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, 2012

or

[    ] 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 1/20th 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, 2012	$	34,382,410,237
Number of shares of registrant’s common stock outstanding as of January 31, 2013		391,758,883

Documents Incorporated By Reference

Portions of registrant’s proxy statement relating to registrant’s 2013 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		21
1B.	UNRESOLVED STAFF COMMENTS		32
2.	PROPERTIES		1
3.	LEGAL PROCEEDINGS		32
4.	MINE SAFETY DISCLOSURES		32
	PART II
5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES		33
6.	SELECTED FINANCIAL DATA		35
7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		36
7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		66
8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA		69
9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE		69
9A.	CONTROLS AND PROCEDURES		69
9B.	OTHER INFORMATION		69
	PART III
10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE		70
11.	EXECUTIVE COMPENSATION		70
12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS		70
13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE		70
14.	PRINCIPAL ACCOUNTING FEES AND SERVICES		70
	PART IV
15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES		71

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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.

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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, the U.K. 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 June 7, 2012, 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 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. Information on our website or any other website is not incorporated by reference into, and does not constitute a part of, this Annual Report on Form 10-K.

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

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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 27 years and production 32 out of the past 34 years, a testament to our consistency over the long-term.

Apache pursues opportunities for growth through exploration and development drilling, supplemented by occasional strategic acquisitions. After a three-year period of significant portfolio expansion through acquisitions, we have shifted our focus back to developing our enlarged property base. In 2012, we generated approximately $8.5 billion of cash flows from operating activities, which enabled us to have an active drilling and development program across all of our regions. As a result, we reported record production of 779 Mboe/d, up over four percent from the prior year. At the same time, we have also invested a larger portion of our capital budget on long-lead time projects than we have in the past. In 2012, we spent approximately one-quarter of our capital budget on purchasing additional leasehold acreage, obtaining seismic data, building infrastructure, and proceeding on long-lead development projects including LNG facilities. Coupled with an active drilling program and our new venture exploration efforts, these longer-term investments secure a platform for future profitable growth.

While we are focused on growth through the drill bit, we also seek acquisition opportunities that meet our criteria for risk, reward, rate of return, and growth potential. From April 2010 through the end of 2012, Apache announced several significant acquisitions, each of which fit well with our long-term growth strategy. These properties are strategically positioned with our existing infrastructure and play to the strengths that come with our operating experience. Our significant acquisitions and other transactions since 2010 are described below.

2012 Transactions

Chevron Kitimat transaction    On December 24, 2012, Chevron Canada Limited (Chevron Canada) and Apache Canada Ltd. (Apache Canada) entered into an agreement to build and operate the Kitimat LNG project. Pursuant to the agreement, each will become a 50-percent owner of the proposed Kitimat LNG plant, the Pacific Trail Pipeline, and 644,000 gross undeveloped acres in the Horn River and Liard basins. Chevron Canada will operate the LNG plant, which will be located on the northern British Columbia coast, and the pipeline; Apache Canada will operate Horn River and Liard. The transaction closed on February 8, 2013.

Central Anadarko basin acquisition    In April 2012 Apache completed the acquisition of Cordillera Energy Partners III, LLC (Cordillera), a privately held company, for $2.7 billion in cash and approximately 6.3 million shares of Apache common stock.

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

2011 Transactions

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 Transactions

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.

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.

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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.

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.

For a more in-depth discussion of our growth strategy, 2012 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, the U.K. 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 table sets out a brief comparative summary of certain key 2012 data for each of our operating areas. Additional data and discussion is provided in Part II, Item 7 of this Form 10-K.

	2012 Production		Percentage of Total 2012 Production		2012 Production Revenue		12/31/12 Estimated Proved Reserves		Percentage of Total Estimated Proved Reserves		2012 Gross Wells Drilled		2012 Gross Productive Wells Drilled
	(In MMboe)				(In millions)		(In MMboe)
United States		113.5		40%	$	6,226		1,424		50%		1,052		1,035
Canada		44.7		16		1,322		541		19		169		145
Total North America		158.2		56		7,548		1,965		69		1,221		1,180
Egypt		58.1		20		4,554		273		10		198		174
Australia		23.6		8		1,575		342		12		15		8
North Sea		27.4		10		2,751		170		6		21		16
Argentina		17.7		6		519		102		3		30		30
Other International		—		—		—		—		—		1		—
Total International		126.8		44		9,399		887		31		265		228
Total		285.0		100%	$	16,947		2,852		100%		1,486		1,408

North America

Apache’s North American asset base primarily comprises operations in the central U.S., the Permian Basin, the Gulf Coast onshore and offshore areas of the U.S., and operations in Western Canada. In 2012, our North America assets contributed 56 percent of our production and 45 percent of our oil and gas production revenues. At year-end 2012, 69 percent of our estimated proved reserves were located in North America.

United States

Overview    We have 12.3 million gross acres across the U.S., approximately 60 percent of which is undeveloped. After expanding our portfolio over the last three years, we now hold leading positions in many attractive basins and plays within the United States. To focus our development efforts in the U.S., we have divided our assets into five distinct regions: Central, Permian, Gulf of Mexico Shelf, Gulf of Mexico Deepwater, and Gulf Coast Onshore. We also have leasehold acreage holdings in Alaska and other states where we are

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pursuing exploration opportunities. Our holdings in the U.S. provide a balance of hydrocarbon mix and reserve life and an opportunity for continued exploration. In 2012, 54 percent of our U.S. production and 63 percent of our U.S. year-end estimated proved reserves were oil and liquids. In addition, the reserve life of our U.S. regions ranged from 6 to 20 years with the Gulf of Mexico offshore region’s shorter-lived reserves balancing longer-lived reserves in the Central and Permian regions. In 2012, 40 percent of Apache’s equivalent production and 50 percent of Apache’s total year-end estimated proved reserves were in the U.S.

Central Region    The Central region includes more than 3,500 producing wells primarily in western Oklahoma and the Texas panhandle and controls nearly 1.9 million gross acres. The region is Apache’s first core area dating back over half a century and has historically grown through low-risk, highly predictable natural gas exploitation. Over the last three years, however, a transformation from vertical to horizontal drilling and continued price disparity between crude oil and natural gas have evolved the region from one targeting natural gas to one now targeting oil and liquids-rich gas plays. This focus resulted in liquids production growth of over 115 percent during 2011. Oil and liquids production further expanded during 2012, with oil production more than doubling and NGL production almost tripling compared to the prior year. Total region production was up 37 percent in 2012. The Central region contributed 8 percent of Apache’s 2012 equivalent production and 9 percent of total year-end proved reserves.

The primary driver of the region’s growth was an active exploration and development program where we drilled or participated in drilling 192 wells during 2012, 99 percent of which were completed as producers. A significant focus of our drilling program has been in the Anadarko basin’s Granite Wash play. The Granite Wash consists of a series of thick, multi-layered formations of low-permeability and liquids-rich sandstones. The Company’s significant acreage position in the play has generated an active drilling plan for the next several years across numerous formations, notably the Tonkawa, Marmaton, Cottage Grove, and Cleveland.

We have also been drilling Canyon Wash wells on approximately 92,000 net acres in the Whittenburg basin. During the year, we drilled and completed seven successful wells in the Canyon Wash, which averaged 30-day gross rates of approximately 675 b/d and 500 Mcf/d. These tests are an encouraging validation of this play, given the results are from vertically drilled wells.

Our drilling momentum in the Central region was further bolstered in April when the Company completed the acquisition of Cordillera, a privately held company with approximately 312,000 net acres in the heart of the Anadarko basin, nearly 18 Mboe/d of production, and estimated proved reserves of 70 MMboe. The acquisition doubled Apache’s acreage in the Granite Wash area and added a robust drilling inventory that was immediately integrated into our existing program.

The region operated an average of 18 drilling rigs during 2012 and, with a growing portfolio of drilling opportunities, plans to run an average of 29 rigs during 2013. We expect to invest approximately $1.4 billion in 2013 for drilling, recompletions, equipment upgrades, and production enhancement projects. The region will also invest in facility and transportation projects to increase takeaway capacity.

Permian Region    Our Permian region controls over 3.5 million gross acres with exposure across every major play in the Permian Basin. The region’s property and acreage base has increased substantially over the last three years through an active acquisition effort. Apache is now one of the largest operators in the Permian Basin, operating more than 12,000 wells in 152 fields, including 47 waterfloods and 7 active CO2 floods, including the Roberts Unit, which initiated CO2 injection in January 2013. In 2012, liquids production in the region was up 25 percent, contributing to a total sequential production increase of over 18 percent as a result of an active drilling program that is continuing to ramp up. We averaged running 32 rigs during the year, drilling or participating in 781 wells, and plan to run 34 rigs in 2013. The Permian region’s year-end 2012 estimated proved reserves were 800 MMboe and represented 28 percent of Apache’s total proved reserves.

A key focus area of our activity during the year continued to be the multi-zone development of the Deadwood area. Deadwood is the most active of our plays in the Midland basin, where we ran an average of

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16 rigs and drilled 317 wells. Specifically, the region is primarily drilling vertical wells targeting the Wolfwood and the Fusselman zones. With additional 3-D seismic data recently acquired, our ability to target other prolific accumulations and new drilling locations has been enhanced.

The region is also building a large inventory of horizontal drilling opportunities based on success achieved over 2012, having drilled or participated in drilling 104 horizontal wells during the period. Two horizontal plays in the Midland Basin, the Wolfcamp and Cline shales, have been drilled and commercialized with multi-rig development programs moving forward. Also in the Midland Basin, we recently drilled and completed oil-producing wells in the Barnett and Deadwood shales focusing on the future potential across our large acreage position. New horizontal plays in the Mississippian Lime and Clearfork shales are planned for 2013. We recently commenced horizontal well programs in the Yeso area of New Mexico as well as in the Bone Spring and Wolfcamp plays in Texas. We also continue to achieve positive results in the Central basin with horizontal redevelopment of historically conventional fields and reservoirs. We expect to conduct greater horizontal drilling into 2013, when we project that nearly half of our rigs will be drilling horizontal wells by year-end.

Our active drilling program has resulted in production growth for the past eight sequential quarters, rising 37 percent over the past two years. Given a current inventory of over 34,000 locations, the region has a deep portfolio of drilling opportunities for multiple years. For 2013, the Permian region plans to invest approximately $2.4 billion in drilling, recompletion projects, equipment upgrades, expansion of existing facilities and equipment, and leasing activities.

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. The area is divided into three regions, which include the Gulf of Mexico Shelf, Gulf of Mexico Deepwater, and Gulf Coast Onshore.

In water depths less than 500 feet, 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, holding approximately three million gross acres. The region contributed 12 percent of our worldwide production and revenue during 2012. 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. During 2012 the region drilled or participated in 36 wells with an 80-percent success rate, consistent with activity levels of the prior two years. In June 2012, the region also participated in the federal lease sale where we were awarded 60 blocks, opening up additional exploration and development opportunities.

In water depths greater than 500 feet, 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 was extended through our participation in the June 2012 federal lease sale where we were awarded 28 new leases. The Company now owns approximately 900,000 gross acres across 166 blocks as of the end of 2012. The Deepwater region contributed only 2 percent of Apache’s worldwide production in 2012; however, there are several large projects and developments underway that could spur significant growth. The non-operated Lucius project, where Apache holds an 11.7-percent working interest, is currently under development with first production projected for 2014. In addition, the large-scale non-operated Heidelberg project continues to move forward. Apache has a 12.5-percent working interest in this development with first production projected for 2016. The region also continues to increase its exploration activity. After drilling two wells in 2011, we drilled five wells in 2012 with a 60-percent success rate. Seven wells are planned for drilling in the areas in which we hold an interest during 2013.

Apache’s Gulf Coast Onshore region includes mature onshore and near-shore basins of Texas, Louisiana, and Mississippi, where it has a significant acreage position of approximately 1.4 million gross acres, including 330,000 mineral fee acres. With advancements in modern seismic imaging, horizontal drilling and completion technologies, additional opportunities continue to evolve. During the year, the region focused on drilling shallow and moderate-depth targets, increasing acreage holdings, and expanding regional 3-D seismic databases. In

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addition, the region continued evaluating several unconventional resource plays and deeper exploitation opportunities. The region drilled or participated in drilling 35 wells during 2012 and plans to drill or participate in approximately 39 wells in 2013.

