 2011, the Company held approximately 750,000 gross acres across 148 blocks. The Bushwood, Wide Berth, and Mandy development projects are expected to begin production in the second quarter of 2012, with combined net initial production of 12 Mboe/d. In addition, the larger scale non-operated Lucius project was sanctioned in the fourth quarter of 2011. Apache has an 11.7-percent working interest in this development, with first production projected for 2014. We also plan to increase our exploration activity in 2012, having recently been awarded four deepwater exploration plans. We expect to drill or participate in drilling nine wells during 2012 compared with two wells drilled in the current year.

Significant Events

Egypt Political Unrest

In February 2011, former Egyptian president Hosni Mubarak stepped down, and the Egyptian Supreme Council of the Armed Forces took power. In November 2011, Egypt held its first round of parliamentary elections. Despite the Muslim Brotherhood’s Freedom and Justice Party’s victory in the parliamentary elections,

Egypt remains under martial law. Although Egypt’s first post-revolutionary parliament convened on January 23, 2012, the new Parliament remains subordinate to the Egyptian Supreme Council of the Armed Forces, which has stated its intention to turn over power to civilians following the presidential election expected in June 2012. Apache’s operations, located in remote locations in the Western Desert, have continued uninterrupted, and we currently plan to invest $1 billion in Egypt in 2012.

Our operations in Egypt contributed 22 percent of our 2011 production and accounted for 10 percent of our year-end estimated proved reserves. At year-end 2011, 17 percent of our estimated discounted future net cash flows and 7.5 percent of our net capitalized oil and gas property was attributable to Egypt. For further information regarding our Egypt region, please see Note 13—Business Segment Information and Note 14—Supplemental Oil and Gas Disclosures (Unaudited) in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.

Apache purchases multi-year political risk insurance from the Overseas Private Investment Corporation (OPIC) and other highly-rated international insurers covering its investments in Egypt. In the aggregate, these policies, subject to the policy terms and conditions, provide approximately $1 billion of coverage to Apache for losses arising from confiscation, nationalization, and expropriation risks, with a $237.5 million sub-limit for currency inconvertibility. In addition, the Company has a separate policy with OPIC, which provides $225 million of coverage, including a self-insured retention of $37.5 million, for losses arising from (1) non-payment by EGPC of arbitral awards covering amounts owed Apache on past due invoices and (2) expropriation of exportable petroleum when actions taken by the government of Egypt prevent Apache from exporting our share of production.

A deterioration in the political, economic, and social conditions or other relevant policies of the Egyptian government, such as changes in laws or regulations, export restrictions, expropriation of our assets or resource nationalization, and/or forced renegotiation or modification of our existing contracts with EGPC, could materially and adversely affect our business, financial condition, and results of operations.

Potential Pipeline Capacity Constraints on North Sea Production

On April 8, 2011, BP Exploration Operating Company Limited (BP Exploration) sent a letter to Apache North Sea Limited alleging the potential for capacity constraints or increased tariffs relating to the Shippers Pipeline Liquids Transportation and Processing Agreement, dated January 11, 2003, between BP Exploration and Apache North Sea Limited. Apache North Sea Limited disagrees with the characterizations in the letter and will contest them vigorously. However, because this matter is unresolved, resolution of this matter, through litigation or otherwise, and/or forced renegotiation or modification of our existing contract with BP Exploration could, in the future, adversely affect our production and revenues from the Forties Field in the North Sea.

Argentina Tax and Royalty Claims

ENARGAS, an autonomous entity that functions under the Argentina Ministry of Economy, has issued administrative orders creating a tariff charge on all fuel gas used by oil and gas producers in field operations effective December 1, 2011. The tariff charge is applicable to the operations of Company affiliates in Argentina and could cost approximately $21 million annually. In addition, in late 2010 and early 2011, the Province of Tierra del Fuego notified Company affiliates of its claims for additional royalty on natural gas, crude oil, and liquefied petroleum gas. The Company’s affiliates have initiated legal proceedings challenging both ENARGAS’ tariff charge and the Province’s claims for additional royalty.

Results of Operations

Oil and Gas Revenues


	For the Year Ended December 31,
	2011				2010				2009
	$ Value		% Contribution		$ Value		% Contribution		$ Value		% Contribution
	(In millions)				(In millions)				(In millions)
Oil Revenues:
United States	$	4,163		33%	$	2,683		30%	$	1,922		32%
Canada		485		4%		388		4%		311		5%

North America		4,648		37%		3,071		34%		2,233		37%

Egypt		4,169		33%		2,875		32%		2,063		34%
Australia		1,552		12%		1,296		14%		230		4%
North Sea		2,072		16%		1,590		18%		1,356		22%
Argentina		238		2%		209		2%		207		3%

International		8,031		63%		5,970		66%		3,856		63%

Total ⁽¹⁾	$	12,679		100%	$	9,041		100%	$	6,089		100%


Natural Gas Revenues:
United States	$	1,550		43%	$	1,409		49%	$	1,054		44%
Canada		1,033		29%		647		23%		546		23%

North America		2,583		72%		2,056		72%		1,600		67%

Egypt		621		17%		495		17%		490		21%
Australia		182		5%		163		6%		133		6%
North Sea		19		0%		16		0%		13		0%
Argentina		204		6%		132		5%		133		6%

