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		–		3
Project financing draw-downs		–		–		250
Fixed-rate debt borrowings		–		2,470		–
Proceeds from issuance of common stock		–		2,258		–
Proceeds from issuance of depositary shares		–		1,227		–
Common stock activity		52		70		28
Other		32		36		35

		10,459		13,105		5,332

Uses of Cash and Cash Equivalents:
Capital expenditures ⁽¹⁾		7,078		4,922		3,632
Acquisitions		1,813		8,360		310
Commercial paper, credit facility and bank loan repayments, net		925		–		2
Project financing repayment		–		350		–
Payments on fixed-rate notes		–		1,023		100
Redemption of preferred stock		–		–		98
Dividends		306		226		209
Other		176		138		114

		10,298		15,019		4,465

Increase (decrease) in cash and cash equivalents	$	161	$	(1,914)	$	867

⁽¹⁾

The table presents capital expenditures on a cash basis; therefore, the amounts differ from those discussed elsewhere in this document, which include accruals.

Net Cash Provided by Operating Activities

Cash flows are our primary source of capital and liquidity and are impacted, both in the short-term and the long-term, by volatile oil and natural gas prices. The factors in determining operating cash flows are largely the same as those that affect net earnings, with the exception of non-cash expenses such as DD&A, asset retirement obligation (ARO) accretion, and deferred income tax expense, which affect earnings but do not affect cash flows.

Net cash provided by operating activities for 2011 totaled $10.0 billion, up $3.3 billion from 2010. The increase reflects the $4.6 billion impact of higher oil and gas revenues, with higher commodity prices contributing $3.2 billion, and a 14-percent increase in daily equivalent production adding another $1.4 billion. This increase was partially offset by higher income tax payments in 2011 as compared to the 2010 period.

For a detailed discussion of commodity prices, production, and expenses, please see “Results of Operations” in this Item 7. For additional detail on the changes in operating assets and liabilities and the non-cash expenses which do not impact net cash provided by operating activities, please see the Statement of Consolidated Cash Flows in the Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.

Sale of Oil and Gas Properties

During 2011, Apache completed the sale of certain properties in Canada and the U.S. for $422 million. Divestitures comprised several non-strategic assets.

Proceeds from Debt, Common Stock and Share Issuance

On July 28, 2010, in conjunction with Apache’s $6.4 billion acquisition of properties from BP, the Company issued 26.45 million shares of common stock and 25.3 million depositary shares. Proceeds, after underwriting discounts and before expenses, from the common stock and depositary share offerings totaled approximately $2.3 billion and $1.2 billion, respectively.

On August 20, 2010, the Company issued $1.5 billion principal amount of senior unsecured 5.1-percent notes maturing September 1, 2040. The proceeds were used to repay borrowings under a bridge facility and the Company’s commercial paper program that were used to finance the 2010 BP acquisitions. On December 3, 2010, the Company issued $500 million principal amount of senior unsecured 3.625-percent notes maturing February 1, 2021, and $500 million principal amount of senior unsecured 5.25-percent notes maturing February 1, 2042. The proceeds were used to redeem the outstanding public debt of $1.0 billion assumed upon completion of Apache’s acquisition of Mariner in November 2010.

Repayment of Commercial Paper and Lines of Credit

During 2011, Apache repaid $925 million on commercial paper and money market lines of credit. For further discussion of our commercial paper program, please see “Liquidity” in this Item 7 and Note 6—Debt in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.

Dividends

The Company has paid cash dividends on its common stock for 47 consecutive years through 2011. Future dividend payments will depend on the Company’s level of earnings, financial requirements, and other relevant factors. Common stock dividends paid during 2011 totaled $230 million, compared with $206 million in 2010 and $202 million in 2009. The 2011 and 2010 periods included dividend payments of $76 million and $20 million, respectively, on the Company’s Series D Preferred Stock. The 2009 period included dividend payments of $7 million on the Company’s Series B Preferred Stock.

Capital Expenditures

We fund exploration and development activities primarily through operating cash flows and budget capital expenditures based on projected operating cash flows. Our operating cash flows, both in the short and long term, are impacted by highly volatile oil and natural gas prices, production levels, industry trends impacting operating expenses, and our ability to continue to acquire or find high-margin reserves at competitive prices. For these reasons, operating cash flow forecasts are revised monthly in response to changing market conditions and production projections. Apache routinely adjusts capital expenditure budgets in response to these adjusted operating cash flow forecasts and market trends in drilling and acquisitions costs.

Historically, we have used a combination of operating cash flows, borrowings under lines of credit and commercial paper program and, from time to time, issues of public debt or common stock to fund significant acquisitions.

The following table details capital expenditures for each country in which we do business.


	Year Ended December 31,
	2011		2010		2009
	(In millions)
Exploration and Development (E&D):
United States	$	2,768	$	1,623	$	929
Canada		817		860		412

North America		3,585		2,483		1,341

Egypt		896		757		676
Australia		576		624		602
North Sea		823		617		375
Argentina		346		240		140
Other International		61		20		11

International		2,702		2,258		1,804

Worldwide Exploration and Development Costs		6,287		4,741		3,145

Gathering, Transmission and Processing Facilities (GTP):
United States		27		–		–
Canada		148		159		83
Egypt		111		182		151
Australia		345		162		69
Argentina		12		3		2

Total GTP Costs		643		506		305

Asset Retirement Costs		819		459		288

Capitalized Interest		263		120		61

Capital Expenditures, excluding Acquisitions		8,012		5,826		3,799
Acquisitions, including GTP		3,189		11,557		310
Asset Retirement Costs – Acquired		592		847		5

Total Capital Expenditures	$	11,793	$	18,230	$	4,114

Exploration and Development Apache continues to focus on spending within the limits of our operating cash flows. As a result of Apache’s acquisitions in 2010 and the rise in commodity prices, our 2011 drilling and development budgets were increased while remaining below projected increases in operating cash flows in order to pay down debt. Accordingly, worldwide E&D expenditures for 2011 were 33 percent higher than 2010.

E&D spending in North America, which totaled 57 percent of worldwide E&D spending, was up 44 percent in 2011 from the prior year on increased activity in every U.S. region. U.S. E&D expenditures were $1.1 billion, or 71 percent, higher than year-ago levels primarily on activity in the Permian region, where we continue an aggressive drilling program on our Mariner-acquired Deadwood acreage. Current-year activity also includes expenditures on Mariner-acquired deepwater properties for ongoing field development activities at Mandy, Wideberth, and Lucius. Our Central region’s active horizontal drilling program in the Granite Wash and Cherokee plays further contributed to our increase in expenditures.

E&D expenditures outside of North America increased 20 percent over 2010 to $2.7 billion. E&D spending in the North Sea was up $206 million from prior-year levels on the Forties field drilling program and the

construction of the Forties Alpha satellite platform. Egypt was $139 million higher than the prior year on continued drilling activity across all major basins. Argentina expenditures were up $106 million on additional drilling and development activity.

Gathering, Transmission and Processing Facilities We invested $643 million in GTP in 2011 compared to $506 million in 2010. GTP expenditures in Australia consisted of construction activity at the Devil Creek and Macedon gas plants. Australia has also incurred costs related to the FEED study and purchases of long-lead items for the Wheatstone LNG project. Activity in Canada was centered on the Kitimat LNG development and in the Horn River basin, with expenditures for compressor stations, a water treatment facility, gathering systems, and a gas processing plant. Expenditures in Egypt primarily comprised final stages of construction on the Kalabsha oil processing facility. In addition, approximately $338 million of the value of our 2011 acquisitions is associated with GTP.

Asset Retirement Costs In 2011, we recorded $819 million of additional future asset retirement costs associated with our worldwide drilling programs and upward revisions to prior-year estimates for timing and costs.

Acquisitions We acquired $3.2 billion of oil and gas properties in 2011 compared to $11.6 billion in 2010. We also assumed $592 million in asset retirement costs. Acquisition capital expenditures occur as attractive opportunities arise and, therefore, vary from year to year. For information regarding our acquisitions and divestitures, 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.

Liquidity


	At December 31,
(In millions, except percentages)	2011		2010

Cash and cash equivalents	$	295	$	134
Total debt		7,216		8,141
Shareholders’ equity		28,993		24,377
Available committed borrowing capacity		3,300		2,387
Floating-rate debt/total debt		0.4%		12%
Percent of total debt to capitalization		20%		25%

Cash and Cash Equivalents

We had $295 million in cash and cash equivalents at December 31, 2011, of which $237 million of cash was held by foreign subsidiaries, and approximately $58 million was held by Apache Corporation and U.S. subsidiaries. The cash held by foreign subsidiaries is subject to additional U.S. income taxes if repatriated. Almost all of the cash is denominated in U.S. dollars and, at times, is invested in highly liquid, investment-grade securities with maturities of three months or less at the time of purchase. We intend to use cash from our international subsidiaries to fund international projects.

Debt

At December 31, 2011, outstanding debt, which consisted of notes, debentures, commercial paper, and uncommitted bank lines, totaled $7.2 billion. Current debt consists of $400 million in 6.25-percent debentures due in April 2012 and $31 million borrowed under uncommitted money market/overdraft lines of credit in Argentina. We have $900 million of debt maturing in 2013, $350 million maturing in 2015, and the remaining $5.6 billion maturing intermittently in years 2016 through 2096.

The Company’s debt-to-capitalization ratio as of December 31, 2011 was 20 percent as compared to 25 percent at December 31, 2010.

Available Credit Facilities

As of December 31, 2011, the Company had unsecured committed revolving syndicated bank credit facilities totaling $3.3 billion, of which $2.3 billion matures in May 2013 and $1.0 billion matures in August 2016. The facilities consist of a $1.5 billion facility, a $1.0 billion facility and a $450 million facility in the U.S., a $200 million facility in Australia, and a $150 million facility in Canada. As of December 31, 2011, available borrowing capacity under the Company’s credit facilities was $3.3 billion. The U.S. credit facilities are used to support Apache’s commercial paper program.

The financial covenants of the credit facilities require the Company to maintain a debt-to-capitalization ratio of not greater than 60 percent at the end of any fiscal quarter. The negative covenants include restrictions on the Company’s ability to create liens and security interests on our assets, with exceptions for liens typically arising in the oil and gas industry, purchase money liens, and liens arising as a matter of law, such as tax and mechanics’ liens. The Company may incur liens on assets located in the U.S. and Canada of up to five percent of the Company’s consolidated assets, or approximately $2.6 billion as of December 31, 2011. There are no restrictions on incurring liens in countries other than U.S. and Canada. There are also restrictions on Apache’s ability to merge with another entity, unless the Company is the surviving entity, and a restriction on our ability to guarantee debt of entities not within our consolidated group.

There are no clauses in the facilities that permit the lenders to accelerate payments or refuse to lend based on unspecified material adverse changes. The credit facility agreements do not have drawdown restrictions or prepayment obligations in the event of a decline in credit ratings. However, the agreements allow the lenders to accelerate payments and terminate lending commitments if Apache, or any of its U.S. or Canadian subsidiaries, defaults on any direct payment obligation in excess of $100 million or has any unpaid, non-appealable judgment against it in excess of $100 million. The Company was in compliance with the terms of the credit facilities as of December 31, 2011.

At the Company’s option, the interest rate for the facilities is based on a base rate, as defined, or LIBOR plus a margin determined by the Company’s senior long-term debt rating.

At December 31, 2011, the margin over LIBOR for committed loans was 0.19 percent on the $1.5 billion facility, 0.875 percent on the $1.0 billion facility, and 0.23 percent on the $450 million facility in the U.S., the $200 million facility in Australia, and the $150 million facility in Canada. If the total amount of the loans borrowed under the $1.5 billion facility equals or exceeds 50 percent of the total facility commitments, then an additional 0.05 percent will be added to the margins over LIBOR. If the total amount of the loans borrowed under the $450 million facility in the U.S., the $200 million facility in Australia, and the $150 million facility in Canada equals or exceeds 50 percent of the total facility commitments, then an additional 0.10 percent will be added to the margins over LIBOR. The Company also pays quarterly facility fees of 0.06 percent on the total amount of the $1.5 billion facility, 0.125 percent on the total amount of the $1.0 billion facility, and 0.07 percent on the total amount of the other three facilities. The facility fees vary based upon the Company’s senior long-term debt rating.

Substantially all of the banks with lending commitments to the Company have credit ratings of at least single-A, which in some cases is based on government support. There is no assurance that the financial condition of these banks will not deteriorate. We closely monitor the ratings of the 28 banks in our bank group. Having a large bank group allows the Company to mitigate the potential impact of any bank’s failure to honor its lending commitment.

Commercial Paper Program

The Company has available a $2.95 billion commercial paper program, which generally enables Apache to borrow funds for up to 270 days at competitive interest rates. Our 2011 weighted-average interest rate for commercial paper was 0.37 percent. If the Company is unable to issue commercial paper following a significant credit downgrade or dislocation in the market, the Company’s U.S. credit facilities are available as a 100-percent

backstop. The commercial paper program is fully supported by available borrowing capacity under U.S. committed credit facilities, which expire in 2013 and 2016. As of December 31, 2011, the Company had no commercial paper outstanding.

Future Debt and Stock Issuances

Subsequent to year-end, Apache plans to issue additional equity and debt in conjunction with the recently announced Cordillera Energy acquisition. As discussed above in “Significant Acquisitions and Divestures” in this Item 7, the Company is planning to issue approximately 6.3 million shares of common stock to the sellers and fund the remaining $2.2 billion balance with cash on hand and debt at closing, which is projected to be in the second quarter of 2012.

Dividend Increase

Based on strong future growth prospects and Apache’s financial position, the Board of Directors approved a 13-percent increase to $0.17 per share for the regular quarterly cash dividend on the Company’s common shares. This increase applies to the dividend on common shares payable on May 22, 2012, to stockholders of record on April 23, 2012.

Off-Balance Sheet Arrangements

Apache enters into customary agreements in the oil and gas industry for drilling rig commitments, firm transportation agreements, and other obligations as described below in Contractual Obligations in this Item 7. Other than the off-balance sheet arrangements described herein, Apache does not have any off-balance sheet arrangements with unconsolidated entities that are reasonably likely to materially affect our liquidity or capital resource positions.

Contractual Obligations

The following table summarizes the Company’s contractual obligations as of December 31, 2011. For additional information regarding these obligations, please see Note 6—Debt 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.


Contractual Obligations^(a)	Note Reference	Total		2012		2013-2014		2015-2016		2017 & Beyond
	(In millions)

Debt, at face value	Note 6	$	7,262	$	431	$	900	$	351	$	5,580
Interest payments	Note 6		7,358		399		708		660		5,591
Drilling rig commitments^(b)	Note 8		799		288		510		1		–
Purchase obligations^(c)	Note 8		1,408		578		603		186		41
Firm transportation agreements	Note 8		756		117		224		149		266
Office and related equipment	Note 8		281		52		79		54		96
Other operating lease obligations^(d)	Note 8		694		184		227		183		100


Total Contractual Obligations		$	18,558	$	2,049	$	3,251	$	1,584	$	11,674

^(a)

This table does not include the Company’s liability for dismantlement, abandonment, and restoration costs of oil and gas properties, derivative liabilities, pension or postretirement benefit obligations, or tax reserves. For additional information regarding these liabilities, please see Notes 5, 3, 8, and 7, respectively, in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.

^(b)

This represents minimum future expenditures for drilling rig services. Apache’s expenditures for drilling rig services will exceed such minimum amounts to the extent Apache utilizes the drilling rigs subject to a particular contractual commitment for a period greater than the period set forth in the governing contract.

^(c)

Purchase obligations represent agreements to purchase goods or services that are enforceable, are legally binding, and specify all significant terms, including fixed and minimum quantities to be purchased; fixed, minimum or variable price provisions; and the appropriate timing of the transaction. These include minimum commitments associated with take-or-pay contracts, hydraulic fracturing service agreements, obtaining and processing seismic data, and contractual obligations to buy or build oil and gas plants and facilities.

^(d)

Other operating lease obligations pertain to other long-term exploration, development, and production activities. The Company has work-related commitments for oil and gas operations equipment, acreage maintenance commitments, FPSOs, and aircraft, among other things.

Apache is also subject to various contingent obligations that become payable only if certain events or rulings were to occur. The inherent uncertainty surrounding the timing of and monetary impact associated with these events or rulings prevents any meaningful accurate measurement, which is necessary to assess settlements resulting from litigation. Apache’s management feels that it has adequately reserved for its contingent obligations, including approximately $120 million for environmental remediation and approximately $20 million for various contingent legal liabilities. For a detailed discussion of the Company’s environmental and legal contingencies, please see Note 8—Commitments and Contingencies in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.

The Company also had approximately $118 million accrued as of December 31, 2011, for an insurance contingency as a member of Oil Insurance Limited (OIL). This insurance co-op insures specific property, pollution liability, and other catastrophic risks of the Company. As part of its membership, the Company is contractually committed to pay a withdrawal premium if we elect to withdraw from OIL. Apache does not anticipate withdrawal from the insurance pool; however, the potential withdrawal premium is calculated annually based on past losses and the nature of our asset base.

Insurance Program

We maintain insurance coverage that includes coverage for physical damage to our assets, third party liability, workers’ compensation, employers’ liability, sudden pollution, and other risks. Our insurance coverage includes deductibles that must be met prior to recovery. Additionally, our insurance is subject to exclusions and limitations, and there is no assurance that such coverage will adequately protect us against liability from all potential consequences and damages.

Our current insurance policies covering physical damage to our assets provide $1 billion in coverage per occurrence. These policies also provide sudden pollution coverage. Coverage for damage to our U.S. Gulf of Mexico assets specifically resulting from a named windstorm, however, is subject to a maximum of $250 million per named windstorm, which includes a self-insured retention of 40 percent of the losses above a $100 million deductible, and is limited to a maximum of two storms per year.

Our current insurance policies covering general liabilities provide coverage of $610 million per occurrence subject to Apache’s interest. This coverage is in excess of existing policies, including, but not limited to, charterer’s liability, aircraft liability, employer’s liability, and automobile liability. Our service agreements, including drilling contracts, generally indemnify Apache for injuries and death of the service provider’s employees as well as subcontractors hired by the service provider.

Our insurance policies generally renew in January and June of each year. Future insurance coverage for our industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable.

Apache purchases multi-year political risk insurance from the 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.

Non-GAAP Measures

The Company makes reference to some measures in discussion of its financial and operating highlights that are not required by or presented in accordance with GAAP. Management uses these measures in assessing operating results and believes the presentation of these measures provides information useful in assessing the Company’s financial condition and results of operations. These non-GAAP measures should not be considered as alternatives to GAAP measures and may be calculated differently from, and therefore may not be comparable to, similarly titled measures used at other companies.

Adjusted Earnings

To assess the Company’s operating trends and performance, management uses Adjusted Earnings, which is net income excluding certain items that management believes affect the comparability of operating results. Management believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported company earnings for items that may obscure underlying fundamentals and trends. The reconciling items below are the types of items management excludes and believes are frequently excluded by analysts when evaluating the operating trends and comparability of the Company’s results.


	For the Year Ended December 31,
	2011		2010		2009
	(In millions, except share data)

Income (Loss) Attributable to Common Stock (GAAP)	$	4,508	$	3,000	$	(292)
Adjustments:
United Kingdom tax rate increase impact		218		–		–
Oil & gas asset impairment of Chile, net of tax		60		–		–
Merger, acquisitions & transition costs, net of tax		13		120		–
Unrealized foreign currency fluctuation impact on deferred tax expense		(73)		52		198
Deferred tax adjustments		(75)		–		–
U.S. and Canada proved property write-down, net of tax		–		–		1,981

Adjusted Earnings (Non-GAAP)	$	4,651	$	3,172	$	1,887


Net Income (Loss) per Common Share – Diluted (GAAP)	$	11.47	$	8.46	$	(0.87)
Adjustments:
United Kingdom tax rate increase impact		.55		–		–
Oil & gas asset impairment of Chile, net of tax		.15		–		–
Merger, acquisitions & transition costs, net of tax		.03		.33		–
Unrealized foreign currency fluctuation impact on deferred tax expense		(.18)		.15		.59
Deferred tax adjustments		(.19)		–		–
U.S. and Canada proved property write-down, net of tax		–		–		5.87

Adjusted Earnings Per Share – Diluted (Non-GAAP)	$	11.83	$	8.94	$	5.59

Critical Accounting Policies and Estimates

Apache prepares its financial statements and the accompanying notes in conformity with accounting principles generally accepted in the United States of America, which require management to make estimates and assumptions about future events that affect the reported amounts in the financial statements and the accompanying notes. Apache identifies certain accounting policies as critical based on, among other things, their impact on the portrayal of Apache’s financial condition, results of operations, or liquidity and the degree of difficulty, subjectivity, and complexity in their deployment. Critical accounting policies cover accounting matters that are inherently uncertain because the future resolution of such matters is unknown. Management routinely discusses the development, selection, and disclosure of each of the critical accounting policies. The following is a discussion of Apache’s most critical accounting policies.

Reserves Estimates

Proved undeveloped 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.

Despite the inherent imprecision in these engineering estimates, our reserves are used throughout our financial statements. For example, since we use the units-of-production method to amortize our oil and gas properties, the quantity of reserves could significantly impact our DD&A expense. Our oil and gas properties are also subject to a “ceiling” limitation based in part on the quantity of our proved reserves. Finally, these reserves are the basis for our supplemental oil and gas disclosures.

Reserves as of December 31, 2011, 2010, and 2009, were calculated using 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.

Apache has elected not to disclose probable and possible reserves or reserve estimates in this filing.

Asset Retirement Obligation (ARO)

The Company has significant obligations to remove tangible equipment and restore land or seabed at the end of oil and gas production operations. Apache’s removal and restoration obligations are primarily associated with plugging and abandoning wells and removing and disposing of offshore oil and gas platforms. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety, and public relations considerations.

ARO associated with retiring tangible long-lived assets is recognized as a liability in the period in which the legal obligation is incurred and becomes determinable. The liability is offset by a corresponding increase in the underlying asset. The ARO liability reflects the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with Apache’s oil and gas properties. The Company utilizes current retirement costs to estimate the expected cash outflows for retirement obligations. Inherent in the

present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit-adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental, and political environments. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property balance. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value.

Income Taxes

Our oil and gas exploration and production operations are subject to taxation on income in numerous jurisdictions worldwide. We record deferred tax assets and liabilities to account for the expected future tax consequences of events that have been recognized in our financial statements and our tax returns. We routinely assess the realizability of our deferred tax assets. If we conclude that it is more likely than not that some portion or all of the deferred tax assets will not be realized under accounting standards, the tax asset would be reduced by a valuation allowance. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and gas prices).

The Company regularly assesses and, if required, establishes accruals for tax contingencies that could result from assessments of additional tax by taxing jurisdictions in countries where the Company operates. Tax reserves have been established and include any related interest, despite the belief by the Company that certain tax positions meet certain legislative, judicial, and regulatory requirements. These reserves are subject to a significant amount of judgment and are reviewed and adjusted on a periodic basis in light of changing facts and circumstances considering the progress of ongoing tax audits, case law, and any new legislation. The Company believes that the reserves established are adequate in relation to the potential for any additional tax assessments.

Purchase Price Allocation

Accounting for the acquisition of a business requires the allocation of the purchase price to the various assets and liabilities of the acquired business and recording deferred taxes for any differences between the allocated values and tax basis of assets and liabilities. Any excess of the purchase price over the amounts assigned to assets and liabilities is recorded as goodwill.

The purchase price allocation is accomplished by recording each asset and liability at its estimated fair value. Estimated deferred taxes are based on available information concerning the tax basis of the acquired company’s assets and liabilities and tax-related carryforwards at the merger date, although such estimates may change in the future as additional information becomes known. The amount of goodwill recorded in any particular business combination can vary significantly depending upon the values attributed to assets acquired and liabilities assumed relative to the total acquisition cost.

In estimating the fair values of assets acquired and liabilities assumed, we made various assumptions. The most significant assumptions related to the estimated fair values assigned to proved and unproved crude oil and natural gas properties. To estimate the fair values of these properties, we prepared estimates of crude oil and natural gas reserves as described above in Reserve Estimates of this Item 7. Estimated fair values assigned to assets acquired can have a significant effect on results of operations in the future.

ITEM 7A.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our exposure to market risk. The term market risk relates to the risk of loss arising from adverse changes in oil, gas, and NGL prices, interest rates, or foreign currency and adverse governmental actions. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. The forward-looking information provides indicators of how we view and manage our ongoing market risk exposures.

Commodity Risk

The Company’s revenues, earnings, cash flow, capital investments, and, ultimately, future rate of growth are highly dependent on the prices we receive for our crude oil, natural gas, and NGLs, which have historically been very volatile due to unpredictable events such as economic growth or retraction, weather, and political climate. In 2011, our average worldwide crude oil realizations saw a significant increase from $91.74 per barrel in January to $110.98 in April, followed by a decrease to $97.88 in August. In 2011, crude oil prices averaged $102.19 per barrel, up 33 percent from 2010. Apache’s average worldwide natural gas price realizations remained within a $0.44 range during 2011, with a high of $4.58 per Mcf in June and July, as compared to a $0.95 range during 2010. Average realized prices in 2011 for natural gas increased five percent to $4.37 per Mcf.

We periodically enter into hedging activities on a portion of our projected oil and natural gas production through a variety of financial and physical arrangements intended to support oil and natural gas prices at targeted levels and to manage our overall exposure to oil and gas price fluctuations. In 2011, approximately 16 percent of our natural gas production and 29 percent of our crude oil production was subject to financial derivative hedges, compared with 23 percent and 12 percent, respectively, in 2010.

Apache may use futures contracts, swaps, options, and fixed-price physical contracts to hedge its commodity prices. Realized gains or losses from the Company’s price-risk management activities are recognized in oil and gas production revenues when the associated production occurs. Apache does not hold or issue derivative instruments for trading purposes.

On December 31, 2011, the Company had open natural gas derivative hedges in an asset position with a fair value of $426 million. A 10-percent increase in natural gas prices would reduce the fair value by approximately $39 million, while a 10-percent decrease in prices would increase the fair value by approximately $38 million. The Company also had open crude oil derivatives in a liability position with a fair value of $248 million. A 10-percent increase in oil prices would increase the liability by approximately $193 million, while a 10-percent decrease in prices would decrease the liability by approximately $170 million. These fair value changes assume volatility based on prevailing market parameters at December 31, 2011. For notional volumes and terms associated with the Company’s derivative contracts, 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.

Apache conducts its risk management activities for its commodities under the controls and governance of its risk management policy. The Risk Committee approves and oversees these controls, which have been implemented by designated members of the treasury department. The treasury and accounting departments also provide separate checks and reviews on the results of hedging activities. Controls for our commodity risk management activities include limits on credit, limits on volume, segregation of duties, delegation of authority and a number of other policy and procedural controls.

Interest Rate Risk

The Company considers its interest rate risk exposure to be minimal as a result of fixing interest rates on approximately 99.6 percent of the Company’s debt. At December 31, 2011, total debt included $31 million of floating-rate debt. A 10 percent change in floating interest rates on year-end floating debt balances would change annual interest expense by approximately $742,000.

Foreign Currency Risk

The Company’s cash flow stream relating to certain international operations is based on the U.S. dollar equivalent of cash flows measured in foreign currencies. In Australia, oil production is sold under U.S. dollar contracts, and gas production is sold largely under fixed-price Australian dollar contracts. Approximately half the costs incurred for Australian operations are paid in U.S. dollars. In Canada, oil and gas prices and costs, such as equipment rentals and services, are generally denominated in Canadian dollars but heavily influenced by U.S. markets. Our North Sea production is sold under U.S. dollar contracts, and the majority of costs incurred are paid in British pounds. In Egypt, all oil and gas production is sold under U.S. dollar contracts, and the majority of the costs incurred are denominated in U.S. dollars. Argentine revenues and expenditures are largely denominated in U.S. dollars, but are converted into Argentine pesos at the time of payment. Revenue and disbursement transactions denominated in Australian dollars, Canadian dollars, British pounds, and Argentine pesos are converted to U.S. dollar equivalents based on the average exchange rates during the period.