In 2013, Apache plans to invest approximately $700 million, $400 million, and $250 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, and seismic and lease activities. The Company spent $435 million on abandonment activities in 2012 over the entire Gulf Coast area and expects similar activity levels in 2013.

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 customer 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. Our 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    Since entering the Canadian market in 1995, Apache has continued to increase its presence in the region and now holds approximately seven million gross acres across the provinces of British Columbia, Alberta, and Saskatchewan. The region’s large acreage position provides portfolio diversification as well as significant drilling opportunity. Canada represented approximately 19 percent of Apache’s worldwide proved reserves at year-end 2012 and approximately 16 percent of 2012 worldwide production.

In 2012, Apache drilled or participated in drilling 169 wells in Canada, with a continued focus on increasing oil and liquids-rich gas production. Reservoir modeling and state-of-the-art horizontal drilling technology advanced several oil plays in the Viking, Glauconite, Dunvegan, and Sparky formations, and success with multi-stage fracture completions continues to increase the scope of oil and liquids-rich gas drilling opportunities.

Future natural gas drilling activity will be driven by market prices and the Kitimat LNG project. In December 2012, Apache announced an agreement with Chevron Canada to build and operate the Kitimat LNG project and develop shale gas resources at the Liard and Horn River basins in British Columbia. Chevron Canada and Apache Canada will each hold a 50-percent interest in the Kitimat LNG plant, the Pacific Trail Pipeline, and approximately 644,000 gross undeveloped acres in the Horn River and Liard basins. Chevron Canada will operate the LNG plant and pipeline, and Apache Canada will operate Horn River and Liard. The Kitimat plant has received all significant environmental approvals and a 20-year export license from the Canadian federal government. Although the project has not reached a final investment decision, we believe Chevron’s experience in developing LNG projects and marketing expertise will assist in moving the development forward. The transaction was completed on February 8, 2013.

In 2013, the region plans to invest approximately $680 million in drilling and development projects, equipment upgrades, production enhancement projects, seismic acquisition, and Kitimat project development. Drilling in 2013 will continue to focus on conventional oil and liquids-rich gas plays.

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Marketing    Our Canadian natural gas marketing activities focus on sales to utilities, end-users, integrated major oil companies, supply aggregators, and marketers. We maintain a diverse client portfolio, which is intended to reduce the concentration of credit risk in our portfolio. To diversify our market exposure, we transport natural gas via firm transportation contracts to export border points for delivery into Washington, 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 AECO index 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 on pipeline or truck within Western Canada to the market hubs in Alberta and Manitoba where it is sold, allowing 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 2012, international assets contributed 44 percent of our production and 55 percent of our oil and gas revenues. At year-end 2012, 31 percent of our estimated proved reserves were located outside North America.

Egypt

Overview    Our activity in 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 213 Mb/d and 900 MMcf/d in 2012, or 100 Mb/d and 354 MMcf/d net to Apache. The remaining 82 percent of our acreage is undeveloped, providing us with considerable exploration and development opportunities for the future. In 2012, the region contributed 27 percent of Apache’s worldwide production revenue, 20 percent of our worldwide production, and 10 percent of our year-end 2012 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 23 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.

Historically, growth in Egypt has been driven by an ongoing drilling program, and we are one of the most active drillers in the region. Throughout 2012, we averaged running 25 rigs and drilled 188 development and injection wells and 51 exploration wells. Approximately 55 percent of our exploration wells were successful, further expanding our presence in the westernmost concessions and unlocking additional opportunities in existing plays. A key component of the region’s success has been our ability to acquire and evaluate 3-D seismic surveys that enable the region’s technical teams to consistently high-grade existing prospects and identify new targets across multiple pay horizons in the Cretaceous, Jurassic, and deeper Paleozoic reservoirs.

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Heading into 2013, the region will continue an active drilling program and plans to invest approximately $1.1 billion for drilling, recompletion projects, development projects, and seismic acquisition. There are also several key infrastructure projects underway that will focus on maintaining gas deliverability and bringing additional liquids to market.

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, plus an upward adjustment for liquids content. Apache previously 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 $3.90 per Mcf in 2012.

Oil from the Khalda Concession, the Qarun Concession, and other nearby Western Desert blocks is sold to third parties in the Mediterranean market or to EGPC when called upon to supply domestic demand. Oil sales are 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.

Egypt political unrest    In February 2011, former Egyptian president Hosni Mubarak stepped down, and the Egyptian Supreme Council of the Armed Forces took power, announcing that it would remain in power until the presidential and parliamentary elections could be held. In June 2012, Mohamed Morsi of the Muslim Brotherhood’s Freedom and Justice Party was elected as Egypt’s new president. In December 2012 the people of Egypt ratified a new constitution. Under the new constitution, the government must hold elections for the lower house of parliament within 60 days. Apache’s operations, located in remote locations in the Western Desert, have not experienced production interruptions, and we have continued to receive development lease approvals for our drilling program. 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 a portion of its investments in Egypt. In the aggregate, these insurance 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 $263 million sub-limit for currency inconvertibility.

In addition, the Company has a separate policy with OPIC, which provides $300 million of coverage 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 in the event that actions taken by the government of Egypt prevent Apache from exporting our share of production. In October 2012, the Multilateral Investment Guarantee Agency (MIGA), a member of the World Bank Group, announced that it was providing $150 million in reinsurance to OPIC for the remainder of the policy term. This provision of long-term reinsurance to OPIC will allow Apache to maintain the $300 million of insurance coverage through 2024.

Australia

Overview    Apache’s holdings in Australia are focused offshore Western Australia in the Carnarvon, Exmouth, and Browse basins. We have operated in the Carnarvon basin since acquiring the gas processing facilities on Varanus Island and adjacent producing properties in 1993. Production operations are located in the Carnarvon and Exmouth basins. In total, we control approximately 7.9 million gross acres offshore Western Australia through 30 exploration permits, 17 production licenses, and 13 retention leases. Approximately 90 percent of our acreage is undeveloped, and the region continues to actively pursue additional acreage opportunities.

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During 2012, the region had net production of 29 Mb/d of oil and 214 MMcf/d of natural gas, contributing 9 percent of Apache’s worldwide production revenue, 8 percent of worldwide production and 12 percent of year-end estimated proved reserves. Production compared to the prior year was 7 percent lower primarily as a result of natural decline in the Pyrenees and Van Gogh oil fields. Offsetting production declines was a full year of production from the Reindeer field. This gas is processed through the Devil Creek Gas Plant, which came online in December 2011. 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 prior year realizations.

The region is a key component of Apache’s exploration program. During 2012, we participated in drilling 15 offshore wells, of which 10 were exploration or appraisal wells. This compares to nine wells drilled in 2011. Over the past decade, the region’s exploration activity has established a significant pipeline of projects that are expected to contribute to production growth as they are brought onstream in the coming years.

First production is projected in 2013 from four completed gas wells in the Macedon gas field. Gas will be delivered via a 60-mile pipeline to a 200 MMcf/d gas plant being built at Ashburton North in Western Australia. Apache has successfully marketed nearly all of its proved reserves in the Macedon field under long-term contracts at prices significantly higher than current realizations. We have a 29-percent non-operating working interest in the field and gas plant.

Development of the Coniston oil field project, which lies just north of the Van Gogh field, continued toward projected first production in 2014. The field will be produced via subsea completions tied back to the Floating Production Storage and Offloading Vessel (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. To accommodate production from Coniston, the FPSO is scheduled to go offline to the shipyard in early 2014 to complete required modifications.

The region will also continue 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.

Further advances were made on the region’s largest development effort, which is the Chevron-operated Wheatstone LNG 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 the end of 2016.

These development projects require significant capital investments above those for traditional drilling programs. During 2013, the region plans to invest approximately $1.9 billion for drilling, recompletion projects, development projects, equipment upgrades, production enhancement projects, and seismic acquisition. Approximately $1.5 billion of our 2013 capital will be invested in long-lead development projects.

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, 2012, Apache had 21 active gas contracts in Australia with expiration dates ranging from

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July 2014 to December 2026. 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 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 crude sold at West Texas Intermediate (WTI)-based prices.

During 2011, advances were made on Wheatstone, with binding Sales and Purchase Agreements signed by two Asian customers for the delivery of approximately 60 percent of Apache’s net LNG offtake. In 2012, further advances were made on the Wheatstone project with the signing of two non-binding Heads of Agreements, which will take the total committed delivery volumes to over 80 percent once the final binding Sales and Purchase Agreements are signed. These binding Sales and Purchase Agreements are expected to be finalized and signed in 2013.

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. This success spurred last year’s Mobil North Sea Limited (Mobil North Sea) acquisition, which provided the region with additional exploration and development opportunities across numerous fields, including operated interests in the Beryl, Nevis, Nevis South, Skene, and Buckland fields and non-operated interests in the Maclure, Scott, and Telford fields. During 2012, we also announced that the U.K. Department of Energy & Climate Change awarded the region 11 new operated licenses and 1 non-operated license, which together added approximately 613,000 gross acres to the region’s portfolio. Included in these licenses is all of the available acreage adjacent to the Beryl field plus two key licenses near the Forties field.

In 2012, the North Sea region produced 64 Mb/d of oil and 57 MMcf/d of natural gas, contributing 16 percent of Apache’s worldwide production revenue, 10 percent of worldwide production and 6 percent of year-end estimated proved reserves. The region’s production was 36 percent higher compared to the prior year on production from the recently acquired Beryl assets and an active drilling program in both the Forties and Beryl fields. Drilling in the Forties field continued to benefit from extensive 4-D seismic interpretations obtained over the last two years and has targeted many areas of bypassed oil in the mature reservoir. A 3-D seismic survey of the Beryl field commenced in early August and, when completed, will further refine our drilling plans for these acquired assets. In 2012, 21 wells were drilled in the North Sea, of which 16 were productive. Two of the highest producing wells were the Beryl B72 well, which commenced production in May at a rate of 11.6 Mb/d and 13.1 MMcf/d, and the Beryl B73 well, which was completed in September with an initial rate of 8.2 Mb/d and 5.9 MMcf/d. Apache has a 55-percent net interest in the Beryl field as of year-end.

The region also made notable progress in several key development projects during the year. In April, production from the first Bacchus field well commenced at a peak rate of 6 Mb/d; in July, a second horizontal well was brought online at a peak rate of 9 Mb/d. Combined production from the two wells has been steady at 10 Mb/d since July. Apache’s net interest is 50 percent. In September, the jacket for the Forties Alpha Satellite Platform was installed, with a topside and bridge scheduled to be delivered during the second quarter of 2013. This platform has been constructed to continue to exploit new opportunities at Forties and sits adjacent to the main Alpha platform. It will provide an additional 18 drilling slots beginning in the third quarter of 2013 along with power generation, fluid separation, gas lift compression, and oil export pumping.

In 2013, the region plans to invest approximately $900 million on a diverse set of capital projects. The region will continue to refine drilling programs associated with properties acquired in the Mobil North Sea acquisition and integrate the additional opportunities gained over the last year.

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Marketing    We have traditionally sold our North Sea crude oil under both term contracts and spot cargoes. The term sales are composed of a market-based index price 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.

Natural gas from the Beryl field is processed through the SAGE gas plant operated by Apache. The gas is sold to a third party at the St. Fergus entry point of the national grid on a National Balancing Point index price basis. The condensate mix from the SAGE plant is processed further downstream. The split streams of propane and butane are sold on a monthly entitlement basis, and condensate is sold on a spot basis at the Braefoot Bay terminal using index pricing less transportation.

Argentina

Overview    We have had a continuous presence in Argentina since 2001 and have grown our holdings in the region through an active drilling program and targeted acquisitions. The region currently has active operations in the provinces of Neuquén, Rio Negro, and Tierra del Fuego. We have interests in 32 concessions, exploration permits, and other interests totaling 4.4 million gross acres in four of the main Argentine hydrocarbon basins: Neuquén, Austral, Cuyo, and Noroeste. Our concessions have varying expiration dates ranging from two years to over 15 years remaining, subject to potential extensions. Apache is currently in the process of extending our 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.