International		1,026		28%		806		28%		769		33%

Total ⁽²⁾	$	3,609		100%	$	2,862		100%	$	2,369		100%


Natural Gas Liquids (NGL) Revenues:
United States	$	391		75%	$	208		74%	$	74		64%
Canada		99		19%		39		14%		20		17%

North America		490		94%		247		88%		94		81%

Egypt		1		0%		2		1%		–		0%
Argentina		31		6%		31		11%		22		19%

International		32		6%		33		12%		22		19%

Total	$	522		100%	$	280		100%	$	116		100%


Total Oil and Gas Revenues:
United States	$	6,104		36%	$	4,300		35%	$	3,050		36%
Canada		1,617		10%		1,074		9%		877		10%

North America		7,721		46%		5,374		44%		3,927		46%

Egypt		4,791		29%		3,372		28%		2,553		30%
Australia		1,734		10%		1,459		12%		363		4%
North Sea		2,091		12%		1,606		13%		1,369		16%
Argentina		473		3%		372		3%		362		4%

International		9,089		54%		6,809		56%		4,647		54%

Total	$	16,810		100%	$	12,183		100%	$	8,574		100%

⁽¹⁾	Financial derivative hedging activities and the North Sea fixed-price sales contract decreased 2011 and 2010 oil revenues by $379 million and $57 million, respectively, and increased 2009 oil revenues by $45 million.

⁽²⁾	Financial derivative hedging activities increased natural gas revenues for 2011, 2010, and 2009 by $272 million, $222 million, and $136 million, respectively.

Production


	For the Year Ended December 31,
	2011		Increase (Decrease)		2010		Increase (Decrease)		2009
Oil Volume – b/d:
United States		119,415		+24%		96,576		+8%		89,133
Canada		14,252		-2%		14,581		-4%		15,186

North America		133,667		+20%		111,157		+7%		104,319

Egypt		103,912		+5%		99,122		+8%		92,139
Australia		38,228		-17%		45,908		+369%		9,779
North Sea		54,541		-4%		56,791		-7%		60,984
Argentina		9,597		-4%		9,956		-13%		11,505

International		206,278		-3%		211,777		+21%		174,407

Total ⁽¹⁾		339,945		+5%		322,934		+16%		278,726

Natural Gas Volume – Mcf/d:
United States		864,742		+18%		730,847		+10%		666,084
Canada		632,550		+60%		396,005		+10%		359,235

North America		1,497,292		+33%		1,126,852		+10%		1,025,319

Egypt		365,418		-3%		374,858		+3%		362,618
Australia		185,079		-7%		199,729		+9%		183,617
North Sea		2,284		-4%		2,391		-12%		2,703
Argentina		212,311		+15%		184,830		0%		184,557

International		765,092		+0%		761,808		+4%		733,495

Total ⁽²⁾		2,262,384		+20%		1,888,660		+7%		1,758,814

NGL Volume – b/d:
United States		22,111		+60%		13,777		+125%		6,136
Canada		5,958		+107%		2,884		+38%		2,089

North America		28,069		+68%		16,661		+103%		8,225

Egypt		49		N/A		82		N/A		–
North Sea		4		N/A		–		N/A		–
Argentina		3,018		-5%		3,180		-2%		3,241

International		3,071		-6%		3,262		+1%		3,241

Total		31,140		+56%		19,923		+74%		11,466

BOE per day ⁽³⁾
United States		285,650		+23%		232,161		+13%		206,284
Canada		125,636		+51%		83,466		+8%		77,147

North America		411,286		+30%		315,627		+11%		283,431

Egypt		164,864		+2%		161,680		+6%		152,575
Australia		69,074		-13%		79,196		+96%		40,382
North Sea		54,925		-4%		57,190		-7%		61,435
Argentina		48,000		+9%		43,941		-3%		45,505

International		336,863		-2%		342,007		+14%		299,897

Total		748,149		+14%		657,634		+13%		583,328

⁽¹⁾	Approximately 29 percent of 2011 oil production was subject to financial derivative hedges, compared to 12 percent in 2010 and 10 percent in 2009.

⁽²⁾	Approximately 16 percent of 2011 gas production was subject to financial derivative hedges, compared to 23 percent in 2010 and nine percent in 2009.

⁽³⁾	The table shows production on a boe basis in which natural gas is converted to an equivalent barrel of oil based on a 6:1 energy equivalent ratio. This ratio is not reflective of the current price ratio between the two products.