Foreign currency gains and losses also arise when monetary assets and monetary liabilities denominated in foreign currencies are translated at the end of each month. Currency gains and losses are included as either a component of “Other” under “Revenues and Other” or, as is the case when we re-measure our foreign tax liabilities, as a component of the Company’s provision for income tax expense on the Statement of Consolidated Operations. A 10-percent strengthening or weakening of the Australian dollar, Canadian dollar, British pound, and Argentine peso as of December 31, 2011, would result in a foreign currency net loss or gain, respectively, of approximately $150 million.

Forward-Looking Statements and Risk

This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical facts included or incorporated by reference in this report, including, without limitation, statements regarding our future financial position, business strategy, budgets, projected revenues, projected costs and plans, and objectives of management for future operations, are forward-looking statements. Such forward-looking statements are based on our examination of historical operating trends, the information that was used to prepare our estimate of proved reserves as of December 31, 2011, and other data in our possession or available from third parties. In addition, forward-looking statements generally can be identified by the use of forward-looking terminology such as “may,” “will,” “could,” “expect,” “intend,” “project,” “estimate,” “anticipate,” “plan,” “believe,” or “continue” or similar terminology. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to have been correct. Important factors that could cause actual results to differ materially from our expectations include, but are not limited to, our assumptions about:

•

the market prices of oil, natural gas, NGLs, and other products or services;

•

our commodity hedging arrangements;

•

the integration of acquisitions;

•

the supply and demand for oil, natural gas, NGLs, and other products or services;

•

production and reserve levels;

•

drilling risks;

•

economic and competitive conditions;

•

the availability of capital resources;

•

capital expenditure and other contractual obligations;

•

currency exchange rates;

•

weather conditions;

•

inflation rates;

•

the availability of goods and services;

•

legislative or regulatory changes;

•

the impact on our operations due to the change in government in Egypt;

•

terrorism or cyber-attacks;

•

occurrence of property acquisitions or divestitures;

•

the securities or capital markets and related risks such as general credit, liquidity, market and interest rate risks; and

•

other factors disclosed under Items 1 and 2—Business and Properties—Estimated Proved Reserves and Future Net Cash Flows, Item 1A—Risk Factors, Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations, Item 7A—Quantitative and Qualitative Disclosures About Market Risk and elsewhere in this Form 10-K.

All subsequent written and oral forward-looking statements attributable to the Company, or persons acting on its behalf, are expressly qualified in their entirety by the cautionary statements. Except as required by law, we assume no duty to update or revise our forward-looking statements based on changes in internal estimates or expectations or otherwise.

ITEM 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The financial statements and supplementary financial information required to be filed under this Item 8 are presented on pages F-1 through F-71 in Part IV, Item 15 of this Form 10-K and are incorporated herein by reference.

ITEM 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

The financial statements for the fiscal years ended December 31, 2011, 2010, and 2009, included in this report, have been audited by Ernst & Young LLP, registered public accounting firm, as stated in their audit report appearing herein.

ITEM 9A. CONTROLS

AND PROCEDURES

Disclosure Controls and Procedures

G. Steven Farris, the Company’s Chairman and Chief Executive Officer, in his capacity as principal executive officer, and Thomas P. Chambers, the Company’s Executive Vice President and Chief Financial Officer, in his capacity as principal financial officer, evaluated the effectiveness of our disclosure controls and procedures as of December 31, 2011, the end of the period covered by this report. Based on that evaluation and as of the date of that evaluation, these officers concluded that the Company’s disclosure controls and procedures were effective, providing effective means to ensure that the information we are required to disclose under applicable laws and regulations is recorded, processed, summarized, and reported within the time periods specified in the Commission’s rules and forms and accumulated and communicated to our management, including our principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure. We also made no changes in internal controls over financial reporting during the quarter ending December 31, 2011, that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

We periodically review the design and effectiveness of our disclosure controls, including compliance with various laws and regulations that apply to our operations both inside and outside the United States. We make modifications to improve the design and effectiveness of our disclosure controls and may take other corrective action, if our reviews identify deficiencies or weaknesses in our controls.

Management’s Report on Internal Control over Financial Reporting

The management report called for by Item 308(a) of Regulation S-K is incorporated herein by reference to “Report of Management on Internal Control Over Financial Reporting,” included on Page F-1 in Part IV, Item 15 of this Form 10-K.

The independent auditors attestation report called for by Item 308(b) of Regulation S-K is incorporated herein by reference to the “Report of Independent Registered Public Accounting Firm,” included on Page F-3 in Part IV, Item 15 of this Form 10-K.

Changes in Internal Control over Financial Reporting

There was no change in our internal controls over financial reporting during the quarter ending December 31, 2011, that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

ITEM 9B. OTHER

INFORMATION

None.

PART III

ITEM 10. DIRECTORS,

EXECUTIVE OFFICERS OF THE REGISTRANT AND CORPORATE GOVERNANCE

The information set forth under the captions “Nominees for Election as Directors,” “Continuing Directors,” “Executive Officers of the Company,” and “Securities Ownership and Principal Holders” in the proxy statement relating to the Company’s 2012 annual meeting of shareholders (the Proxy Statement) is incorporated herein by reference.

Code of Business Conduct

Pursuant to Rule 303A.10 of the NYSE and Rule 4350(n) of the NASDAQ, we are required to adopt a code of business conduct and ethics for our directors, officers, and employees. In February 2004, the Board of Directors adopted the Code of Business Conduct (Code of Conduct), and revised it in November 2011. The revised Code of Conduct also meets the requirements of a code of ethics under Item 406 of Regulation S-K. You can access the Company’s Code of Conduct on the Governance page of the Company’s website at www.apachecorp.com. Any shareholder who so requests may obtain a printed copy of the Code of Conduct by submitting a request to the Company’s corporate secretary at the address on the cover of this Form 10-K. Changes in and waivers to the Code of Conduct for the Company’s directors, chief executive officer and certain senior financial officers will be posted on the Company’s website within five business days and maintained for at least 12 months.

ITEM 11. EXECUTIVE

COMPENSATION

The information set forth under the captions “Compensation Discussion and Analysis,” “Summary Compensation Table,” “Grants of Plan Based Awards Table,” “Outstanding Equity Awards at Fiscal Year-End Table,” “Option Exercises and Stock Vested Table,” “Non-Qualified Deferred Compensation Table,” “Employment Contracts and Termination of Employment and Change-in-Control Arrangements” and “Director Compensation Table” in the Proxy Statement is incorporated herein by reference.

ITEM 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The information set forth under the captions “Securities Ownership and Principal Holders” and “Equity Compensation Plan Information” in the Proxy Statement is incorporated herein by reference.

ITEM 13. CERTAIN

RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

The information set forth under the captions “Certain Business Relationships and Transactions” and “Director Independence” in the Proxy Statement is incorporated herein by reference.

ITEM 14. PRINCIPAL

ACCOUNTING FEES AND SERVICES

The information set forth under the caption “Independent Auditors” in the Proxy Statement is incorporated herein by reference.

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a)

Documents included in this report:

Financial Statements


Report of management			F-1
Report of independent registered public accounting firm			F-2
Report of independent registered public accounting firm			F-3
Statement of consolidated operations for each of the three years in the period ended December 31, 2011			F-4
Statement of consolidated comprehensive income (loss) for each of the three years in the period ended December 31, 2011			F-5
Statement of consolidated cash flows for each of the three years in the period ended December 31, 2011			F-6
Consolidated balance sheet as of December 31, 2011 and 2010			F-7
Statement of consolidated shareholders’ equity for each of the three years in the period ended December 31, 2011			F-8
Notes to consolidated financial statements			F-9

Financial Statement Schedules

Financial statement schedules have been omitted because they are either not required, not applicable or the information required to be presented is included in the Company’s financial statements and related notes.

Exhibits


EXHIBIT NO.		DESCRIPTION

2.1	–	Agreement and Plan of Merger, dated April 14, 2010, by and among Registrant, ZMZ Acquisitions LLC, and Mariner Energy, Inc. (incorporated by reference to Exhibit 2.1 to Registrant’s Current Report on Form 8-K, dated April 14, 2010, filed April 16, 2010, SEC File No. 001-4300) (the schedules and annexes have been omitted pursuant to Item 601(b)(2) of Regulation S-K).

2.2	–	Amendment No. 1, dated August 2, 2010, to Agreement and Plan of Merger, dated April 14, 2010, by and among Registrant, ZMZ Acquisitions LLC, and Mariner Energy, Inc. ( incorporated by reference to Exhibit 2.1 to Registrant’s Current Report on Form 8-K, dated August 2, 2010, filed on August 3, 2010, SEC File No. 001-4300) (the schedules and annexes have been omitted pursuant to Item 601(b)(2) of Regulation S-K).

2.3	–	Purchase and Sale Agreement by and between BP America Production Company and ZPZ Delaware I LLC dated July 20, 2010 (incorporated by reference to Exhibit 2.1 to Registrant’s Current Report on Form 8-K/A, dated July 20, 2010, filed on July 21, 2010, SEC File No. 001-4300) (the exhibits and schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K).


EXHIBIT NO.		DESCRIPTION

2.4	–	Partnership Interest and Share Purchase and Sale Agreement by and between BP Canada Energy and Apache Canada Ltd. dated July 20, 2010 (incorporated by reference to Exhibit 2.2 to Registrant’s Current Report on Form 8-K/A, dated July 20, 2010, filed on July 21, 2010, SEC File No. 001-4300) (the exhibits have been omitted pursuant to Item 601(b)(2) of Regulation S-K).

2.5	–	Purchase and Sale Agreement by and among BP Egypt Company, BP Exploration (Delta) Limited and ZPZ Egypt Corporation LDC dated July 20, 2010 (incorporated by reference to Exhibit 2.3 to Registrant’s Current Report on Form 8-K/A, dated July 20, 2010, filed on July 21, 2010, SEC File No. 001-4300) (the exhibits and schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K).

3.1	–	Restated Certificate of Incorporation of Registrant, dated February 23, 2010, as filed with the Secretary of State of Delaware on February 23, 2010 (incorporated by reference to Exhibit 3.1 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2009, SEC File No. 001-4300).

3.2	–	Certificate of Designations of the 6.00% Mandatory Convertible Preferred Stock, Series D (incorporated by reference to Exhibit 3.3 to Registrant’s Registration Statement on Form 8-A, dated July 29, 2010, SEC File No. 001-4300).

3.3	–	Amendment to Restated Certificate of Incorporation of Registrant, dated May 5, 2011, as filed with the Secretary of State of Delaware on May 5, 2011 (incorporated by reference to Exhibit 3.1 to Registrant’s Current Report on Form 8-K filed May 11, 2011, SEC File No. 001-4300).

3.4	–	Bylaws of Registrant, as amended July 21, 2011 (incorporated by reference to Exhibit 3.1 to Registrant’s Current Report on Form 8-K filed July 27, 2011, SEC File No. 001-4300).

4.1	–	Form of Certificate for Registrant’s Common Stock (incorporated by reference to Exhibit 4.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2004, SEC File No. 001-4300).

4.2	–	Form of Certificate for the 6.00% Mandatory Convertible Preferred Stock, Series D(incorporated by reference to Exhibit A of Exhibit 3.3 to Registrant’s Registration Statement on Form 8-A, dated July 29, 2010, SEC File No. 001-4300).

4.3	–	Form of 3.625% Notes due 2021 (incorporated by reference to Exhibit 4.1 to Registrant’s Current Report on Form 8-K, dated November 30, 2010, filed on December 3, 2010, SEC File No. 001-4300).


EXHIBIT NO.		DESCRIPTION

4.4	–	Form of 5.250% Notes due 2042 (incorporated by reference to Exhibit 4.2 to Registrant’s Current Report on Form 8-K, dated November 30, 2010, filed on December 3, 2010, SEC File No. 001-4300).

4.5	–	Form of 5.100% Notes due 2040 (incorporated by reference to Exhibit 4.1 to Registrant’s Current Report on Form 8-K, dated August 17, 2010, filed on August 20, 2010, SEC File No. 001-4300).

4.6	–	Rights Agreement, dated January 31, 1996, between Registrant and Wells Fargo Bank, N.A. (as successor-in-interest to Norwest Bank Minnesota, N.A.), rights agent, relating to the declaration of a rights dividend to Registrant’s common shareholders of record on January 31, 1996 (incorporated by reference to Exhibit (a) to Registrant’s Registration Statement on Form 8-A, dated January 24, 1996, SEC File No. 001-4300).

4.7	–	Amendment No. 1, dated as of January 31, 2006, to the Rights Agreement dated as of December 31, 1996, between Apache Corporation, a Delaware corporation, and Wells Fargo Bank, N.A. (as successor-in-interest to Norwest Bank Minnesota, N.A.) (incorporated by reference to Exhibit 4.4 to Registrant’s Amendment No. 1 to Registration Statement on Form 8-A, dated January 31, 2006, SEC File No. 001-4300).

4.8	–	Senior Indenture, dated February 15, 1996, between Registrant and The Bank of New York Mellon Trust Company, N.A. (formerly known as the Bank of New York Trust Company, N.A., as successor-in-interest to JPMorgan Chase Bank), formerly known as The Chase Manhattan Bank, as trustee, governing the senior debt securities and guarantees (incorporated by reference to Exhibit 4.6 to Registrant’s Registration Statement on Form S-3, dated May 23, 2003, Reg. No. 333-105536).

4.9	–	First Supplemental Indenture to the Senior Indenture, dated as of November 5, 1996, between Registrant and The Bank of New York Mellon Trust Company, N.A. (formerly known as the Bank of New York Trust Company, N.A., as successor-in-interest to JPMorgan Chase Bank, formerly known as The Chase Manhattan Bank), as trustee, governing the senior debt securities and guarantees (incorporated by reference to Exhibit 4.7 to Registrant’s Registration Statement on Form S-3, dated May 23, 2003, Reg. No. 333-105536).

4.10	–	Form of Indenture among Apache Finance Pty Ltd, Registrant and The Bank of New York Mellon Trust Company, N.A. (formerly known as the Bank of New York Trust Company, N.A., as successor-in-interest to The Chase Manhattan Bank), as trustee, governing the debt securities and guarantees (incorporated by reference to Exhibit 4.1 to Registrant’s Registration Statement on Form S-3, dated November 12, 1997, Reg. No. 333-339973).


EXHIBIT NO.		DESCRIPTION

4.11	–	Form of Indenture among Registrant, Apache Finance Canada Corporation and The Bank of New York Mellon Trust Company, N.A. (formerly known as the Bank of New York Trust Company, N.A., as successor-in-interest to The Chase Manhattan Bank), as trustee, governing the debt securities and guarantees (incorporated by reference to Exhibit 4.1 to Amendment No. 1 to Registrant’s Registration Statement on Form S-3, dated November 12, 1999, Reg. No. 333-90147).

4.12	–	Deposit Agreement, dated as of July 28, 2010, between Registrants and Wells Fargo Bank, N.A., as depositary, on behalf of all holders from time to time of the receipts issued there under (incorporated by reference to Exhibit 4.2 to Registrant’s Current Report on Form 8-K, dated July 22, 2010, filed on July 28, 2010, SEC File No. 001-4300).

4.13	–	Form of Depositary Receipt for the Depositary Shares (incorporated by reference to Exhibit A to Exhibit 4.2 to Registrant’s Current Report on Form 8-K, dated July 22, 2010, filed on July 28, 2010, SEC File No. 001-4300).

4.14	–	Senior Indenture, dated May 19 2011, between Registrant and Wells Fargo Bank, National Association, as trustee, governing the senior debt securities of Apache Corporation (incorporated by reference to Exhibit 4.14 to Registrant’s Registration Statement on Form S-3, dated May 23, 2011, Reg. No. 333-174429).

4.15	–	Senior Indenture, dated May 19, 2011, among Apache Finance Pty Ltd, Apache Corporation, as guarantor, and Wells Fargo Bank, National Association, as trustee, governing the senior debt securities of Apache Finance Pty Ltd and the related guarantees (incorporated by reference to Exhibit 4.16 to Registrant’s Registration Statement on Form S-3, dated May 23, 2011, Reg. No. 333-174429).

4.16	–	Senior Indenture, dated May 19, 2011, among Apache Finance Canada Corporation, Apache Corporation, as guarantor, and Wells Fargo Bank, National Association, as trustee, governing the senior debt securities of Apache Finance Corporation and the related guarantees (incorporated by reference to Exhibit 4.20 to Registrant’s Registration Statement on Form S-3, dated May 23, 2011, Reg. No. 333-174429).

4.17	–	Form of Apache Corporation November 10, 2010 First Non-Qualified Stock Option Agreement for Certain Employees of Apache Corporation (incorporated by reference to Exhibit 4.6 to Registrant’s Registration Statement on Form S-8 filed on November 10, 2010, Reg. No. 333-170533).


EXHIBIT NO.		DESCRIPTION

4.18	–	Form of Apache Corporation November 10, 2010 Second Non-Qualified Stock Option Agreement for Certain Employees of Apache Corporation (incorporated by reference to Exhibit 4.7 to Registrant’s Registration Statement on Form S-8 filed on November 10, 2010, Reg. No. 333-170533).

4.19	–	Form of Apache Corporation November 10, 2010 Non-Statutory Stock Option Agreement for Certain Employees of Apache Corporation (incorporated by reference to Exhibit 4.8 to Registrant’s Registration Statement on Form S-8 filed on November 10, 2010, Reg. No. 333-170533).

10.1	–	Form of Amended and Restated Credit Agreement, dated as of May 9, 2006, among Registrant, the Lenders named therein, JPMorgan Chase Bank, as Administrative Agent, Citibank, N.A. and Bank of America, N.A., as Co-Syndication Agents, and BNP Paribas and UBS Loan Finance LLC, as Co-Documentation Agents (incorporated by reference to Exhibit 10.1 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2006, SEC File No. 001-4300).

10.2	–	Form of Request for Approval of Extension of Maturity Date and Amendment, dated as of April 5, 2007, among Registrant, the Lenders named therein, JPMorgan Chase Bank, as Administrative Agent, Citibank, N.A. and Bank of America, N.A., as Co-Syndication Agents, and BNP Paribas and UBS Loan Finance LLC, as Co-Documentation Agents (incorporated by reference to Exhibit 10.2 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2007, SEC File No. 001-4300).

10.3	–	Form of Request for Approval of Extension of Maturity Date and Amendment, dated as of February 18, 2008, among Registrant, the Lenders named therein, JPMorgan Chase Bank, as Administrative Agent, Citibank, N.A. and Bank of America, N.A., as Co-Syndication Agents, and BNP Paribas and UBS Loan Finance LLC, as Co-Documentation Agents (incorporated by reference to Exhibit 10.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2008, SEC File No. 001-4300).

10.4	–	Form of Credit Agreement, dated as of May 12, 2005, among Registrant, the Lenders named therein, JPMorgan Chase Bank, N.A., as Global Administrative Agent, J.P. Morgan Securities Inc. and Banc of America Securities, LLC, as Co-Lead Arrangers and Joint Bookrunners, Bank of America, N.A. and Citibank, N.A., as U.S. Co-Syndication Agents, and Calyon New York Branch and Société Générale, as U.S. Co-Documentation Agents (excluding exhibits and schedules) (incorporated by reference to Exhibit 10.01 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005, SEC File No. 001-4300).


EXHIBIT NO.		DESCRIPTION

10.5	–	Form of Credit Agreement, dated as of May 12, 2005, among Apache Canada Ltd, a wholly-owned subsidiary of Registrant, the Lenders named therein, JPMorgan Chase Bank, N.A., as Global Administrative Agent, RBC Capital Markets and BMO Nesbitt Burns, as Co-Lead Arrangers and Joint Bookrunners, Royal Bank of Canada, as Canadian Administrative Agent, Bank of Montreal and Union Bank of California, N.A., Canada Branch, as Canadian Co-Syndication Agents, and The Toronto-Dominion Bank and BNP Paribas (Canada), as Canadian Co-Documentation Agents (excluding exhibits and schedules) (incorporated by reference to Exhibit 10.02 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005, SEC File No. 001-4300).

10.6	–	Form of Credit Agreement, dated as of May 12, 2005, among Apache Energy Limited, a wholly-owned subsidiary of Registrant, the Lenders named therein, JPMorgan Chase Bank, N.A., as Global Administrative Agent, Citigroup Global Markets Inc. and Deutsche Bank Securities Inc., as Co-Lead Arrangers and Joint Bookrunners, Citi securities Limited, as Australian Administrative Agent, Deutsche Bank AG, Sydney Branch, and JPMorgan Chase Bank, as Australian Co-Syndication Agents, and Bank of America, N.A., Sydney Branch, and UBS AG, Australia Branch, as Australian Co-Documentation Agents (excluding exhibits and schedules) (incorporated by reference to Exhibit 10.03 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005, SEC File No. 001-4300).

10.7	–	Form of Request for Approval of Extension of Maturity Date and Amendment, dated April 5, 2007, among Registrant, Apache Canada Ltd., Apache Energy Limited, the Lenders named therein, JPMorgan Chase Bank, N.A., as Global Administrative Agent, and the other agents party thereto (incorporated by reference to Exhibit 10.6 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2007, SEC File No. 001-4300).

10.8	–	Form of Request for Approval of Extension of Maturity Date and Amendment, dated February 18, 2008, among Registrant, Apache Canada Ltd., Apache Energy Limited, the Lenders named therein, JPMorgan Chase Bank, N.A., as Global Administrative Agent, and the other agents party thereto (incorporated by reference to Exhibit 10.2 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2008, SEC File No. 001-4300).

10.9	–	Credit Agreement, dated August 13, 2010, among Registrant, JP Morgan Chase Bank, N.A., as Administrative Agent, and Citibank, N.A., Bank Of America, N.A. and Goldman Sachs Bank USA, as Co-Syndication Agents, J.P. Morgan Securities Inc., Citigroup Global Markets Inc., Banc Of America Securities, LLC and Goldman Sachs Bank USA, As Co-Lead Arrangers and Joint Bookrunners, and the lenders party thereto (excluding exhibits and schedules) (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed August 16, 2010).


EXHIBIT NO.		DESCRIPTION

10.10	–	Credit Agreement, dated August 12, 2011, among Registrant, the lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, and Citibank, N.A., Bank of America, N.A., and Wells Fargo Bank, National Association, as Syndication Agents (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed August 18, 2011, SEC File No. 001-4300).

†10.11	–	Apache Corporation Corporate Incentive Compensation Plan A (Senior Officers’ Plan), dated July 16, 1998 (incorporated by reference to Exhibit 10.13 to Registrant’s Annual Report on Form 10-K for year ended December 31, 1998, SEC File No. 001-4300).

†10.12	–	First Amendment to Apache Corporation Corporate Incentive Compensation Plan A, dated November 20, 2008, effective as of January 1, 2005 (incorporated by reference to Exhibit 10.17 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2008, SEC File No. 001-4300).

†10.13	–	Apache Corporation Corporate Incentive Compensation Plan B (Strategic Objectives Format), dated July 16, 1998 (incorporated by reference to Exhibit 10.14 to Registrant’s Annual Report on Form 10-K for year ended December 31, 1998, SEC File No. 001-4300).

†10.14	–	First Amendment to Apache Corporation Corporate Incentive Compensation Plan B, dated November 20, 2008, effective as of January 1, 2005 (incorporated by reference to Exhibit 10.19 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2008, SEC File No. 001-4300).

†10.15	–	Apache Corporation 401(k) Savings Plan, as amended and restated, dated October 28, 2010 (incorporated by reference to Exhibit 10.14 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2010, SEC File No. 001-4300).

†10.16	–	Amendment to Apache Corporation 401(k) Savings Plan, dated December 30, 2010, effective as of November 10, 2010, except as otherwise specified (incorporated by reference to Exhibit 10.15 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2010, SEC File No. 001-4300).

†10.17	–	Amendment to Apache Corporation 401(k) Savings Plan, dated August 31, 2011, effective September 1, 2011 (incorporated by reference to Exhibit 10.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2011, SEC File No. 001-4300).

*†10.18	–	Amendment to Apache Corporation 401(k) Savings Plan, dated December 19, 2011, effective January 1, 2012, except as otherwise specified.


EXHIBIT NO.		DESCRIPTION

†10.19	–	Non-Qualified Retirement/Savings Plan of Apache Corporation, as amended and restated July 14, 2010, except as otherwise specified (incorporated by reference to Exhibit 10.3 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, SEC File No. 001-4300).

*†10.20	–	Amendment to Apache Corporation Non-Qualified Retirement/Savings Plan of Apache Corporation, dated December 19, 2011, effective January 1, 2012.

†10.21	–	Non-Qualified Restorative Retirement Savings Plan of Apache Corporation, dated November 7, 2011, effective January 1, 2012 (incorporated by reference to Exhibit 4.7 to Registrant’s Registration Statement on Form S-8, dated December 21, 2011, Reg. No. 333-178672).

†10.22	–	Apache Corporation 2011 Omnibus Equity Compensation Plan, effective May 5, 2011 (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed May 11, 2011, SEC File No. 001-4300).

†10.23	–	Apache Corporation 2007 Omnibus Equity Compensation Plan, as amended and restated May 4, 2011 (incorporated by reference to Exhibit 10.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2011, SEC File No. 001-4300).

†10.24	–	Apache Corporation 1998 Stock Option Plan, as amended and restated May 5, 2011 (incorporated by reference to Exhibit 10.2 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2011, SEC File No. 001-4300).

†10.25	–	Apache Corporation 2000 Stock Option Plan, as amended and restated May 5, 2011 (incorporated by reference to Exhibit 10.3 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2011, SEC File No. 001-4300).

†10.26	–	Apache Corporation 2003 Stock Appreciation Rights Plan, as amended and restated May 4, 2011 (incorporated by reference to Exhibit 10.5 to Registrant’s Quarterly Report on Form 10-Q for quarter ended March 31, 2011, SEC File No. 001-4300).

†10.27	–	Apache Corporation 2005 Stock Option Plan, as amended and restated May 5, 2011 (incorporated by reference to Exhibit 10.4 to Registrant’s Quarterly Report on Form 10-Q for quarter ended March 31, 2011, Commission File No. 001-4300).

†10.28	–	Apache Corporation 2005 Share Appreciation Plan, as amended and restated August 14, 2008 (incorporated by reference to Exhibit 10.7 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, Commission File No. 001-4300).


EXHIBIT NO.		DESCRIPTION

†10.29	–	Apache Corporation 2008 Share Appreciation Program Specifications, pursuant to Apache Corporation 2007 Omnibus Equity Compensation Plan (incorporated by reference to Exhibit 10.3 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2008, SEC File No. 001-4300).

†10.30	–	Apache Corporation Executive Restricted Stock Plan, as amended and restated November 19, 2008 (incorporated by reference to Exhibit 10.37 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2008, SEC File No. 001-4300).

†10.31	–	Apache Corporation Income Continuance Plan, as amended and restated July 14, 2010, effective January 1, 2009 (incorporated by reference to Exhibit 10.5 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, SEC File No. 001-4300).

†10.32	–	Apache Corporation Deferred Delivery Plan, as amended and restated July 13, 2010, effective January 1, 2009 (incorporated by reference to Exhibit 10.6 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, SEC File No. 001-4300).

†10.33	–	Apache Corporation Non-Employee Directors’ Compensation Plan, as amended and restated November 20, 2008, effective as of January 1, 2009 (incorporated by reference to Exhibit 10.38 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2008, SEC File No. 001-4300).

†10.34	–	Apache Corporation Outside Directors’ Retirement Plan, as amended and restated July 21, 2011, effective January 1, 2009 (incorporated by reference to Exhibit 10.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, SEC File No. 001-4300).

†10.35	–	Apache Corporation Equity Compensation Plan for Non-Employee Directors, as amended and restated February 8, 2007 (incorporated by reference to Exhibit 10.2 to Registrant’s Quarterly Report on Form 10-Q for quarter ended March 31, 2007, SEC File No. 001-4300).

†10.36	–	Apache Corporation Non-Employee Directors’ Restricted Stock Units Program Specifications, dated August 14, 2008, pursuant to Apache Corporation 2007 Omnibus Equity Compensation Plan (incorporated by reference to Exhibit 10.9 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, SEC File No. 001-4300).