In 2012, Argentina produced 6 percent of our worldwide production and held 4 percent of our estimated proved reserves at year-end. We continue to focus our exploration and development activities in the Neuquén basin. During the year, the region drilled or participated in drilling 28 gross wells pursuant to a development drilling program that achieved a 100-percent success rate by focusing on unconventional Gas Plus gas and shallow oil plays. Our 2012 exploration program included drilling two gross horizontal wells targeting the Vaca Muerta shale formation, where we hold 1.3 million net acres, of which 586,000 net acres are in the oil play. In 2013, the region plans to finish testing and evaluating those wells in preparation for future drilling programs.

During 2013, the region plans to invest approximately $200 million for drilling, recompletion projects, development projects, equipment upgrades, production enhancement projects, and seismic acquisition.

Marketing

Natural Gas    Apache sells its natural gas in Argentina 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 2012, the average Gas Plus volume sold by Apache was 73.2 MMcf/d at an average price of $4.89 per Mcf. For 2013, Apache has signed contracts for total gross volumes to be sold under Gas Plus contracts of 80 MMcf/d at $5.01.

• Government-regulated pricing: The volumes we are required to sell at regulated prices are set by the Argentine government and vary based on seasonal factors and industry category. During 2012, we realized an average price of $0.84 per Mcf on government-regulated sales.

• Unregulated market: The majority of our remaining volumes are sold into the unregulated market. In 2012, realizations on sales in the unregulated market averaged $3.52 per Mcf.

• The weighted average of government-regulated and unregulated sales for 2012 was $2.03 per Mcf.

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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.

Other Exploration

New Ventures

Apache’s global New Ventures team provides exposure to new growth opportunities by looking outside of the Company’s traditional core areas and targeting higher-risk, high-reward exploration opportunities located in frontier basins as well as new plays in more mature basins. The New Ventures group was established in 2010 with a worldwide program focused on deepwater exploration, where many of the world’s large oil discoveries have occurred over the last decade, unconventional resources in North America and elsewhere, and underexplored basins that can be developed through application of new technologies.

Apache’s 2012 activities included drilling in offshore Kenya; participating in the Suriname bid round and winning offshore block 53; establishing a presence in several known U.S. resource plays; and acquiring seismic and spudding our first well on our acreage in the Cook Inlet of Alaska. Apache’s first exploration well in Kenya, the Mbawa 1, was drilled in the third quarter of 2012, encountering approximately 170 feet of natural gas pay in three zones. We have a 50-percent interest in the block and continue to analyze the well data to determine future exploration activities. In Alaska, the New Ventures team has acquired approximately 700,000 net acres over the last two years in the Cook Inlet basin and has commenced a robust seismic study over the area to facilitate future drilling activity. Apache has also leased nearly 500,000 net acres in the Mississippian Lime play in Kansas and Nebraska and 300,000 net acres in Montana’s Williston basin. We have commenced drilling activity in both of these plays.

During 2013, we plan to invest approximately $100 million to further these projects and continue pursuing additional exploration opportunities.

Major Customers

In 2012, 2011, and 2010 purchases by Royal Dutch Shell plc and its subsidiaries accounted for 20 percent, 11 percent, and 15 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 2012 we participated in drilling 1,486 gross wells, with 1,408 (95 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 development wells. In addition to our completed wells, at year-end several wells had not yet reached completion: 70 in the U.S. (55.73 net); 11 in Canada (9.00 net); 26 in Egypt (26.00 net); 2 in Australia (1.65 net); and 4 in Argentina (3.75 net).

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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
2012
United States		9.5		3.5		13.0		746.0		9.6		755.6		755.5		13.1		768.6
Canada		5.0		7.5		12.5		110.3		14.0		124.3		115.3		21.5		136.8
Egypt		28.0		22.5		50.5		144.4		1.0		145.4		172.4		23.5		195.9
Australia		1.9		2.7		4.6		1.3		0.7		2.0		3.2		3.4		6.6
North Sea		1.3		0.0		1.3		11.7		3.9		15.6		13.0		3.9		16.9
Argentina		2.0		0.0		2.0		23.0		0.0		23.0		25.0		0.0		25.0
Other International		0.0		0.5		0.5		0.0		0.0		0.0		0.0		0.5		0.5
Total		47.7		36.7		84.4		1,036.7		29.2		1,065.9		1,084.4		65.9		1,150.3
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

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, 2012, is set forth below:

	Oil				Gas				Total
	Gross		Net		Gross		Net		Gross		Net
United States		13,762		9,192		5,375		3,149		19,137		12,341
Canada		2,195		997		9,065		7,744		11,260		8,741
Egypt		977		937		79		74		1,056		1,011
Australia		49		25		13		8		62		33
North Sea		151		99		23		12		174		111
Argentina		474		397		417		383		891		780
Total		17,608		11,647		14,972		11,370		32,580		23,017

Gross natural gas and crude oil wells include 1,625 wells with multiple completions.

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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)				Oil   (Per bbl)		NGLs   (Per bbl)		Gas   (Per Mcf)
2012
United States		49.1		12.3		312.6	$	12.83	$	94.98	$	32.19	$	3.74
Canada		5.8		2.3		219.9		13.87		84.89		34.63		3.42
Egypt		36.5		–		129.5		7.73		110.92		–		3.90
Australia		10.6		–		78.3		9.08		115.22		–		4.55
North Sea		23.3		0.6		21.0		12.38		107.97		77.11		8.95
Argentina		3.5		1.1		78.1		10.85		75.89		21.55		2.87
Total		128.8		16.3		839.4		11.49		102.53		33.45		3.80
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		–		4.66
Australia		14.0		–		67.6		7.80		111.22		–		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		–		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

Gross and Net Undeveloped and Developed Acreage

The following table sets out our gross and net acreage position as of December 31, 2012, in each country where we have operations:

	Undeveloped Acreage				Developed Acreage
	Gross Acres		Net Acres		Gross Acres		Net Acres
United States		7,447,487		4,896,442		4,873,810		2,609,338
Canada		2,659,323		2,328,842		4,278,252		3,226,076
Egypt		7,934,690		5,142,158		1,800,720		1,693,216
Australia		7,058,038		3,854,352		880,467		534,665
North Sea		563,129		245,729		159,961		94,448
Argentina		4,182,067		3,106,969		221,422		188,795
Total		29,844,734		19,574,492		12,214,632		8,346,538

As of December 31, 2012, we had 5,229,947, 1,940,328, and 2,596,636 net acres scheduled to expire by December 31, 2013, 2014, and 2015, respectively, if production is not established or we take no other action to extend the terms. We strive to continue the terms of many of these licenses and concession areas through operational or administrative actions, but cannot assure that such extensions can be achieved on an economic basis or otherwise on terms agreeable to both the Company and third-parties including governments.

As of December 31, 2012, 37 percent of U.S. net undeveloped acreage and 47 percent of Canadian undeveloped acreage was held by production.

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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.

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 period.

The following table shows proved oil, NGL, and gas reserves as of December 31, 2012, based on average commodity prices in effect on the first day of each month in 2012, 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		474		155		2,354		1,021
Canada		80		22		1,735		391
Egypt		107		–		690		222
Australia		29		–		596		128
North Sea		120		2		93		138
Argentina		16		5		365		82
Proved Undeveloped:
United States		203		61		832		403
Canada		71		12		403		150
Egypt		17		–		205		51
Australia		35		–		1,074		214
North Sea		28		–		20		32
Argentina		3		1		97		20
TOTAL PROVED		1,183		258		8,464		2,852

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As of December 31, 2012, Apache had total estimated proved reserves of 1,441 MMbbls of crude oil, condensate, and NGLs and 8.5 Tcf of natural gas. Combined, these total estimated proved reserves are the energy equivalent of 2.9 billion barrels of oil or 17.1 Tcf of natural gas, of which oil represents 41 percent. As of December 31, 2012, the Company’s proved developed reserves totaled 1,982 MMboe and estimated PUD reserves totaled 870 MMboe, or approximately 30 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, 2012, 2011, and 2010, 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, 2012 and 2011, 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 870 MMboe as of December 31, 2012, decreased by 128 MMboe from 998 MMboe of PUD reserves estimated at the end of 2011. Driven by the significant decline in North America natural gas prices, a portion of our PUD reserves fell below the threshold for economic development and were removed from our proved reserves balance. The majority of these pricing revisions were associated with dry gas development projects in Canada. During the year, Apache converted 133 MMboe of PUD reserves to proved developed reserves through development drilling activity. In North America, we converted 98 MMboe, with the remaining 35 MMboe in our international areas. We acquired 47 MMboe of PUD reserves during the year. We added 158 MMboe of new PUD reserves through extensions and discoveries and had negative revisions of 200 MMboe associated with changes in product prices and revised development plans.

During the year, a total of approximately $3.4 billion was spent on projects associated with reserves that were carried as PUD reserves at the end of 2011. 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 $1.5 billion on PUD reserve development activity in North America and $1.9 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, 2012.

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 corporate and operating region engineers to ensure forecasts of operating expenses, netback prices, production trends, and development timing are reasonable.

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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 2012, the properties selected for each country ranged from 77 to 99 percent of the total future net cash flows discounted at 10 percent. These properties also accounted for over 86 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 83 percent of total proved reserves, including 86 percent of proved developed reserves and 74 percent of PUD reserves.

During 2012, 2011, and 2010, Ryder Scott’s review covered 88, 81, and 72 percent, respectively, of the Company’s worldwide estimated proved reserves value and 83, 70, and 63 percent, respectively, of the Company’s total proved reserves volume. Ryder Scott’s review of 2012 covered 81 percent of U.S., 78 percent of Canada, 64 percent of Argentina, 99 percent of Australia, 84 percent of Egypt, and 88 percent of the U.K.’s total proved reserves. 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. 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, 2012, we had 5,976 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 2012, 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, with the exception of our Midland office, which we own. 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.

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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), developed Oil 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 as required by the Bureau of Safety and Environmental Enforcement (BSEE) 30 CFR 254.30. Annually, 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, and representatives of governmental agencies. In the event of a spill, the CGA is the primary oil spill response association available to Apache and ADW. Apache and ADW have received approval for the Plans from BSEE. Apache and ADW personnel each review their respective Plan biennially and update where necessary.

Both Apache and ADW are members of, and Apache has an employee representative on the executive committee of, Clean Gulf Associates (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. Until December 31, 2012, CGA’s equipment was maintained by 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. CGA’s equipment maintained by MSRC included a high-volume open sea barge oil skimming system, 11 rigid sweeping arms, an oceangoing boom barge with 25,000 feet of offshore containment boom, a fire boom, six fast response vessels, 12 fast response skimming units, multiple shallow water skimming and recovery systems, wildlife cleaning and rehabilitation facilities, and dispersant inventory. In the event of a spill, MSRC stood ready to mobilize all of this equipment to CGA members. MSRC also handled the maintenance and mobilization of CGA non-marine equipment. Effective January 1, 2013, CGA’s marine and non-marine equipment is now maintained by the Clean Gulf Associates Service, LLC. In the event of a spill, this equipment, which is positioned at various staging points around the Gulf, is ready to be mobilized. In addition, CGA has contracted with Airborne Support Inc. to provide aircraft and dispersant capabilities for CGA member companies. In 2012, Apache incurred charges for CGA of approximately $380,000 based on a per-member fee and 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 (OSRL), which entitles any Apache entity worldwide to access OSRL’s service. OSRL has access to resources from the Global Response Network, a collaboration of

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seven major oil industry funded spill response organizations worldwide. OSRL 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, OSRL’s resources may be, and have been, deployed to areas across the globe, including the Gulf of Mexico. In addition, in February 2012, ADW became a member of MSRC and National Response Corporation (NRC), and their resources are available to ADW for its deepwater Gulf of Mexico operations. Furthermore, the spill response resources of other organizations are also 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. MSRC’s equipment currently includes 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, 7 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 the MSRC and the NRC changes from time to time, and current information is generally available on each company’s website. In 2012, Apache’s Gulf of Mexico Deepwater region incurred charges for NRC of $12,000 based on annual production and charges for MSRC of approximately $735,000 based on annual production and total wells spud in 2012.

ADW has also 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 2012 membership dues were approximately $1 million.