Pricing


	For the Year Ended December 31,
	2011		Increase (Decrease)	2010		Increase (Decrease)	2009
Average Oil Price – Per barrel:
United States	$	95.51	+25%	$	76.13	+29%	$	59.06
Canada		93.19	+28%		72.83	+30%		56.16
North America		95.27	+26%		75.69	+29%		58.64
Egypt		109.92	+38%		79.45	+30%		61.34
Australia		111.22	+44%		77.32	+20%		64.42
North Sea		104.09	+36%		76.66	+26%		60.91
Argentina		68.02	+18%		57.47	+16%		49.42
International		106.67	+38%		77.21	+27%		60.58
Total ⁽¹⁾		102.19	+33%		76.69	+28%		59.85
Average Natural Gas Price – Per Mcf:
United States	$	4.91	-7%	$	5.28	+22%	$	4.34
Canada		4.47	0%		4.48	+7%		4.17
North America		4.72	-6%		5.00	+17%		4.28
Egypt		4.66	+29%		3.62	-2%		3.70
Australia		2.69	+20%		2.24	+13%		1.99
North Sea		22.25	+19%		18.64	+42%		13.15
Argentina		2.64	+35%		1.96	0%		1.96
International		3.67	+27%		2.90	+1%		2.87
Total ⁽²⁾		4.37	+5%		4.15	+12%		3.69
Average NGL Price – Per barrel:
United States	$	48.42	+17%	$	41.45	+26%	$	33.02
Canada		45.72	+25%		36.61	+43%		25.54
North America		47.85	+18%		40.62	+31%		31.12
Egypt		66.36	N/A		69.75	N/A		–
North Sea		65.45	N/A		–	N/A		–
Argentina		27.90	+3%		27.08	+44%		18.76
International		28.56	+1%		28.15	+50%		18.76
Total		45.95	+19%		38.58	+40%		27.63

⁽¹⁾	Reflects per-barrel decrease of $3.05 and $0.48 in 2011 and 2010, respectively, and an increase of $0.44 in 2009 from financial derivative hedging activities and the North Sea fixed-price sales contract.

⁽²⁾	Reflects per-Mcf increase of $0.33, $0.32, and $0.21 in 2011, 2010, and 2009, respectively, from financial derivative hedging activities.

Crude Oil Prices

A substantial portion of our oil production is sold at prevailing market prices, which fluctuate in response to many factors that are outside of the Company’s control. Prices we received for crude oil in 2011 were 33 percent above 2010, with political unrest and economic uncertainty increasing market volatility.

Continued volatility in the commodity price environment reinforces the importance of our balanced portfolio approach. International Dated Brent crudes and sweet crude from the Gulf Coast continue to be priced at a significant premium to WTI-based prices. We are realizing these premium prices on approximately 76 percent of our crude oil production. Crude oil prices realized in 2011 averaged $102.19 per barrel, compared with $76.69 per barrel in 2010. Our Egypt, Australia, and North Sea regions, which comprise 58 percent of our worldwide oil production and receive Dated Brent premiums, had 2011 oil realizations averaging $108.55 per barrel compared with 2010 oil realizations of $78.18 per barrel. Our Gulf Coast regions, which comprise 18 percent of our worldwide oil production and receive similar premiums, had price realizations averaging $108.26 per barrel, an increase of 37 percent over 2010 realizations of $79.00 per barrel.

Crude oil tends to trade at a global price. With the exception of Argentina, price movements for all types and grades of crude oil generally move in the same direction. In Argentina, we currently sell our oil in the domestic market. The Argentine government imposes a sliding-scale tax on oil exports, which significantly influences prices domestic buyers are willing to pay. Domestic oil prices are currently indexed to a $42 per barrel base price, subject to quality adjustments and local premiums, and producers realize a gradual increase or decrease as market prices deviate from the base price. In Tierra del Fuego, similar pricing formulas exist; however, Apache retains the value-added tax collected from buyers, effectively increasing realized prices by 21 percent. As a result, 2011 oil prices realized from Tierra del Fuego oil production averaged $65.03 per barrel as compared to our Neuquén basin production, which averaged $53.68 per barrel.

Apache uses financial instruments to manage a portion of its exposure to fluctuations in crude oil prices, particularly in North America. In 2011, 29 percent of our oil production was subject to financial derivative hedges, reducing revenues by $379 million. In 2010, 12 percent of our oil production was subject to financial derivative hedges, reducing revenues by $57 million. For the year-end status of our derivatives, please see Note 3—Derivative Instruments and Hedging Activities in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.

Natural Gas Prices

Natural gas, which currently has a limited global transportation system, is subject to price variances based on local supply and demand conditions. The majority of our gas sales contracts are indexed to prevailing local market prices, which again illustrates the importance of a geographically balanced portfolio.

Apache primarily sells natural gas into the North American market, where realized prices decreased six percent compared to 2010; however, approximately one-third of our natural gas is produced outside North America, where our average contracted prices rose 27 percent from 2010. Our primary markets include North America, Egypt, Australia, and Argentina. An overview of the market conditions in our primary gas-producing regions follows.

•

North America has a common market; most of our gas is sold on a monthly or daily basis at either monthly or daily market prices.

•

In Egypt, our gas is sold to EGPC, primarily under an industry pricing formula indexed to Dated Brent crude oil with a maximum gas price of $2.65 per MMBtu. Under a legacy oil-indexed contract, which expires at the end of 2012, there is no price cap for our gas up to 100 MMcf/d of gross production. Overall, the region averaged $4.66 per Mcf in 2011.

•

Australia has historically had a local market with a limited number of buyers and sellers resulting in mostly long-term, fixed-price contracts that are periodically adjusted for changes in the local consumer price index. Recent increases in demand and higher development costs have increased the prices required from the local market in order to support the development of new supplies. As a result, market prices received on recent contracts are substantially higher than historical levels.