†10.37	–	Apache Corporation Non-Employee Directors’ Restricted Stock Units Program Specifications, dated May 5, 2011, pursuant to Apache Corporation 2011 Omnibus Equity Compensation Plan (incorporated by reference to Exhibit 10.6 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2011, SEC File No. 001-4300).


EXHIBIT NO.		DESCRIPTION

†10.38	–	Restated Employment and Consulting Agreement, dated January 15, 2009, between Registrant and Raymond Plank (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K, dated January 15, 2009, filed January 16, 2009, SEC File No. 001-4300).

†10.39	–	Amended and Restated Employment Agreement, dated December 20, 1990, between Registrant and John A. Kocur (incorporated by reference to Exhibit 10.10 to Registrant’s Annual Report on Form 10-K for year ended December 31, 1990, SEC File No. 001-4300).

†10.40	–	Employment Agreement between Registrant and G. Steven Farris, dated June 6, 1988, and First Amendment, dated November 20, 2008, effective as of January 1, 2005 (incorporated by reference to Exhibit 10.44 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2008, SEC File No. 001-4300).

†10.41	–	Amended and Restated Conditional Stock Grant Agreement, dated September 15, 2005, effective January 1, 2005, between Registrant and G. Steven Farris (incorporated by reference to Exhibit 10.06 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2005, SEC File No. 001-4300).

†10.42	–	Restricted Stock Unit Award Agreement, dated May 8, 2008, between Registrant and G. Steven Farris (incorporated by reference to Exhibit 10.4 to Registrant’s Quarterly Report on Form 10-Q for quarter ended March 31, 2008, SEC File No. 001-4300).

†10.43	–	Form of Restricted Stock Unit Award Agreement, dated February 12, 2009, between Registrant and each of John A. Crum, Rodney J. Eichler, and Roger B. Plank (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K, dated February 12, 2009, filed February 18, 2009, SEC File No. 001-4300).

†10.44	–	Amendment to Restricted Stock Unit Award Agreement, dated March 7, 2011, between Registrant and John A. Crum (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report Form 8-K/A filed March 8, 2011, SEC File No. 001-4300).

†10.45	–	Resignation Agreement, dated March 7, 2011 between Registrant and John A. Crum (incorporated by reference to Exhibit 10.2 to Registrant’s Current Report on Form 8-K/A filed March 8, 2011, SEC File No. 001-4300).

†10.46	–	Form of Restricted Stock Unit Award Agreement, dated November 18, 2009, between Registrant and Michael S. Bahorich (incorporated by reference to Exhibit 10.37 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2009, SEC File No. 001-4300).


EXHIBIT NO.		DESCRIPTION

†10.47	–	Form of Restricted Stock Unit Grant Agreement, dated May 6, 2009, between Registrant and each of G. Steven Farris, Roger B. Plank, John A. Crum, Rodney J. Eichler, and Michael S. Bahorich (incorporated by reference to Exhibit 10.38 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2009, SEC File No. 001-4300).

†10.48	–	Form of Stock Option Award Agreement, dated May 6, 2009, between Registrant and each of G. Steven Farris, Roger B. Plank, John A. Crum, Rodney J. Eichler, and Michael S. Bahorich (incorporated by reference to Exhibit 10.39 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2009, SEC File No. 001-4300).

†10.49	–	Form of 2010 Performance Program Agreement, dated January 15, 2010, between Registrant and each of G. Steven Farris, John A. Crum, Rodney J. Eichler, and Roger B. Plank (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed January 19, 2010, SEC File No. 001-4300).

†10.50	–	Form of First Amendment, effective May 5, 2010, to 2010 Performance Program Agreement, dated January 15, 2010, between Registrant and each of G. Steven Farris, John A. Crum, Rodney J. Eichler, and Roger B. Plank (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed May 11, 2010, SEC File No. 001-4300).

†10.51	–	Form of Restricted Stock Unit Award Agreement, dated January 15, 2010, between Registrant and each of John A. Crum, Rodney J. Eichler, and Roger B. Plank (incorporated by reference to Exhibit 10.2 to Registrant’s Current Report on Form 8-K filed January 19, 2010, SEC File No. 001-4300).

†10.52	–	Form of 2011 Performance Program Agreement, dated January 7, 2011, between Registrant and each of G. Steven Farris, John A. Crum, Rodney J. Eichler, Roger B. Plank, Michael S. Bahorich, and Thomas P. Chambers (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed January 13, 2011, SEC File No. 001-4300).

†10.53	–	Restricted Stock Unit Award Agreement, dated February 9, 2011, between Registrant and Thomas P. Chambers (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed February 14, 2011, SEC File No. 001-4300).

†10.54	–	Form of 2012 Performance Program Agreement, dated January 11, 2012, between Registrant and each of G. Steven Farris, Rodney J. Eichler, Roger B. Plank, P. Anthony Lannie, and Thomas P. Chambers (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed January 13, 2012, SEC File No. 001-4300).

*12.1	–	Statement of Computation of Ratios of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividends.


EXHIBIT NO.		DESCRIPTION

*14.1	–	Code of Business Conduct, as amended and restated November 15, 2011

*21.1	–	Subsidiaries of Registrant

*23.1	–	Consent of Ernst & Young LLP

*23.2	–	Consent of Ryder Scott Company L.P., Petroleum Consultants

*24.1	–	Power of Attorney (included as a part of the signature pages to this report)

*31.1	–	Certification (pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Exchange Act) by Principal Executive Officer.

*31.2	–	Certification (pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Exchange Act) by Principal Financial Officer.

*32.1	–	Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by Principal Executive Officer and Principal Financial Officer.

*99.1	–	Report of Ryder Scott Company L.P., Petroleum Consultants

*101.INS	–	XBRL Instance Document.

*101.SCH	–	XBRL Taxonomy Schema Document.

*101.CAL	–	XBRL Calculation Linkbase Document.

*101.LAB	–	XBRL Label Linkbase Document.

*101.PRE	–	XBRL Presentation Linkbase Document.

*101.DEF	–	XBRL Definition Linkbase Document.

*	Filed herewith.

†	Management contracts or compensatory plans or arrangements required to be filed herewith pursuant to Item 15 hereof.

NOTE: Debt instruments of the Registrant defining the rights of long-term debt holders in principal amounts not exceeding 10 percent of the Registrant’s consolidated assets have been omitted and will be provided to the Commission upon request.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, hereunto duly authorized.

APACHE CORPORATION

/s/ G. STEVEN FARRIS

G. Steven Farris

Chairman of the Board and Chief Executive Officer

Dated: February 28, 2012

REPORT OF MANAGEMENT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Management of the Company is responsible for the preparation and integrity of the consolidated financial statements appearing in this annual report on Form 10-K. The financial statements were prepared in conformity with accounting principles generally accepted in the United States and include amounts that are based on management’s best estimates and judgments.

Management of the Company is responsible for establishing and maintaining effective internal control over financial reporting as such term is defined in Rule 13a-15(f) under the Securities Exchange Act of 1934. The Company’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the consolidated financial statements. Our internal control over financial reporting is supported by a program of internal audits and appropriate reviews by management, written policies and guidelines, careful selection and training of qualified personnel and a written code of business conduct adopted by our Company’s board of directors, applicable to all Company directors and all officers and employees of our Company and subsidiaries.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements and even when determined to be effective, can only provide reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.

Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2011. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control — Integrated Framework. Based on our assessment, management believes that the Company maintained effective internal control over financial reporting as of December 31, 2011.

The Company’s independent auditors, Ernst & Young LLP, a registered public accounting firm, are appointed by the Audit Committee of the Company’s board of directors. Ernst & Young LLP have audited and reported on the consolidated financial statements of Apache Corporation and subsidiaries, and the effectiveness of the Company’s internal control over financial reporting. The reports of the independent auditors follow this report on pages F-2 and F-3.

/s/ G. Steven Farris

Chairman of the Board and Chief Executive Officer

(principal executive officer)

/s/ Thomas P. Chambers

Executive Vice President and Chief Financial Officer

(principal financial officer)

/s/ Rebecca A. Hoyt

Vice President, Chief Accounting Officer and Controller

(principal accounting officer)

Houston, Texas

February 28, 2012

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Shareholders of Apache Corporation:

We have audited the accompanying consolidated balance sheets of Apache Corporation and subsidiaries as of December 31, 2011 and 2010, and the related consolidated statements of operations, comprehensive income (loss), shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2011. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Apache Corporation and subsidiaries at December 31, 2011 and 2010, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, in conformity with U.S. generally accepted accounting principles.

As discussed in Note 1 to the consolidated financial statements, in 2009, the Company adopted SEC Release 33-8995 and the amendments to ASC Topic 932, “Extractive Industries — Oil and Gas,” resulting from ASU 2010-03 (collectively, the Modernization Rules).

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Apache Corporation’s internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 28, 2012, expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Houston, Texas

February 28, 2012

F-2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Shareholders of Apache Corporation:

We have audited Apache Corporation and subsidiaries’ internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Apache Corporation and subsidiaries’ management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Report of Management on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with U.S. generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Apache Corporation and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Apache Corporation and subsidiaries as of December 31, 2011 and 2010, and the related consolidated statements of operations, comprehensive income (loss), shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2011 of Apache Corporation and subsidiaries, and our report dated February 28, 2012, expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Houston, Texas

February 28, 2012

F-3

APACHE CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED OPERATIONS


	For the Year Ended December 31,
	2011		2010			2009
	(In millions, except per common share data)
REVENUES AND OTHER:
Oil and gas production revenues	$	16,810	$	12,183		$	8,574
Other		78		(91	)		41

		16,888		12,092			8,615

OPERATING EXPENSES:
Depreciation, depletion and amortization
Recurring		4,095		3,083			2,395
Additional		109		—			2,818
Asset retirement obligation accretion		154		111			105
Lease operating expenses		2,605		2,032			1,662
Gathering and transportation		296		178			143
Taxes other than income		899		690			580
General and administrative		459		380			344
Merger, acquisitions & transition		20		183			—
Financing costs, net		158		229			242

		8,795		6,886			8,289

INCOME BEFORE INCOME TAXES		8,093		5,206			326
Current income tax provision		2,263		1,222			842
Deferred income tax provision (benefit)		1,246		952			(231	)

NET INCOME (LOSS)		4,584		3,032			(285	)
Preferred stock dividends		76		32			7

INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	4,508	$	3,000		$	(292	)

NET INCOME (LOSS) PER COMMON SHARE:
Basic	$	11.75	$	8.53		$	(0.87	)
Diluted	$	11.47	$	8.46		$	(0.87	)

WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
Basic		384		352			336
Diluted		400		359			336

DIVIDENDS DECLARED PER COMMON SHARE	$	0.60	$	0.60		$	0.60

The accompanying notes to consolidated financial statements are an integral part of this statement.

F-4

APACHE CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS)


	For the Year Ended December 31,
	2011			2010			2009
	(In millions)
NET INCOME (LOSS)	$	4,584		$	3,032		$	(285	)

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX:
Pension and postretirement benefit plan		(1	)		(2	)		(4	)
Net commodity hedge gains (losses)		133			151			(308	)

		132			149			(312	)

COMPREHENSIVE INCOME (LOSS)		4,716			3,181			(597	)
Preferred stock dividends		76			32			7

COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	4,640		$	3,149		$	(604	)

The accompanying notes to consolidated financial statements are an integral part of this statement.

F-5

APACHE CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED CASH FLOWS


	For the Year Ended December 31,
	2011			2010			2009
	(In millions)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	4,584		$	3,032		$	(285	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		4,204			3,083			5,213
Asset retirement obligation accretion		154			111			105
Provision for (benefit from) deferred income taxes		1,246			952			(231	)
Other		46			190			183
Changes in operating assets and liabilities, net of effects of acquisitions:
Receivables		(759	)		(496	)		(187	)
Inventories		(37	)		35			(5	)
Drilling advances		26			(28	)		(143	)
Deferred charges and other		27			(141	)		148
Accounts payable		241			214			(180	)
Accrued expenses		90			(309	)		(330	)
Deferred credits and noncurrent liabilities		131			83			(64	)

NET CASH PROVIDED BY OPERATING ACTIVITIES		9,953			6,726			4,224

CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property		(6,414	)		(4,407	)		(3,326	)
Additions to gathering, transmission and processing facilities		(664	)		(515	)		(306	)
Acquisition of Marathon properties		—			—			(181	)
Acquisition of Devon properties		—			(1,018	)		—
Acquisition of BP properties and facilities		—			(6,429	)		—
Mariner Energy, Inc. merger		—			(787	)		—
Acquisition of Mobil North Sea Limited		(1,246	)		—			—
Acquisitions, other		(567	)		(126	)		(129	)
Short-term investments		—			—			792
Restricted cash		—			—			14
Proceeds from sale of oil and gas properties		422			—			3
Other, net		(176	)		(121	)		(114	)

NET CASH USED IN INVESTING ACTIVITIES		(8,645	)		(13,403	)		(3,247	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Commercial paper, credit facility and bank notes, net		(925	)		(32	)		248
Fixed-rate debt borrowings		—			2,470			—
Payments on fixed-rate notes		—			(1,023	)		(100	)
Proceeds from issuance of common stock		—			2,258			—
Proceeds from issuance of mandatory convertible preferred stock		—			1,227			—
Dividends paid		(306	)		(226	)		(209	)
Common stock activity		52			70			28
Redemption of preferred stock		—			—			(98	)
Other		32			19			21

NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		(1,147	)		4,763			(110	)

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		161			(1,914	)		867
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR		134			2,048			1,181

CASH AND CASH EQUIVALENTS AT END OF YEAR	$	295		$	134		$	2,048


SUPPLEMENTARY CASH FLOW DATA:
Interest paid, net of capitalized interest	$	156		$	187		$	243
Income taxes paid, net of refunds		1,686			1,170			686

The accompanying notes to consolidated financial statements are an integral part of this statement.

F-6

APACHE CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET


	December 31,
	2011			2010
	(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	295		$	134
Receivables, net of allowance		3,079			2,134
Inventories		655			564
Drilling advances		229			259
Derivative instruments		304			167
Prepaid assets and other		241			222

		4,803			3,480

PROPERTY AND EQUIPMENT:
Oil and gas property, on the basis of full-cost accounting:
Proved properties		67,805			57,904
Unproved properties and properties under development, not being amortized		5,530			5,048
Gathering, transmission and processing facilities		5,175			4,212
Other		709			582

		79,219			67,746
Less: Accumulated depreciation, depletion and amortization		(33,771	)		(29,595	)

		45,448			38,151

OTHER ASSETS:
Goodwill		1,114			1,032
Deferred charges and other		686			762

	$	52,051		$	43,425

LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	1,048		$	779
Accrued liabilities		2,648			1,816
Current debt		431			46
Asset retirement obligation		447			407
Derivative instruments		113			194
Other		276			282

		4,963			3,524

LONG-TERM DEBT		6,785			8,095

DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes		7,197			4,249
Asset retirement obligation		3,440			2,465
Other		673			715

		11,310			7,429

COMMITMENTS AND CONTINGENCIES (Note 8)
SHAREHOLDERS’ EQUITY:
Preferred stock, no par value, 10,000,000 shares authorized, 6% Cumulative Mandatory Convertible, Series D, $1,000 per share liquidation preference, 1,265,000 shares issued and outstanding		1,227			1,227
Common stock, $0.625 par, 860,000,000 shares authorized, 385,249,885 and 383,668,297 shares issued, respectively		241			240
Paid-in capital		9,066			8,864
Retained earnings		18,500			14,223
Treasury stock, at cost, 1,132,242 and 1,276,555 shares, respectively		(32	)		(36	)
Accumulated other comprehensive loss		(9	)		(141	)

		28,993			24,377

	$	52,051		$	43,425

The accompanying notes to consolidated financial statements are an integral part of this statement.

F-7

APACHE CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED SHAREHOLDERS’ EQUITY


	Series B Preferred Stock			Series D Preferred Stock		Common Stock		Paid-In Capital			Retained Earnings			Treasury Stock			Accumulated Other Comprehensive Income (Loss)			Total Shareholders’ Equity
	(In millions)
BALANCE AT DECEMBER 31, 2008	$	98		$	—	$	214	$	4,473		$	11,930		$	(228	)	$	22		$	16,509
Net loss		—			—		—		—			(285	)		—			—			(285	)
Postretirement, net of income tax benefit of $5		—			—		—		—			—			—			(4	)		(4	)
Commodity hedges, net of income tax benefit of $171		—			—		—		—			—			—			(308	)		(308	)
Cash dividends:
Preferred		—			—		—		—			(7	)		—			—			(7	)
Common ($0.60 per share)		—			—		—		—			(201	)		—			—			(201	)
Preferred stock redemption		(98	)		—		—		—			—			—			—			(98	)
Common stock activity, net		—			—		1		15			—			—			—			16
Treasury stock activity, net		—			—		—		(5	)		—			11			—			6
Compensation expense		—			—		—		128			—			—			—			128
Other		—			—		—		23			—			—			—			23

BALANCE AT DECEMBER 31, 2009	$	—		$	—	$	215	$	4,634		$	11,437		$	(217	)	$	(290	)	$	15,779
Net income		—			—		—		—			3,032			—			—			3,032
Postretirement, net of income tax expense of $2		—			—		—		—			—			—			(2	)		(2	)
Commodity hedges, net of income tax expense of $62		—			—		—		—			—			—			151			151
Cash dividends:
Preferred		—			—		—		—			(32	)		—			—			(32	)
Common ($0.60 per share)		—			—		—		—			(214	)		—			—			(214	)
Mandatory convertible preferred stock issued		—			1,227		—		—			—			—			—			1,227
Common stock issuance		—			—		24		3,969			—			170			—			4,163
Common stock activity, net		—			—		1		26			—			—			—			27
Treasury stock activity, net		—			—		—		1			—			11			—			12
Compensation expense		—			—		—		225			—			—			—			225
Other		—			—		—		9			—			—			—			9

BALANCE AT DECEMBER 31, 2010	$	—		$	1,227	$	240	$	8,864		$	14,223		$	(36	)	$	(141	)	$	24,377
Net income		—			—		—		—			4,584			—			—			4,584
Postretirement, net of income tax benefit of $7		—			—		—		—			—			—			(1	)		(1	)
Commodity hedges, net of income tax expense of $66		—			—		—		—			—			—			133			133
Cash dividends:
Preferred		—			—		—		—			(76	)		—			—			(76	)
Common ($0.60 per share)		—			—		—		—			(231	)		—			—			(231	)
Common stock activity, net		—			—		1		35			—			—			—			36
Treasury stock activity, net		—			—		—		2			—			4			—			6
Compensation expense		—			—		—		167			—			—			—			167
Other		—			—		—		(2	)		—			—			—			(2	)

BALANCE AT DECEMBER 31, 2011	$	—		$	1,227	$	241	$	9,066		$	18,500		$	(32	)	$	(9	)	$	28,993

The accompanying notes to consolidated financial statements are an integral part of this statement.

F-8

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Nature of Operations

Apache Corporation (Apache or the Company) is an oil and gas exploration and production company with operations in six countries: the United States (U.S.), Canada, Egypt, the United Kingdom (U.K.) North Sea, Australia, and Argentina.

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Accounting policies used by Apache and its subsidiaries reflect industry practices and conform to accounting principles generally accepted in the U.S. (GAAP). Certain reclassifications have been made to prior periods to conform to current-year presentation. Significant policies are discussed below.

Principles of Consolidation

The accompanying consolidated financial statements include the accounts of Apache and its subsidiaries after elimination of intercompany balances and transactions. The Company’s interest in oil and gas exploration and production ventures and partnerships are proportionately consolidated. The Company consolidates all investments in which the Company, either through direct or indirect ownership, has more than a 50-percent voting interest.

Use of Estimates

Preparation of financial statements in conformity with GAAP and disclosure of contingent assets and liabilities requires management to make estimates and assumptions that affect reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Company bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about carrying values of assets and liabilities that are not readily apparent from other sources. Apache evaluates its estimates and assumptions on a regular basis. Actual results may differ from these estimates and assumptions used in preparation of its financial statements and changes in these estimates are recorded when known. Significant estimates made in preparing these financial statements include the fair value determination of acquired assets and liabilities (see Note 2 — Acquisitions and Divestitures), the estimate of proved oil and gas reserves and related present value estimates of future net cash flows therefrom (see Note 14 — Supplemental Oil and Gas Disclosures), assessing asset retirement obligations (see Note 5 — Asset Retirement Obligation) and the estimate of income taxes (see Note 7 — Income Taxes).

Cash Equivalents

The Company considers all highly liquid short-term investments with a maturity of three months or less at the time of purchase to be cash equivalents. These investments are carried at cost, which approximates fair value. As of December 31, 2011 and 2010, Apache had $295 million and $134 million, respectively, of cash and cash equivalents.

Accounts Receivable and Allowance for Doubtful Accounts

Accounts receivable are stated at the historical carrying amount net of write-offs and allowance for uncollectible accounts. The carrying amount of Apache’s accounts receivable approximate fair value because of the short-term nature of the instruments. The Company routinely assesses the collectability of all material trade and other receivables. Many of Apache’s receivables are from joint interest owners on properties Apache operates. The Company may have the ability to withhold future revenue disbursements to recover any

F-9

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

non-payment of these joint interest billings. The Company accrues a reserve on a receivable when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of any reserve may be reasonably estimated. As of December 31, 2011 and 2010, the Company had an allowance for doubtful accounts of $58 million and $48 million, respectively.

Inventories

Inventories consist principally of tubular goods and equipment, stated at weighted-average cost, and oil produced but not sold, stated at the lower of cost or market.

Property and Equipment

The carrying value of Apache’s property and equipment represents the cost incurred to acquire the property and equipment, including capitalized interest. Interest costs incurred in connection with qualifying capital expenditures are capitalized and amortized in concurrence with the related assets. For business acquisitions, property and equipment cost is based on the fair values at the acquisition date.

Oil and Gas Property

The Company follows the full-cost method of accounting for its oil and gas property. Under this method of accounting, all costs incurred for both successful and unsuccessful exploration and development activities, including salaries, benefits and other internal costs directly identified with these activities, and oil and gas property acquisitions are capitalized. All costs related to production, general corporate overhead or similar activities are expensed as incurred. Apache capitalized $335 million, $321 million and $219 million of internal costs in 2011, 2010 and 2009, respectively.

Proved properties are amortized on a country-by-country basis using the units of production method (UOP). The UOP calculation, in its simplest terms, multiplies the percentage of estimated proved reserves produced each quarter by the cost of those reserves. The amortization base in the UOP calculation includes the sum of proved property, net of accumulated depreciation, depletion and amortization (DD&A), estimated future development costs (future costs to access and develop reserves) and asset retirement costs that are not already included in oil and gas property, less related salvage value.

The cost of unproved properties and properties under development are excluded from the amortization calculation until it is determined whether or not proved reserves can be assigned to such properties or until development projects are placed in service. Geological and geophysical costs not associated with specific properties are recorded to proved property. Unproved properties and properties under development are reviewed for impairment at least quarterly. In countries where proved reserves exist, exploratory drilling costs associated with dry holes are transferred to proved properties immediately upon determination that a well is dry and amortized accordingly. For international operations where a reserve base has not yet been established, impairments are charged to earnings and are determined through an evaluation considering, among other factors, seismic data, requirements to relinquish acreage, drilling results, remaining time in the commitment period, remaining capital plan and political, economic and market conditions. In 2011, Apache’s statement of consolidated operations includes additional DD&A of $60 million related to impairment of its operations in Chile and $49 million of seismic costs incurred in countries where it has no established presence.

Proceeds from the sale or disposition of oil and gas properties are accounted for as a reduction to capitalized costs unless a significant portion (greater than 25 percent) of the Company’s reserve quantities in a particular country are sold, in which case a gain or loss is recognized in income.

F-10

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Under the full-cost method of accounting, the net book value of oil and gas properties, less related deferred income taxes, may not exceed a calculated “ceiling.” The ceiling limitation is the estimated after-tax future net cash flows from proved oil and gas reserves, discounted at 10 percent per annum and adjusted for cash flow hedges. Estimated future net cash flows exclude future cash outflows associated with settling accrued asset retirement obligations. In 2009, the Company adopted U.S. Securities and Exchange Commission (SEC) Release 33-8995 and the amendments to Accounting Standards Codification (ASC) Topic 932, “Extractive Industries — Oil and Gas” (the Modernization Rules). Under the Modernization Rules, estimated future net cash flows are calculated using 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. Prior to December 31, 2009, estimated after-tax future net cash flows were calculated using commodity prices in effect at the end of each quarter.

Any excess of the net book value of proved oil and gas properties, less related deferred income taxes, over the ceiling is charged to expense and reflected as additional DD&A in the accompanying statement of consolidated operations. Such limitations are imposed separately on a country-by-country basis and are tested quarterly. As of December 31, 2011 and 2010, capitalized costs did not exceed the ceiling limitation, and no write-down was indicated. Excluding the effects of cash flow hedges in calculating the ceiling limitation, there would have been a write-down of $92 million ($69 million net of tax) in Canada as of December 31, 2011. Excluding the effect of cash flow hedges in calculating the ceiling limitation at December 31, 2010, capitalized costs still would not have exceeded the ceiling limitation. See Note 14 — Supplemental Oil and Gas Disclosures for a discussion of the calculation of estimated future net cash flows.

At March 31, 2009, the Company recorded 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. Excluding the effects of cash flow hedges in calculating the ceiling limitation, the write-down as of March 31, 2009, would have been $3.4 billion ($2.4 billion net of tax).

Gathering, Transmission and Processing Facilities

Gathering, transmission, and processing facilities totaled $5.2 billion and $4.2 billion at December 31, 2011 and 2010, respectively. No impairment of gathering, transmission, and processing facilities was recognized during 2011, 2010, or 2009. The Company assesses the carrying amount of its gathering, transmission, and processing facilities whenever events or changes in circumstances indicate that their carrying amount may not be recoverable. If the carrying amount of these facilities is less than the sum of the undiscounted cash flows, an impairment loss is recognized for the excess of the carrying value over its fair value.

Gathering, transmission, and processing facilities, buildings, and equipment are depreciated on a straight-line basis over the estimated useful lives of the assets, which range from three to 25 years. Accumulated depreciation for these assets totaled $1.5 billion and $1.3 billion at December 31, 2011 and 2010, respectively.

Asset Retirement Obligation

The initial estimated asset retirement obligation related to property and equipment is recorded as a liability at its fair value, with an offsetting asset retirement cost recorded as an increase to the associated property and equipment on the consolidated balance sheet. If the fair value of the recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from changes in estimated inflation rates, changes in service and equipment costs and changes in the estimated timing of an asset’s retirement. Asset retirement costs are depreciated using a systematic and rational method similar to that used for the associated property and equipment. Accretion expense on the liability is recognized over the estimated productive life of the related assets.

F-11

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Goodwill

Goodwill represents the excess of the purchase price of an entity over the estimated fair value of the assets acquired and liabilities assumed. The Company assesses the carrying amount of goodwill by testing the goodwill for impairment annually and when impairment indicators arise. Goodwill totaled $1.1 billion and $1.0 billion at December 31, 2011 and 2010, respectively. Goodwill of $82 million was booked in the North Sea during 2011 as a result of the acquisition of Mobil North Sea Limited, as discussed in Note 2 — Acquisitions and Divestitures. As of December 31, 2011 and 2010, $843 million, $103 million, and $86 million were recorded in the U.S., Canada, and Egypt, respectively. Each country was assessed as a reporting unit. No impairment of goodwill was recognized during 2011, 2010, or 2009.

Accounts Payable

Included in accounts payable at December 31, 2011 and 2010, are liabilities of approximately $207 million and $191 million, respectively, representing the amount by which checks issued, but not presented to the Company’s banks for collection, exceeded balances in applicable bank accounts.

Commitments and Contingencies

Accruals for loss contingencies arising from claims, assessments, litigation, environmental and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. These accruals are adjusted as additional information becomes available or circumstances change.

Revenue Recognition and Imbalances

Oil and gas revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collectibility of the revenue is probable. Cash received relating to future revenues is deferred and recognized when all revenue recognition criteria are met.