In 2011, ADW also became a member of the Marine Well Containment Company (MWCC) to fulfill the government’s permit requirements for containment and oil spill response plans in deepwater Gulf of Mexico operations. In March 2012, ADW assigned its interest in MWCC to Apache Well Containment LLC, another wholly owned Apache subsidiary. 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 2013. 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 BSEE requirements. It can operate in water depths up to 8,000 feet and has storage and processing capacity for up to 60,000 b/d and 120 MMcf/d. The capability of the interim containment system continues to grow as components of the expanded system are completed and delivered. The expanded system is designed to operate in 10,000 feet of water and process up to 100,000 b/d and 200 MMcf/d. Membership in MWCC is open to all companies operating in the U.S. Gulf of Mexico. Members and their affiliates 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. As of December 31, 2012, Apache’s investment in MWCC totals approximately $88 million.

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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 commodity prices, 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 and facilities, 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.

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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. The continuation of current global market conditions, uncertainty or further deterioration, including the economic instability in Europe, is likely to have significant long-term effects, 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 any sustainable 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.

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 2012 ranged from a high of $109.77 per barrel to a low of $77.69 per barrel. The NYMEX daily settlement price for the prompt month natural gas contract in 2012 ranged from a high of $3.90 per MMBtu to a low of $1.91 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.

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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:

• well blowouts, explosions, and cratering;

• pipeline ruptures and spills;

• fires;

• formations with abnormal pressures;

• equipment malfunctions;

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• 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; and

• surface spillage and surface or ground water contamination from petroleum constituents or hydraulic fracturing chemical additives.

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, or ground water contamination from hydraulic fracturing chemical additives may result in substantial claims for damages. Ineffective containment of a drilling well blowout or pipeline rupture, or surface spillage and surface or ground water contamination from petroleum constituents or hydraulic fracturing chemical additives 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.

Cyber attacks targeting systems and infrastructure used by the oil and gas industry may adversely impact our operations.

Our business has become increasingly dependent on digital technologies to conduct certain exploration, development and production activities. We depend on digital technology to estimate quantities of oil and gas reserves, process and record financial and operating data, analyze seismic and drilling information, and communicate with our employees and third party partners. Unauthorized access to our seismic data, reserves information or other proprietary information could lead to data corruption, communication interruption, or other operational disruptions in our exploration or production operations. Also, computers control nearly all of the oil and gas distribution systems in the United States and abroad, which are necessary to transport our production to market. A cyber attack directed at oil and gas distribution systems could damage critical distribution and storage assets or the environment, delay or prevent delivery of production to markets and make it difficult or impossible to accurately account for production and settle transactions.

While we have experienced cyber attacks, we have not suffered any material losses relating to such attacks; however, there is no assurance that we will not suffer such losses in the future. Further, as cyber attacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerabilities to cyber attacks.

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 U.S. Department of the Interior, 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 regulations 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.

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.

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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 or other forms of collateral 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

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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;

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• 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.

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 three definitive purchase and sale agreements (the BP Purchase Agreements) we entered into in connection with our 2010 acquisition of properties from BP (the BP Properties) 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

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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.

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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 a change in existing regulations could adversely affect our cash flows and results of 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 2014, when released, is expected to include certain provisions that, if passed, will have an adverse effect on our financial position, results of operations, and cash flows.

To date, the Office of Management and Budget has not released a summary of the proposed U.S. federal budget for fiscal year 2014. When released, it is anticipated that as a result of possible significant deficit reduction or comprehensive tax reform measures currently under consideration the proposed budget may repeal many tax incentives and deductions that are currently used by U.S. oil and gas companies and impose new taxes. These 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.

Derivatives regulation included in current or proposed financial legislation and rulemaking could impede our ability to manage business and financial risks by restricting our use of derivative instruments as hedges against fluctuating commodity prices.

The Dodd-Frank Act, which was signed into law in July 2010, contains significant derivatives regulation, including a requirement that certain transactions be cleared on exchanges and a requirement to post collateral (commonly referred to as “margin”) for such transactions. The Act provides for a potential exception from these

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clearing and collateral requirements for commercial end-users and it includes a number of defined terms that will be used in determining how this exception applies to particular derivative transactions and the parties to those transactions. We expect to qualify as a commercial end-user. As required by the Dodd-Frank Act, the Commodities Futures and Trading Commission (CFTC) has promulgated numerous rules to define these terms. In addition, it is possible that the CFTC, in conjunction with prudential regulators, may mandate that financial counterparties entering into swap transactions with end-users must do so with credit support agreements in place, which could result in negotiated credit thresholds above which an end-user must post collateral.

We use derivative instruments with respect to a portion of our expected crude oil and natural gas production in order to reduce the impact of commodity price fluctuations and enhance the stability of cash flows to support our capital investment programs and acquisitions. Given our current investment grade status, our current derivative contracts do not require the posting of margin regardless of the size of our liability positions.

Depending on the rules and definitions adopted by the CFTC and prudential regulators, we could be required to post significant amounts of collateral with our dealer counterparties for derivative transactions. Requirements to post cash collateral could result in negative impacts on our liquidity and financial flexibility and also cause us to incur additional debt and/or reduce capital investment. In addition, the final CFTC rules may also require the counterparties to our derivative instruments to move some of their derivative activities to a separate entity, which may not be as creditworthy as the current counterparty.

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, announcing that it would remain in power until the presidential and parliamentary elections could be held. In June 2012, Mohamed Morsi of the Muslim Brotherhood’s Freedom and Justice Party was elected as Egypt’s new president. In December 2012 the people of Egypt ratified a new constitution. Under the new constitution, the government must hold elections for the lower house of parliament within 60 days. 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 20 percent of our 2012 production and accounted for 10 percent of our year-end estimated proved reserves. At year-end 2012, 17 percent of our estimated discounted future net cash flows and 7 percent of our net capitalized oil and gas property was attributable to Egypt.

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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 44 percent of our 2012 production was outside North America, and approximately 31 percent of our estimated proved oil and gas reserves on December 31, 2012 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.

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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; and

• 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.

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ITEM 1B.   UNRESOLVED STAFF COMMENTS

As of December 31, 2012, 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.

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PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

During 2012, 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 2012 and 2011. 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.

	2012								2011
	Price Range				Dividends Per Share				Price Range				Dividends Per Share
	High		Low		Declared		Paid		High		Low		Declared		Paid
First Quarter	$	112.09	$	91.48	$	0.17	$	0.15	$	132.50	$	110.29	$	0.15	$	0.15
Second Quarter		102.13		77.93		0.17		0.17		134.13		114.94		0.15		0.15
Third Quarter		94.87		81.55		0.17		0.17		129.26		80.05		0.15		0.15
Fourth Quarter		89.08		74.50		0.17		0.17		105.64		73.04		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, 2013 (last trading day of the month), was $83.76 per share. As of January 31, 2013, there were 391,758,883 shares of our common stock outstanding held by approximately 5,300 stockholders of record and approximately 386,000 beneficial owners.

We have paid cash dividends on our common stock for 48 consecutive years through December 31, 2012. 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 10—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 2013 annual meeting of stockholders, which is incorporated herein by reference.

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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, 2007, through December 31, 2012. 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.

	2007		2008		2009		2010		2011		2012
Apache Corporation	$	100.00	$	69.77	$	97.34	$	113.16	$	86.43	$	75.45
S & P’s Composite 500 Stock Index		100.00		63.00		79.67		91.68		93.61		108.59
DJ US Expl & Prod Index		100.00		59.88		84.17		98.26		94.14		99.62

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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, 2012, 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, 2012 numbers in the following table reflect a total of $1.9 billion ($1.4 billion net of tax) in non-cash write-downs of the carrying value of the Company’s Canadian proved oil and gas properties as of March 31, 2012, June 30, 2012, and September 30, 2012, as a result of ceiling test limitations. The 2009 numbers 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. 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,
	2012		2011		2010		2009		2008
	(In millions, except per share amounts)
Income Statement Data
Total revenues	$	17,078	$	16,888	$	12,092	$	8,615	$	12,390
Income (loss) attributable to common stock		1,925		4,508		3,000		(292)		706
Net income (loss) per common share:
Basic		4.95		11.75		8.53		(0.87)		2.11
Diluted		4.92		11.47		8.46		(0.87)		2.09
Cash dividends declared per common share		0.68		0.60		0.60		0.60		0.70
Balance Sheet Data
Total assets	$	60,737	$	52,051	$	43,425	$	28,186	$	29,186
Long-term debt		11,355		6,785		8,095		4,950		4,809
Shareholders’ equity		31,331		28,993		24,377		15,779		16,509
Common shares outstanding		392		384		382		336		335

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.

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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, the U.K. 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

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. Our growth strategy focuses on economic growth through drilling, acquisitions, or a combination of both, depending on cost levels, availability of acquisition opportunities, and other factors.

Apache’s long-term perspective adheres to a portfolio approach to provide diversity in terms of hydrocarbon mix (crude oil and natural gas), geologic risk, geographic risk, and reserve life in order to achieve consistency in results. Continued volatility in the commodity price environment reinforces the importance of our balanced portfolio. Our 2012 results reflected the benefit of our product balance, as combined crude oil and liquids represented 51 percent of our production but provided 81 percent of our $16.9 billion of oil and gas revenues. In addition, approximately 72 percent of our crude oil production is priced relative to Dated Brent crudes and sweet crude from the Gulf Coast, which continue to be priced at a significant premium to West Texas Intermediate (WTI)-based prices. Our results also reflected our portfolio’s geographic balance, with over one-third of our natural gas produced outside of North America. While Apache’s 2012 natural gas price realizations in North America fell 24 percent from the 2011 average, outside North America our 2012 natural gas realizations averaged 13 percent higher than the prior year.

The Company’s foundation for future growth is driven by our significant producing asset base and large undeveloped acreage positions. This allows 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 capital budgets accordingly and allocate funds to projects based on expected value. We do this through a disciplined and focused process that includes analyzing current economic conditions, projected rate of return on internally generated drilling inventories, and opportunities for tactical acquisitions or leasehold purchases that add substantial drilling prospects or, occasionally, provide access to new core areas that could enhance our portfolio. In addition, we actively seek to identify and pursue ways to control costs and maximize our cash flow from operations. Our overall approach to managing capital allocation has enabled us to consistently deliver strong cash flows, with record production and revenues in 2012.

As we pursue growth, we continually monitor the capital resources available to us to meet our future financial obligations and liquidity needs. Apache has historically utilized cash generated from our operations, available borrowing capacity under our global credit facilities, access to both debt and equity capital markets, and proceeds from the occasional sale of nonstrategic assets to meet our financial needs. Access to the equity markets and the interest cost of debt are greatly influenced by Apache’s ability to maintain both a strong balance sheet and generate ongoing operating cash flow. In 2012, we issued $5.0 billion of fixed-rate notes in the current low interest rate environment, using the proceeds from the notes to fund the Cordillera acquisition, pay down

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maturing debt and commercial paper balances, and for general corporate purposes. The Company’s debt-to-capitalization ratio as of December 31, 2012 was 28 percent as compared to 20 percent at December 31, 2011. We believe the liquidity and capital resource alternatives available to us, 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 commitments or contingencies.

Throughout the cycles of our industry, our strategic focus on balanced portfolio growth has underpinned our ability to deliver production and 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

For the 12-month period ending December 31, 2012, Apache reported record performances in several key metrics. Results for the year include:

• Apache reported its fourth consecutive year of production growth, with annual daily production of oil, natural gas, and natural gas liquids averaging a record 779 Mboe/d, up 4 percent compared with 748 Mboe/d in 2011. Production in the fourth-quarter 2012 averaged 800 Mboe/d, an increase of 5 percent from the 759 Mboe/d averaged in the fourth quarter of 2011.

• Liquids production for the year averaged a record 396 Mboe/d, an increase of 7 percent from 371 Mboe/d in 2011. Crude oil accounted for 89 percent of liquids production.

• Oil and gas production revenues were a record $16.9 billion, up $137 million from the previous record of $16.8 billion set in 2011, reflecting a 4 percent increase in oil production from the prior year, which offset a $416 million reduction in natural gas revenues as realized prices in North America collapsed.

• Apache reported $1.9 billion in income attributable to common stock, or $4.92 per diluted common share, down from $4.5 billion, or $11.47 per share, in 2011. Earnings for 2012 reflect the after-tax impact of oil and gas property write-downs totaling $1.4 billion and certain income tax adjustments of $344 million. For additional discussion regarding these write-downs and tax adjustments, please refer Note 1—Summary of Significant Accounting Policies—“Property and Equipment” and Note 7—Income Taxes in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.