•

Argentina instituted the Gas Plus program in 2008 to encourage new gas supplies through the development of conventional and unconventional (tight sands) reserves. Under this program, Apache is allowed to sell gas from qualifying projects at prices that are above the regulated rates. During 2011, the average Gas Plus volume sold by Apache was 55.1 MMcf/d at an average price of $4.89 per Mcf. In addition, Apache signed or extended Gas Plus contracts with industrial consumers totaling gross rates of 15.5 MMcf/d at $4.28 per Mcf through December 31, 2012.

Separate from the Gas Plus program, Apache sells volumes under Argentina’s government-regulated pricing and into Argentina’s unregulated market. The volumes we are required to sell at regulated prices are set by the government and vary with seasonal factors and industry category. During 2011, we realized an average price of $1.06 per Mcf on government-regulated sales and an average price of $3.14 per Mcf on our unregulated market sales.

Apache uses a variety of fixed-price contracts and derivatives to manage our exposure to fluctuations in natural gas prices, primarily in North America. In 2011, 16 percent of our gas production was subject to financial derivative hedges, increasing revenues by $272 million. In 2010, 23 percent of our gas production was subject to financial derivative hedges, increasing revenues by $222 million. For the year-end status of our derivatives, please see Note 3—Derivative Instruments and Hedging Activities in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K. For more specific information on marketing arrangements by country, please refer to Part I, Items 1 and 2—Business and Properties of this Form 10-K.

Crude Oil Revenues

2011 vs. 2010 During 2011, crude oil revenues totaled $12.7 billion, $3.7 billion higher than the 2010 total of $9.0 billion, driven by a 33-percent increase in average realized prices and a five-percent increase in worldwide production. Average daily production in 2011 was 339.9 Mb/d, with prices averaging $102.19 per barrel. Crude oil represented 75 percent of our 2011 oil and gas production revenues and 45 percent of our equivalent production, compared to 74 and 49 percent, respectively, in the prior year. Higher realized prices contributed $3.0 billion to the increase in full-year revenues, while higher production volumes added another $0.7 billion.

Worldwide oil production increased 17.0 Mb/d, driven by a 22.8 Mb/d increase in the US. The Permian region was up 11.6 Mb/d on properties added from the BP acquisitions, the Mariner merger and drilling and recompletion activity, offset by natural decline. The GOM onshore and offshore regions added 8.0 Mb/d as production from the Devon acquisition, the Mariner merger and drilling and recompletion activity was partially offset by natural decline. Central region production increased 3.2 Mb/d on drilling and recompletion activity. Egypt’s gross oil production increased 15 percent from additional capacity at the Kalabsha oil processing facility, a successful drilling and recompletion program, and volumes acquired in the 2010 BP acquisition. Egypt’s net production was up only five percent, as higher oil prices impact our cost recovery volumes. Australia production decreased 7.7 Mb/d as a result of repairs to the Van Gogh FPSO vessel, natural decline, and tropical cyclones in the first quarter of 2011.

2010 vs. 2009 During 2010, crude oil revenues totaled $9.0 billion, $2.9 billion higher than the 2009 total of $6.1 billion, driven by a 16-percent increase in worldwide production and a 28-percent increase in average realized prices. Average daily production in 2010 was 322.9 Mb/d, with prices averaging $76.69 per barrel. Crude oil represented 74 percent of our 2010 oil and gas production revenues and 49 percent of our equivalent production, compared to 71 percent and 48 percent, respectively, in the prior year. Higher realized prices contributed $1.7 billion to the increase in full-year revenues, while higher production volumes added another $1.2 billion.

Worldwide oil production increased 44.2 Mb/d, driven by a 36.1 Mb/d increase in Australia on new production from the Van Gogh and Pyrenees discoveries, which were brought online in the first quarter of 2010. U.S. production increased eight percent, or 7.4 Mb/d, with the Permian region up 4.4 Mb/d on properties added from the BP acquisitions, the Mariner merger, and drilling and recompletion activity. The Gulf Coast region added 1.8 Mb/d from properties acquired in the Devon acquisition, the Mariner merger, and drilling and recompletion activity. Central region production increased 1.2 Mb/d on drilling and recompletion activity. Gross production in Egypt increased 17 percent, while net production was up only eight percent, a function of the mechanics of our production-sharing contracts. Net production increased 7.0 Mb/d on production gains in the Shushan, Matruh and numerous other concessions. Additional capacity at the Kalabsha oil processing facility, as well as processing of condensate-rich gas through the Salam Gas Plant allowed by the new Jade manifold, allowed for much of the production gains. North Sea production decreased 4.2 Mb/d on natural decline and downtime.

Natural Gas Revenues

2011 vs. 2010 Natural gas revenues for 2011 of $3.6 billion were $747 million higher than 2010 on a five-percent increase in realized prices and a 20-percent increase in production volumes. Realized prices in 2011 averaged $4.37 per Mcf, an increase of $0.22 per Mcf, which added $150 million to revenues. Worldwide production rose 374 MMcf/d, adding another $597 million to revenues.