Apache uses the sales method of accounting for gas production imbalances. The volumes of gas sold may differ from the volumes to which Apache is entitled based on its interests in the properties. These differences create imbalances that are recognized as a liability only when the properties’ estimated remaining reserves net to Apache will not be sufficient to enable the under-produced owner to recoup its entitled share through production. The Company’s recorded liability is generally reflected in other non-current liabilities. No receivables are recorded for those wells where Apache has taken less than its share of production. Gas imbalances are reflected as adjustments to estimates of proved gas reserves and future cash flows in the unaudited supplemental oil and gas disclosures.

Apache markets its own U.S. natural gas production. Since the Company’s production fluctuates because of operational issues, it is occasionally necessary to purchase gas (third-party gas) to fulfill sales obligations and commitments. Both the costs and sales proceeds of this third-party gas are reported on a net basis in oil and gas production revenues. The costs of third-party gas netted against the related sales proceeds totaled $28 million, $33 million and $34 million, for 2011, 2010 and 2009, respectively.

The Company’s Egyptian operations are conducted pursuant to production sharing contracts under which contractor partners pay all operating and capital costs for exploring and developing the concessions. A percentage of the production, generally up to 40 percent, is available to contractor partners to recover these operating and capital costs over contractually defined terms. Cost recovery is reflected in revenue. The balance of the production is split among the contractor partners and the Egyptian General Petroleum Corporation (EGPC) on a contractually defined basis.

F-12

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Derivative Instruments and Hedging Activities

Apache periodically enters into derivative contracts to manage its exposure to commodity price risk. These derivative contracts, which are generally placed with major financial institutions, may take the form of forward contracts, futures contracts, swaps, or options. The oil and gas reference prices, upon which the commodity derivative contracts are based, reflect various market indices that have a high degree of historical correlation with actual prices received by the Company for its oil and gas production.

Apache accounts for its derivative instruments in accordance with ASC Topic 815, “Derivatives and Hedging,” which requires that all derivative instruments, other than those that meet the normal purchases and sales exception, be recorded on the balance sheet as either an asset or liability measured at fair value. Changes in fair value are recognized currently in earnings unless specific hedge accounting criteria are met. Hedge accounting treatment allows unrealized gains and losses on cash flow hedges to be deferred in other comprehensive income. Realized gains and losses from the Company’s oil and gas cash flow hedges, including terminated contracts, are generally recognized in oil and gas production revenues when the forecasted transaction occurs. Gains and losses from the change in fair value of derivative instruments that do not qualify for hedge accounting are reported in current-period income as “Other” under Revenues and Other in the statement of consolidated operations. If at any time the likelihood of occurrence of a hedged forecasted transaction ceases to be “probable,” hedge accounting treatment will cease on a prospective basis, and all future changes in the fair value of the derivative will be recognized directly in earnings. Amounts recorded in other comprehensive income prior to the change in the likelihood of occurrence of the forecasted transaction will remain in other comprehensive income until such time as the forecasted transaction impacts earnings. If it becomes probable that the original forecasted production will not occur, then the derivative gain or loss would be reclassified from accumulated other comprehensive income into earnings immediately. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time, and any ineffectiveness is immediately reported as “Other” under Revenues and Other in the statement of consolidated operations.

General and Administrative Expense

General and administrative expenses are reported net of recoveries from owners in properties operated by Apache and net of amounts related to lease operating activities or capitalized pursuant to the full-cost method of accounting.

Income Taxes

Apache records deferred tax assets and liabilities to account for the expected future tax consequences of events that have been recognized in the financial statements and tax returns. The Company routinely assesses the realizability of its deferred tax assets. If the Company concludes that it is more likely than not that some or all of the deferred tax assets will not be realized, the tax asset is reduced by a valuation allowance. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and gas prices) and changing tax laws.

Earnings from Apache’s international operations are permanently reinvested; therefore, the Company does not recognize U.S. deferred taxes on the unremitted earnings of its international subsidiaries. If it becomes apparent that any of the unremitted earnings will be remitted, the Company will then recognize taxes on those earnings.

F-13

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Foreign Currency Transaction Gains and Losses

The U.S. dollar is the functional currency for each of Apache’s international operations. The functional currency is determined country-by-country based on relevant facts and circumstances of the cash flows, commodity pricing environment and financing arrangements in each country. Foreign currency transaction gains and losses arise when monetary assets and liabilities denominated in foreign currencies are remeasured to their U.S. dollar equivalent at the exchange rate in effect at the end of each reporting period. Foreign currency gains and losses also arise when revenue and disbursement transactions denominated in a country’s local currency are converted to a U.S. dollar equivalent based on the average exchange rates during the reporting period.

The Company accounts for foreign currency gains and losses in accordance with ASC Topic 830, “Foreign Currency Matters.” Foreign currency transaction gains and losses related to current taxes payable and deferred tax liabilities are recorded as a component of provision for income taxes. In 2011, the Company recorded a net tax benefit of $78 million, including a current tax expense of $1 million and deferred tax benefit of $79 million, in connection with foreign currency transaction gains and losses. Included in deferred tax expense for 2011 is approximately $6 million of tax expense attributable to realized foreign currency transactions. In 2010, the Company recorded additional net tax expense of $111 million, including a current tax expense of $2 million and deferred tax expense of $109 million, in connection with foreign currency transaction gains and losses. Included in deferred tax expense for 2010 is approximately $57 million of tax expense attributable to realized foreign currency transactions. In 2009, Apache recorded an additional net tax expense of $195 million, including a current benefit of $3 million and a deferred expense of $198 million. For further discussion, see Note 7 – Income Taxes. All other foreign currency transaction gains and losses are reflected in “Other” under Revenues and Other in the statement of consolidated operations. The Company’s other foreign currency gains and losses netted to a gain in 2011 of $4 million, a loss in 2010 of $39 million, and a gain of $11 million in 2009.

Insurance Coverage

The Company recognizes an insurance receivable when collection of the receivable is deemed probable. Any recognition of an insurance receivable is recorded by crediting and offsetting the original charge. Any differential arising between insurance recoveries and insurance receivables is recorded as a capitalized cost or as an expense, consistent with its original treatment.

Earnings Per Share

The Company’s basic earnings per share (EPS) amounts have been computed based on the weighted-average number of shares of common stock outstanding for the period. Diluted EPS reflects the potential dilution, using the treasury stock method, which assumes that options were exercised and restricted stock was fully vested. The diluted EPS calculation includes additional shares of common stock from the assumed conversion of Apache’s convertible preferred stock.

Diluted EPS also includes the impact of unvested share appreciation plans. For awards in which the share price goals have already been achieved, shares are included in diluted EPS using the treasury stock method. For those awards in which the share price goals have not been achieved, the number of contingently issuable shares included in diluted EPS is based on the number of shares, if any, using the treasury stock method, that would be issuable if the market price of the Company’s stock at the end of the reporting period exceeded the share price goals under the terms of the plan.

F-14

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Stock-Based Compensation

The Company accounts for stock-based compensation under the fair value recognition provisions of ASC Topic 718, “Compensation — Stock Compensation.” The Company grants various types of stock-based awards including stock options, nonvested restricted stock units, and performance-based awards. In 2003 and 2004, the Company also granted cash-based stock appreciation rights. These plans and related accounting policies are defined and described more fully in Note 9 — Capital Stock. Stock compensation awards granted are valued on the date of grant and are expensed, net of estimated forfeitures, over the required service period.

ASC Topic 718 also requires that benefits of tax deductions in excess of recognized compensation cost be reported as financing cash flows rather than as operating cash flows. The Company classified $32 million, $28 million, and $16 million as financing cash inflows in 2011, 2010 and 2009, respectively.

Treasury Stock

The Company follows the weighted-average-cost method of accounting for treasury stock transactions.

Recently Issued Accounting Standards Not Yet Adopted

In May 2011, the FASB issued Accounting Standards Update (ASU) No. 2011-04, which amends ASC Topic 820, “Fair Value Measurements and Disclosures.” The amended guidance clarifies many requirements in GAAP for measuring fair value and for disclosing information about fair value measurements. Additionally, the amendments clarify the FASB’s intent about the application of existing fair value measurement requirements. The guidance provided in ASU No. 2011-04 is effective for interim and annual periods beginning after December 15, 2011. The Company does not expect the adoption of this amendment to have a material impact on its consolidated financial statements.

In September 2011, the FASB issued ASU No. 2011-08, which amends ASC Topic 350-20, “Intangible Assets — Goodwill and Other.” The amended guidance provides the option to first assess qualitative factors to determine whether it is more likely than not (a likelihood of more than 50 percent) that the fair value of a reporting unit is less than its carrying amount. If, after considering the totality of events and circumstances, the qualitative assessment does not indicate that the fair value of a reporting unit is less than its carrying amount, performing the two-step impairment test is unnecessary. The guidance in ASU No. 2011-08 is effective for interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. The Company does not expect the adoption of this amendment to have a material impact on its consolidated financial statements.

In December 2011, the FASB issued ASU No. 2011-11, which increases disclosures about offsetting assets and liabilities. New disclosures are required to enable users of financial statements to understand significant quantitative differences in balance sheets prepared under GAAP and International Financial Reporting Standards (IFRS) related to the offsetting of financial instruments. The existing GAAP guidance allowing balance sheet offsetting, including industry-specific guidance, remains unchanged. The guidance in ASU No. 2011-11 is effective for annual and interim reporting periods beginning on or after January 1, 2013. The disclosures should be applied retrospectively for all prior periods presented. The Company does not expect the adoption of this amendment to have a material impact on its consolidated financial statements.

F-15

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

2. ACQUISITIONS AND DIVESTITURES

2011 Activity

Mobil North Sea Limited Acquisition

On December 30, 2011, Apache completed the acquisition of Mobil North Sea Limited (Mobil North Sea). 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 existing cash on hand.

The transaction was accounted for using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognized at their fair values as of the acquisition date. The following table summarizes the preliminary estimates of the assets acquired and liabilities assumed in the acquisition. The final determination of fair value for certain assets and liabilities will be completed as soon as the information necessary to complete the analysis is obtained. These amounts will be finalized as soon as possible, but no later than one year from the acquisition date.


	(In millions)
Current assets	$	208
Oil and gas properties		2,817
Gathering, transmission and processing facilities		338
Goodwill (1)		82

Total assets acquired	$	3,445

Current liabilities		148
Asset retirement obligation		517
Deferred income tax liabilities		1,533
Other long-term obligations		1

Total liabilities assumed	$	2,199

Net assets acquired	$	1,246

(1)	Goodwill was the excess of the consideration transferred over the net assets recognized and represents the future economic benefits arising from assets acquired that could not be individually identified and separately recognized. Goodwill is not deductible for tax purposes.

2010 Activity

Gulf of Mexico Shelf Acquisition

In June 2010, Apache completed an acquisition of oil and gas assets on the Gulf of Mexico shelf from Devon Energy Corporation (Devon) for $1.05 billion, subject to normal post-closing adjustments. The acquisition was effective January 1, 2010, and was funded primarily from existing cash balances.

BP Acquisitions

In July 2010, Apache entered into three definitive purchase and sale agreements to acquire properties from subsidiaries of BP plc (collectively referred to as “BP”) for aggregate consideration of $7.0 billion. The effective date of the transactions was July 1, 2010. The acquisition of BP’s oil and gas operations, related infrastructure

F-16

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

and acreage in the Permian Basin of west Texas and New Mexico was completed on August 10, 2010, for an agreed-upon purchase price of $3.1 billion. Apache completed the acquisition of substantially all of BP’s western Canadian upstream natural gas assets on October 8, 2010, for $3.25 billion. On November 4, 2010, the Company completed the acquisition of BP’s interests in four development licenses and one exploration concession in the Western Desert of Egypt for $650 million. Preferential purchase rights for $658 million of the value of the Permian Basin properties were exercised, and accordingly, the aggregate purchase price for all three transactions was reduced to approximately $6.4 billion, subject to normal post-closing adjustments.

The acquisitions were funded with a combination of common stock, mandatory convertible preferred shares, new term debt, commercial paper and existing cash balances.

Mariner Energy, Inc. Merger

In November 2010, Apache acquired Mariner Energy, Inc. (Mariner), an independent exploration and production company, in a stock and cash transaction totaling $2.7 billion and assumed approximately $1.7 billion of Mariner’s debt. 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 region. The transaction was accounted for using the acquisition method of accounting, which requires that assets acquired and liabilities assumed be recognized at their fair values as of the acquisition date. There were no significant changes to the purchase price subsequent to completion of the acquisition.

Actual and Pro Forma Impact of Acquisitions (Unaudited)

Revenues attributable to the Devon acquisition, BP acquisitions, and Mariner merger included in Apache’s statement of consolidated operations for the year ended December 31, 2010, were $197 million, $308 million, and $95 million, respectively. Direct expenses attributable to the acquisitions and merger included in the statement of consolidated operations for the same period were $39 million, $78 million, and $26 million, respectively.

The following table presents pro forma information for Apache as if the acquisition of properties from Devon and BP and the Mariner merger occurred on January 1, 2009:


	For the Year Ended December 31,
	2010		2009
	(In millions, except per share amounts)
Revenues and Other	$	13,780	$	10,717

Net Income (Loss)	$	3,364	$	(477	)
Preferred Stock Dividends		76		83

Income (Loss) Attributable to Common Stock	$	3,288	$	(560	)

Net Income (Loss) per Common Share — Basic	$	8.62	$	(1.48	)

Net Income (Loss) per Common Share — Diluted	$	8.52	$	(1.48	)

The historical financial information was adjusted to give effect to the pro forma events that were directly attributable to the acquisitions and merger and are factually supportable. The unaudited pro forma consolidated results are not necessarily indicative of what the Company’s consolidated results of operations actually would

F-17

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

have been had the acquisitions and merger been completed on January 1, 2009. In addition, the unaudited pro forma consolidated results do not purport to project the future results of operations of the combined company. The unaudited pro forma consolidated results reflect the following pro forma adjustments:

•

Adjustment to recognize incremental DD&A expense, using the UOP method, resulting from the purchase of the properties;

•

Adjustment to recognize adjusted general and administrative expense as a result of the purchase of the properties;

•

Adjustment to recognize issuance of $1.5 billion principal amount of senior unsecured 5.1-percent notes maturing September 1, 2040, associated deferred financing cost amortization, and interest expense, net of amounts capitalized;

•

Adjustment to recognize asset retirement obligation accretion on properties acquired;

•

Adjustment to recognize a pro forma income tax provision;

•

Adjustment to recognize the issuance of 26.45 million shares of Apache common stock to partially fund the BP acquisitions and 17.3 million shares to partially fund the Mariner merger;

•

Adjustment to recognize the issuance of 25.3 million depositary shares each representing a 1/20th interest in a share of Apache’s 6.00-percent Mandatory Convertible Preferred Stock, Series D, issued to fund a portion of the BP acquisitions;

•

Adjustment to recognize additional dividends associated with the issuance of 6.00-percent Mandatory Convertible Preferred Stock; and

•

Elimination of transaction costs incurred in 2010 that are directly related to the transactions and do not have a continuing impact on the combined company’s operating results.

Merger, Acquisitions & Transition Expenses

In 2010, the Company recorded $183 million of expenses in connection with the acquisition of properties from BP and the Mariner merger: $114 million of separation and other costs; $42 million of investment banking fees; and $27 million of other expenses related to the transactions. In 2011, Apache recorded $20 million of expenses primarily for separation and other costs related to the Mariner merger and the acquisition of Mobil North Sea.

Subsequent Events

Cordillera Energy Partners

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.

Burrup Holdings Limited

F-18

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Apache has supplied 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. In addition, Apache also acquired an interest in a planned technical ammonia nitrate plant to be developed with Yara.

3. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

Objectives and Strategies

The Company is exposed to fluctuations in crude oil and natural gas prices on the majority of its worldwide production. Management believes it is prudent to manage the variability in cash flows by occasionally entering into hedges on a portion of its crude oil and natural gas production. The Company utilizes various types of derivative financial instruments, including swaps and options, to manage fluctuations in cash flows resulting from changes in commodity prices. Derivative instruments entered into are typically designated as cash flow hedges.

Counterparty Risk

The use of derivative instruments exposes the Company to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments. To reduce the concentration of exposure to any individual counterparty, Apache utilizes a diversified group of investment-grade rated counterparties, primarily financial institutions, for its derivative transactions. As of December 31, 2011, Apache had derivative positions with 18 counterparties. The Company monitors counterparty creditworthiness on an ongoing basis; however, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, Apache may not realize the benefit of some of its derivative instruments resulting from lower commodity prices.

The Company executes commodity derivative transactions under master agreements that have netting provisions that provide for offsetting payables against receivables. In general, if a party to a derivative transaction incurs a material deterioration in its credit ratings, as defined in the applicable agreement, the other party has the right to demand the posting of collateral, demand a transfer, or terminate the arrangement.

Derivative Instruments

As of December 31, 2011, Apache had the following open crude oil derivative positions:


	Fixed-Price Swaps				Collars
Production Period	Mbbls		Weighted Average Fixed Price(1)		Mbbls		Weighted Average Floor Price(1)		Weighted Average Ceiling Price(1)
2012		4,110	$	73.40		12,628	$	76.42	$	101.06
2013		1,972		74.29		4,350		82.17		108.33
2014		76		74.50		—		—		—

(1)	Crude oil prices represent a weighted average of several contracts entered into on a per-barrel basis. Crude oil contracts are primarily settled against the NYMEX WTI Cushing Index. Approximately 28 percent of 2012 collars and 44 percent of 2013 collars are settled against Dated Brent.

F-19

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

As of December 31, 2011, Apache had the following open natural gas derivative positions:


	Fixed-Price Swaps						Collars
Production Period	MMBtu (in 000’s)		GJ (in 000’s)		Weighted Average Fixed Price(1)		MMBtu (in 000’s)		GJ (in 000’s)		Weighted Average Floor Price(1)		Weighted Average Ceiling Price(1)
2012		48,349		—	$	6.22		21,960		—	$	5.54	$	7.30
2012		—		43,920	C$	6.61		—		7,320	C$	6.50	C$	7.27
2013		10,095		—	$	6.74		6,825		—	$	5.35	$	6.67
2014		1,295		—	$	6.72		—		—	$	—	$	—

(1)

U.S. natural gas prices represent a weighted average of several contracts entered into on a per million British thermal units (MMBtu) basis and are settled primarily against NYMEX Henry Hub and various Inside FERC indices. The Canadian gas contracts are entered into on a per gigajoule (GJ) basis and are settled against AECO Index. The Canadian natural gas prices represent a weighted average of AECO Index prices and are shown in Canadian dollars.

Fair Values of Derivative Instruments Recorded in the Consolidated Balance Sheet

The Company accounts for derivative instruments and hedging activity in accordance with ASC Topic 815, “Derivatives and Hedging,” and all derivative instruments are reflected as either assets or liabilities at fair value in the consolidated balance sheet. These fair values are recorded by netting asset and liability positions where counterparty master netting arrangements contain provisions for net settlement. The fair market value of the Company’s derivative assets and liabilities and their locations on the consolidated balance sheet are as follows:


	December 31,		December 31,
	2011		2010
	(In millions)
Current Assets: Derivative instruments	$	304	$	167
Other Assets: Deferred charges and other		28		139

Total Assets	$	332	$	306

Current Liabilities: Derivative instruments	$	113	$	194
Noncurrent Liabilities: Other		41		124

Total Liabilities	$	154	$	318

The methods and assumptions used to estimate the fair values of the Company’s commodity derivative instruments and gross amounts of commodity derivative assets and liabilities are more fully discussed in Note 11 — Fair Value Measurements.

F-20

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Derivative Activity Recorded in Statement of Consolidated Operations

The following table summarizes the effect of derivative instruments on the Company’s statement of consolidated operations:


	Gain (Loss) on Derivatives Recognized in Operations	For the Year Ended December 31,
		2011			2010			2009
		(In millions)
Gain (loss) reclassified from accumulated other comprehensive income (loss) into operations (effective portion)	Oil and Gas Production Revenues	$	(13	)	$	165		$	181
Gain (loss) on derivatives recognized in operations (ineffective portion and basis swaps)	Revenues and Other: Other	$	2		$	(2	)	$	(4	)

Derivative Activity in Accumulated Other Comprehensive Income (Loss)

As of December 31, 2011, the Company’s derivative instruments were designated as cash flow hedges in accordance with ASC Topic 815. A reconciliation of the components of accumulated other comprehensive income (loss) in the statement of consolidated shareholders’ equity related to Apache’s cash flow hedges is presented in the table below:


	2011						2010						2009
	Before tax			After tax			Before tax			After tax			Before tax			After tax
	(In millions)
Unrealized gain (loss) on derivatives at beginning of year	$	(54	)	$	(19	)	$	(267	)	$	(170	)	$	212		$	138
Realized (gain) loss reclassified into earnings		13			19			(165	)		(106	)		(181	)		(123	)
Net change in derivative fair value		188			115			376			256			(297	)		(184	)
Ineffectiveness reclassified into earnings		(2	)		(1	)		2			1			(1	)		(1	)

Unrealized gain (loss) on derivatives at end of year	$	145		$	114		$	(54	)	$	(19	)	$	(267	)	$	(170	)

Gains and losses on existing hedges will be realized in future earnings through mid-2014, in the same period as the related sales of natural gas and crude oil production applicable to specific hedges. Included in accumulated other comprehensive loss as of December 31, 2011, is a net gain of approximately $181 million ($138 million after tax) that applies to the next 12 months; however, estimated and actual amounts are likely to vary materially as a result of changes in market conditions.

4. ACCRUED LIABILITIES

The following table provides detail of our accrued liabilities at December 31, 2011 and 2010:


	2011		2010
	(In millions)
Accrued operating expenses	$	221	$	163
Accrued exploration and development		1,430		1,367
Accrued compensation and benefits		180		231
Accrued income taxes		533		2
Accrued United Kingdom Petroleum Revenue Tax		284		53

Total Accrued Liabilities	$	2,648	$	1,816

F-21

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

5. ASSET RETIREMENT OBLIGATION

The following table describes changes to the Company’s ARO liability for the years ended December 31, 2011 and 2010:


	2011			2010
	(In millions)
Asset retirement obligation at beginning of year	$	2,872		$	1,784
Liabilities incurred		419			270
Liabilities acquired		592			847
Liabilities settled		(549	)		(329	)
Accretion expense		154			111
Revisions in estimated liabilities		399			189

Asset retirement obligation at end of year		3,887			2,872
Less current portion		(447	)		(407	)

Asset retirement obligation, long-term	$	3,440		$	2,465

The ARO liability reflects the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with Apache’s oil and gas properties. The Company utilizes current retirement costs to estimate the expected cash outflows for retirement obligations. The Company estimates the ultimate productive life of the properties, a risk-adjusted discount rate, and an inflation factor in order to determine the current present value of this obligation. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property balance.

During 2011, the Company recorded $592 million in additional abandonment liabilities on properties acquired, primarily related to the Mobil North Sea acquisition. An additional $419 million in abandonment liabilities was recognized on our current year drilling and development program. Increases in offshore abandonment costs, particularly in our international jurisdictions, resulted in a $399 million revision.

Liabilities settled in 2011 relate to individual properties, platforms and facilities plugged and abandoned during the period. The Company continues to have an active ongoing abandonment program, particularly in the Gulf of Mexico and Canada. Additionally, our 2011 abandonment program included the retirement of our offshore facilities in Australia’s Legendre field.

6. DEBT

Overview

All of the Company’s debt is senior unsecured debt and has equal priority with respect to the payment of both principal and interest. The indentures for the notes described below place certain restrictions on the Company, including limits on Apache’s ability to incur debt secured by certain liens and its ability to enter into certain sale and leaseback transactions. Upon certain changes in control, all of these debt instruments would be subject to mandatory repurchase, at the option of the holders. None of the indentures for the notes contain prepayment obligations in the event of a decline in credit ratings.

F-22

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table presents the carrying value of the Company’s debt at December 31, 2011 and 2010:


	December 31,
	2011			2010
	(In millions)
U.S.:
Money market lines of credit	$	—		$	16
Commercial paper		—			913
6.25% notes due 2012(1)		400			400
5.25% notes due 2013(1)		500			500
6.0% notes due 2013(1)		400			400
5.625% notes due 2017(1)		500			500
6.9% notes due 2018(1)		400			400
7.0% notes due 2018		150			150
7.625% notes due 2019		150			150
3.625% notes due 2021(1)		500			500
7.7% notes due 2026		100			100
7.95% notes due 2026		180			180
6.0% notes due 2037(1)		1,000			1,000
5.1% notes due 2040(1)		1,500			1,500
5.25% notes due 2042(1)		500			500
7.375% debentures due 2047		150			150
7.625% debentures due 2096		150			150

		6,580			7,509

Subsidiary and other obligations:
Argentina overdraft lines of credit		31			30
Notes due in 2016 and 2017		1			1
Apache Finance Canada 4.375% notes due 2015(1)		350			350
Apache Finance Canada 7.75% notes due 2029		300			300

		682			681

Debt before unamortized discount		7,262			8,190
Unamortized discount		(46	)		(49	)

Total debt	$	7,216		$	8,141

Current maturities	$	(431	)	$	(46	)

Long-term debt	$	6,785		$	8,095

(1)	These notes are redeemable, as a whole or in part, at Apache’s option, subject to a make-whole premium. The remaining notes and debentures are not redeemable.

F-23

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Debt maturities as of December 31, 2011, excluding discounts, are as follows:


	(In millions)
2012	$	431
2013		900
2014		—
2015		350
2016		1
Thereafter		5,580

Total Debt, excluding discounts	$	7,262

Fair Value

The Company’s debt is recorded at the carrying amount on its consolidated balance sheet. The carrying amount of the Company’s money market lines of credit and commercial paper approximate fair value because the interest rates are variable and reflective of market rates. Apache uses a market approach to determine the fair value of its fixed-rate debt using estimates provided by an independent investment financial data services firm, which is a Level 2 non-recurring fair value measurement.


	December 31, 2011				December 31, 2010
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)
Money market lines of credit	$	31	$	31	$	46	$	46
Commercial paper		—		—		913		913
Notes and debentures		7,185		8,673		7,182		7,870

Money Market and Overdraft Lines of Credit

The Company has certain uncommitted money market and overdraft lines of credit that are used from time to time for working capital purposes. As of December 31, 2011 and 2010, $31 million and $46 million, respectively, were drawn on facilities in the U.S. and Argentina.

Unsecured Committed Bank Credit Facilities

The financial covenants of the credit facilities require the Company to maintain a debt-to-capitalization ratio of not greater than 60 percent at the end of any fiscal quarter. At December 31, 2011, the Company’s debt-to-capitalization ratio was 20 percent.

The negative covenants include restrictions on the Company’s ability to create liens and security interests on its assets, with exceptions for liens typically arising in the oil and gas industry, purchase money liens and liens arising as a matter of law, such as tax and mechanics’ liens. The Company may incur liens on assets located in the U.S. and Canada of up to five percent of the Company’s consolidated assets, or approximately $2.6 billion as

F-24

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

of December 31, 2011. There are no restrictions on incurring liens in countries other than the U.S. and Canada. There are also restrictions on Apache’s ability to merge with another entity, unless the Company is the surviving entity, and a restriction on its ability to guarantee debt of entities not within its consolidated group.

There are no clauses in the facilities that permit the lenders to accelerate payments or refuse to lend based on unspecified material adverse changes. The credit facility agreements do not have drawdown restrictions or prepayment obligations in the event of a decline in credit ratings. However, the agreements allow the lenders to accelerate payments and terminate lending commitments if Apache Corporation, or any of its U.S. or Canadian subsidiaries, defaults on any direct payment obligation in excess of $100 million or has any unpaid, non-appealable judgment against it in excess of $100 million.

The Company was in compliance with the terms of the credit facilities as of December 31, 2011.

At the Company’s option, the interest rate for the facilities is based on a base rate, as defined, or the London Inter-bank Offered Rate (LIBOR) plus a margin determined by the Company’s senior long-term debt rating. The $1.5 billion and the $450 million credit facilities also allow the Company to borrow under competitive auctions.