• Apache’s adjusted earnings, which exclude certain items impacting the comparability of results, were $3.8 billion, or $9.48 per diluted common share, down from $4.7 billion, or $11.83 per share, in 2011. 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.

2013 Outlook

As we head into 2013, we believe our inventory of exploration and development projects offers numerous growth opportunities. Recent drilling successes and acquisitions of acreage positions across our portfolio have built a robust drilling inventory for the Company. 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 gas properties in our portfolio. Our plan for 2013 also includes further

37

development of our major oil and gas discoveries and LNG projects in Australia and Canada, which, if completed, would enable us to monetize significant gas resources at prices more closely linked to crude oil. Rate of return will drive our decision making while we continue our focus on costs and operational efficiency.

Our initial 2013 capital budget is approximately $10.5 billion. Approximately $6.4 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 2013 exploration wells, 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 quarterly based on changes to actual and predicted operating cash flows.

Apache’s current capital budget is estimated to deliver an increase in 2013 production between 3 percent and 5 percent from full-year 2012 production levels. We generally do not project production impacts from weather-related shut-ins or for acquisitions or divestitures because they are specific, discrete events where occurrence and timing is unpredictable. We are, however, targeting asset sales of approximately $2.0 billion in 2013, of which $405 million was completed on February 8, 2013 with the closing of our Chevron Canada transaction.

Operational Developments

Apache pursues opportunities for growth through exploration, exploitation, and development drilling, supplemented by strategic acquisitions. In 2012, we invested over $10 billion in capital expenditures across all of our regions while also investing approximately $3.5 billion in various acquisitions.

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. Highlights of our 2012 drilling successes, exploration discoveries, LNG project milestones, and other opportunities for continued growth include:

International Activities

North Sea Drilling, Exploitation, and Exploration    During 2012, we drilled 21 wells, of which 16 were productive. Two of the highest producing wells were the Beryl B72 well, which commenced production in May at a rate of 11.6 Mb/d and 13.1 MMcf/d, and the Beryl B73 well, which was completed in September with an initial rate of 8.2 Mb/d and 5.9 MMcf/d. A 3-D seismic survey of the Beryl field commenced in early August, which when completed in 2013, will further refine our drilling plans for these Mobil North Sea assets acquired in 2011. We also announced during the year that the U.K. Department of Energy & Climate Change awarded the Company 11 new operated licenses and 1 non-operated license, which added approximately 613,000 gross acres to our North Sea portfolio. This award was effective January 2013 and covers areas surrounding our Beryl field plus two key licenses near the Forties field.

North Sea Satellite Platform Project    In September, the jacket of the Forties Alpha Satellite Platform was installed, with a topside and bridge scheduled to be delivered during the second quarter of 2013. This platform sits adjacent to the main Alpha Platform and will provide an additional 18 drilling slots beginning in the third quarter of 2013 along with power generation, fluid separation, gas lift compression, and oil export pumping.

Egypt Discoveries    Apache maintained an active drilling and development program throughout 2012, running an average of 25 rigs and drilling 188 development and injection wells. We also drilled 51 exploration wells with a 55 percent success rate. Our exploration program continues to benefit from the acquisition and evaluation of 3-D seismic surveys that enable the Company to high-grade existing prospects and identify new targets across multiple pay horizons in the Cretaceous, Jurassic, and deeper Paleozoic reservoirs.

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Argentina Exploration    Apache focused exploration and development activities primarily in the Neuquén basin during 2012, drilling 28 development wells targeting unconventional Gas Plus gas and shallow oil plays. The region’s exploration program included drilling two wells in the Vaca Muerta shale formation. Testing and evaluation of these wells continues in preparation for future drilling opportunities.

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

Australia Coniston Oil Field Development    The Coniston oil field development project, which lies just north of our Van Gogh field, continued toward projected first production in 2014. 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.

Australia Balnaves Oil Development    The Company continues development of its offshore Balnaves field, an oil accumulation located in a separate reservoir within the large gas reservoirs of our Brunello gas field offshore Western Australia. The field is projected 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, advances were made on the Chevron-operated Wheatstone LNG development project (Wheatstone) in Western Australia, with binding Sales and Purchase Agreements signed by two Asian customers for the delivery of approximately 60 percent of Apache’s net LNG offtake. In 2012, further advances were made on the project with the signing of two non-binding Heads of Agreements, which will take the total committed delivery volumes to over 80 percent once the final binding Sales and Purchase Agreements are signed. These binding Sales and Purchase Agreements are expected to be finalized and signed in 2013. 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 the end of 2016.

North American Activities

Record Drilling Activity in U.S. Onshore Regions    For 2012, our Permian region’s active drilling program continued to set new highs for net production, averaging 108 Mboe/d, up 18 percent from the prior year. Over 72 percent of this production was from crude oil and natural gas liquids. The Central region also achieved record production on the strength of an active drilling program and the Cordillera acquisition. The region drilled over 190 wells during the year and increased production 37 percent compared to the prior year. Oil and liquids growth increased 128 percent as the Central team targeted drilling oil and liquids-rich gas plays primarily on our Granite Wash acreage. Both the Permian and Central regions have continued their active drilling programs into 2013.

United States Horizontal Drilling    Apache continues to evaluate horizontal drilling potential across our acreage positions, in both conventional and unconventional reservoirs. Nearly all of our drilling activity in the Central region is horizontal, while the Permian region continues to develop a large inventory of horizontal opportunities based on 2012 drilling success in the Cline, Atoka, and Wolfcamp shale formations in the Midland

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basin of Texas. Horizontal redevelopment of historically conventional fields and reservoirs in the Central basin platform in the Permian region have also yielded positive results during 2012. We anticipate a continued shift to more horizontal drilling throughout 2013.

New Venture Acreage Positions    During 2012, Apache accumulated acreage positions in several prospective basins. Our New Ventures team has built a 500,000 net acre position in the Mississippian Lime play in Kansas and Nebraska and a 300,000 net acre position in the Williston Basin in Montana. We have commenced drilling activity in both of these plays.

Gulf of Mexico Deepwater Exploration    Apache’s strategic presence in the Gulf of Mexico deepwater portfolio was gained through the 2010 Mariner merger and was extended through our participation in the June 2012 federal lease sale, where we were awarded 28 new deepwater leases. At the end of 2012, the Company held approximately 900,000 gross acres across 166 blocks. The region increased its exploration activity for 2012, having drilled or participated in five wells during 2012, as compared to only two wells in the prior year. We plan to drill or participate in drilling seven wells during 2013.

Kitimat LNG Project    In December 2012, Apache announced an agreement with Chevron Canada Limited (Chevron Canada) to build and operate the Kitimat LNG project and develop shale gas resources at the Liard and Horn River basins in British Columbia. Chevron Canada and Apache Canada will each hold a 50-percent interest in the Kitimat LNG plant, the Pacific Trail Pipeline, and approximately 644,000 gross undeveloped acres in the Horn River and Liard basins. Chevron Canada will operate the LNG plant and pipeline and Apache Canada will operate Horn River and Liard. Although the project has not reached a final investment decision, we believe Chevron’s experience in developing LNG projects and marketing expertise will assist in moving the development forward. The transaction was completed on February 8, 2013.

Merger and Acquisitions of Property and Acreage

During 2012, 2011, and 2010, we completed approximately $17 billion in acquisitions, leaving Apache poised for growth. As we head into 2013, Apache is focused on further developing our inventory of available drilling opportunities. 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 acquired properties 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.

Egypt Political Unrest

In February 2011, former Egyptian president Hosni Mubarak stepped down, and the Egyptian Supreme Council of the Armed Forces took power, announcing that it would remain in power until the presidential and parliamentary elections could be held. In June 2012, Mohamed Morsi of the Muslim Brotherhood’s Freedom and Justice Party was elected as Egypt’s new president. In December 2012 the people of Egypt ratified a new constitution. Under the new constitution, the government must hold elections for the lower house of parliament within 60 days. Apache’s operations, located in remote locations in the Western Desert, have not experienced production interruptions, and we have continued to receive development lease approvals for our drilling program. We currently plan to invest $1.1 billion in Egypt in 2013.

Our operations in Egypt contributed 20 percent of our 2012 production and accounted for 10 percent of our year-end estimated proved reserves. At year-end 2012, 17 percent of our estimated discounted future net cash flows and 7 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.

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Apache purchases multi-year political risk insurance from the Overseas Private Investment Corporation (OPIC) and other highly-rated international insurers covering a portion of 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 $263 million sub-limit for currency inconvertibility. In addition, the Company has a separate policy with OPIC, which provides $300 million of coverage for losses arising from (1) non-payment by Egyptian General Petroleum Corporation (EGPC) of arbitral awards covering amounts owed Apache on past due invoices and (2) expropriation of exportable petroleum in the event that actions taken by the government of Egypt prevent Apache from exporting our share of production. In October 2012, the Multilateral Investment Guarantee Agency (MIGA), a member of the World Bank Group, announced that it was providing $150 million in reinsurance to OPIC for the remainder of the policy term. This provision of long-term reinsurance to OPIC will allow Apache to maintain the $300 million of insurance coverage through 2024.

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.

Argentina Tax and Royalty Claims

ENARGAS, an autonomous entity that functions under the Argentina Ministry of Economy, 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 totaled approximately $24 million in 2012. 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. The Province’s claims for additional royalty on liquefied petroleum gas exports have been paid under protest by the Company’s affiliates. That payment is expected to resolve the claims for additional royalty on liquefied petroleum gas exports.

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Results of Operations

Oil and Gas Revenues

	For the Year Ended December 31,
	2012				2011				2010
	$ Value		% Contribution		$ Value		% Contribution		$ Value		% Contribution
	($ in millions)
Total Oil Revenues:
United States	$	4,662		35%	$	4,163		33%	$	2,683		30%
Canada		492		4%		485		4%		388		4%
North America		5,154		39%		4,648		37%		3,071		34%
Egypt		4,050		31%		4,169		33%		2,875		32%
Australia		1,218		9%		1,552		12%		1,296		14%
North Sea		2,517		19%		2,072		16%		1,590		18%
Argentina		271		2%		238		2%		209		2%
International		8,056		61%		8,031		63%		5,970		66%
Total  (1)	$	13,210		100%	$	12,679		100%	$	9,041		100%
Total Gas Revenues:
United States	$	1,169		37%	$	1,550		43%	$	1,409		49%
Canada		751		23%		1,033		29%		647		23%
North America		1,920		60%		2,583		72%		2,056		72%
Egypt		504		16%		621		17%		495		17%
Australia		357		11%		182		5%		163		6%
North Sea		188		6%		19		0%		16		0%
Argentina		224		7%		204		6%		132		5%
International		1,273		40%		1,026		28%		806		28%
Total  (2)	$	3,193		100%	$	3,609		100%	$	2,862		100%
Natural Gas Liquids (NGL) Revenues:
United States	$	395		73%	$	391		75%	$	208		74%
Canada		79		14%		99		19%		39		14%
North America		474		87%		490		94%		247		88%
Egypt		–		–		1		0%		2		1%
North Sea		46		8%		–		–		–		–
Argentina		24		5%		31		6%		31		11%
International		70		13%		32		6%		33		12%
Total	$	544		100%	$	522		100%	$	280		100%
Total Oil and Gas Revenues:
United States	$	6,226		37%	$	6,104		36%	$	4,300		35%
Canada		1,322		8%		1,617		10%		1,074		9%
North America		7,548		45%		7,721		46%		5,374		44%
Egypt		4,554		27%		4,791		29%		3,372		28%
Australia		1,575		9%		1,734		10%		1,459		12%
North Sea		2,751		16%		2,091		12%		1,606		13%
Argentina		519		3%		473		3%		372		3%
International		9,399		55%		9,089		54%		6,809		56%
Total	$	16,947		100%	$	16,810		100%	$	12,183		100%

⁽¹⁾  Financial derivative hedging activities decreased 2012, 2011, and 2010 oil revenues $146 million, $379 million, and $57 million, respectively.

⁽²⁾  Financial derivative hedging activities increased 2012, 2011, and 2010 natural gas revenues $414 million, $272 million, and $222 million, respectively.