Worldwide gas production rose 20 percent, driven by a 236.5 MMcf/d, or 60 percent, increase in Canada on additional volumes from properties acquired from BP and an active drilling and completion program. U.S. daily production was up 133.9 MMcf/d, or 18 percent, primarily a result of 2010 acquisition activity. GOM onshore and offshore regions production rose 73.4 MMcf/d on new drilling activity and properties acquired from Devon and the Mariner merger. Permian region production was up 56.4 MMcf/d on incremental volumes from properties added from the BP acquisition and Mariner merger and on increased drilling activity. Argentina’s production was up 27 MMcf/d from drilling and recompletions. Daily gas production in Australia fell 14.7 MMcf/d on downtime from tropical cyclones and customer maintenance activities resulting in lower takes under our existing contractual arrangements. Egypt’s gross production was up eight percent on a successful drilling program, additional gas throughput at the Obaiyed Gas Plant, and production from properties added in the BP acquisition. Net production was down three percent, as higher prices impacted our cost recovery volumes.

2010 vs. 2009 Natural gas revenues for 2010 of $2.9 billion were $493 million higher than 2009 on a 12-percent increase in realized prices and a seven-percent increase in production volumes. Realized prices in 2010 averaged $4.15 per Mcf, an increase of $0.46 per Mcf, which added $297 million to revenues. Worldwide production rose 130 MMcf/d, adding another $197 million to revenues.

Worldwide gas production rose in all of our core gas-producing regions. U.S. production was up 64.8 MMcf/d, or 10 percent. Driven by new drilling, recompletion activity, and properties acquired from Devon and the Mariner merger, Gulf Coast region production was up 38.2 MMcf/d. Permian region production was up 20.1 MMcf/d, primarily on volumes from properties acquired from BP. Central region production was up 6.5 MMcf/d as additional production from new drilling and recompletions outpaced natural decline. Canada region production increased 36.8 MMcf/d as the result of an active drilling and completion program at Horn River and additional volumes from properties acquired from BP. Production in Australia was up 16.1 MMcf/d on higher customer takes from our John Brookes field. In Egypt, gross production was up 14 percent, while net production rose only three percent, a function of our production-sharing contracts. The 12.2 MMcf/d increase in net production relative to 2009 was attributable to several factors, including a successful drilling and recompletion program on our Matruh concession, additional volumes processed through the Obaiyed Gas Plant and a full year of additional capacity provided by the completion of two new gas trains at the Salam Gas Plant. Argentina’s production was up marginally as production from new drilling and recompletions was mostly offset by natural decline.

Operating Expenses

The table below presents a comparison of our expenses on an absolute dollar basis and an equivalent unit of production (boe) basis. Our discussion may reference expenses on a boe basis, on an absolute dollar basis or both, depending on context.


	Year Ended December 31,						Year Ended December 31,
	2011		2010		2009		2011		2010		2009
	(In millions)						(Per boe)
Depreciation, depletion and amortization:
Oil and gas property and equipment
Recurring	$	3,814	$	2,861	$	2,202	$	13.97	$	11.92	$	10.34
Additional		109		–		2,818		.40		–		13.24
Other assets		281		222		193		1.03		.92		.91
Asset retirement obligation accretion		154		111		105		.56		.46		.49
Lease operating expenses		2,605		2,032		1,662		9.54		8.47		7.81
Gathering and transportation		296		178		143		1.08		.73		.67
Taxes other than income		899		690		580		3.29		2.88		2.72
General and administrative expenses		459		380		344		1.68		1.58		1.62
Merger, acquisitions & transition		20		183		–		.07		.77		–
Financing costs, net		158		229		242		.58		.95		1.13

Total	$	8,795	$	6,886	$	8,289	$	32.20	$	28.68	$	38.93

Depreciation, Depletion and Amortization

The following table details the changes in recurring depreciation, depletion and amortization (DD&A) of oil and gas properties between December 31, 2011 and December 31, 2009:


	Recurring DD&A
	(In millions)
2009	$	2,202
Volume change		317
Rate change		342

2010	$	2,861
Volume change		349
Rate change		604

2011	$	3,814

2011 vs. 2010 Recurring full-cost depletion expense increased $953 million on an absolute dollar basis: $604 million on higher rate and $349 million from additional production. Our full-cost depletion rate increased $2.05 to $13.97 per boe as costs to acquire, find, and develop reserves, which were significantly impacted by higher oil prices, exceeded our historical cost basis. In 2011, additional depletion expense of $60 million was

associated with the write-off of the carrying value of our Chilean oil and gas property leases relinquished during 2011, and $49 million was associated with impairments of new venture seismic activity in countries where Apache is pursuing exploration opportunities but has not yet established a presence. Other asset depreciation increased $59 million over 2010 primarily on higher other asset balances from 2010 acquisitions.

2010 vs. 2009 Recurring full-cost depletion expense increased $659 million on an absolute dollar basis: $342 million on higher rate and $317 million from additional production. Our full-cost depletion rate increased $1.58 to $11.92 per boe as costs to acquire, find, and develop reserves exceeded our historical cost basis. In 2009, additional depletion expense of approximately $2.8 billion was associated with a non-cash write-down of the carrying value of our March 31, 2009, proved oil and gas property balances in the U.S. and Canada.

Lease Operating Expenses

Lease operating expenses (LOE) include several components: direct operating costs, repair and maintenance, and workover costs.