At December 31, 2011, the margin over LIBOR for committed loans was 0.19 percent on the $1.5 billion facility and 0.23 percent on the $450 million facility in the U.S., the $200 million facility in Australia, and the $150 million facility in Canada. If the total amount of the loans borrowed under the $1.5 billion facility equals or exceeds 50 percent of the total facility commitments, then an additional 0.05 percent will be added to the margins over LIBOR. If the total amount of the loans borrowed under all of the other three facilities equals or exceeds 50 percent of the total facility commitments, then an additional 0.10 percent will be added to the margins over LIBOR. The Company also pays quarterly facility fees of 0.06 percent on the total amount of the $1.5 billion facility and 0.07 percent on the total amount of the other three facilities. The facility fees vary based upon the Company’s senior long-term debt rating.

On August 16, 2011, Apache entered into a $1.0 billion five-year syndicated revolving credit facility. The credit facility is subject to covenants, events of default and representations and warranties that are substantially similar to those in Apache’s other revolving credit facilities. The facility may be used for acquisitions and for general corporate purposes or to support the Company’s commercial paper program. Loans under the facility will bear interest at a base rate, as defined in the credit agreement, or at LIBOR plus a margin determined by the Company’s senior long-term debt rating. At December 31, 2011, the margin over LIBOR for committed loans was 0.875 percent on the $1.0 billion five-year syndicated revolving credit facility, and the quarterly facility fee was 0.125 percent.

Commercial Paper Program

The Company has available a $2.95 billion commercial paper program, which generally enables Apache to borrow funds for up to 270 days at competitive interest rates. Apache’s 2011 weighted-average interest rate for commercial paper was 0.37 percent. If the Company is unable to issue commercial paper following a significant credit downgrade or dislocation in the market, the Company’s U.S. credit facilities are available as a 100-percent backstop. The commercial paper program is fully supported by available borrowing capacity under U.S. committed credit facilities, which expire in 2013 and 2016. As of December 31, 2011, the Company had no outstanding commercial paper. As of December 31, 2010, the Company had $913 million in commercial paper outstanding.

F-25

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Subsidiary Notes — Apache Finance Canada

Apache Finance Canada Corporation (Apache Finance Canada) has approximately $300 million of publicly-traded notes due in 2029 and an additional $350 million of publicly-traded notes due in 2015 that are fully and unconditionally guaranteed by Apache.

For further discussion of subsidiary debt, please see Note 16 — Supplemental Guarantor Information.

Financing Costs, Net

Financing costs incurred during the periods 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

The Company has $46 million of debt discounts as of December 31, 2011, which will be charged to interest expense over the life of the related debt issuances. Discount amortization of $2 million, $2 million, and $1 million were recorded as interest expense in 2011, 2010, and 2009, respectively.

As of December 31, 2011 and 2010, the Company had approximately $48 million and $53 million, respectively, of unamortized deferred loan costs associated with its various debt obligations. These costs are included in deferred charges and other in the accompanying consolidated balance sheet and are being charged to financing costs and expensed over the life of the related debt issuances.

7. INCOME TAXES

Income before income taxes is composed of the following:


	For the Year Ended December 31,
	2011		2010		2009
	(In millions)
United States	$	2,373	$	1,328	$	(567	)
Foreign		5,720		3,878		893

Total	$	8,093	$	5,206	$	326

F-26

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The total provision for income taxes consists of the following:


	For the Year Ended December 31,
	2011		2010		2009
	(In millions)
Current taxes:
Federal	$	64	$	25	$	(130	)
State		2		4		(2	)
Foreign		2,197		1,193		974

		2,263		1,222		842

Deferred taxes:
Federal		656		431		(81	)
State		17		7		(24	)
Foreign		573		514		(126	)

		1,246		952		(231	)

Total	$	3,509	$	2,174	$	611

A reconciliation of the tax on the Company’s income before income taxes and total tax expense is shown below:


	For the Year Ended December 31,
	2011			2010			2009
	(In millions)
Income tax expense at U.S. statutory rate	$	2,833		$	1,822		$	114
State income tax, less federal benefit		12			6			(17	)
Taxes related to foreign operations		568			245			310
Tax credits		(15	)		(8	)		(39	)
Non-deductible merger costs		—			6			—
Current and deferred taxes related to currency fluctuations		(78	)		111			195
Increase in United Kingdom tax rate		218			—			—
Net change in tax contingencies		(6	)		(2	)		36
Increase in valuation allowance		8			12			20
All other, net		(31	)		(18	)		(8	)

	$	3,509		$	2,174		$	611

F-27

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The net deferred tax liability consists of the following:


	December 31,
	2011			2010
	(In millions)
Deferred tax assets:
Deferred income	$	(89	)	$	(6	)
Federal and state net operating loss carryforwards		(236	)		(277	)
Foreign net operating loss carryforwards		(55	)		(55	)
Tax credits		(66	)		(42	)
Accrued expenses and liabilities		(90	)		(76	)
Other		—			(25	)

Total deferred tax assets		(536	)		(481	)
Valuation allowance		60			53

Net deferred tax assets		(476	)		(428	)

Deferred tax liabilities:
Other		21			—
Depreciation, depletion and amortization		7,443			4,569

Total deferred tax liabilities		7,464			4,569

Net deferred income tax liability	$	6,988		$	4,141

The Company has not recorded U.S. deferred income taxes on the undistributed earnings of its foreign subsidiaries as management intends to permanently reinvest such earnings. As of December 31, 2011, the undistributed earnings of the foreign subsidiaries amounted to approximately $13.7 billion. Upon distribution of these earnings in the form of dividends or otherwise, the Company may be subject to U.S. income taxes and foreign withholding taxes. It is not practical, however, to estimate the amount of taxes that may be payable on the eventual remittance of these earnings after consideration of available foreign tax credits. Presently, limited foreign tax credits are available to reduce the U.S. taxes on such amounts if repatriated.

On December 31, 2011, the Company had net operating losses as follows:


	December 31, 2011
	Amount		Expiration
	(In millions)
Net operating losses:
United States — Federal	$	531	2027
United States — State		1,104	Various
Canada		9	2014
Australia		59	Indefinite
Argentina		13	2012

The Company’s federal net operating loss carryforward of $531 million is related to the merger with Mariner and is subject to annual limitations under Section 382 of the Internal Revenue Code (IRC). The Company also had $295 million of capital loss carryforwards in Canada, which have an indefinite carryover period.

F-28

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The tax benefits of carryforwards are recorded as assets to the extent that management assesses the utilization of such carryforwards to be “more likely than not.” When the future utilization of some portion of the carryforwards is determined to not meet the “more likely than not” standard, a valuation allowance is provided to reduce the tax benefits from such assets. As the Company does not believe the utilization of certain state, Argentina, and Canadian capital losses to be “more likely than not,” a valuation allowance was provided to reduce the tax benefit from these deferred tax assets.

Apache accounts for income taxes in accordance with ASC Topic 740, “Income Taxes,” which prescribes a minimum recognition threshold a tax position must meet before being recognized in the financial statements. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:


	2011			2010			2009
	(In millions)
Balance at beginning of year	$	110		$	123		$	213
Additions based on tax positions related to the current year		13			(1	)		23
Additions for tax positions of prior years		—			—			77
Reductions for tax positions of prior years		(4	)		(12	)		(92	)
Settlements		(22	)		—			(98	)

Balance at end of year	$	97		$	110		$	123

The Company records interest and penalties related to unrecognized tax benefits as a component of income tax expense. Each quarter the Company assesses the amounts provided for and, as a result, may increase (expense) or reduce (benefit) the amount of interest and penalties. During the years ended December 31, 2011, 2010, and 2009 the Company recorded tax expense of $6 million, tax expense of $12 million, and a tax benefit of $17 million, respectively, for interest and penalties. As of December 31, 2011 and 2010, the Company had approximately $42 million and $36 million, respectively, accrued for payment of interest and penalties.

The Company is in Administrative Appeals with the U.S. Internal Revenue Service (IRS) regarding the tax years 2004 through 2008. The Company is under IRS audit for 2009 and 2010 and under audit in various states as well as in most of the Company’s foreign jurisdictions as part of its normal course of business. Resolution of any of the above, which may occur in 2012, could result in a significant change to the Company’s tax reserves. However, the resolution of unagreed tax issues in the Company’s open tax years cannot be predicted with absolute certainty, and differences between what has been recorded and the eventual outcomes may occur. Due to this uncertainty and the uncertain timing of the final resolution of the Appeals process, an accurate estimate of the range of outcomes occurring during the next 12 months cannot be made at this time. Nevertheless, the Company believes that it has adequately provided for income taxes and any related interest and penalties for all open tax years.

Apache and its subsidiaries are subject to U.S. federal income tax as well as income tax in various states and foreign jurisdictions. The Company’s uncertain tax positions are related to tax years that may be subject to examination by the relevant taxing authority. Apache’s earliest open tax years in its key jurisdictions are as follows:


Jurisdiction
United States			2004
Canada			2007
Egypt			1998
Australia			2007
United Kingdom			2010
Argentina			2004

F-29

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

8. COMMITMENTS AND CONTINGENCIES

Legal Matters

Apache is party to various legal actions arising in the ordinary course of business, including litigation and governmental and regulatory controls. The Company has an accrued liability of approximately $20 million for all legal contingencies that are deemed to be probable of occurring and can be reasonably estimated. Apache’s estimates are based on information known about the matters and its experience in contesting, litigating, and settling similar matters. Although actual amounts could differ from management’s estimate, none of the actions are believed by management to involve future amounts that would be material to Apache’s financial position or results of operations after consideration of recorded accruals. It is management’s opinion that the loss for any other litigation matters and claims that are reasonably possible to occur will not have a material adverse effect on the Company’s financial position or results of operations.

Argentine Environmental Claims

In connection with the acquisition from Pioneer Natural Resources (Pioneer) in 2006, the Company acquired a subsidiary of Pioneer in Argentina (PNRA) that is involved in various administrative proceedings with environmental authorities in the Neuquén Province relating to permits for and discharges from operations in that province. In addition, PNRA was named in a suit initiated against oil companies operating in the Neuquén basin entitled Asociación de Superficiarios de la Patagonia v YPF S.A., et. al., originally filed on August 21, 2003, in the Argentine National Supreme Court of Justice. The plaintiffs, a private group of landowners, have also named the national government and several provinces as third parties. The lawsuit alleges injury to the environment generally by the oil and gas industry. The plaintiffs principally seek from all defendants, jointly, (i) the remediation of contaminated sites, of the superficial and underground waters, and of soil that allegedly was degraded as a result of deforestation, (ii) if the remediation is not possible, payment of an indemnification for the material and moral damages claimed from defendants operating in the Neuquén basin, of which PNRA is a small portion, (iii) adoption of all the necessary measures to prevent future environmental damages, and (iv) the creation of a private restoration fund to provide coverage for remediation of potential future environmental damages. Much of the alleged damage relates to operations by the Argentine state oil company, which conducted oil and gas operations throughout Argentina prior to its privatization, which began in 1990. While the plaintiffs will seek to make all oil and gas companies operating in the Neuquén basin jointly liable for each other’s actions, PNRA will defend on an individual basis and attempt to require the plaintiffs to delineate damages by company. PNRA intends to defend itself vigorously in the case. It is not certain exactly what the court will do in this matter as it is the first of its kind. While it is possible PNRA may incur liabilities related to the environmental claims, no reasonable prediction can be made as PNRA’s exposure related to this lawsuit is not currently determinable.

U.S. Royalty Litigation

Two potential class action lawsuits are pending in respect of oil and gas royalties paid by the Company: Foster v. Apache Corporation, Civil Action No. CIV-10-0573-HE, in the United States District Court for the Western District of Oklahoma, and Joyce Holder Trust v. Apache Corporation, Civil Action No. 4:11-cv-03872, in the United States District Court for the Southern District of Texas, Houston Division. There has not yet been class certification in these cases. Plaintiffs in the Foster case have asserted recently that they may seek damages of approximately $100 million. No facts have been introduced that would support that amount or any lesser amount. No specific dollar amount has been claimed in either case. Apache intends to vigorously defend against these claims.

F-30

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Louisiana Restoration

Numerous surface owners have filed claims or sent demand letters to various oil and gas companies, including Apache, claiming that, under either expressed or implied lease terms or Louisiana law, they are liable for damage measured by the cost of restoration of leased premises to their original condition as well as damages from contamination and cleanup. Because the Company has continuing operations in Louisiana, from time-to-time restoration lawsuits and claims are resolved by the Company for amounts that are not material to the Company while new lawsuits and claims are asserted against the Company. With respect to each of the pending lawsuits and claims, the amount claimed is not currently determinable or is not material, except that in a lawsuit captioned Ardoin Limited Partnership et al. v. Meridian Resources & Exploration et al., Case No.10-18692, in the District Court of Cameron Parish, Louisiana, the plaintiffs’ expert has opined that the cost to restore plaintiffs’ property would be approximately $61 million.

In addition to the matters discussed above, in a lawsuit filed on May 4, 2010 against Phoenix Exploration Company LP (Phoenix) captioned Belle Isle, L.L.C. v. Anadarko Petroleum Corporation et al., Docket No. 121742, in the District Court of St. Mary Parish, Louisiana, plaintiff alleges that over three thousand acres of land has been contaminated by oil and gas operations. On August 31, 2011, subsidiaries of Apache acquired 75 percent of the general partner interests and 75 percent of the Class A and Class B limited partner interests in Phoenix. Apache is analyzing whether any remediation activities are necessary separate and apart from normal operating activities.

The overall exposure related to these lawsuits and claims is not currently determinable. While an adverse judgment against Apache is possible, Apache intends to actively defend the cases.

Hurricane-Related Litigation

On May 27, 2011, a lawsuit captioned Comer et al. v. Murphy Oil USA, Inc. et al., Case No. 1:11-cv-220 HS0-JMR, in the United States District Court for the Southern District of Mississippi, was filed in which certain named residents of Mississippi, as plaintiffs, allege that the oil, coal, and chemical industries are responsible for global warming, which they claim caused or increased the effect of Hurricane Katrina, allegedly resulting among other things in economic losses and increased insurance premiums. Plaintiffs seek class certification, damages for losses sustained, a declaration that state law tort claims are not preempted by federal law, and punitive and exemplary damages. Apache is one of numerous defendants. A similar action filed by Comer et al. was previously dismissed in 2011.

Australia Gas Pipeline Force Majeure

Company subsidiaries reported a pipeline explosion that interrupted deliveries of natural gas to customers under various long-term contracts. Company subsidiaries believe that the event was a force majeure, and as a result, the subsidiaries and their joint venture participants declared force majeure under those contracts.

On December 16, 2009, a customer, Burrup Fertilisers Pty Ltd, filed a lawsuit on behalf of itself and certain of its underwriters at Lloyd’s of London and other insurers, against the Company and its subsidiaries in Texas state court, asserting claims for negligence, breach of contract, alter ego, single business enterprise, res ipsa loquitur, and gross negligence/exemplary damages. In their Harris County, Texas petition, Burrup Fertilisers and its underwriters and insurers seek to recover unspecified actual damages, cost of repair and replacement, exemplary damages, lost profits, loss of business goodwill, value of the gas lost under the Gas Supply and Purchase Argreement (GSA), interest, and court costs. On March 24, 2011, another customer, Alcoa of Australia

F-31

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Limited (“Alcoa”) filed a lawsuit captioned Alcoa of Australia Limited vs. Apache Energy Limited, Apache Northwest Pty Ltd, Tap (Harriet) Pty Ltd, and Kufpec Australia Pty Ltd, Civ. 1481 of 2011, in the Supreme Court of Western Australia. The lawsuit concerns the interruption of deliveries of natural gas to Alcoa under two long-term contracts. Alcoa challenges the declaration of force majeure and the validity of the liquidated damages provisions in the contracts. Alcoa asserts claims based on breach of contract, statutory duties, and duty of care. Alcoa seeks approximately $158 million AUD in general damages or, alternatively, approximately $5.7 million AUD in liquidated damages. The Company and its subsidiaries do not believe that the Burrup Fertilisers and Alcoa claims have merit and will vigorously pursue their defenses against such claims.

Other customers have threatened to file suit challenging the declaration of force majeure under their contracts. Contract prices under customer contracts are significantly below current spot prices for natural gas in Australia. In the event it is determined that the pipeline explosion was not a force majeure, Company subsidiaries believe that liquidated damages should be the extent of the damages under those long-term contracts with such provisions. Approximately 90 percent of the natural gas volumes sold by Company subsidiaries under long-term contracts have liquidated damages provisions. Contractual liquidated damages under the long-term contracts with such provisions would not be expected to exceed $200 million AUD. No assurance can be given that Burrup Fertilisers and other customers would not assert claims in excess of contractual liquidated damages, and exposure related to such claims is not currently determinable. While an adverse judgment against Company subsidiaries (and the Company, in the case of the Burrup Fertilisers lawsuit) is possible, the Company and Company subsidiaries do not believe any such claims would have merit and plan to vigorously pursue their defenses against any such claims.

In December 2008, the Senate Economics Committee of the Parliament of Australia released its findings from public hearings concerning the economic impact of the gas shortage following the explosion on Varanus Island and the government’s response. The Committee concluded, among other things, that the macroeconomic impact to Western Australia will never be precisely known, but cited to a range of estimates from $300 million AUD to $2.5 billion AUD consisting in part of losses alleged by some parties who have long-term contracts with Company subsidiaries (as described above), but also losses alleged by third parties who do not have contracts with Company subsidiaries (but who may have purchased gas that was re-sold by customers or who may have paid more for energy following the explosion or who lost wages or sales due to the inability to obtain energy or the increased price of energy). A timber industry group, whose members do not have a contract with Company subsidiaries, has announced that it intends to seek compensation for its members and their subcontractors from Company subsidiaries for $20 million AUD in losses allegedly incurred as a result of the gas supply shortage following the explosion. In Johnson Tiles Pty Ltd v. Esso Australia Pty Ltd [2003] VSC 27 (Supreme Court of Victoria, Gillard J presiding), which concerned a 1998 explosion at an Esso natural gas processing plant at Longford in East Gippsland, Victoria, the Court held that Esso was not liable for $1.3 billion AUD of pure economic losses suffered by claimants that had no contract with Esso, but was liable to such claimants for reasonably foreseeable property damage which Esso settled for $32.5 million AUD plus costs. In reaching this decision the Court held that third-party claimants should have protected themselves from pure economic losses, through the purchase of insurance or the installation of adequate backup measures, in case of an interruption in their gas supply from Esso. While an adverse judgment against Company subsidiaries is possible if litigation is filed, Company subsidiaries do not believe any such claims would have merit and plan to vigorously pursue their defenses against any such claims. Exposure related to any such potential claims is not currently determinable.

On October 10, 2008, the Australia National Offshore Petroleum Safety Authority (NOPSA) released a self-titled “Final Report” of the findings of its investigation into the pipeline explosion, prepared at the request of the Western Australian Department of Industry and Resources (DoIR). NOPSA concluded in its report that the evidence gathered to date indicates that the main causal factors in the incident were: (1) ineffective anti-corrosion

F-32

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

coating at the beach crossing section of the 12-inch sales gas pipeline, due to damage and/or dis-bondment from the pipeline; (2) ineffective cathodic protection of the wet-dry transition zone of the beach crossing section of the 12-inch sales gas pipeline; and (3) ineffective inspection and monitoring by Company subsidiaries of the beach crossing and shallow water section of the 12-inch sales gas pipeline. NOPSA further concluded that the investigation identified that Apache Northwest Pty Ltd and its co-licensees may have committed offenses under the Petroleum Pipelines Act 1969, Sections 36A & 38(b) and the Petroleum Pipelines Regulations 1970, Regulation 10, and that some findings may also constitute non-compliance with pipeline license conditions. On May 28, 2009, the Department of Mines and Petroleum (DMP) filed a prosecution notice in the Magistrates Court of Western Australia, charging Apache Northwest Pty Ltd and its co-licensees with failure to maintain a pipeline in good condition and repair under the Petroleum Pipelines Act 1969, Section 38(b). The maximum fine associated with the alleged offense is $50,000 AUD. The Company subsidiary does not believe that the charge has merit and plans to vigorously pursue its defenses.

NOPSA states in its report that an application for renewal of the pipeline license (the “pipeline license”) covering the area of the Varanus Island facility was granted in May 1985 with 21 years validity, and an application for renewal of the pipeline license was submitted to DoIR by Company subsidiaries in December 2005 and remained pending at the time NOPSA issued its report. The application by Apache Northwest, Kufpec Australia Pty Ltd, and Tap (Harriet) Pty Ltd for renewal and variation of the pipeline license covering the area of the Varanus Island facility was granted on April 19, 2011 by the DMP. The period of the pipeline license is 21 years commencing April 20, 2011.

Company subsidiaries disagree with NOPSA’s conclusions and believe that the NOPSA report is premature, based on an incomplete investigation, and misleading. In a July 17, 2008, media statement, DoIR acknowledged, “The pipelines and Varanus Island facilities have been the subject of an independent validation report [by Lloyd’s Register] which was received in August 2007. NOPSA has also undertaken a number of inspections between 2005 and the present.” These and numerous other inspections, audits and reviews conducted by top international consultants and regulators did not identify any warnings that the pipeline had a corrosion problem or other issues that could lead to its failure. Company subsidiaries believe that the explosion was not reasonably foreseeable, and was not within the reasonable control of Company’s subsidiaries or able to be reasonably prevented by Company subsidiaries.

On January 9, 2009, the governments of Western Australia and the Commonwealth of Australia announced a joint inquiry to consider the effectiveness of the regulatory regime for occupational health and safety and integrity that applied to operations and facilities at Varanus Island and the role of DoIR, NOPSA, and the Western Australian Department of Consumer and Employment Protection. The joint inquiry’s report was published in June 2009.

On May 8, 2009, the government of Western Australia announced that the DMP will carry out “the final stage of investigations into the Varanus Island gas explosion.” Inspectors were appointed under the Petroleum Pipelines Act to coordinate the final stage of the investigations. Their report has been delivered to the Minister for Mines and Petroleum, but neither the report nor its contents have been made available to Company subsidiaries for their review and comment.

Breton Lawsuit

On October 4, 2011, plaintiffs filed suit in Breton Energy, L.L.C. et al. v. Mariner Energy Resources, Inc., et al., Case 4:11-cv-03561, in the United States District Court for the Southern District of Texas, Houston Division, seeking compensation from defendants for allegedly depriving plaintiffs, either negligently or intentionally, of

F-33

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

rights to hydrocarbons in a reservoir described by plaintiffs as a common reservoir in West Cameron Blocks 171 and 172 offshore Louisiana in the Gulf of Mexico. In their original petition plaintiffs named, among others, Mariner Energy, Inc. and certain of its affiliates as defendants. On December 12, 2011, plaintiffs filed an amended petition to add as defendants Apache Corporation and Apache Shelf, Inc. as successors to the Mariner interests. The case is in the early stages of discovery and the exposure related to the lawsuit is not currently determinable. While an adverse judgment against Apache is possible, Apache intends to actively defend the case.

Escheat Audits

The State of Delaware, Department of Finance, Division of Revenue (Unclaimed Property), has notified numerous companies, including Apache Corporation, that the State intends to examine its books and records and those of its subsidiaries and related entities to determine compliance with the Delaware Escheat Laws. The review will be conducted by Kelmar Associates on behalf of the State. At least 30 other states have retained their own consultants and have sent similar notifications. The scope of each state’s audit varies. The State of Delaware advises, for example, that the scope of its examination will be for the period 1981 through the present. It is possible that one or more of the State audits could extend to all 50 states.

Burrup-Related Gas Supply Lawsuits

On May 19, 2011, a lawsuit captioned Oswal v. Apache Corporation, Cause No. 2011-30302, in the District Court of Harris County, Texas, was filed in which plaintiff Pankaj Oswal, in his personal capacity and as trustee for the Burrup Trust, asserts claims against the Company under the Australian Trade Practices Act. This lawsuit is one of a number of legal actions involving the Burrup Fertilisers Pty Ltd (Burrup Fertilisers) ammonia plant in Western Australia (the Burrup plant) founded by Oswal. Oswal’s shares, and those of his wife, together representing 65 percent of Burrup Holdings Limited (BHL, which owns Burrup Fertilisers), were offered for sale by externally-appointed administrators in Australia as a result of events of default on loans made to the Oswals by the Australia and New Zealand Banking Group Ltd (ANZ). In the Texas lawsuit, plaintiff Oswal alleges, among other things, that the Company induced him to make investments covering construction cost overruns on the ammonia plant that was completed in 2006. Plaintiff Oswal seeks damages in the amount of $491 million USD. The Company believes that the claims are without merit and intends to vigorously defend against them. The Texas lawsuit has been consolidated for certain purposes with the Burrup Fertilisers lawsuit arising from the Australia gas pipeline force majeure as described above and the consolidated action has been stayed by the trial court in Houston, Texas, pending resolution of related litigation in Australia.

The Texas lawsuit relates to a pending action filed by Tap (Harriet) Pty Ltd (Tap) against Burrup Fertilisers Pty Ltd et al., Civ 2329 of 2009, in the Supreme Court of Western Australia (the “Tap action”), seeking a declaratory judgment regarding its contractual rights and obligations under a gas sales agreement between Burrup Fertilisers and the Harriet Joint Venture (comprised of a Company subsidiary and two joint venture partners, Tap and Kufpec Australia Pty Ltd). The Company and the Company’s subsidiary, each of which has been added as a defendant by counterclaim, are diligently pursuing their claims and defenses.

As part of the sale process described above, on January 31, 2012, a Company affiliate acquired a 49 percent interest in BHL, while Yara Australia Pty Ltd (Yara) increased its interest in BHL from 35 percent to 51 percent. Yara will operate the ammonia plant, which it has rebranded Yara Pilbara, and intends to proceed with development of a technical ammonium nitrate (TAN) plant in the Burrup Peninsula region of Western Australia to be developed by a consortium including BHL. BHL share ownership continues to be the subject of ongoing litigation in Australia with third parties, including Pankaj and Radhika Oswal. A Company affiliate’s existing agreement to supply gas to the ammonia plant has been modified (with, among other things, new pricing,

F-34

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

delivery quantities, and term). The new gas supply agreement resolves counterclaims by Burrup Fertilisers against Apache and its affiliate in the Tap action. If Tap and Kufpec do not settle the remaining claims in the Tap action, it is expected that the trial court in the Tap action will issue its ruling in respect of phase 1 of those proceedings, which was tried in September 2011 and concerned construction of the original gas supply agreement.

Environmental Matters

The Company, as an owner or lessee and operator of oil and gas properties, is 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 and subject to the lessee to liability for pollution damages. In some instances, the Company may be directed to suspend or cease operations in the affected area. We maintain insurance coverage, which we believe is customary in the industry, although we are not fully insured against all environmental risks.

Apache manages its exposure to environmental liabilities on properties to be acquired by identifying existing problems and assessing the potential liability. The Company also conducts periodic reviews, on a Company-wide basis, to identify changes in its environmental risk profile. These reviews evaluate whether there is a probable liability, the amount, and the likelihood that the liability will be incurred. The amount of any potential liability is determined by considering, among other matters, incremental direct costs of any likely remediation and the proportionate cost of employees who are expected to devote a significant amount of time directly to any possible remediation effort. As it relates to evaluations of purchased properties, depending on the extent of an identified environmental problem, the Company may exclude a property from the acquisition, require the seller to remediate the property to Apache’s satisfaction, or agree to assume liability for the remediation of the property. The Company’s general policy is to limit any reserve additions to any incidents or sites that are considered probable to result in an expected remediation cost exceeding $300,000. Any environmental costs and liabilities that are not reserved for are treated as an expense when actually incurred. In Apache’s estimation, neither these expenses nor expenses related to training and compliance programs are likely to have a material impact on its financial condition.

As of December 31, 2011, the Company had an undiscounted reserve for environmental remediation of approximately $120 million. Apache is not aware of any environmental claims existing as of December 31, 2011 that have not been provided for or would otherwise have a material impact on its financial position or results of operations. There can be no assurance however, that current regulatory requirements will not change or past non-compliance with environmental laws will not be discovered on the Company’s properties.