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Production

	For the Year Ended December 31,
	2012		Increase (Decrease)			2011		Increase (Decrease)			2010
Oil Volume – b/d:
United States		134,123		12%			119,415		24%			96,576
Canada		15,830		11%			14,252		(2%	)		14,581
North America		149,953		12%			133,667		20%			111,157
Egypt  (3)		99,756		(4%	)		103,912		5%			99,122
Australia		28,884		(24%	)		38,228		(17%	)		45,908
North Sea		63,692		17%			54,541		(4%	)		56,791
Argentina		9,741		2%			9,597		(4%	)		9,956
International		202,073		(2%	)		206,278		(3%	)		211,777
Total  (1)		352,026		4%			339,945		5%			322,934
Natural Gas Volume – Mcf/d:
United States		854,099		(1%	)		864,742		18%			730,847
Canada		600,680		(5%	)		632,550		60%			396,005
North America		1,454,779		(3%	)		1,497,292		33%			1,126,852
Egypt  (3)		353,738		(3%	)		365,418		(3%	)		374,858
Australia		214,013		16%			185,079		(7%	)		199,729
North Sea		57,457		NM			2,284		(4%	)		2,391
Argentina		213,464		1%			212,311		15%			184,830
International		838,672		10%			765,092		0%			761,808
Total  (2)		2,293,451		1%			2,262,384		20%			1,888,660
Natural Gas Liquids (NGL) Volume – b/d:
United States		33,527		52%			22,111		60%			13,777
Canada		6,258		5%			5,958		107%			2,884
North America		39,785		42%			28,069		68%			16,661
Egypt		–		NM			49		NM			82
North Sea		1,618		NM			4		NM			–
Argentina		3,008		0%			3,018		(5%	)		3,180
International		4,626		51%			3,071		(6%	)		3,262
Total		44,411		43%			31,140		56%			19,923
BOE per day (4)
United States		310,000		9%			285,650		23%			232,161
Canada		122,201		(3%	)		125,636		51%			83,466
North America		432,201		5%			411,286		30%			315,627
Egypt		158,713		(4%	)		164,864		2%			161,680
Australia		64,552		(7%	)		69,074		(13%	)		79,196
North Sea		74,887		36%			54,925		(4%	)		57,190
Argentina		48,326		1%			48,000		9%			43,941
International		346,478		3%			336,863		(2%	)		342,007
Total		778,679		4%			748,149		14%			657,634

⁽¹⁾  Approximately 13 percent of 2012 worldwide oil production was subject to financial derivative hedges, compared to 29 percent in 2011 and 12 percent in 2010.

⁽²⁾  Approximately 13 percent of 2012 worldwide natural gas production was subject to financial derivative hedges, compared to 16 percent in 2011 and 23 percent in 2010.

⁽³⁾  Gross oil production in Egypt for 2012, 2011, and 2010 was 213,112 b/d, 217,207 b/d, and 189,342 b/d, respectively. Gross natural gas production in Egypt for 2012, 2011, and 2010 was 899,972 Mcf/d, 865,485 Mcf/d, and 798,645 Mcf/d, respectively.

⁽⁴⁾  The table shows production on a barrel of oil equivalent basis (boe) 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 price ratio between the two products.

NM – Not meaningful

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Pricing

	For the Year Ended December 31,
	2012		Increase (Decrease)	2011		Increase (Decrease)	2010
Average Oil Price – Per barrel
United States	$	94.98	(1%)	$	95.51	25%	$	76.13
Canada		84.89	(9%)		93.19	28%		72.83
North America		93.91	(1%)		95.27	26%		75.69
Egypt		110.92	1%		109.92	38%		79.45
Australia		115.22	4%		111.22	44%		77.32
North Sea		107.97	4%		104.09	36%		76.66
Argentina		75.89	12%		68.02	18%		57.47
International		108.92	2%		106.67	38%		77.21
Total  (1)		102.53	0%		102.19	33%		76.69
Average Natural Gas Price – Per Mcf:
United States	$	3.74	(24%)	$	4.91	(7%)	$	5.28
Canada		3.42	(23%)		4.47	0%		4.48
North America		3.61	(24%)		4.72	(6%)		5.00
Egypt		3.90	(16%)		4.66	29%		3.62
Australia		4.55	69%		2.69	20%		2.24
North Sea		8.95	(60%)		22.25	19%		18.64
Argentina		2.87	9%		2.64	35%		1.96
International		4.15	13%		3.67	27%		2.90
Total  (2)		3.80	(13%)		4.37	5%		4.15
Average NGL Price – Per barrel
United States	$	32.19	(34%)	$	48.42	17%	$	41.45
Canada		34.63	(24%)		45.72	25%		36.61
North America		32.57	(32%)		47.85	18%		40.62
Egypt		–	NM		66.36	NM		69.75
North Sea		77.11	18%		65.45	NM		–
Argentina		21.55	(23%)		27.90	3%		27.08
International		40.98	43%		28.56	1%		28.15
Total		33.45	(27%)		45.95	19%		38.58

⁽¹⁾  Reflects a per-barrel decrease of $1.13, $3.05, and $0.48 in 2012, 2011, and 2010, respectively, from financial derivative hedging activities.

⁽²⁾  Reflects a per-Mcf increase of $0.49, $0.33, and $0.32 in 2012, 2011, and 2010, respectively, from financial derivative hedging activities.

NM – Not meaningful

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 2012 were essentially flat compared to 2011, although prices varied significantly throughout the year as political unrest and economic uncertainty continued to impact market volatility.

Continued volatility in the commodity price environment reinforces the importance of our balanced portfolio approach. Crude oil prices realized in 2012 averaged $102.53 per barrel; however International Dated Brent crudes and sweet crude from the Gulf Coast continue to be priced at a significant premium to WTI-based

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prices. We are realizing these premium prices on approximately 72 percent of our crude oil production. Our Egypt, Australia, and North Sea regions, which comprise 55 percent of our worldwide oil production, receive International Dated Brent pricing with 2012 oil realizations averaging $110.59 per barrel compared with 2011 oil realizations averaging $108.55 per barrel. Our Gulf Coast regions, which comprise 17 percent of our worldwide oil production and receive similar premiums, had price realizations averaging $108.02 per barrel, remaining essentially flat with 2011 realizations averaging $108.26 per barrel.

While the market price received for natural gas varies among geographic areas, crude oil tends to trade within a tighter global range. 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 retained the value-added tax collected from buyers, effectively increasing realized prices by 21 percent from sales made until May 2012 (when the Federal Government withdrew the benefit). As a result, 2012 oil prices realized from Tierra del Fuego production averaged $71.81 per barrel as compared to our Neuquén basin production, which averaged $77.50 per barrel.

Apache uses financial instruments to manage a portion of its exposure to fluctuations in crude oil prices, particularly in North America. In 2012, 13 percent of our oil production was subject to financial derivative hedges, reducing revenues by $146 million. In 2011, 29 percent of our oil production was subject to financial derivative hedges, reducing revenues by $379 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, highlighting the importance of a geographically balanced portfolio.

Apache primarily sells natural gas into the North American market, where realized prices decreased 24 percent compared to 2011; however, approximately one-third of our natural gas is produced outside North America, where our average contracted prices rose 13 percent from 2011. 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, plus an upward adjustment for liquids content. Under a legacy oil-indexed contract, which expired at the end of 2012, there was no price cap for our gas up to 100 MMcf/d of gross production. Overall, the region averaged $3.90 per Mcf in 2012.

• 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, prices received on recent contracts are substantially higher than historical levels. During 2012, the region averaged $4.55 per Mcf, a 69 percent increase over 2011 pricing.

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• Natural gas from the North Sea Beryl field is processed through the SAGE gas plant operated by Apache. The gas is sold to a third party at the St. Fergus entry point of the national grid on a National Balancing Point index price basis. The region averaged $8.95 per Mcf in 2012.

• 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 2012, the average Gas Plus volume sold by Apache was 73.2 MMcf/d at an average price of $4.89 per Mcf. For 2013, Apache has signed contracts for total gross volumes to be sold under Gas Plus contracts of 80 MMcf/d at $5.01.

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 based on seasonal factors and industry category. During 2012, we realized an average price of $0.84 per Mcf on government-regulated sales and an average price of $3.52 per Mcf on our unregulated market sales, for a weighted average of $2.03 per Mcf on non-Gas Plus 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 2012, 13 percent of our gas production was subject to financial derivative hedges, increasing revenues by $414 million. In 2011, 16 percent of our gas production was subject to financial derivative hedges, increasing revenues by $272 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

2012 vs. 2011    During 2012, crude oil revenues totaled $13.2 billion, $531 million higher than the 2011 total of $12.7 billion, driven by a four-percent increase in worldwide production. Average daily production in 2012 was 352.0 Mb/d, with prices averaging $102.53 per barrel. Crude oil represented 78 percent of our 2012 oil and gas production revenues and 45 percent of our equivalent production, compared to 75 and 45 percent, respectively, in the prior year. Higher realized prices contributed $43 million to the increase in full-year revenues, while higher production volumes added another $488 million.

Worldwide oil production increased 12.1 Mb/d, driven by a 14.7 Mb/d increase in the U.S. The Permian region increased 9.2 Mb/d on increased drilling activity, primarily in the Deadwood, Spraberry, and Wolfcamp plays. The Central region increased 7.4 Mb/d on properties added from the Cordillera acquisition and drilling and recompletion activity across several Granite Wash formations. North Sea production increased 9.2 Mb/d primarily on volumes from the 2011 Mobil North Sea acquisition. Australia production decreased 9.3 Mb/d as a result of natural decline from our Pyrenees and Van Gogh fields. Egypt’s gross oil production decreased 2 percent, while net oil production decreased 4 percent, a product of the terms of our production sharing contracts.

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.

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Worldwide oil production increased 17.0 Mb/d, driven by a 22.8 Mb/d increase in the U.S. The Permian region increased 11.6 Mb/d on properties added from the BP acquisitions, the Mariner merger and drilling and recompletion activity, offset by natural decline. The Gulf of Mexico (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 an active drilling program in the Granite Wash play. 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 increased only 5 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.

Natural Gas Revenues

2012 vs. 2011    Natural gas revenues for 2012 of $3.2 billion were $416 million lower than 2011, the result of a 13-percent decrease in realized prices partially offset by a one-percent increase in production volumes. Worldwide production rose 31.1 MMcf/d, adding $51 million to revenues. Realized prices in 2012 averaged $3.80 per Mcf, a decrease of $0.57 per Mcf, which reduced revenues by $467 million.

Worldwide gas production rose 1 percent on increases in the North Sea and Australia, partially offset by decreases in North America. North Sea daily production increased 55.2 MMcf/d, primarily as a result of the 2011 Mobil North Sea acquisition. Daily gas production in Australia increased 28.9 MMcf/d on new contracts associated with the recently completed gas processing facilities at Devil Creek. Central region rose 29.6 MMcf/d on production from the Cordillera acquisition. Daily production in Canada and the GOM onshore and offshore regions decreased 31.9 MMcf/d and 47.9 MMcf/d, respectively, as drilling and recompletion activity shifted from dry gas to liquids-rich gas properties. Egypt’s gross production was up 4 percent while net production decreased 3 percent, a product of the terms of our production sharing contracts.

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 increased 133.9 MMcf/d, or 18 percent, primarily a result of 2010 acquisition activity. GOM onshore and offshore region production rose 73.4 MMcf/d on new drilling activity and properties acquired from Devon and the Mariner merger. Permian region production increased 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 increased 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 increased 8 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 decreased 3 percent, as higher prices impacted our cost recovery volumes.

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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.