Direct operating costs generally trend with commodity prices and are impacted by the type of commodity produced and the location of properties (i.e., offshore, onshore, remote locations, etc.). Fluctuations in commodity prices impact operating cost elements both directly and indirectly. They directly impact costs such as power, fuel, and chemicals, which are commodity price based. Commodity prices also affect industry activity and demand, thus indirectly impacting the cost of items such as labor, boats, helicopters, materials, and supplies. Oil, which contributed nearly half of our production, is inherently more expensive to produce than natural gas. Repair and maintenance costs are typically higher on offshore properties, which account for all of our production in Australia and the North Sea and 86 percent of our production from the U.S. Gulf Coast regions, and in areas with remote plants and facilities. Workovers accelerate production; hence, activity generally increases with higher commodity prices. Foreign exchange rate fluctuations generally impact the Company’s LOE, with a weakening U.S. dollar adding to per-unit costs and a strengthening U.S. dollar lowering per-unit costs in our international regions.

The following table details the LOE rate impact by component:


For the Year Ended December 31, 2011			For the Year Ended December 31, 2010
	Per boe			Per boe
2010 LOE	$	8.47	2009 LOE	$	7.81
Acquisitions, net of associated production		(0.02)	Acquisitions, net of associated production		0.27
FX impact		0.23	FX impact		0.22
Labor and pumper costs		0.21	Equipment rental		0.22
Workover costs		0.18	Workover costs		0.16
Chemicals, power, and fuel		0.13	Stock-based compensation		0.14
Transportation		0.11	Labor and pumper costs		0.08
Other		0.12	Material		0.07
Other decreased production		0.11	Chemicals, power, and fuel		0.07

2011 LOE	$	9.54	Other		0.20

			Other increased production		(0.77)

			2010 LOE	$	8.47

2011 vs. 2010 Our 2011 LOE increased $573 million from 2010, or 28 percent. On a per-unit basis, LOE increased 13 percent due to higher costs on the items listed above.

2010 vs. 2009 Our 2010 LOE increased $370 million from 2009, or 22 percent. On a per-unit basis, LOE increased eight percent with a 22 percent increase on higher costs, offset by a 14 percent decline related to increased production. The rate was impacted by the items listed above.

Gathering and Transportation

We generally sell oil and natural gas under two common types of agreements, both of which include a transportation charge. One is a netback arrangement, under which we sell oil or natural gas at the wellhead and collect a lower relative price to reflect transportation costs to be incurred by the purchaser. In this case, we record sales at the netback price received from the purchaser. Alternatively, we sell oil or natural gas at a specific delivery point, pay our own transportation to a third-party carrier, and receive a price with no transportation deduction. In this case, we record the separate transportation cost as gathering and transportation costs.

In the U.S., Canada, and Argentina, we sell oil and natural gas under both types of arrangements. In the North Sea, we pay transportation charges to a third-party carrier. In Australia, oil and natural gas are sold under netback arrangements. In Egypt, our oil and natural gas production is primarily sold to EGPC under netback arrangements; however, we also export crude oil under both types of arrangements.

The following table presents gathering and transportation costs we paid directly to third-party carriers for each of the periods presented:


	For the Year Ended December 31,
	2011		2010		2009
	(In millions)
U.S.	$	64	$	42	$	36
Canada		166		75		53
North Sea		25		25		26
Egypt		34		31		23
Argentina		7		5		5

Total Gathering and Transportation	$	296	$	178	$	143

2011 vs. 2010 Gathering and transportation costs increased $118 million from 2010. Canada’s expense increased $91 million from a combination of an increase in gas volumes, higher average rates, and foreign exchange impacts. Average per-unit costs were directly influenced by Apache’s increased production in Canada’s Horn River basin and properties acquired during 2010, where the associated gathering, processing, and transportation contracts have higher average rates than Apache’s legacy properties. The $22 million increase in the U.S. is directly related to increased volumes.

2010 vs. 2009 Gathering and transportation costs increased $35 million from 2009. The increase in the U.S. resulted from an increase in both the volumes transported under arrangements where we pay costs directly to third parties and in rates. The increase in Canada resulted from an increase in volumes, rate, and foreign exchange rates. North Sea costs were down on lower production and foreign exchange rates. Egypt costs increased as a result of higher shipping, handling, and pipeline fees as compared to the prior year.

Taxes Other Than Income

Taxes other than income primarily consist of U.K. Petroleum Revenue Tax (PRT), severance taxes on properties onshore and in state or provincial waters off the coast of the U.S., Australia, and Argentina, and ad valorem taxes on properties in the U.S. and Canada. Severance taxes are generally based on a percentage of oil and gas production revenues, while the U.K. PRT is assessed on net receipts (revenues less qualifying operating costs and capital spending) from the Forties and Nelson fields in the U.K. North Sea. We are subject to a variety

of other taxes including U.S. franchise taxes, Australian Petroleum Resources Rent tax, and various Canadian taxes, including the Freehold Mineral tax, Saskatchewan Capital tax, and Saskatchewan Resources surtax. We also pay taxes on invoices and bank transactions in Argentina. The table below presents a comparison of these expenses:


	For the Year Ended December 31,
	2011		2010		2009
	(In millions)
U.K. PRT	$	538	$	422	$	383
Severance taxes		212		142		88
Ad valorem taxes		94		80		55
Other taxes		55		46		54

Total Taxes other than income	$	899	$	690	$	580

2011 vs. 2010 Taxes other than income were $209 million higher than 2010. U.K. PRT increased $116 million over the comparable 2010 period as a result of a 27-percent increase in net receipts, primarily driven by higher revenues. Prior-year property acquisitions and higher realized oil and gas prices resulted in a $70 million and $14 million increase to severance and ad valorem tax expense, respectively.