Apache Canada Ltd. has asserted a claim against BP Canada arising out of the acquisition of certain Canadian properties under the parties’ Partnership Interest and Share Purchase and Sale Agreement dated July 20, 2010. The dispute centers on Apache Canada Ltd.’s identification of Alleged Adverse Conditions, as that term is defined in the parties’ agreement, and more specifically the contention that liabilities associated with such conditions were retained by BP Canada as seller. Apache Canada Ltd. is diligently pursuing this claim.

On May 25, 2011, a panel of the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE) published a report dated May 23, 2011, and titled “Vermilion Block, Production Platform A: An Investigation of the September 2, 2010 Incident in the Gulf of Mexico.” The report concerned the BOEMRE’s investigation of a fire on the Vermilion 380 A platform located in the Gulf of Mexico. At the time of the incident, Mariner operated the platform. A small amount of hydrocarbons spilled from the platform into the surrounding

F-35

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

water as a result of the incident, and 13 workers were rescued and evacuated to safety after jumping into the water. The BOEMRE concluded in its investigation that the fire was caused by Mariner’s failure to adequately maintain or operate the platform’s heater-treater in a safe condition. The BOEMRE also identified other safety deficiencies on the platform. On December 27, 2011, the BOEMRE issued several Incidents of Non-Compliance, which may provide the basis for the assessment of civil penalties against Mariner. The Company is evaluating whether to contest the Incidents of Non-Compliance in whole or in part. Effective November 10, 2010, Mariner was acquired by Apache.

Contractual Obligations

At December 31, 2011, contractual obligations for drilling rigs, purchase obligations, firm transportation agreements, and long-term operating leases are as follows:


Net Minimum Commitments	Total		2012		2013-2014		2015-2016		2017& Beyond
	(In millions)
Drilling rig commitments(1)	$	799	$	288	$	510	$	1	$	—
Purchase obligations(2)		1,408		578		603		186		41
Firm transportation agreements(3)		756		117		224		149		266
Office and related equipment(4)		281		52		79		54		96
Other operating lease obligations(5)		694		184		227		183		100

Total Net Minimum Commitments	$	3,938	$	1,219	$	1,643	$	573	$	503

(1)	Includes day-rate and other contractual agreements with third party service providers for use of drilling, completion, and workover rigs.

(2)	Includes contractual obligations to buy or build oil and gas plants and facilities, seismic and drilling work program commitments, take-or-pay contracts, and hydraulic fracturing services agreements.

(3)	Relates to contractual obligations for capacity rights on third-party pipelines.

(4)	Includes office and other building rentals and related equipment leases.

(5)	Includes commitments required to retain acreage and commitments associated with floating production storage and offloading units (FPSOs), compressors, helicopters, and boats.

The table above includes leases for buildings, facilities, and related equipment with varying expiration dates through 2035. Net rental expense was $64 million, $46 million, and $38 million for 2011, 2010, and 2009, respectively.

Retirement and Deferred Compensation Plans

Apache Corporation provides retirement benefits to its U.S. employees through the use of multiple plans: an IRC 401(k) savings plan, a money purchase retirement plan, a non-qualified top hat retirement savings plan, and a non-qualified restorative retirement savings plan. The non-qualified restorative retirement savings plan was implemented January 1, 2012. The 401(k) savings plan provides participating employees the ability to elect to contribute up to 50 percent of eligible compensation to the plan with the Company making matching contributions up to a maximum of eight percent of each employee’s annual eligible compensation. In addition, the Company annually contributes six percent of each participating employee’s annual eligible compensation, as defined, to a money purchase retirement plan. The 401(k) plan and the money purchase retirement plan are subject to certain annually-adjusted, government-mandated restrictions that limit the amount of employee and

F-36

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Company contributions. For certain eligible employees, the Company also provides a non-qualified top hat retirement savings plan or a non-qualified restorative retirement savings plan that allows the deferral of up to 50 percent of each employee’s salary, up to 75 percent of each employee’s annual bonus (that accepts employee contributions) and the Company’s matching contributions in excess of the government mandated limitations imposed in the 401(k) savings plan and money purchase retirement plan.

Vesting in the Company’s contributions in the 401(k) savings plan, the money purchase retirement plan, the non-qualified top hat retirement savings plan and the non-qualified restorative retirement savings plan occurs at the rate of 20 percent for every full year of employment. Upon a change in control of ownership, immediate and full vesting occurs.

Additionally, Apache Energy Limited, Apache Canada Ltd., and Apache North Sea Limited maintain separate retirement plans, as required under the laws of Australia, Canada, and the U.K., respectively.

The aggregate annual cost to Apache of all 401(k) savings plans, money purchase retirement plans and non-qualified top hat retirement savings plans was $93 million, $80 million, and $66 million for 2011, 2010, and 2009, respectively.

Apache also provides a funded noncontributory defined benefit pension plan (U.K. Pension Plan) covering certain employees of the Company’s North Sea operations in the U.K. The plan provides defined pension benefits based on years of service and final salary. The plan applies only to employees who were part of the BP North Sea’s pension plan as of April 2, 2003, prior to the acquisition of BP North Sea by the Company effective July 1, 2003.

Additionally, the Company offers postretirement medical benefits to U.S. employees who meet certain eligibility requirements. Covered participants receive medical benefits up until the age of 65, provided the participant remits the required portion of the cost of coverage. The plan is contributory with participants’ contributions adjusted annually. The postretirement benefit plan does not cover benefit expenses once a covered participant becomes eligible for Medicare.

F-37

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following tables set forth the benefit obligation, fair value of plan assets and funded status as of December 31, 2011, 2010, and 2009, and the underlying weighted average actuarial assumptions used for the U.K. Pension Plan and U.S. postretirement benefit plan. Apache uses a measurement date of December 31 for its pension and postretirement benefit plans.


	2011						2010						2009
	Pension Benefits			Postretirement Benefits			Pension Benefits			Postretirement Benefits			Pension Benefits			Postretirement Benefits
	(In millions)
Change in Projected Benefit Obligation
Projected benefit obligation beginning of year	$	136		$	29		$	135		$	18		$	99		$	17
Service cost		5			3			5			2			4			2
Interest cost		7			1			7			1			6			1
Foreign currency exchange rate changes		(1	)		—			(4	)		—			13			—
Amendments		—			—			—			—			—			—
Actuarial losses (gains)		6			(2	)		(1	)		8			17			(1	)
Effect of curtailment and settlements		—			—			—			—			—			—
Benefits paid		(3	)		(1	)		(6	)		—			(4	)		(1	)
Retiree contributions		—			—			—			—			—			—

Projected benefit obligation at end of year		150			30			136			29			135			18

Change in Plan Assets
Fair value of plan assets at beginning of year		135			—			118			—			83			—
Actual return on plan assets		4			—			14			—			12			—
Foreign currency exchange rates		(1	)		—			(3	)		—			11			—
Employer contributions		10			1			12			—			16			1
Benefits paid		(3	)		(1	)		(6	)		—			(4	)		(1	)
Retiree contributions		—			—			—			—			—			—

Fair value of plan assets at end of year		145			—			135			—			118			—

Funded status at end of year	$	(5	)	$	(30	)	$	(1	)	$	(29	)	$	(17	)	$	(18	)

Amounts recognized in Consolidated Balance Sheet
Current liability		—			(1	)		—			(1	)		—			(1	)
Non-current liability		(5	)		(29	)		(1	)		(28	)		(17	)		(17	)

	$	(5	)	$	(30	)	$	(1	)	$	(29	)	$	(17	)	$	(18	)

Pre-tax Amounts Recognized in Accumulated Other Comprehensive Income (Loss)
Accumulated gain (loss)		(25	)		(6	)		(15	)		(8	)		(24	)		—
Prior service cost		—			—			—			—			—			—
Transition asset (obligation)		—			—			—			—			—			—

	$	(25	)	$	(6	)	$	(15	)	$	(8	)	$	(24	)	$	—

Weighted Average Assumptions used as of December 31
Discount rate		4.70	%		4.04	%		5.40	%		4.93	%		5.70	%		5.56	%
Salary increases		4.60	%		N/A			5.00	%		N/A			5.30	%		N/A
Expected return on assets		4.85	%		N/A			6.25	%		N/A			6.65	%		N/A
Healthcare cost trend
Initial		N/A			7.50	%		N/A			8.00	%		N/A			7.50	%
Ultimate in 2016		N/A			5.00	%		N/A			5.00	%		N/A			5.00	%

F-38

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

As of December 31, 2011, 2010, and 2009, the accumulated benefit obligation for the pension plan was $119 million, $107 million, and $89 million, respectively.

Apache’s defined benefit pension plan assets are held by a non-related trustee who has been instructed to invest the assets in an equal blend of equity securities and low-risk debt securities. The Company intends that this blend of investments will provide a reasonable rate of return such that the benefits promised to members are provided.

The U.K. Pension Plan policy is to target an ongoing funding level of 100 percent through prudent investments and includes policies and strategies such as investment goals, risk management practices, and permitted and prohibited investments. A breakout of previous allocations for plan asset holdings and the target allocation for the Company’s plan assets are summarized below:


	Target Allocation			Percentage of Plan Assets at Year-End
	2011			2011			2010
Asset Category
Equity securities:
U.K. quoted equities		17	%		17	%		18	%
Overseas quoted equities		33	%		31	%		34	%

Total equity securities		50	%		48	%		52	%

Debt securities:
U.K. Government bonds		31	%		30	%		31	%
U.K. corporate bonds		19	%		18	%		17	%

Debt securities		50	%		48	%		48	%

Cash		—			4	%		—

Total		100	%		100	%		100	%

The plan’s assets do not include any equity or debt securities of Apache. The fair value of plan assets is based upon unadjusted quoted prices for identical instruments in active markets, which is a Level 1 fair value measurement. See discussion of the fair value hierarchy as set forth by ASC 820-10-35 in Note 11 — Fair Value Measurements. The following table presents the fair values of plan assets for each major asset category based on the nature and significant concentration of risks in plan assets at December 31, 2011:


	Fair Value Measurements Using:
	Quoted Price in Active Markets (Level 1)		Significant Other Inputs (Level 2)		Unobservable Inputs (Level 3)		Total Fair Value
	(In millions)
Equity securities:
U.K. quoted equities(1)	$	24	$	—	$	—	$	24
Overseas quoted equities(2)		46		—		—		46

Total equity securities		70		—		—		70

Debt securities:
U.K. Government bonds(3)		43		—		—		43
U.K. corporate bonds(4)		26		—		—		26

Total debt securities		69		—		—		69

Cash		6		—		—		6

Fair value of plan assets	$	145	$	—	$	—	$	145

(1)	This category comprises U.K. equities, which are benchmarked against the FTSE All-Share Index.

F-39

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(2)

This category includes overseas equities, which comprises 85 percent global equities benchmarked against the MSCI World Index and 15 percent emerging markets benchmarked against the MSCI Emerging Markets Index, both of which have a performance target of 2 percent per annum over the benchmark over a rolling three-year period.

(3)

This category includes U.K. Government bonds: 35 percent benchmarked against iBoxx Sterling Overall Index, with a performance target of 0.75 percent per annum over the benchmark over a rolling three-year period; and 65 percent against the FTSE Actuaries Government Securities Index-Linked Over 5 Years Index.

(4)

This category comprises U.K. corporate bonds: 47 percent benchmarked against iBoxx Sterling Overall Index, with a performance target of 0.75 percent per annum over the benchmark over a rolling three-year period; and 53 percent benchmarked against iBoxx Sterling Non Gilt Index, with a performance target of 0.75 percent per annum over the benchmark over a rolling five-year period.

The expected long-term rate of return on assets assumptions are derived relative to the yield on long-dated fixed-interest bonds issued by the U.K. government (gilts). For equities, outperformance relative to gilts is assumed to be 3.5 percent per year.

The following table presents the fair values of plan assets for each major asset category based on the nature and significant concentration of risks in plan assets at December 31, 2010:


	Fair Value Measurements Using:
	Quoted Price in Active Markets (Level 1)		Significant Other Inputs (Level 2)		Unobservable Inputs (Level 3)		Total Fair Value
	(In millions)
Equity securities:
U.K. quoted equities(1)	$	24	$	—	$	—	$	24
Overseas quoted equities(2)		46		—		—		46

Total equity securities		70		—		—		70

Debt securities:
U.K. Government bonds(3)		42		—		—		42
U.K. corporate bonds(4)		23		—		—		23

Total debt securities		65		—		—		65

Cash		—		—		—		—

Fair value of plan assets	$	135	$	—	$	—	$	135

(1)	This category comprises U.K. equities, which are benchmarked against the FTSE All-Share Index.

(2)

(3)

This category includes U.K. Government bonds: 72 percent benchmarked against iBoxx Sterling Overall Index, with a performance target of 0.75 percent per annum over the benchmark over a rolling three-year period; and 28 percent against the FTSE Actuaries Government Securities Index-Linked Over 5 Years Index.

F-40

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(4)	This category comprises U.K. corporate bonds benchmarked against the iBoxx Sterling Overall Index.

The following tables set forth the components of the net periodic cost and the underlying weighted average actuarial assumptions used for the pension and postretirement benefit plans as of December 31, 2011, 2010 and 2009:


	2011						2010						2009
	Pension Benefits			Postretirement Benefits			Pension Benefits			Postretirement Benefits			Pension Benefits			Postretirement Benefits
	(In millions)
Components of Net Periodic Benefit Costs
Service cost	$	5		$	3		$	5		$	2		$	4		$	2
Interest cost		7			1			7			1			6			1
Expected return on assets		(8	)		—			(8	)		—			(6	)		—
Amortization of actuarial (gain) loss		—			—			1			—			—			—

Net periodic benefit cost	$	4		$	4		$	5		$	3		$	4		$	3

Weighted Average Assumptions used to determine Net Periodic Benefit Costs for the Years ended December 31
Discount rate		5.40	%		4.93	%		5.70	%		5.56	%		5.50	%		6.03	%
Salary increases		5.00	%		N/A			5.30	%		N/A			4.50	%		N/A
Expected return on assets		6.25	%		N/A			6.65	%		N/A			6.05	%		N/A
Healthcare cost trend
— Initial		—			8.00	%		—			7.50	%		—			8.00	%
— Ultimate in 2017		—			5.00	%		—			5.00	%		—			5.00	%

Assumed health care cost trend rates effect amounts reported for postretirement benefits. A one-percentage-point change in assumed health care cost trend rates would have the following effects:


	Postretirement Benefits
	1% Increase		1% Decrease
	(In millions)
Effect on service and interest cost components	$	1	$	—
Effect on postretirement benefit obligation		3		(3	)

F-41

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Apache expects to contribute approximately $5 million to its pension plan and $1 million to its postretirement benefit plan in 2012. The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:


	Pension Benefits		Postretirement Benefits
	(In millions)
2012	$	3	$	1
2013		5		1
2014		6		2
2015		6		2
2016		7		2
Years 2017 – 2021		41		19

9. CAPITAL STOCK

Common Stock Outstanding


	2011		2010		2009
Balance, beginning of year		382,391,742		336,436,972		334,710,064
Shares issued for stock-based compensation plans:
Treasury shares issued		144,313		363,263		404,232
Common shares issued		1,581,588		1,864,498		1,322,676
Equity offering (BP acquisitions)		—		26,450,000		—
Mariner consideration		—		17,277,009		—

Balance, end of year		384,117,643		382,391,742		336,436,972

Net Income (Loss) Per Common Share

A reconciliation of the components of basic and diluted net income (loss) per common share for the years ended December 31, 2011, 2010, and 2009 is presented in the table below.


	2011						2010						2009
	Income		Shares		Per Share		Income		Shares		Per Share		Loss			Shares		Per Share
	(In millions, except per share amounts)
Basic:
Income (loss) attributable to common stock	$	4,508		384	$	11.75	$	3,000		352	$	8.53	$	(292	)		336	$	(.87	)

Effect of Dilutive Securities:
Mandatory Convertible Preferred Stock	$	76		14			$	32		5			$	—			—
Stock options and other		—		2				—		2				—			—

Diluted:
Income (loss) attributable to common stock, including assumed conversions	$	4,584		400	$	11.47	$	3,032		359	$	8.46	$	(292	)		336	$	(.87	)

F-42

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The diluted EPS calculation excludes options and restricted shares that were anti-dilutive totaling 2.5 million, 2.3 million, and 4.2 million for the years ended December 31, 2011, 2010, and 2009, respectively.

Issuance of Common Stock

On July 28, 2010, in conjunction with Apache’s acquisition of properties from BP, the Company issued 26.45 million shares of common stock at a public offering price of $88 per share. Proceeds, after underwriting discounts and before expenses, from the common stock offering totaled approximately $2.3 billion.

On November 10, 2010, in connection with the Mariner merger, Apache issued 17.28 million shares of common stock in exchange for Mariner common and restricted stock. The total value of stock consideration, based on the November 10, 2010, closing value on the NYSE of $110.25 per share, was approximately $1.9 billion.

On May 5, 2011, Apache shareholders approved amendments to the Certificate of Incorporation increasing the number of common shares authorized for issuance from 430 million to 860 million.

For further discussion of the BP acquisitions and Mariner merger, please see Note 2 — Acquisitions and Divestitures.

Common Stock Dividend

The Company paid common stock dividends of $0.60 per share in 2011, 2010, and 2009.

Stock Compensation Plans

The Company has several stock-based compensation plans, which include stock options, stock appreciation rights, restricted stock, and performance-based share appreciation plans. On May 5, 2011, the Company’s shareholders approved the 2011 Omnibus Equity Compensation Plan (the 2011 Plan), which is intended to provide eligible employees with equity-based incentives. The 2011 Plan provides for the granting of Incentive Stock Options, Non-Qualified Stock Options, Performance Awards, Restricted Stock, Restricted Stock Units, Stock Appreciation Rights, or any combination of the foregoing. Previously-approved plans remain in effect solely for the purpose of governing grants still outstanding that were issued prior to approval of the 2011 Plan. All new grants are issued from the 2011 Plan.

For 2011, 2010, and 2009, stock-based compensation expensed was $113 million, $164 million, and $104 million ($73 million, $106 million, and $67 million after tax), respectively. Costs related to the plans are capitalized or expensed based on the nature of each employee’s activities. A description of the Company’s stock-based compensation plans and related costs follows:


	2011		2010		2009
	(In millions)
Stock-based compensation expensed:
General and administrative	$	69	$	98	$	67
Lease operating expenses		44		66		37
Stock-based compensation capitalized		42		71		46

	$	155	$	235	$	150

F-43

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Stock Options

As of December 31, 2011, officers and employees held options to purchase shares of the Company’s common stock under one or more of the employee stock option plans adopted in 1998, 2000 and 2005 (together, the Stock Option Plans), as well as the 2007 Omnibus Equity Compensation Plan (the 2007 Plan), and the 2011 Plan discussed above (collectively, the Omnibus Plans). New shares of Company stock will be issued for employee stock option exercises; however, under the 2000 Stock Option Plan, shares of treasury stock are used for employee stock option exercises to the extent treasury stock is held. Under the Stock Option Plans and the Omnibus Plans, the exercise price of each option equals the closing price of Apache’s common stock on the date of grant. Options generally become exercisable ratably over a four-year period and expire 10 years after granted. All of these plans allow for accelerated vesting if there is a change in control, as defined in each plan. The Omnibus Plans and all of the Stock Option Plans, except for the 2000 Stock Option Plan, were submitted to and approved by the Company’s shareholders.

A summary of stock options issued and outstanding under the Stock Option Plans and the Omnibus Plans is presented in the table and narrative below:


	2011
	Shares Under Option			Weighted Average Exercise Price
	(In thousands)
Outstanding, beginning of year		5,861		$	80.30
Granted		1,336			126.61
Exercised		(878	)		63.61
Forfeited or expired		(227	)		104.74

Outstanding, end of year(1)		6,092			91.95

Expected to vest(1)		2,135			109.28

Exercisable, end of year(1)		3,422			77.74

Available for grant, end of year		25,408

Weighted average fair value of options granted during the year	$	42.20

(1)

As of December 31, 2011, the weighted average remaining contractual life for options outstanding, expected to vest, and exercisable is 6.6 years, 8.5 years, and 5.1 years, respectively. The aggregate intrinsic value of options outstanding, expected to vest and exercisable at year-end was $62 million, $4 million, and $58 million, respectively. The weighted-average grant-date fair value of options granted during the years 2011, 2010, and 2009 was $42.20, $34.12, and $29.71, respectively.

F-44

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The fair value of each stock option award is estimated on the date of grant using the Black-Scholes option pricing model. Assumptions used in the valuation are disclosed in the following table. Expected volatilities are based on historical volatility of the Company’s common stock and other factors. The expected dividend yield is based on historical yields on the date of grant. The expected term of stock options granted represents the period of time that the stock options are expected to be outstanding and is derived from historical exercise behavior, current trends, and values derived from lattice-based models. The risk-free rate is based on the U.S. Treasury yield curve in effect at the time of grant.


	2011			2010			2009
Expected volatility		34.47	%		35.02	%		38.73	%
Expected dividend yields		0.47	%		0.60	%		0.73	%
Expected term (in years)		5.5			5.5			5.5
Risk-free rate		1.95	%		2.31	%		2.06	%

The intrinsic value of options exercised during 2011, 2010, and 2009 was approximately $50 million, $62 million and $39 million, respectively. The cash received from exercise of options during 2011 was approximately $56 million. The Company realized an additional tax benefit of approximately $10 million for the amount of intrinsic value in excess of compensation cost recognized in 2011. As of December 31, 2011, the total compensation cost related to non-vested options not yet recognized was $79 million, which will be recognized over the remaining vesting period of the options.

Stock Appreciation Rights

In 2003 and 2004, respectively, the Company issued a total of 1,809,060 and 1,334,300 stock appreciation rights (SARs) to non-executive employees in lieu of stock options. The SARs vested ratably over four years and are settled in cash upon exercise throughout their ten-year life. The weighted-average exercise price was $42.68 and $28.78 for those issued in 2004 and 2003, respectively. The number of SARs outstanding and exercisable as of December 31, 2011, was 475,130. Since SARs are cash-settled, the Company records compensation expense based on the fair value of the SARs at the end of each period. As of year-end, the weighted-average fair value of SARs outstanding was $54.66 based on the Black-Scholes valuation methodology using assumptions comparable to those discussed above. During 2011, 120,531 SARs were exercised. The aggregate of cash payments made to settle SARs was $12 million.

Restricted Stock and Restricted Stock Units

The Company has restricted stock and restricted stock unit plans for eligible employees including officers. The programs created under the Omnibus Plans have been approved by Apache’s Board of Directors. In 2011, the Company awarded 887,851 restricted stock units at a weighted-average per-share market price of $124.16. In 2010 and 2009, the Company awarded 1,143,989 and 1,119,936 restricted stock units at a weighted-average per-share market price of $103.88 and $84.30, respectively. The value of the stock issued was established by the market price on the date of grant and is being recorded as compensation expense ratably over the vesting terms. During 2011, 2010 and 2009, $76 million ($49 million after tax), $73 million ($47 million after tax) and $37 million ($24 million after tax), respectively, was charged to expense. In 2011, 2010, and 2009, $28 million, $28 million, and $12 million was capitalized, respectively. As of December 31, 2011, there was $154 million of total unrecognized compensation cost related to 2,115,107 unvested restricted stock units. The weighted-average remaining life of unvested restricted stock units is approximately 1.2 years.

F-45

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The fair value of the awards vested during 2011, 2010, and 2009 was approximately $85 million, $69 million, and $34 million, respectively. A summary of restricted stock activity for the year ended December 31, 2011, is presented below.


Restricted Stock	Shares			Weighted- Average Grant- Date Fair Value
	(In thousands)
Non-vested at January 1, 2011		2,210		$	100.72
Granted		888			124.16
Vested		(829	)		102.12
Forfeited		(154	)		86.61

Non-vested at December 31, 2011		2,115			109.31

Conditional Restricted Stock Units

To provide long-term incentives for Apache employees to deliver competitive returns to the Company’s stockholders, in January 2011 and 2010 the Company granted conditional restricted stock units to eligible employees, pursuant to the 2007 Plan. The ultimate number of shares awarded from these conditional restricted stock units is based upon measurement of total shareholder return of Apache common stock as compared to a designated peer group during a three-year performance period. Should any restricted stock units be awarded at the end of the three-year performance period, 50 percent of restricted stock units awarded will immediately vest, and an additional 25 percent will vest on succeeding anniversaries of the end of the performance period. Two conditional restricted stock unit programs have been approved, as described below:

•

In November 2009 the Company’s Board of Directors approved the 2010 Performance Program. In January 2010 eligible employees received initial conditional restricted stock unit awards totaling 541,440 units. A total of 479,890 units were outstanding at December 31, 2011, from which a minimum of zero and a maximum of 1,199,725 units could be awarded.

•

In November 2010 the Company’s Board of Directors approved the 2011 Performance Program. In January 2011 eligible employees received initial conditional restricted stock unit awards totaling 585,811 units. A total of 539,526 units were outstanding at December 31, 2011, from which a minimum of zero and a maximum of 1,348,815 units could be awarded.

F-46

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The fair value cost of the awards was estimated on the date of grant and is being recorded as compensation expense ratably over the vesting terms. During 2011 and 2010, $12 million ($8 million after tax) and $7 million ($4 million after tax), respectively, was charged to expense. During 2011 and 2010 $5 million and $3 million was capitalized, respectively. As of December 31, 2011, there was $91 million of total unrecognized compensation cost related to 1,019,416 unvested conditional restricted stock units. The weighted-average remaining life of the unvested conditional restricted stock units is approximately 2.3 years.


Conditional Restricted Stock Award	Shares			Weighted- Average Grant- Date Fair Value(1)
	(In thousands)
Non-vested at January 1, 2011		523		$	141.86
Granted		586			91.29
Vested		(2	)		118.31
Forfeited		(88	)		115.67

Non-vested at December 31, 2011		1,019			115.10

(1)

The fair value of each conditional restricted stock unit award is estimated as of the date of grant using a Monte Carlo simulation with the following assumptions used for all grants made under the plan: (i) a three-year continuous risk-free interest rate; (ii) a constant volatility assumption based on the historical realized stock price volatility of the Company and the designated peer group; and (iii) the historical stock prices and expected dividends of the common stock of the Company and its designated peer group.

In January 2012 the Company’s Board of Directors approved the 2012 Performance Program, pursuant to the 2011 Plan, with terms similar to the 2010 and 2011 Performance Programs. Eligible employees received initial conditional restricted stock unit awards totaling 851,985 units, with the ultimate number of restricted stock units to be awarded ranging from zero to a maximum of 2,129,962 units.

Share Appreciation Plans

The Company previously utilized share appreciation plans to provide incentives for substantially all full-time employees and officers to increase Apache’s share price within a stated measurement period. To achieve the payout, the Company’s stock price must close at or above a stated threshold for 10 out of any 30 consecutive trading days before the end of the stated period. Shares of Apache common stock contingently issuable under the plans are excluded from the computation of income per common share until the stated goals are met as described below.

Since 2005, two share appreciation plans have been approved. A summary of these plans is as follows:

•

On May 7, 2008, the Stock Option Plan Committee of the Company’s Board of Directors, pursuant to the 2007 Plan, approved the 2008 Share Appreciation Program with a target to increase Apache’s share price to $216 by the end of 2012 and an interim goal of $162 to be achieved by the end of 2010. Any awards under the program would be payable in five equal annual installments. The interim target of $162 was not met by the end of 2010, and the related awards were cancelled. The $216 share price target has not been met.

F-47

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

•

On May 5, 2005, the Company’s stockholders approved the 2005 Share Appreciation Plan, with a target to increase Apache’s share price to $108 by the end of 2008 and an interim goal of $81 to be achieved by the end of 2007. Awards under the plan were payable in four equal annual installments to eligible employees remaining with the Company. Apache’s share price exceeded the interim $81 threshold for the 10-day requirement as of June 14, 2007, and the first and second installments were awarded in July 2007 and 2008. The third and fourth installments were awarded in June 2009 and 2010. Apache’s share price exceeded the $108 threshold for the 10-day requirement as of February 29, 2008. The first three installments were awarded in March 2008, 2009 and 2010, and the fourth and final installment was awarded in March 2011. No additional awards will be made under the 2005 Share Appreciation Plan.