	For the Year Ended December 31,
	2012		2011		2010		2012		2011		2010
	(In millions)						(Per boe)
Depreciation, depletion and amortization:
Oil and gas property and equipment
Recurring	$	4,812	$	3,814	$	2,861	$	16.88	$	13.97	$	11.92
Additional		1,926		109		–		6.76		0.40		–
Other assets		371		281		222		1.30		1.03		0.92
Asset retirement obligation accretion		232		154		111		0.81		0.56		0.46
Lease operating costs		2,968		2,605		2,032		10.41		9.54		8.47
Gathering and transportation costs		303		296		178		1.08		1.08		0.73
Taxes other than income		862		899		690		3.02		3.29		2.88
General and administrative expense		531		459		380		1.86		1.68		1.58
Merger, acquisitions & transition		31		20		183		0.11		0.07		0.77
Financing costs, net		165		158		229		0.58		0.58		0.95
Total	$	12,201	$	8,795	$	6,886	$	42.81	$	32.20	$	28.68

Depreciation, Depletion and Amortization (DD&A)

The following table details the changes in recurring DD&A of oil and gas properties between December 31, 2010, and December 31, 2012:

	Recurring DD&A
	(In millions)
2010 DD&A	$	2,861
Volume change		349
DD&A Rate change		604
2011 DD&A	$	3,814
Volume change		231
DD&A Rate change		767
2012 DD&A	$	4,812

2012 vs. 2011    Recurring full-cost depletion expense increased $998 million on an absolute dollar basis: $767 million on higher costs and $231 million from additional production. Our full-cost depletion rate increased $2.91 to $16.88 per boe as costs to acquire, find, and develop reserves, which were significantly impacted by higher oil prices, exceeded our historical cost basis. Price related reserve revisions in North America also had a negative impact on the rate.

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In addition, in 2012 we recorded a non-cash write-down on the carrying value of our proved oil and gas property balances in Canada of $1.9 billion ($1.4 billion net of tax). Under the full-cost method of accounting, the Company is required to review the carrying value of its proved oil and gas properties each quarter on a country-by-country basis. Under these rules, capitalized costs of oil and gas properties, net of accumulated DD&A and deferred income taxes, may not exceed the present value of estimated future net cash flows from proved oil and gas reserves, net of related tax effects and discounted 10 percent per annum and adjusted for cash flow hedges. 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. The Company also recorded $28 million of additional DD&A in 2012 related to the write-off of the carrying value of our oil and gas properties in New Zealand upon exiting the country and $15 million of seismic costs incurred in countries where Apache is pursuing exploration opportunities.

2011 vs. 2010    Recurring full-cost depletion expense increased $953 million on an absolute dollar basis: $604 million on higher costs 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.

Lease Operating Expenses

Lease operating expenses (LOE) include several key components, such as: 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 2012 production, is inherently more expensive to produce than natural gas. Repair and maintenance costs are typically higher on offshore properties, which in 2012 accounted for all of our production in Australia and the North Sea and 83 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 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.

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The following table details the LOE rate impact by component:

For the Year Ended December 31, 2012
	Per boe
2011 LOE	$	9.54
Repairs and maintenance		0.39
Labor and pumper costs		0.31
Non-operated property costs		0.12
Workover costs		0.06
Other		0.10
Other decreased production		0.01
Acquisitions (1)		(0.12)
2012 LOE	$	10.41

For the Year Ended December 31, 2011
	Per boe
2010 LOE	$	8.47
FX impact		0.23
Labor and pumper costs		0.21
Workover costs		0.18
Chemicals, power, and fuel		0.13
Transportation		0.11
Other		0.12
Other decreased production		0.11
Acquisitions (1)		(0.02)
2011 LOE	$	9.54

⁽¹⁾  Per-unit impact of acquisitions is shown net of associated production.

2012 vs. 2011    Our 2012 LOE increased $363 million from 2011, or 14 percent. On a per-unit basis, LOE increased 9 percent due to higher costs on the items listed above.

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.

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,
	2012		2011		2010
	(In millions)
Canada	$	163	$	166	$	75
U.S.		69		64		42
Egypt		39		34		31
North Sea		24		25		25
Argentina		8		7		5
Total Gathering and transportation	$	303	$	296	$	178

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2012 vs. 2011    Gathering and transportation costs increased $7 million from 2011. The U.S. costs for 2012 increased $5 million as compared to 2011 on increased production in the Central region, primarily resulting from our acquisition of Cordillera. Egypt’s costs were up $5 million on a higher number of sales cargoes, increased terminal fees, and higher vessel freight costs. Canada’s costs decreased $3 million from a decline in activity in the region.

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.

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 from 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,
	2012		2011		2010
	(In millions)
U.K. PRT	$	451	$	538	$	422
Severance taxes		220		212		142
Ad valorem taxes		104		94		80
Other		87		55		46
Total Taxes other than income	$	862	$	899	$	690

2012 vs. 2011    Taxes other than income were $37 million lower than 2011. U.K. PRT decreased $87 million over the comparable 2011 period as a result of a decrease in net receipts, primarily driven by lower revenues on qualifying fields during the year. Property acquisitions in 2011 and 2012 resulted in increases of $8 million and $10 million to severance and ad valorem tax expense, respectively.

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 an 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.

General and Administrative Expenses

2012 vs. 2011    General and administrative (G&A) expenses increased $72 million, or 16 percent, from 2011. On a per-unit basis, G&A expenses increased 11 percent, or $0.18 per boe: $0.12 per boe primarily relates to stock-based performance plan charges and $0.14 per boe on growth-related increases, less $0.08 on increased production.

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2011 vs. 2010    G&A expenses increased $79 million, or 21 percent from 2010. On a per-unit basis, G&A expenses increased 6 percent, or $0.11 per boe: $0.07 per boe on higher insurance costs and $0.04 per boe on nonrecurring expenses.

Merger, Acquisitions & Transition Costs

In 2012, the Company recognized $31 million in merger, acquisitions, & transition costs, reflecting additional expenses related to our 2011 acquisition of Mobil North Sea Limited and expenses associated with our 2012 acquisition of Cordillera.

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,
	2012		2011		2010
	(In millions)
Separation and retention costs	$	12	$	12	$	114
Investment banking fees		7		–		42
Other costs		12		8		27
Total Merger, acquisitions & transition costs	$	31	$	20	$	183

Financing Costs, Net

Financing costs incurred during the period comprised the following:

	For the Year Ended December 31,
	2012		2011		2010
	(In millions)
Interest expense	$	509	$	433	$	345
Amortization of deferred loan costs		7		5		17
Capitalized interest		(334)		(263)		(120)
Interest income		(17)		(17)		(13)
Total Financing costs, net	$	165	$	158	$	229

2012 vs. 2011    Net financing costs increased $7 million from 2011. The increase is primarily related to a $76 million increase in interest expense from debt issuances during 2012, partially offset by a $71 million increase in capitalized interest resulting from additional unproved property balances associated with the significant undeveloped acreage from the Cordillera acquisition and the U.S. new ventures program.

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.

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Provision for Income Taxes

2012 vs. 2011    The provision for income taxes totaled $2.9 billion in 2012 compared to $3.5 billion in 2011, driven by lower income before income taxes and an increase in the effective tax rate to 59.0 percent from 43.4 percent in 2011. The 2012 effective rate reflects the tax impact from the $1.9 billion Canadian non-cash write-down, a North Sea decommissioning tax rate adjustment charge, and other tax adjustments. As part of the increase in the corporate income tax rate on North Sea oil and gas profits from 50 percent to 62 percent announced in March 2011, the U.K. government also proposed that the corporation income tax relief attributable to decommissioning expenditures in the North Sea remain at 50 percent. Related legislation was then introduced in Finance Bill 2012 and was enacted on July 17, 2012, upon receiving Royal Assent. As a result of this enacted legislation the Company recorded a non-recurring tax charge of $118 million in the third quarter of 2012. For additional information regarding income taxes, please see Note 7—Income Taxes in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.

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.

Significant Acquisitions and Divestitures

2012 Activity

On December 24, 2012, Apache Canada and Chevron Canada entered into an agreement pursuant to which each will become a 50-percent owner of the Kitimat LNG plant, the Pacific Trail Pipeline, and 644,000 gross undeveloped acres in the Horn River and Liard basins. Chevron Canada will operate the LNG plant, which will be located on the northern British Columbia coast, and the pipeline; Apache Canada will operate Horn River and Liard. Apache’s net proceeds from the transaction were approximately $405 million. The transaction closed on February 8, 2013. Apache originally purchased interest in the Kitimat LNG facility and the related proposed pipeline in the first quarter of 2010.

On April 30, 2012, Apache completed the acquisition of Cordillera, a privately held exploration and production company, in a stock and cash transaction. Cordillera’s properties include approximately 312,000 net acres in the Granite Wash, Tonkawa, Cleveland, and Marmaton plays in western Oklahoma and the Texas Panhandle. The effective date of the transaction was September 1, 2011. Apache issued 6,272,667 shares of common stock and paid approximately $2.7 billion of cash to the sellers as consideration for the transaction. The cash paid at closing was funded with a portion of the proceeds from the Company’s April 2012 public note offering. For further discussion of the equity issuance and note offering, please see Note 10—Capital Stock and Note 6—Debt in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K and “Liquidity” in this Item 7.

On January 31, 2012, a subsidiary of Apache Energy Limited completed the acquisition of a 49-percent interest in Yara Pilbara Holdings Pty Limited (YPHPL, formerly Burrup Holdings Limited) for $439 million, including working capital adjustments. The transaction was funded with debt. YPHPL is the owner of an ammonia plant on the Burrup Peninsula of Western Australia. Apache has supplied gas to the plant since operations commenced in 2006. Yara Australia Pty Ltd (Yara) owns the remaining 51 percent of YPHPL and operates the plant. In addition, Apache also acquired an interest in a planned technical ammonia nitrate plant to be developed with Yara and Orica Limited. The investment in YPHPL is accounted for under the equity method of accounting, with the balance recorded as a component of “Deferred charges and other” in Apache’s consolidated balance sheet and results of operations recorded as a component of “Other” under “Revenues and Other” in the Company’s statement of consolidated operations.

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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.

2010 Activity

In November 2010, Apache completed the acquisition of 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.

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 offshore blocks.

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 the Company’s primary source of liquidity. 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.

Apache’s operating 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 our revenues, earnings and cash flows, 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 and have less impact than 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 to fund activity necessary to offset the inherent declines in production and proven crude oil and natural gas reserves. Future success in maintaining and growing reserves and production is highly dependent on the success of our exploration and development activities and our ability to acquire additional reserves at reasonable costs.

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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.

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:

	For the Year Ended December 31,
	2012		2011		2010
	(In millions)
Sources of Cash and Cash Equivalents:
Net cash provided by operating activities	$	8,504	$	9,953	$	6,726
Fixed-rate debt borrowings		4,978		–		2,470
Commercial paper and bank loan borrowings, net		549		–		318
Sale of oil and gas properties		27		422		–
Proceeds from issuance of common stock		–		–		2,258
Proceeds from issuance of depositary shares		–		–		1,227
Other		–		84		106
		14,058		10,459		13,105
Uses of Cash and Cash Equivalents:
Capital expenditures (1)	$	9,531	$	7,078	$	4,922
Acquisitions		2,918		1,813		8,360
Equity investment in Yara Pilbara Holdings Pty Limited (YPHPL)		439		–		–
Commercial paper, credit facility and bank loan repayments, net		–		925		–
Project financing repayment		–		–		350
Payments on fixed-rate notes		400		–		1,023
Dividends		332		306		226
Other		573		176		138
		14,193		10,298		15,019
Increase (decrease) in cash and cash equivalents	$	(135)	$	161	$	(1,914)

⁽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

Operating 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.

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Net cash provided by operating activities for 2012 totaled $8.5 billion, down $1.4 billion from 2011. The decrease reflects the impact of a change in working capital during the fiscal year, higher operating costs, and higher income tax payments in 2012 as compared to the 2011 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.

Proceeds from Debt, Common Stock, and Share Issuance

In April 2012, the Company issued $3.0 billion principal amount of senior unsecured notes. The Company used the proceeds to fund the cash portion of the purchase price paid to acquire Cordillera, repay $400 million of notes that matured on April 15, 2012, and for general corporate purposes.

In December 2012, the Company issued $2.0 billion principal amount of senior unsecured notes to repay commercial paper borrowings and for general corporate purposes.

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 for approximately $3.5 billion in proceeds.

On August 20, 2010, the Company issued $1.5 billion principal amount of senior unsecured notes 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 $1 billion principal amount of senior unsecured notes to redeem the outstanding public debt of $1.0 billion assumed upon completion of Apache’s acquisition of Mariner in November 2010.

For further discussion of the equity issuance and note offerings, please see Note 10—Capital Stock and Note 6—Debt in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.

Commercial Paper and Lines of Credit

As of December 31, 2012, Apache had $580 million in commercial paper and money market lines of credit outstanding. 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.