2010 vs. 2009 Taxes other than income were $110 million higher than 2009. U.K. PRT increased $39 million over 2009 as a result of a 10-percent increase in net receipts, primarily driven by higher revenues. Severance taxes increased $54 million from higher taxable revenues in the U.S., predominantly resulting from acquisitions, and consistent with higher realized oil and natural gas prices relative to the prior year. The $25 million increase in ad valorem taxes resulted from higher taxable valuations in the U.S. associated with increases in oil and natural gas prices relative to the prior year and the BP and Devon acquisitions and the Mariner merger.

General and Administrative Expenses

2011 vs. 2010 General and administrative (G&A) expenses increased $79 million, or 21 percent from 2010. On a per-unit basis, G&A expenses increased six percent, or $.11 per boe: $.07 per boe on higher insurance costs and $.04 per boe on nonrecurring expenses.

2010 vs. 2009 G&A expenses were $36 million higher in 2010 than in 2009. On a per boe basis, G&A expenses decreased two percent as the effect of higher volumes more than offset the increase in costs.

Merger, Acquisitions & Transition Costs

In 2011, the Company recognized $20 million in merger, acquisitions, & transition costs, reflecting additional expenses related to our 2010 BP asset acquisitions and the Mariner merger as well as costs arising from our 2011 acquisition of Mobil North Sea Limited.

In 2010, the Company recognized $183 million in merger, acquisitions, & transition costs related to our BP and Devon acquisitions and the Mariner merger. A summary of these costs follows:


	For the Year Ended December 31,
	2011		2010
	(In millions)
Separation and retention costs	$	12	$	114
Investment banking fees		–		42
Other costs		8		27

Total Merger, Acquisitions & Transition	$	20	$	183

Financing Costs, Net

Net financing costs incurred during the periods noted are composed of the following:


	For the Year Ended December 31,
	2011		2010		2009
	(In millions)
Interest expense	$	433	$	345	$	309
Amortization of deferred loan costs		5		17		6
Capitalized interest		(263)		(120)		(61)
Interest income		(17)		(13)		(12)

Total Financing costs, net	$	158	$	229	$	242

2011 vs. 2010 Net financing costs decreased $71 million from 2010. The decrease is primarily related to a $143 million increase in capitalized interest, the result of additional unproved balances from the BP acquisitions and Mariner merger. This decrease is partially offset by an $88 million increase in interest expense from debt issuances in 2010.

2010 vs. 2009 Net financing costs decreased $13 million from 2009. The decrease is primarily related to a $59 million increase in capitalized interest, the result of additional unproved balances from the BP acquisitions and Mariner merger. This decrease is partially offset by a $36 million increase in interest expense from debt issuances in 2010 and $11 million higher amortization of deferred loan costs related to the new debt and repayment of the Australian project financing facility.

Provision for Income Taxes

2011 vs. 2010 The provision for income taxes totaled $3.5 billion in 2011 compared to $2.2 billion in 2010, driven by a 55 percent increase in income before income taxes and an increase in the effective tax rate to 43.4 percent in 2011 from 41.8 percent in 2010. The largest driver of the increased tax rate was an increase in the U.K. corporate income tax rate on North Sea oil and gas profits from 50 percent to 62 percent. As a result of the enacted legislation, in 2011 the Company recorded a tax charge of $218 million resulting from the remeasurement of our U.K. deferred tax liability as of December 31, 2010. The effective rates for 2011 and 2010 were also impacted by the effect of currency exchange rates on our foreign deferred tax liabilities.

2010 vs. 2009 The provision for income taxes totaled $2.2 billion in 2010 compared to $611 million in 2009. The effective rates for 2010 and 2009 were impacted by the effect of currency exchange rates on our foreign deferred tax liabilities and other net tax settlements. Total taxes and the effective rate for 2009 were also impacted by the magnitude of the taxes related to the full-cost write-down in that year.

Significant Acquisitions and Divestitures

2011 Activity

On December 30, 2011, Apache completed the acquisition of Exxon Mobil Corporation’s U.K. subsidiary, Mobil North Sea Limited. The assets acquired include: operated interests in the Beryl, Nevis, Nevis South, Skene, and Buckland fields; operated interest in the Beryl/Brae gas pipeline and the SAGE gas plant; non-operated interests in the Maclure, Scott, and Telford fields; and Benbecula (west of Shetlands) exploration acreage. This acquisition was funded with $1.25 billion of existing cash on hand.

In February and March 2011, Apache completed two separate transactions to align ownership and interests on the planned Kitimat LNG facility and pipeline development. Apache Canada currently owns a 40-percent interest in both the Kitimat facility and the pipeline.