A summary of the number of shares contingently issuable as of December 31, 2011, 2010, and 2009 for each plan is presented in the table below:


	Shares Subject to Conditional Grants
	2011			2010			2009
	(In thousands)
2008 Share Appreciation Program
Outstanding, beginning of year		1,485			2,592			2,814
Granted		—			25			93
Forfeited or cancelled		(113	)		(1,132	)		(315	)

Outstanding, end of year(1)		1,372			1,485			2,592

Weighted-average fair value of grants outstanding(2)	$	71.28		$	71.16		$	79.61

2005 Share Appreciation Plan
Outstanding, beginning of year		400			1,103			2,001
Issued(3)		(398	)		(678	)		(815	)
Forfeited or cancelled		(2	)		(25	)		(83	)

Outstanding, end of year		—			400			1,103

Weighted-average fair value of grants outstanding(4)	$	—		$	21.64		$	24.29

(1)

Represents shares issuable upon target achievement and vesting of awards related to the $216 and $162 per share price goals of 1,372,190 and zero shares, respectively, at December 31, 2011;1,485,210 and zero shares, respectively, at December 31, 2010; and 1,556,160 and 1,035,640 shares, respectively, at December 31, 2009.

(2)

The fair value of each Share Price Goal conditional grant is estimated as of the date of grant using a Monte Carlo simulation with the following weighted-average assumptions used for all grants made under the plan: (i) risk-free interest rate of 2.98 percent; (ii) expected volatility of 28.31 percent; and (iii) expected dividend yield of .54 percent.

(3)	The total fair value of these awards vested during 2011, 2010, and 2009 was approximately $9 million, $18 million, and $21 million, respectively.

(4)

The fair value of each Share Price Goal conditional grant is estimated as of the date of grant using a Monte Carlo simulation with the following weighted-average assumptions used for all grants made under the plan: (i) risk-free interest rate of 3.95 percent; (ii) expected volatility of 28.02 percent; and (iii) expected dividend yield of .57 percent.

F-48

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The Company recognizes over the requisite service period the fair value cost determined at the grant date based on numerous assumptions, including an estimate of the likelihood that Apache’s stock price will achieve these thresholds and the expected forfeiture rate. If a price target is not met before the end of the stated achievement period, any unamortized expense must be immediately recognized. Since the $162 interim price target of the 2008 Share Appreciation Program was not met prior to the stated achievement period, on December 31, 2010, Apache recognized $27 million of unamortized expense and $14 million of unamortized capital costs. The Company will recognize total expense and capitalized costs for the 2008 Share Appreciation Program of approximately $188 million through 2014. As of March 2011, the Company had recognized $79 million of total expense and capitalized costs for the 2005 Share Appreciation Program and had no unamortized costs remaining. A summary of the amounts recognized as expense and capitalized costs for each plan are detailed in the table below:


	For the Year Ended December 31,
	2011		2010		2009
	(In millions)
2008 Share Appreciation Program
Compensation expense	$	8	$	49	$	23
Compensation expense, net of tax		5		31		15
Capitalized costs		5		27		13
2005 Share Appreciation Plan
Compensation expense	$	1	$	6	$	6
Compensation expense, net of tax		1		4		4
Capitalized costs		1		3		3

Preferred Stock

The Company has 10,000,000 shares of no par preferred stock authorized, of which 25,000 shares have been designated as Series A Junior Participating Preferred Stock (the Series A Preferred Stock) and 1.265 million shares as 6.00-percent Mandatory Convertible Preferred Stock, Series D (the Series D Preferred Stock). The Company redeemed the 100,000 outstanding shares of its 5.68 percent Series B Cumulative Preferred Stock (the Series B Preferred Stock) on December 30, 2009.

Series A Preferred Stock

In December 1995, the Company declared a dividend of one right (a Right) for each 2.31 shares (adjusted for subsequent stock dividends and a two-for-one stock split) of Apache common stock outstanding on January 31, 1996. Each full Right entitles the registered holder to purchase from the Company one ten-thousandth (1/10,000) of a share of Series A Preferred Stock at a price of $100 per one ten-thousandth of a share, subject to adjustment. The Rights are exercisable 10 calendar days following a public announcement that certain persons or groups have acquired 20 percent or more of the outstanding shares of Apache common stock or 10 business days following commencement of an offer for 30 percent or more of the outstanding shares of Apache’s outstanding common stock (flip in event); each Right will become exercisable for shares of Apache’s common stock at 50 percent of the then-market price of the common stock. If a 20-percent shareholder of Apache acquires Apache, by merger or otherwise, in a transaction where Apache does not survive or in which Apache’s common stock is changed or exchanged (flip over event), the Rights become exercisable for shares of the common stock of the Company acquiring Apache at 50 percent of the then-market price for Apache common stock. Any Rights that are or were beneficially owned by a person who has acquired 20 percent or more of the outstanding shares of Apache common stock and who engages in certain transactions or realizes the benefits of

F-49

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

certain transactions with the Company will become void. If an offer to acquire all of the Company’s outstanding shares of common stock is determined to be fair by Apache’s board of directors, the transaction will not trigger a flip in event or a flip-over event. The Company may also redeem the Rights at $.01 per Right at any time until 10 business days after public announcement of a flip in event. 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 issued by the Company after January 31, 1996 will include Rights. Unless and until the Rights become exercisable, they will be transferred with and only with the shares of Apache common stock.

Series B Preferred Stock

In August 1998, Apache issued 100,000 shares ($100 million) of Series B Preferred Stock in the form of one million depositary shares, each representing one-tenth (1/10) of a share of Series B Preferred Stock, for net proceeds of $98 million. On December 30, 2009, Apache redeemed all Series B Preferred Stock at $1,000 per preferred share plus $9.47 in accrued and unpaid dividends. Holders of the shares were entitled to receive cumulative cash dividends at an annual rate of $5.68 per depositary share. As the final dividend payment was accelerated with the redemption of the Series B Preferred Stock, Apache paid $7 million in dividends on this stock during 2009.

Series D Preferred Stock

On July 28, 2010, Apache issued 25.3 million depositary shares, each representing a 1/20th interest in a share of Apache’s 6.00-percent Mandatory Convertible Preferred Stock, Series D (Preferred Share), or 1.265 million Preferred Shares. The Company received proceeds of approximately $1.2 billion, after underwriting discounts and before expenses, from the sale.

Each Preferred Share has an initial liquidation preference of $1,000 per share (equivalent to $50 liquidation preference per depositary share). When and if declared by the Board of Directors, Apache will pay cumulative dividends on each Preferred Share at a rate of 6.00 percent per annum on the initial liquidation preference. Dividends will be paid in cash quarterly on February 1, May 1, August 1, and November 1 of each year, commencing on November 1, 2010, and until and including May 1, 2013. The final dividend payment on August 1, 2013, may be paid or delivered, as the case may be, in cash, shares of Apache common stock, or a combination thereof, at the election of the Company.

The Preferred Shares may be converted, at the option of the holder, into 9.164 shares of Apache common stock at any time prior to July 15, 2013. If not converted prior to that time, each Preferred Share will automatically convert on August 1, 2013, into a minimum of 9.164 or a maximum of 11.364 shares of Apache common stock depending on the volume-weighted average price per share of Apache’s common stock over the ten trading day period ending on, and including, the third scheduled trading day immediately preceding the mandatory conversion. Upon conversion, a minimum of 11.6 million Apache common shares and a maximum of 14.4 million common shares will be issued.

F-50

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

10. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

Components of accumulated other comprehensive income (loss) consists of the following:


	For the Year Ended December 31,
	2011			2010			2009
	(In millions)
Currency translation adjustment(1)	$	(109	)	$	(109	)	$	(109	)
Unrealized gain (loss) on derivatives (Note 3)		114			(19	)		(170	)
Unfunded pension and postretirement benefit plan		(14	)		(13	)		(11	)

Accumulated other comprehensive loss	$	(9	)	$	(141	)	$	(290	)

(1)	Currency translation adjustments resulting from translating the Canadian subsidiaries’ financial statements into U.S. dollar equivalents, prior to adoption of the U.S. dollar as their functional currency, were reported separately and accumulated in other comprehensive income (loss).

11. FAIR VALUE MEASUREMENTS

ASC 820-10-35 provides a hierarchy that prioritizes and defines the types of inputs used to measure fair value. The fair value hierarchy gives the highest priority to Level 1 inputs, which consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived from inputs that are significant and unobservable; hence, these valuations have the lowest priority.

The valuation techniques that may be used to measure fair value include a market approach, an income approach, and a cost approach. A market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. An income approach uses valuation techniques to convert future amounts to a single present amount based on current market expectations, including present value techniques, option-pricing models, and excess earnings method. The cost approach is based on the amount that currently would be required to replace the service capacity of an asset (replacement cost).

Certain assets and liabilities are reported at fair value on a recurring basis in Apache’s consolidated balance sheet. The following methods and assumptions were used to estimate the fair values:

Cash, Cash Equivalents, Short-Term Investments, Accounts Receivable, and Accounts Payable

The carrying amounts approximate fair value because of the short-term nature or maturity of the instruments.

Commodity Derivative Instruments

Apache’s commodity derivative instruments consist of variable-to-fixed price commodity swaps and options. The fair values of the Company’s derivative instruments are not actively quoted in the open market. The Company uses a market approach to estimate the fair values of its derivative instruments, utilizing commodity futures price strips for the underlying commodities provided by a reputable third party. These valuations are Level 2 inputs. For further information regarding Apache’s derivative instruments and hedging activities, please see Note 3 – Derivative Instruments and Hedging Activities.

F-51

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table presents the Company’s material assets and liabilities measured at fair value on a recurring basis for each hierarchy level:


	Fair Value Measurements Using
	Quoted Price in Active Markets (Level 1)		Significant Other Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Fair Value		Netting(1)			Carrying Amount
	(In millions)
December 31, 2011
Assets:
Commodity Derivative Instruments	$	—	$	428	$	—	$	428	$	(96	)	$	332
Liabilities:
Commodity Derivative Instruments		—		250		—		250		(96	)		154
December 31, 2010
Assets:
Commodity Derivative Instruments	$	—	$	454	$	—	$	454	$	(148	)	$	306
Liabilities:
Commodity Derivative Instruments		—		466		—		466		(148	)		318

(1)

The derivative fair values above are based on analysis of each contract as required by ASC Topic 820. Derivative assets and liabilities with the same counterparty are presented here on a gross basis, even where the legal right of offset exists. For a discussion of net amounts recorded on the consolidated balance sheet at December 31, 2011 and 2010, please see Note 3 – Derivative Instruments and Hedging Activities.

12. 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.

F-52

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

13. BUSINESS SEGMENT INFORMATION

Apache is engaged in a single line of business. Both domestically and internationally, the Company explores for, develops, and produces natural gas, crude oil, and natural gas liquids. At December 31, 2011, the Company had production in six countries: the United States, Canada, Egypt, Australia, offshore the U.K. 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. Financial information for each country is presented below:


	United States		Canada		Egypt		Australia		North Sea		Argentina		Other International			Total
	(In millions)
2011
Oil and gas production revenues	$	6,103	$	1,617	$	4,791	$	1,734	$	2,091	$	474	$	—		$	16,810
Operating Expenses:
Depreciation, depletion and amortization
Recurring		1,684		546		818		440		409		198		—			4,095
Additional		—		—		—		—		—		—		109			109
Asset retirement obligation accretion		97		26		—		10		17		4		—			154
Lease operating expenses		1,167		470		398		197		208		165		—			2,605
Gathering and transportation		64		165		35		—		25		7		—			296
Taxes other than income		259		51		13		9		539		28		—			899

Operating Income (Loss)(1)	$	2,832	$	359	$	3,527	$	1,078	$	893	$	72	$	(109	)		8,652

Other Income (Expense):
Other																	78
General and administrative																	(459	)
Merger, acquisitions & transition																	(20	)
Financing costs, net																	(158	)

Income Before Income Taxes																$	8,093

Net Property and Equipment	$	21,038	$	8,022	$	4,923	$	4,194	$	5,737	$	1,512	$	22		$	45,448

Total Assets	$	23,499	$	8,816	$	6,656	$	4,681	$	6,600	$	1,766	$	33		$	52,051

Additions to Net Property and Equipment	$	3,854	$	1,288	$	1,015	$	1,140	$	4,175	$	374	$	73		$	11,919

2010 Oil and gas production revenues	$	4,300	$	1,074	$	3,372	$	1,459	$	1,606	$	372	$	—		$	12,183
Operating Expenses:
Depreciation, depletion and amortization
Recurring		1,163		294		754		408		304		160		—			3,083
Asset retirement obligation accretion		62		23		—		9		15		2		—			111
Lease operating expenses		924		334		298		185		168		123		—			2,032
Gathering and transportation		42		75		31		—		25		5		—			178
Taxes other than income		190		35		10		11		422		22		—			690

Operating Income(1)	$	1,919	$	313	$	2,279	$	846	$	672	$	60	$	—			6,089

Other Income (Expense):
Other																	(91	)
General and administrative																	(380	)
Merger, acquisitions & transition																	(183	)
Financing costs, net																	(229	)

Income Before Income Taxes																$	5,206

Net Property and Equipment	$	19,069	$	7,497	$	4,726	$	3,495	$	1,970	$	1,336	$	58		$	38,151

Total Assets	$	21,326	$	8,273	$	6,036	$	3,831	$	2,362	$	1,537	$	60		$	43,425

Additions to Net Property and Equipment	$	10,371	$	5,277	$	1,569	$	925	$	620	$	274	$	20		$	19,056

F-53

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	United States			Canada			Egypt		Australia		North Sea		Argentina		Other International		Total
	(In millions)
2009
Oil and gas production revenues	$	3,050		$	877		$	2,553	$	363	$	1,369	$	362	$	—	$	8,574
Operating Expenses:
Depreciation, depletion and amortization
Recurring		947			257			578		204		260		149		—		2,395
Additional		1,222			1,596			—		—		—		—		—		2,818
Asset retirement obligation accretion		63			19			—		6		14		3		—		105
Lease operating expenses		762			269			264		101		158		108		—		1,662
Gathering and transportation		36			53			23		—		26		5		—		143
Taxes other than income		121			43			9		10		383		14		—		580

Operating Income (Loss)(1)	$	(101	)	$	(1,360	)	$	1,679	$	42	$	528	$	83	$	—		871

Other Income (Expense):
Other																		41
General and administrative																		(344	)
Financing costs, net																		(242	)

Income Before Income Taxes																	$	326

Net Property and Equipment	$	9,859		$	3,251		$	3,910	$	2,965	$	1,655	$	1,223	$	38	$	22,901

Total Assets	$	11,526		$	3,776		$	5,626	$	3,346	$	2,444	$	1,428	$	40	$	28,186

Additions to Net Property and Equipment	$	1,342		$	604		$	873	$	774	$	379	$	171	$	11	$	4,154

(1)	Operating Income (Loss) consists of oil and gas production revenues less depreciation, depletion and amortization, asset retirement obligation accretion, lease operating expenses, gathering and transportation costs, and taxes other than income.

F-54

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

14. SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited)

Oil and Gas Operations

The following table sets forth revenue and direct cost information relating to the Company’s oil and gas exploration and production activities. Apache has no long-term agreements to purchase oil or gas production from foreign governments or authorities.


	United States		Canada		Egypt		Australia		North Sea		Argentina		Other International			Total
	(In millions, except per boe)
2011
Oil and gas production revenues	$	6,103	$	1,617	$	4,791	$	1,734	$	2,091	$	474	$	—		$	16,810


Operating cost:
Depreciation, depletion and amortization
Recurring(1)		1,634		537		818		435		405		195		—			4,024
Additional		—		—		—		—		—		—		109			109
Asset retirement obligation accretion		97		26		—		10		17		4		—			154
Lease operating expenses		1,167		470		398		197		208		165		—			2,605
Gathering and transportation		64		165		35		—		25		7		—			296
Production taxes(2)		255		44		—		9		538		19		—			865
Income tax		1,025		95		1,699		325		557		29		—			3,730

		4,242		1,337		2,950		976		1,750		419		109			11,783

Results of operations	$	1,861	$	280	$	1,841	$	758	$	341	$	55	$	(109	)	$	5,027

Amortization rate per boe	$	15.55	$	10.44	$	11.63	$	16.59	$	20.21	$	10.87	$	—		$	13.97


2010
Oil and gas production revenues	$	4,300	$	1,074	$	3,372	$	1,459	$	1,606	$	372	$	—		$	12,183


Operating cost:
Depreciation, depletion and amortization
Recurring(1)		1,126		287		754		403		301		157		—			3,028
Asset retirement obligation accretion		62		23		—		9		15		2		—			111
Lease operating expenses		924		334		298		185		168		123		—			2,032
Gathering and transportation		42		75		31		—		25		5		—			178
Production taxes(2)		177		31		—		11		423		14		—			656
Income tax		699		82		1,099		255		337		25		—			2,497

		3,030		832		2,182		863		1,269		326		—			8,502

Results of operations	$	1,270	$	242	$	1,190	$	596	$	337	$	46	$	—		$	3,681

Amortization rate per boe	$	13.23	$	8.13	$	11.05	$	13.38	$	14.42	$	9.56	$	—		$	11.92

F-55

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	United States			Canada			Egypt		Australia		North Sea		Argentina		Other International		Total
	(In millions, except per boe)

2009
Oil and gas production revenues	$	3,050		$	877		$	2,553	$	363	$	1,369	$	362	$	—	$	8,574

Operating cost:
Depreciation, depletion and amortization
Recurring(1)		915			250			578		202		256		147		—		2,348
Additional		1,222			1,596			—		—		—		—		—		2,818
Asset retirement obligation accretion		63			19			—		6		14		3		—		105
Lease operating expenses		762			269			264		101		158		108		—		1,662
Gathering and transportation		36			53			23		—		26		5		—		143
Production taxes(2)		107			35			—		10		383		7		—		542
Income tax		(19	)		(336	)		810		14		266		32		—		767

		3,086			1,886			1,675		333		1,103		302		—		8,385

Results of operations	$	(36	)	$	(1,009	)	$	878	$	30	$	266	$	60	$	—	$	189

Amortization rate per boe	$	12.10		$	7.58		$	8.86	$	12.61	$	11.40	$	8.62	$	—	$	10.34

(1)	This amount only reflects DD&A of capitalized costs of oil and gas proved properties and, therefore, does not agree with DD&A reflected on Note 13 — Business Segment Information.

(2)	This amount only reflects amounts directly related to oil and gas producing properties and, therefore, does not agree with taxes other than income reflected on Note 13 — Business Segment Information.

F-56

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Costs Incurred in Oil and Gas Property Acquisitions, Exploration, and Development Activities


	United States		Canada		Egypt			Australia		North Sea		Argentina			Other International		Total
	(In millions)
2011
Acquisitions:
Proved	$	368	$	—	$	(12	)	$	—	$	2,399	$	—		$	—	$	2,755
Unproved		116		33		2			48		476		—			13		688
Exploration		418		209		570			286		18		202			59		1,762
Development		2,832		883		344			429		941		156			2		5,587

Costs incurred(1)	$	3,734	$	1,125	$	904		$	763	$	3,834	$	358		$	74	$	10,792

(1) Includes capitalized interest and asset retirement costs as follows:
Capitalized interest	$	152	$	47	$	18		$	14	$	—	$	12		$	—	$	243
Asset retirement costs		380		228		—			125		678		—			—		1,411
2010
Acquisitions:
Proved	$	5,604	$	2,752	$	325		$	—	$	—	$	—		$	—	$	8,681
Unproved		2,497		542		145			32		—		—			—		3,216
Exploration		261		312		477			236		142		136			20		1,584
Development		1,724		611		290			496		475		131			—		3,727

Costs incurred(1)	$	10,086	$	4,217	$	1,237		$	764	$	617	$	267		$	20	$	17,208

(1) Includes capitalized interest and asset retirement costs as follows:
Capitalized interest	$	52	$	23	$	10		$	15	$	—	$	11		$	—	$	111
Asset retirement costs		1,099		98		—			93		—		16			—		1,306
2009
Acquisitions:
Proved	$	196	$	13	$	—		$	—	$	—	$	24		$	—	$	233
Unproved		—		—		39			38		—		—			—		77
Exploration		233		179		438			182		105		97			11		1,245
Development		892		326		245			474		270		47			—		2,254

Costs incurred(1)	$	1,321	$	518	$	722		$	694	$	375	$	168		$	11	$	3,809

(1) Includes capitalized interest and asset retirement costs as follows:
Capitalized interest	$	15	$	12	$	8		$	15	$	—	$	11		$	—	$	61
Asset retirement costs		182		80		—			38		—		(7	)		—		293

F-57

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Capitalized Costs

The following table sets forth the capitalized costs and associated accumulated depreciation, depletion and amortization, including impairments, relating to the Company’s oil and gas production, exploration and development activities:


	United States			Canada			Egypt			Australia			North Sea			Argentina			Other International			Total
	(In millions)

2011
Proved properties	$	33,905		$	12,619		$	6,117		$	5,183		$	7,430		$	2,442		$	109		$	67,805
Unproved properties		2,690			1,093			615			270			513			327			22			5,530

		36,595			13,712			6,732			5,453			7,943			2,769			131			73,335
Accumulated DD&A		(16,013	)		(6,506	)		(3,672	)		(2,061	)		(2,550	)		(1,343	)		(109	)		(32,254	)

	$	20,582		$	7,206		$	3,060		$	3,392		$	5,393		$	1,426		$	22		$	41,081


2010
Proved properties	$	30,273		$	11,679		$	5,286		$	4,435		$	4,078		$	2,153		$	—		$	57,904
Unproved properties		2,791			1,113			542			254			31			259			58			5,048

		33,064			12,792			5,828			4,689			4,109			2,412			58			62,952
Accumulated DD&A		(14,391	)		(6,027	)		(2,971	)		(1,642	)		(2,146	)		(1,153	)		—			(28,330	)

	$	18,673		$	6,765		$	2,857		$	3,047		$	1,963		$	1,259		$	58		$	34,622

Costs Not Being Amortized

The following table sets forth a summary of oil and gas property costs not being amortized at December 31, 2011, by the year in which such costs were incurred. There are no individually significant properties or significant development projects included in costs not being amortized. The majority of the evaluation activities are expected to be completed within five to ten years.


	Total		2011		2010		2009		2008 and Prior
	(In millions)
Property acquisition costs	$	4,258	$	1,015	$	2,861	$	53	$	329
Exploration and development		1,115		803		217		32		63
Capitalized interest		157		33		43		14		67

Total	$	5,530	$	1,851	$	3,121	$	99	$	459

Oil and Gas Reserve Information

Proved oil and gas reserves are the estimated quantities of natural gas, crude oil, condensate, and natural gas liquids (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.

F-58

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 which 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.

F-59

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

There are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and timing of development expenditures. The following reserve data only represent estimates and should not be construed as being exact.


	Crude Oil, Condensate and Natural Gas Liquids																					Natural Gas																					Total
	(Thousands of barrels)																					(Millions of cubic feet)																					(Thousands
	United States			Canada			Egypt			Australia			North Sea			Argentina			Total			United States			Canada			Egypt			Australia			North Sea			Argentina			Total			barrels of oil equivalent)
Proved developed reserves:
December 31, 2008		363,516			85,038			93,103			39,758			168,925			26,752			777,092			1,866,988			1,594,782			1,010,102			713,290			5,585			487,980			5,678,727			1,723,547
December 31, 2009		373,010			89,222			97,787			34,662			142,022			25,985			762,688			1,785,155			1,436,151			838,000			699,963			4,851			473,145			5,237,265			1,635,565
December 31, 2010		514,537			113,993			109,657			48,072			115,705			22,458			924,422			2,284,116			2,181,615			748,573			682,763			4,144			462,206			6,363,417			1,984,991
December 31, 2011		535,741			105,102			105,840			35,725			145,743			21,940			950,091			2,215,973			2,108,801			700,866			675,618			105,028			447,132			6,253,418			1,992,327
Proved undeveloped reserves:
December 31, 2008		151,248			70,707			21,303			36,777			18,990			5,027			304,052			670,194			608,580			360,876			540,255			—			58,393			2,238,298			677,102
December 31, 2009		150,627			57,552			17,806			43,779			29,692			5,104			304,560			652,766			869,197			321,141			661,478			—			54,184			2,558,766			731,021
December 31, 2010		244,478			60,997			17,470			18,064			38,663			4,641			384,313			988,869			1,310,352			328,344			805,735			—			70,465			3,503,765			968,274
December 31, 2011		258,306			67,939			22,195			32,220			32,924			5,800			419,384			760,238			1,438,710			282,100			893,966			3,414			90,427			3,468,855			997,527
Total proved reserves:
Balance December 31, 2008		514,764			155,745			114,406			76,535			187,915			31,779			1,081,144			2,537,182			2,203,361			1,370,978			1,253,545			5,585			546,374			7,917,025			2,400,648
Extensions, discoveries and other additions		17,642			1,839			41,104			3,574			6,056			4,865			75,080			150,668			340,278			2,142			174,883			252			50,714			718,937			194,903
Purchases of minerals in-place		13,023			—			—			—			—			—			13,023			47,782			35			—			—			—			—			47,817			20,993
Revisions of previous estimates		12,981			(4,504	)		(6,286	)		1,901			2			(173	)		3,921			(54,591	)		(107,205	)		(81,623	)		33			–			(2,395	)		(245,781	)		(37,043	)
Production		(34,773	)		(6,306	)		(33,631	)		(3,569	)		(22,259	)		(5,382	)		(105,920	)		(243,120	)		(131,121	)		(132,356	)		(67,020	)		(986	)		(67,364	)		(641,967	)		(212,915	)

Balance December 31, 2009		523,637			146,774			115,593			78,441			171,714			31,089			1,067,248			2,437,921			2,305,348			1,159,141			1,361,441			4,851			527,329			7,796,031			2,366,586
Extensions, discoveries and other additions		72,928			6,816			41,205			4,452			3,383			426			129,210			102,180			274,755			46,692			199,958			166			71,632			695,383			245,108
Purchases of minerals in-place		195,131			42,440			11,261			—			—			—			248,832			951,654			1,064,618			49,044			—			—			—			2,065,316			593,051
Revisions of previous estimates		7,597			(14,592	)		(4,723	)		—			—			379			(11,339	)		47,989			(8,211	)		(41,137	)		—			—			1,173			(186	)		(11,370	)
Production		(40,278	)		(6,375	)		(36,209	)		(16,757	)		(20,729	)		(4,795	)		(125,143	)		(266,759	)		(144,542	)		(136,823	)		(72,901	)		(873	)		(67,463	)		(689,361	)		(240,037	)
Sales of properties		—			(73	)		—			—			—			—			(73	)		—			(1	)		—			—			—			—			(1	)		(73	)

Balance December 31, 2010		759,015			174,990			127,127			66,136			154,368			27,099			1,308,735			3,272,985			3,491,967			1,076,917			1,488,498			4,144			532,671			9,867,182			2,953,265
Extensions, discoveries and other additions		89,591			22,602			45,039			15,762			404			5,014			178,412			169,506			505,049			77,049			148,640			475			81,274			981,993			342,078
Purchases of minerals in-place		5,683			752			—			—			43,803			—			50,238			67,595			8,838			—			—			104,658			—			181,091			80,420
Revisions of previous estimates		(7,191	)		(16,343	)		(6,185	)		—			—			232			(29,487	)		(7,716	)		(133,359	)		(37,623	)		—			—			1,107			(177,591	)		(59,086	)
Production		(51,658	)		(7,376	)		(37,946	)		(13,953	)		(19,908	)		(4,605	)		(135,446	)		(315,631	)		(230,880	)		(133,377	)		(67,554	)		(835	)		(77,493	)		(825,770	)		(273,074	)
Sales of properties		(1,393	)		(1,584	)		—			—			—			—			(2,977	)		(210,528	)		(94,104	)		—			—			—			—			(304,632	)		(53,749	)

Balance December 31, 2011		794,047			173,041			128,035			67,945			178,667			27,740			1,369,475			2,976,211			3,547,511			982,966			1,569,584			108,442			537,559			9,722,273			2,989,854

F-60

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

During 2011, Apache added 80 MMboe of estimated proved reserves through purchases of minerals in- place. The Company recorded 57 MMboe in connection with the acquisition of Mobil North Sea. Other individually insignificant acquisitions added 23 MMboe across several regions. During 2011, Apache also added 342 MMboe from extensions, discoveries and other additions. In the U.S., the Company recorded 54 MMboe primarily associated with drilling successes in the Permian Basin and 64 MMboe from various drilling programs in other U.S. regions. In Canada, additions of 107 MMboe were primarily a result of North East British Columbia drilling activity, including development of the Noel and Ojay fields acquired from BP in 2010. Egypt contributed 58 MMboe from exploration activity in the West Kalabsha and North East Abu Gharadig concessions along with extensions to waterfloods in the East Bahariya concession and development of the Razzak and Abu Gharadig fields acquired from BP in 2010. Australia additions of 41 MMboe were primarily from two discoveries in the Carnarvon basin offshore Western Australia. Various drilling programs in Argentina and North Sea regions combined to contribute 19 MMboe. During 2011 Apache divested 54 MMboe composed primarily of properties in Western Alberta and East Texas.

Approximately 17 percent of Apache’s year-end 2011 estimated proved developed reserves are classified as proved not producing. These reserves relate to zones that are either behind pipe, or that have been completed but not yet produced, or zones that have been produced in the past, but are not now producing because of mechanical reasons. These reserves are considered to be a lower tier of reserves than producing reserves because they are frequently based on volumetric calculations rather than performance data. Future production associated with behind pipe reserves is scheduled to follow depletion of the currently producing zones in the same wellbores. It should be noted that additional capital may have to be spent to access these reserves. The capital and economic impact of production timing are reflected in this Note 14, under “Future Net Cash Flows.”

Future Net Cash Flows

Future cash inflows as of December 31, 2011 and 2010 were calculated using an unweighted arithmetic average of oil and gas prices in effect on the first day of each month in the respective year, except where prices are defined by contractual arrangements. Operating costs, production and ad valorem taxes and future development costs are based on current costs with no escalation.

The following table sets forth unaudited information concerning future net cash flows for proved oil and gas reserves, net of income tax expense. Income tax expense has been computed using expected future tax rates and giving effect to tax deductions and credits available, under current laws, and which relate to oil and gas producing activities. This information does not purport to present the fair market value of the Company’s oil and gas assets, but does present a standardized disclosure concerning possible future net cash flows that would result under the assumptions used.


	United States			Canada			Egypt			Australia			North Sea			Argentina			Total
	(In millions)
2011
Cash inflows	$	85,041		$	27,727		$	17,092		$	20,579		$	19,012		$	3,082		$	172,533
Production costs		(25,379	)		(13,142	)		(2,467	)		(3,588	)		(8,810	)		(1,190	)		(54,576	)
Development costs		(6,493	)		(3,274	)		(1,909	)		(3,124	)		(3,003	)		(232	)		(18,035	)
Income tax expense		(15,351	)		(972	)		(4,565	)		(3,455	)		(4,453	)		(184	)		(28,980	)

Net cash flows		37,818			10,339			8,151			10,412			2,746			1,476			70,942
10 percent discount rate		(20,311	)		(4,956	)		(2,168	)		(6,624	)		(493	)		(443	)		(34,995	)

Discounted future net cash flows(1)	$	17,507		$	5,383		$	5,983		$	3,788		$	2,253		$	1,033		$	35,947

F-61

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	United States			Canada			Egypt			Australia			North Sea			Argentina			Total
	(In millions)

2010
Cash inflows	$	70,119		$	27,738		$	13,086		$	12,787		$	11,697		$	2,627		$	138,054
Production costs		(20,122	)		(12,207	)		(1,432	)		(2,808	)		(5,974	)		(968	)		(43,511	)
Development costs		(5,695	)		(2,736	)		(2,035	)		(2,288	)		(1,289	)		(182	)		(14,225	)
Income tax expense		(11,635	)		(1,464	)		(3,407	)		(2,213	)		(2,207	)		(177	)		(21,103	)

Net cash flows		32,667			11,331			6,212			5,478			2,227			1,300			59,215
10 percent discount rate		(17,289	)		(5,446	)		(1,744	)		(3,407	)		(532	)		(355	)		(28,773	)

Discounted future net cash flows(1)	$	15,378		$	5,885		$	4,468		$	2,071		$	1,695		$	945		$	30,442

(1)	Estimated future net cash flows before income tax expense, discounted at 10 percent per annum, totaled approximately $52.3 billion and $41.6 billion as of December 31, 2011 and 2010, respectively.

The following table sets forth the principal sources of change in the discounted future net cash flows:


	For the Year Ended December 31,
	2011			2010			2009
	(In millions)
Sales, net of production costs	$	(13,152	)	$	(9,152	)	$	(5,943	)
Net change in prices and production costs		12,167			13,006			7,650
Discoveries and improved recovery, net of related costs		6,751			5,147			1,718
Change in future development costs		(2,250	)		(1,637	)		(447	)
Previously estimated development costs incurred during the period		2,479			1,355			1,685
Revision of quantities		(1,475	)		(1,905	)		(1,258	)
Purchases of minerals in-place		2,139			7,794			530
Accretion of discount		4,161			2,439			1,054
Change in income taxes		(4,303	)		(4,535	)		823
Sales of properties		(1,285	)		(3	)		—
Change in production rates and other		273			182			(1,009	)

	$	5,505		$	12,691		$	4,803

F-62

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

15. SUPPLEMENTAL QUARTERLY FINANCIAL DATA (Unaudited)


	First		Second		Third		Fourth		Total
	(In millions, except per share amounts)
2011
Revenues and other	$	3,925	$	4,338	$	4,328	$	4,297	$	16,888
Expenses		2,791		3,079		3,326		3,108		12,304

Net income	$	1,134	$	1,259	$	1,002	$	1,189	$	4,584

Income attributable to common stock	$	1,115	$	1,240	$	983	$	1,170	$	4,508

Net income per common share(1):
Basic	$	2.91	$	3.23	$	2.56	$	3.05	$	11.75

Diluted	$	2.86	$	3.17	$	2.50	$	2.98	$	11.47

2010
Revenues and other	$	2,673	$	2,972	$	3,013	$	3,434	$	12,092
Expenses		1,968		2,112		2,235		2,745		9,060

Net income	$	705	$	860	$	778	$	689	$	3,032

Income attributable to common stock	$	705	$	860	$	765	$	670	$	3,000

Net income per common share(1):
Basic	$	2.09	$	2.55	$	2.14	$	1.79	$	8.53

Diluted	$	2.08	$	2.53	$	2.12	$	1.77	$	8.46

(1)	The sum of the individual quarterly net income per common share amounts may not agree with year-to-date net income per common share as each quarterly computation is based on the weighted-average number of common shares outstanding during that period.

16. SUPPLEMENTAL GUARANTOR INFORMATION

Rule 3-10 of SEC Regulation S-X (Rule 3-10) generally requires filing of financial statements by every issuer of a registered security with independent operations. Rule 3-10 also allows condensed consolidating financial statements in a footnote of the parent company financial statements as an alternative to filing separate financial statements, if the publicly-traded notes are fully and unconditionally guaranteed by the parent company. Issuers with no independent operations qualify as “finance subsidiaries” and are exempt from the reporting requirements. Apache Finance Canada does not qualify as a “finance subsidiary.”

Apache Finance Canada Corporation (Apache Finance Canada) issued approximately $300 million of publicly-traded notes due in 2029 and an additional $350 million of publicly-traded notes due in 2015 that are fully and unconditionally guaranteed by Apache. The following condensed consolidating financial statements are provided as an alternative to filing separate financial statements.

Apache Finance Canada has been fully consolidated in Apache’s consolidated financial statements. As such, the condensed consolidating financial statements should be read in conjunction with the financial statements of Apache Corporation and subsidiaries and notes thereto of which this note is an integral part.

F-63

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

For the Year Ended December 31, 2011


	Apache Corporation		Apache Finance Canada			All Other Subsidiaries of Apache Corporation			Reclassifications & Eliminations			Consolidated
	(In millions)
REVENUES AND OTHER:
Oil and gas production revenues	$	4,380	$	—		$	12,430		$	—		$	16,810
Equity in net income (loss) of affiliates		3,590		234			46			(3,870	)		—
Other		9		125			(52	)		(4	)		78

		7,979		359			12,424			(3,874	)		16,888


OPERATING EXPENSES:
Depreciation, depletion and amortization		1,257		—			2,947			—			4,204
Asset retirement obligation accretion		70		—			84			—			154
Lease operating expenses		794		—			1,811			—			2,605
Gathering and transportation		51		—			245			—			296
Taxes other than income		170		—			729			—			899
General and administrative		365		—			98			(4	)		459
Merger, acquisitions & transition		14		—			6			—			20
Financing costs, net		149		(18	)		27			—			158

		2,870		(18	)		5,947			(4	)		8,795


INCOME BEFORE INCOME TAXES		5,109		377			6,477			(3,870	)		8,093
Provision for income taxes		525		97			2,887			—			3,509

NET INCOME		4,584		280			3,590			(3,870	)		4,584
Preferred stock dividends		76		—			—			—			76

INCOME ATTRIBUTABLE TO COMMON STOCK	$	4,508	$	280		$	3,590		$	(3,870	)	$	4,508

F-64

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

For the Year Ended December 31, 2010


	Apache Corporation		Apache Finance Canada			All Other Subsidiaries of Apache Corporation			Reclassifications & Eliminations			Consolidated
	(In millions)
REVENUES AND OTHER:
Oil and gas production revenues	$	3,665	$	—		$	8,518		$	—		$	12,183
Equity in net income (loss) of affiliates		2,265		81			(7	)		(2,339	)		—
Other		27		(1	)		(113	)		(4	)		(91	)

		5,957		80			8,398			(2,343	)		12,092


OPERATING EXPENSES:
Depreciation, depletion and amortization		1,041		—			2,042			—			3,083
Asset retirement obligation accretion		57		—			54			—			111
Lease operating expenses		797		—			1,235			—			2,032
Gathering and transportation		42		—			136			—			178
Taxes other than income		140		—			550			—			690
General and administrative		273		—			111			(4	)		380
Merger, acquisitions & transition		183		—			—			—			183
Financing costs, net		158		(19	)		90			—			229

		2,691		(19	)		4,218			(4	)		6,886


INCOME BEFORE INCOME TAXES		3,266		99			4,180			(2,339	)		5,206
Provision for income taxes		234		25			1,915			—			2,174

NET INCOME		3,032		74			2,265			(2,339	)		3,032
Preferred stock dividends		32		—			—			—			32

INCOME ATTRIBUTABLE TO COMMON STOCK	$	3,000	$	74		$	2,265		$	(2,339	)	$	3,000

F-65

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

For the Year Ended December 31, 2009


	Apache Corporation			Apache Finance Canada			All Other Subsidiaries of Apache Corporation			Reclassifications & Eliminations			Consolidated
	(In millions)
REVENUES AND OTHER:
Oil and gas production revenues	$	2,770		$	—		$	5,804		$	—		$	8,574
Equity in net income (loss) of affiliates		235			(448	)		168			45			—
Other		(3	)		59			(11	)		(4	)		41

		3,002			(389	)		5,961			41			8,615

OPERATING EXPENSES:
Depreciation, depletion and amortization		2,097			—			3,116			—			5,213
Asset retirement obligation accretion		63			—			42			—			105
Lease operating expenses		691			—			971			—			1,662
Gathering and transportation		34			—			109			—			143
Taxes other than income		100			—			480			—			580
General and administrative		275			—			73			(4	)		344
Financing costs, net		228			(15	)		29			—			242

		3,488			(15	)		4,820			(4	)		8,289

INCOME (LOSS) BEFORE INCOME TAXES		(486	)		(374	)		1,141			45			326
Provision (benefit) for income taxes		(201	)		(93	)		905			—			611

NET INCOME		(285	)		(281	)		236			45			(285	)
Preferred stock dividends		7			—			—			—			7

INCOME ATTRIBUTABLE TO COMMON STOCK	$	(292	)	$	(281	)	$	236		$	45		$	(292	)

F-66

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

For the Year Ended December 31, 2011


	Apache Corporation			Apache Finance Canada			All Other Subsidiaries of Apache Corporation			Reclassifications & Eliminations			Consolidated
	(In millions)
CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	$	2,191		$	13		$	7,749		$	—		$	9,953

CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property		(1,478	)		—			(4,936	)		—			(6,414	)
Additions to gathering, transmission and processing facilities		—			—			(664	)		—			(664	)
Acquisition of Mobil North Sea		—			—			(1,246	)		—			(1,246	)
Acquisitions, other		(448	)		—			(119	)		—			(567	)
Proceeds from sale of oil and gas properties		204			—			218			—			422
Investment in and advances to subsidiaries, net		772			—			—			(772	)		—
Other, net		(81	)		—			(95	)		—			(176	)

NET CASH USED IN INVESTING ACTIVITIES		(1,031	)		—			(6,842	)		(772	)		(8,645	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Commercial paper, credit facility and bank notes, net		(927	)		—			2			—			(925	)
Intercompany borrowings		—			(1	)		(763	)		764			—
Dividends paid		(306	)		—			—			—			(306	)
Common stock activity		52			(7	)		(1	)		8			52
Other		56			—			(24	)		—			32

NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		(1,125	)		(8	)		(786	)		772			(1,147	)

NET INCREASE IN CASH AND CASH EQUIVALENTS		35			5			121			—			161
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR		6			—			128			—			134

CASH AND CASH EQUIVALENTS AT END OF YEAR	$	41		$	5		$	249		$	—		$	295

F-67

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

For the Year Ended December 31, 2010


	Apache Corporation			Apache Finance Canada			All Other Subsidiaries of Apache Corporation			Reclassifications & Eliminations			Consolidated
	(In millions)
CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	$	(1,848	)	$	(100	)	$	8,674		$	—		$	6,726

CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property		(1,552	)		—			(2,855	)		—			(4,407	)
Additions to gathering, transmission and processing facilities		(4	)		—			(511	)		—			(515	)
Acquisitions of Devon properties		(1,018	)		—			—			—			(1,018	)
Acquisitions of BP properties		—			—			(6,429	)		—			(6,429	)
Mariner Energy, Inc. merger		—			—			(787	)		—			(787	)
Acquisitions, other		—			—			(126	)		—			(126	)
Investment in and advances to subsidiaries, net		(2,853	)		—			—			2,853			—
Other, net		(72	)		—			(49	)		—			(121	)

NET CASH USED IN INVESTING ACTIVITIES		(5,499	)		—			(10,757	)		2,853			(13,403	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Commercial paper, credit facility and bank notes, net		928			—			(960	)		—			(32	)
Intercompany borrowings		—			2			2,720			(2,722	)		—
Fixed-rate debt borrowings		2,470			—			—			—			2,470
Payments on fixed-rate notes		—			—			(1,023	)		—			(1,023	)
Proceeds from issuance of common stock		2,258			—			—			—			2,258
Proceeds from issuance of mandatory convertible preferred stock		1,227			—			—			—			1,227
Dividends paid		(226	)		—			—			—			(226	)
Common stock activity		70			96			35			(131	)		70
Other		(21	)		—			40			—			19

NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		6,706			98			812			(2,853	)		4,763

NET INCREASE IN CASH AND CASH EQUIVALENTS		(641	)		(2	)		(1,271	)		—			(1,914	)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR		647			2			1,399			—			2,048

CASH AND CASH EQUIVALENTS AT END OF YEAR	$	6		$	—		$	128		$	—		$	134

F-68

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

For the Year Ended December 31, 2009


	Apache Corporation			Apache Finance Canada			All Other Subsidiaries of Apache Corporation			Reclassifications & Eliminations			Consolidated
							(In millions)
CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	$	1,857		$	(15	)	$	2,382		$	—		$	4,224

CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property		(1,008	)		—			(2,318	)		—			(3,326	)
Additions to gathering, transmission and processing facilities		—			—			(306	)		—			(306	)
Acquisitions, other		(196	)		—			(114	)		—			(310	)
Short-term investments		792			—			—			—			792
Restricted cash		14			—			—			—			14
Proceeds from sale of oil and gas properties		—			—			3			—			3
Investment in and advances to subsidiaries, net		(657	)		—			—			657			—
Other, net		(39	)		—			(75	)		—			(114	)

NET CASH USED IN INVESTING ACTIVITIES		(1,094	)		—			(2,810	)		657			(3,247	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Commercial paper, credit facility and bank notes, net		1			(3	)		903			(653	)		248
Payments on fixed-rate notes		—			—			(100	)		—			(100	)
Dividends paid		(209	)		—			—			—			(209	)
Common stock activity		28			18			(14	)		(4	)		28
Redemption of preferred stock		(98	)		—			—			—			(98	)
Other		20			—			1			—			21

NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		(258	)		15			790			(657	)		(110	)

NET INCREASE IN CASH AND CASH EQUIVALENTS		505			—			362			—			867
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR		142			2			1,037			—			1,181

CASH AND CASH EQUIVALENTS AT END OF YEAR	$	647		$	2		$	1,399		$	—		$	2,048

F-69

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

CONDENSED CONSOLIDATING BALANCE SHEET

December 31, 2011


	Apache Corporation		Apache Finance Canada		All Other Subsidiaries of Apache Corporation			Reclassifications & Eliminations			Consolidated
					(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	41	$	5	$	249		$	—		$	295
Receivables, net of allowance		773		—		2,306			—			3,079
Inventories		51		—		604			—			655
Drilling advances		11		—		218			—			229
Derivative instruments		113		—		191			—			304
Prepaid assets and other		3,859		—		(3,618	)		—			241

		4,848		5		(50	)		—			4,803

PROPERTY AND EQUIPMENT, NET		12,262		—		33,186			—			45,448

OTHER ASSETS:
Intercompany receivable, net		3,931		—		(1,908	)		(2,023	)		—
Equity in affiliates		20,214		1,372		99			(21,685	)		—
Goodwill, net		—		—		1,114			—			1,114
Deferred charges and other		158		1,002		526			(1,000	)		686

	$	41,413	$	2,379	$	32,967		$	(24,708	)	$	52,051

LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	609	$	1	$	2,461		$	(2,023	)	$	1,048
Accrued liabilities		468		—		2,180			—			2,648
Current debt		400		—		31			—			431
Asset retirement obligation		434		—		13			—			447
Derivative instruments		76		—		37			—			113
Other		146		5		125			—			276

		2,133		6		4,847			(2,023	)		4,963

LONG-TERM DEBT		6,137		647		1			—			6,785

DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes		2,622		5		4,570			—			7,197
Asset retirement obligation		936		—		2,504			—			3,440
Other		592		250		831			(1,000	)		673

		4,150		255		7,905			(1,000	)		11,310

COMMITMENTS AND CONTINGENCIES
SHAREHOLDERS’ EQUITY		28,993		1,471		20,214			(21,685	)		28,993

	$	41,413	$	2,379	$	32,967		$	(24,708	)	$	52,051

F-70

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

CONDENSED CONSOLIDATING BALANCE SHEET

December 31, 2010


	Apache Corporation		Apache Finance Canada		All Other Subsidiaries of Apache Corporation			Reclassifications & Eliminations			Consolidated
	(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	6	$	—	$	128		$	—		$	134
Receivables, net of allowance		691		—		1,443			—			2,134
Inventories		55		—		509			—			564
Drilling advances		10		2		247			—			259
Derivative instruments		31		—		136			—			167
Prepaid assets and other		3,282		—		(3,060	)		—			222

		4,075		2		(597	)		—			3,480

PROPERTY AND EQUIPMENT, NET		11,314		—		26,837			—			38,151

OTHER ASSETS:
Intercompany receivable, net		4,695		—		(3,149	)		(1,546	)		—
Equity in affiliates		16,649		1,275		98			(18,022	)		—
Goodwill, net		—		—		1,032			—			1,032
Deferred charges and other		178		1,003		581			(1,000	)		762

	$	36,911	$	2,280	$	24,802		$	(20,568	)	$	43,425

LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	480	$	2	$	1,843		$	(1,546	)	$	779
Accrued liabilities		535		—		1,281			—			1,816
Current debt		16		—		30			—			46
Asset retirement obligation		317		—		90			—			407
Derivative instruments		153		—		41			—			194
Other		139		3		140			—			282

		1,640		5		3,425			(1,546	)		3,524

LONG-TERM DEBT		7,447		647		1			—			8,095

DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes		1,803		5		2,441			—			4,249
Asset retirement obligation		1,001		—		1,464			—			2,465
Other		643		250		822			(1,000	)		715

		3,447		255		4,727			(1,000	)		7,429

COMMITMENTS AND CONTINGENCIES
SHAREHOLDERS’ EQUITY		24,377		1,373		16,649			(18,022	)		24,377

	$	36,911	$	2,280	$	24,802		$	(20,568	)	$	43,425

F-71


Board of Directors		Officers

G. Steven Farris(1)		G. Steven Farris
Chairman and Chief Executive Officer,		Chairman and Chief Executive Officer
Apache Corporation
		Roger B. Plank
Randolph M. Ferlic, M.D.(1)(2)		President and Chief Corporate Officer
Founder and Former President,
Surgical Services of the Great Plains, P.C.		Rodney J. Eichler
		President and Chief Operating Officer
Eugene C. Fiedorek(2)
Private Investor, Co-Founder and Former President		Michael S. Bahorich
and Managing Director,		Executive Vice President and Chief
EnCap Investments L.C.		Technology Officer
		Thomas P. Chambers
A.D. Frazier, Jr.(3)(5)		Executive Vice President and Chief Financial Officer
President, Georgia Oak Partners
		Margery M. Harris
Patricia Albjerg Graham(4)		Executive Vice President — Human Resources
Charles Warren Professor of the
History of Education Emerita,		Jon A. Jeppesen
Harvard University		Executive Vice President — Gulf of Mexico Regions
Scott D. Josey(1)		P. Anthony Lannie
Private Investor, Former Chairman		Executive Vice President and General Counsel
and Chief Executive Officer
Mariner Energy, Inc.		W. Kregg Olson
		Executive Vice President — Corporate Reservoir Engineering
Chansoo Joung(2)(4)
Senior Advisor and Former Partner,		Matthew W. Dundrea
Warburg Pincus LLC		Senior Vice President — Treasury and Administration
John A. Kocur(1)(3)(4)
Attorney at Law; Former Vice Chairman of the Board,		Robert J. Dye
Apache Corporation		Senior Vice President — Global Communication and
		Corporate Affairs
George D. Lawrence(1)(3)
Private Investor; Former Chief Executive Officer,		Janine J. McArdle
The Phoenix Resource Companies, Inc.		Senior Vice President — Gas Monetization

William C. Montgomery(3)(5)		Sarah B. Teslik
Managing Director, Quantum Energy Partners		Senior Vice President — Policy and Governance

Rodman D. Patton(2)		John R. Bedingfield
Former Managing Director,		Vice President — Worldwide Exploration and New Ventures
Merrill Lynch Energy Group
		David L. French
Charles J. Pitman(4)(5)		Vice President — Business Development
Former Regional President — Middle East/
Caspian/Egypt/India, BP Amoco plc		Jon A. Graham
		Vice President — Environmental, Health and Safety

		Rodney A. Gryder
		Vice President — Audit

		Rebecca A. Hoyt
		Vice President, Chief Accounting Officer and Controller

		Alfonso Leon
		Vice President — Planning and Strategy

		Aaron S. G. Merrick
		Vice President — Information Technology

		Urban F. O’Brien
		Vice President — Government Affairs

		Jon W. Sauer Vice President — Tax

		Cheri L. Peper Corporate Secretary

(1)	Executive Committee

(2)	Audit Committee

(3)	Management Development and Compensation Committee

(4)	Corporate Governance and Nominating Committee

(5)	Stock Plan Committee

Shareholder Information

Stock Data


	Price Range				Dividends per Share
	High		Low		Declared		Paid
2011
First Quarter	$	132.50	$	110.29	$	0.15	$	0.15
Second Quarter		134.13		114.94		0.15		0.15
Third Quarter		129.26		80.05		0.15		0.15
Fourth Quarter		105.64		73.04		0.15		0.15
2010
First Quarter	$	108.92	$	95.15	$	0.15	$	0.15
Second Quarter		111.00		83.55		0.15		0.15
Third Quarter		99.09		81.94		0.15		0.15
Fourth Quarter		120.80		96.51		0.15		0.15

The Company has paid cash dividends on its common stock for 47 consecutive years through December 31, 2011. Future dividend payments will depend upon the Company’s level of earnings, financial requirements and other relevant factors.

Apache common stock is listed on the New York and Chicago stock exchanges and the NASDAQ National Market (symbol APA). At December 31, 2011, the Company’s shares of common stock outstanding were held by approximately 5,600 shareholders of record and 444,000 beneficial owners. Also listed on the New York Stock Exchange are:

•

Apache Depositary Shares (symbol APA/PD), each representing a 1/20th interest in Apache’s 6% Mandatory Convertible Preferred Stock, Series D

•

Apache Finance Canada’s 7.75% notes, due 2029 (symbol APA/29)

Corporate Offices

One Post Oak Central

2000 Post Oak Boulevard

Suite 100

Houston, Texas 77056-4400

(713) 296-6000

Independent Public Accountants

Ernst & Young LLP

Five Houston Center

1401 McKinney Street, Suite 1200

Houston, Texas 77010-2007

Stock Transfer Agent and Registrar

Wells Fargo Bank, N.A.

Attn: Shareowner Services

P.O. Box 64854

South St. Paul, Minnesota 55164-0854

(651) 450-4064 or (800) 468-9716

Communications concerning the transfer of shares, lost certificates, dividend checks, duplicate mailings, or change of address should be directed to the stock transfer agent. Shareholders can access account information on the web site: www.shareowneronline.com

Dividend Reinvestment Plan

Shareholders of record may invest their dividends automatically in additional shares of Apache common stock at the market price. Participants may also invest up to an additional $25,000 in Apache shares each quarter through this service. All bank service fees and brokerage commissions on purchases are paid by Apache. A prospectus describing the terms of the Plan and an authorization form may be obtained from the Company’s stock transfer agent, Wells Fargo Bank, N.A.

Direct Registration

Shareholders of record may hold their shares of Apache common stock in book-entry form. This eliminates costs related to safekeeping or replacing paper stock certificates. In addition, shareholders of record may request electronic movement of book-entry shares between your account with the Company’s stock transfer agent and your broker. Stock certificates may be converted to book-entry shares at any time. Questions regarding this service may be directed to the Company’s stock transfer agent, Wells Fargo Bank, N.A.

Annual Meeting

Apache will hold its annual meeting of shareholders on Thursday, May 24, 2012, at 10:00 a.m. in the Ballroom, Hilton Houston Post Oak, 2001 Post Oak Boulevard, Houston, Texas. Apache plans to web cast the annual meeting live; connect through the Apache web site: www.apachecorp.com

Stock Held in “Street Name”

The Company maintains a direct mailing list to ensure that shareholders with stock held in brokerage accounts receive information on a timely basis. Shareholders wanting to be added to this list should direct their requests to Apache’s Public and International Affairs Department, 2000 Post Oak Boulevard, Suite 100, Houston, Texas, 77056-4400, by calling (713) 296-6157 or by registering on Apache’s web site: www.apachecorp.com

Form 10-K Request

Shareholders and other persons interested in obtaining, without cost, a copy of the Company’s Form 10-K filed with the Securities and Exchange Commission may do so by writing to Cheri L. Peper, Corporate Secretary, 2000 Post Oak Boulevard, Suite 100, Houston, Texas, 77056-4400.

Investor Relations

Shareholders, brokers, securities analysts, or portfolio managers seeking information about the Company are welcome to contact Patrick Cassidy, Investor Relations Director, at (713) 296-6100.

Members of the news media and others seeking information about the Company should contact Apache’s Public and International Affairs Department at (713) 296-7276.

Web site: www.apachecorp.com