2010 Activity

In the fourth quarter of 2010, Apache acquired Mariner, an independent exploration and production company, in a stock and cash transaction totaling $2.7 billion. We also assumed approximately $1.7 billion of Mariner’s debt in connection with the merger. The transaction was accounted for as a business combination, with Mariner’s assets and liabilities reflected in Apache’s financial statements at fair value. Mariner’s oil and gas properties are primarily located in the Gulf of Mexico deepwater and shelf, the Permian Basin, and onshore in the Gulf Coast. The Permian Basin and Gulf of Mexico shelf assets are complementary to Apache’s existing holdings and provide an inventory of future potential drilling locations, particularly in the Spraberry and Wolfcamp formation oil plays of the Permian Basin. Additionally, Mariner has accumulated acreage in emerging unconventional shale oil resources in the U.S.

In the third and fourth quarters of 2010, Apache completed the acquisition of BP’s oil and gas operations, related infrastructure, and acreage in the Permian Basin of west Texas and New Mexico, substantially all of BP’s Western Canadian upstream natural gas assets, and BP’s interests in four development licenses and one exploration concession (East Badr El Din) in the Western Desert of Egypt. The aggregate purchase price of the BP acquisitions, subsequent to exercise of preferential purchase rights, was $6.4 billion, subject to normal post-closing adjustments. The effective date of these acquisitions was July 1, 2010.

In the second quarter of 2010, Apache completed an acquisition of oil and gas assets on the Gulf of Mexico shelf from Devon for $1.05 billion, subject to normal post-closing adjustments. The acquisition from Devon was effective January 1, 2010, and included 477,000 acres across 150 blocks.

During the first quarter of 2010, Apache Canada, through its subsidiaries, closed the acquisition of a 51-percent interest in the Kitimat LNG facility and a 25.5-percent interest in a partnership that owns a related proposed pipeline.

Subsequent Events

The following significant transactions occurred subsequent to December 31, 2011:

In January 2012, Apache agreed to acquire Cordillera Energy Partners III LLC, a privately held company with approximately 254,000 net acres in the Granite Wash, Tonkawa, Cleveland, and Marmaton plays in western Oklahoma and the Texas Panhandle. Upon closing, the sellers will receive approximately 6.3 million shares of Apache common stock and $2.2 billion in cash, to be funded with cash on hand and debt. The effective date of the transaction is September 1, 2011, with closing projected to be in the second quarter of 2012, subject to customary closing conditions.

On January 31, 2012, a subsidiary of Apache Energy Limited acquired a 49-percent interest in Burrup Holdings Limited (BHL) for $439 million, including working capital adjustments. The transaction was funded with debt. BHL is the owner of an ammonia fertilizer plant on the Burrup Peninsula of Western Australia. Apache has been supplying natural gas to the plant since operations commenced in 2006. Yara Australia Pty Ltd (Yara) owns the remaining 51 percent of BHL and will operate the plant, which has been rebranded Yara Pilbara. Apache also acquired an interest in a planned technical ammonia nitrate plant to be developed with Yara.

For further information regarding these acquisitions, please see Note 2—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.

Capital Resources and Liquidity

Operating cash flows are a primary source of liquidity. Apache’s cash flows, both in the short-term and the long-term, are impacted by highly volatile oil and natural gas prices. Significant deterioration in commodity prices negatively impacts revenues, earnings and cash flows, capital spending, and potentially our liquidity if spending does not trend downward as well. Sales volumes and costs also impact cash flows; however, these historically have not been as volatile or as impactive as commodity prices in the short-term.

Apache’s long-term operating cash flows are dependent on reserve replacement and the level of costs required for ongoing operations. Our business, as with other extractive industries, is a depleting one in which each barrel produced must be replaced or the Company and its reserves, a critical source of future liquidity, will shrink. Cash investments are required continuously to fund exploration and development projects and acquisitions, which are necessary to offset the inherent declines in production and proven reserves. Future success in maintaining and growing reserves and production is highly dependent on the success of our exploration and development activities or our ability to acquire additional reserves at reasonable costs. For a discussion of risk factors related to our business and operations, please see Part I, Item 1A – Risk Factors of this Form 10-K.

We may also elect to utilize available committed borrowing capacity, access to both debt and equity capital markets, or proceeds from the occasional sale of nonstrategic assets for all other liquidity and capital resource needs.

We believe the liquidity and capital resource alternatives available to Apache, combined with internally-generated cash flows, will be adequate to fund short-term and long-term operations, including our capital spending program, repayment of debt maturities, and any amount that may ultimately be paid in connection with contingencies.

Apache’s primary uses of cash are exploration, development, and acquisition of oil and gas properties, costs necessary to maintain ongoing operations, repayment of principal and interest on outstanding debt, and payment of dividends. We fund our exploration and development activities primarily through operating cash flows and budget capital expenditures based on projected cash flows.

For additional information, please see Part I, Items 1 and 2 – Business and Properties and Part I, Item 1A – Risk Factors of this Form 10-K.

Sources and Uses of Cash

The following table presents the sources and uses of our cash and cash equivalents for the years presented:

Year Ended December 31,

2011

2010

2009

(In millions)

Sources of Cash and Cash Equivalents:

Net cash provided by operating activities

9,953

6,726

4,224

Commercial paper and bank loan borrowings, net

–

318

–

Sale of short-term investments

–

792

Sale of oil and gas properties

422

–

Project financing draw-downs

–

250