Sale of Oil and Gas Properties

During 2012, Apache completed the sale of certain properties in Canada and the U.S. for $27 million. Divestitures comprised several non-strategic assets. In 2011 Apache completed the sale of certain properties in Canada and the U.S. for $422 million.

We are targeting asset sales of approximately $2.0 billion in 2013, of which $405 million was completed on February 8, 2013 with our Chevron Canada transaction.

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

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reasons, operating cash flow forecasts are revised monthly in response to changing market conditions and production projections. We routinely adjust our capital budget on a quarterly basis in response to changing market conditions and operating cash flow forecasts.

Historically, we have used a combination of operating cash flows, borrowings under lines of credit and our 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.

	For the Year Ended December 31,
	2012		2011		2010
	(In millions)
Exploration and Development (E&D):
United States	$	5,151	$	2,768	$	1,623
Canada		590		817		860
North America		5,741		3,585		2,483
Egypt		1,074		896		757
Australia		873		576		624
North Sea		886		823		617
Argentina		289		346		240
Other International		98		61		20
International		3,220		2,702		2,258
Worldwide Exploration and Development Costs		8,961		6,287		4,741
Gathering, Transmission, and Processing Facilities (GTP):
United States		75		27		–
Canada		172		148		159
Egypt		33		111		182
Australia		441		345		162
Argentina		16		12		3
North Sea		1		–		–
Total GTP Costs		738		643		506
Asset Retirement Costs		948		819		459
Capitalized Interest		334		263		120
Capital Expenditures, excluding acquisitions		10,981		8,012		5,826
Acquisitions, including GTP		3,543		3,189		11,557
Asset Retirement Costs – Acquired		84		592		847
Total Capital Expenditures	$	14,608	$	11,793	$	18,230

Exploration and Development    Worldwide E&D expenditures for 2012 totaled $9 billion, or 43 percent above 2011. E&D spending in North America, which totaled 64 percent of worldwide E&D spending, was up 60 percent from the prior year on increased activity in every U.S. region. Expenditures in the U.S. reflect increased drilling activity in the Permian region, particularly in the Deadwood area, and in our Central region where our active horizontal drilling program in the Granite Wash and Cherokee plays continued to expand. U.S.

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expenditures also reflect an increase in leasehold acquisition efforts where we have spent over $1 billion to gain new acreage positions in several prospects, including the Mississippian Lime play in Kansas and Nebraska, the Williston Basin play in Montana and multiple offshore blocks in the GOM Deepwater and Shelf regions. E&D spending in Canada decreased 28 percent from the prior year period as our drilling program has been re-focused to oil and liquids-rich gas plays given current North American gas prices.

E&D expenditures outside of North America increased 19 percent over 2011. Australia spending rose $297 million from increased exploration and development drilling, and Egypt was $178 million higher than the prior year on continued drilling activity across all major basins. E&D spending in the North Sea was up $63 million on Beryl field development activity, following the field’s acquisition at the end of 2011.

Gathering, Transmission and Processing Facilities    We invested $738 million in GTP in 2012 compared to $643 million in 2011. The increase is primarily related to Australia, driven by the purchase of the Ningaloo Vision FPSO and higher expenditures for the Wheatstone LNG project.

Asset Retirement Costs    During 2012, we recorded $603 million of additional future abandonment liabilities and deferred tax liabilities directly attributable to Apache’s active exploration and development capital program. An additional $345 million of abandonment costs were recognized for upward revisions to prior-year estimates of timing and costs, particularly in Australia and Canada.

Acquisitions    We acquired $3.5 billion of oil and gas properties and GTP in 2012 compared to $3.2 billion in 2011. 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.

Equity Investment in YPHPL

On January 31, 2012, a subsidiary of Apache Energy Limited completed the acquisition of a 49-percent interest in YPHPL (formerly Burrup Holdings Limited) for $439 million, including working capital adjustments. The transaction was funded with debt. The investment in YPHPL is accounted for under the equity method of accounting, with the balance recorded as a component of “Deferred charges and other” in Apache’s consolidated balance sheet and results of operations recorded as a component of “Other” under “Revenues and Other” in the Company’s statement of consolidated operations.

Payments on Fixed-Rate Notes

During the second quarter of 2012 Apache repaid the $400 million in aggregate principal amount of 6.25-percent notes that matured on April 15, 2012.

Dividends

The Company has paid cash dividends on its common stock for 48 consecutive years through 2012. Future dividend payments will depend on the Company’s level of earnings, financial requirements, and other relevant factors. Common stock dividends paid during 2012 totaled $256 million, compared with $230 million in 2011 and $206 million in 2010. The Company paid dividends on its Series D Preferred Stock totaling $76 million in 2012, compared with $76 million in 2011, and $20 million in 2010.

Based on strong future growth prospects and Apache’s financial position, in the first quarter of 2012 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 applied to the dividend on common shares payable on May 22, 2012, to stockholders of record on April 23, 2012, and subsequent dividends paid.

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In the first quarter of 2013, the Board of Directors approved a further 18-percent increase to $0.20 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, 2013, to stockholders of record on April 22, 2013.

Liquidity

	At December 31,
	2012		2011
	(In millions, except percentages)
Cash and cash equivalents	$	160	$	295
Total debt		12,345		7,216
Shareholders’ equity		31,331		28,993
Available committed borrowing capacity		2,811		3,300
Floating-rate debt/total debt		5%		0.4%
Percent of total debt-to-capitalization		28%		20%

Cash and Cash Equivalents

At December 31, 2012, we had $160 million in cash and cash equivalents, of which $155 million of cash was held by foreign subsidiaries, and approximately $5 million was held by 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, 2012, outstanding debt, which consisted of notes, debentures, commercial paper, and uncommitted bank lines, totaled $12.3 billion. Current debt consists of $500 million of 5.25-percent debentures due in April 2013, $400 million in 6.0-percent debentures due in September 2013, and $91 million borrowed under uncommitted money market/overdraft lines of credit in the U.S., Argentina, and Canada. We have $350 million of debt maturing in 2015, $1 million maturing in 2016, $1.4 billion maturing in 2017, and the remaining $9.7 billion maturing intermittently in years 2018 through 2096.

In April 2012 the Company issued $400 million principal amount of senior unsecured 1.75-percent notes maturing April 15, 2017, $1.1 billion principal amount of senior unsecured 3.25-percent notes maturing April 15, 2022, and $1.5 billion principal amount of senior unsecured 4.75-percent notes maturing April 15, 2043. The notes are redeemable, as a whole or in part, at Apache’s option, subject to a make-whole premium. The Company used the proceeds to fund the cash portion of the purchase price paid to acquire Cordillera, repay the $400 million 6.25-percent notes that matured on April 15, 2012, and for general corporate purposes.

In December 2012 the Company issued $1.2 billion principal amount of senior unsecured 2.625-percent notes maturing January 15, 2023 and $800 million principal amount of senior unsecured 4.25-percent notes maturing January 15, 2044. The notes are redeemable, as a whole or in part, at Apache’s option, subject to a make-whole premium. The Company used the proceeds to pay down commercial paper and for general corporate purposes.

Available Credit Facilities

On June 4, 2012, the Company entered into a new Global Credit Facility consisting of a $1.7 billion revolving syndicated bank credit facility for the U.S., a $300 million revolving syndicated bank credit facility for Australia, and a $300 million revolving syndicated bank credit facility for Canada, which replaced the

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Company’s existing syndicated bank credit facilities that were scheduled to mature in May 2013. The new facilities are scheduled to mature on June 4, 2017. There were no changes to the Company’s $1.0 billion U.S. credit facility that matures on August 12, 2016.

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 $1.7 billion credit facility also allows the Company to borrow under competitive auctions.

At December 31, 2012, the margin over LIBOR for committed loans was 0.875 percent on the $1.0 billion U.S. credit facility and 0.90 percent on each of the $1.7 billion U.S. credit facility, the $300 million Australian credit facility, and the $300 million Canadian credit facility. The Company also pays quarterly facility fees of 0.125 percent on the total amount of the $1.0 billion facility and 0.10 percent on the total amount of the other three facilities. The facility fees vary based upon the Company’s senior long-term debt rating.

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, 2012, the Company’s debt-to-capitalization ratio was 28 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 5 percent of the Company’s consolidated assets, or approximately $3.0 billion as of December 31, 2012. 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 the stated thresholds noted in the agreements or has any unpaid, non-appealable judgment against it in excess of the stated thresholds noted in the agreements. The Company was in compliance with the terms of the credit facilities as of December 31, 2012.

There is no assurance that the financial condition of banks with lending commitments to the Company will not deteriorate. We closely monitor the ratings of the 24 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

In June 2012 the Company increased the size of its commercial paper program from $2.95 billion to $3.0 billion, which generally enables Apache to borrow funds for up to 270 days at competitive interest rates. Our 2012 weighted-average interest rate for commercial paper was 0.43 percent. If the Company is unable to issue commercial paper following a significant credit downgrade or dislocation in the market, the Company’s committed credit facilities, which expire in 2016 and 2017, are available as a 100-percent backstop. As of December 31, 2012, the Company had $489 million in commercial paper outstanding.

Total Debt-to-Capitalization

The Company’s debt-to-capitalization ratio as of December 31, 2012 was 28 percent as compared to 20 percent at December 31, 2011. The increase in our debt-to-capitalization ratio is directly related to the 2012 notes issued for funding the Cordillera acquisition, to pay down commercial paper balances, and for general corporate

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purposes. Apache has historically utilized available committed borrowing capacity, access to both debt and equity capital markets, and proceeds from the occasional sale of nonstrategic assets for liquidity and capital resources 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 commitments or contingencies.

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, 2012. 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 (1)	Note Reference	Total		2013		2014-2015		2016-2017		2018 & Beyond
	(In millions)
Debt, at face value	Note 6	$	12,411	$	991	$	350	$	1,390	$	9,680
Interest payments	Note 6		11,007		533		1,035		994		8,445
Drilling rig commitments (2)	Note 8		896		602		289		3		2
Purchase obligations (3)	Note 8		2,588		1,200		1,182		184		22
Firm transportation agreements	Note 8		763		148		264		134		217
Office and related equipment	Note 8		402		49		91		96		166
Other operating lease obligations (4)	Note 8		754		209		316		205		24
Total Contractual Obligations		$	28,821	$	3,732	$	3,527	$	3,006	$	18,556

⁽¹⁾  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, 9, and 7, respectively, in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.

⁽²⁾  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.

⁽³⁾  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, including LNG facilities.

⁽⁴⁾  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.

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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 $104 million for environmental remediation and approximately $12 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 $108 million accrued as of December 31, 2012, 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 policies that include 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 $660 million 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 Overseas Private Investment Corporation (OPIC) and other highly rated international insurers covering its investments in Egypt. In the aggregate, these insurance 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 $263 million sub-limit for currency inconvertibility.

In addition, the Company has a separate policy with OPIC, which provides $300 million of coverage 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 in the event that actions taken by the government of Egypt prevent Apache from exporting our share of production. In October 2012, the Multilateral Investment Guarantee Agency (MIGA), a member of the World Bank Group, announced that it was providing $150 million in reinsurance to OPIC for the remainder of the policy term. This provision of long-term reinsurance to OPIC will allow Apache to maintain the $300 million of insurance coverage through 2024.

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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,
	2012		2011		2010
	(In millions, except per share data)
Income (Loss) Attributable to Common Stock (GAAP)	$	1,925	$	4,508	$	3,000
Adjustments:
Canada and other oil & gas property write-down, net of tax (1)		1,427		60		–
Deferred tax adjustments		226		(75)		–
U.K. income tax adjustments		118		218		–
Commodity derivative mark-to-market, net of tax (3)		51		–		–
Merger, acquisitions & transition, net of tax (2)		19		13		120
Unrealized foreign currency fluctuation impact on deferred tax expense		1		(73)		52
Adjusted Earnings (Non-GAAP)	$	3,767	$	4,651	$	3,172
Net Income per Common Share – Diluted (GAAP)	$	4.92	$	11.47	$	8.46
Adjustments:
Canada and other oil & gas property write-down, net of tax (1)		3.53		0.15		–
Deferred tax adjustments		0.56		(0.19)		–
U.K. income tax adjustments		0.30		0.55		–
Commodity derivative mark-to-market, net of tax (3)		0.13		–		–
Merger, acquisitions & transition, net of tax (2)		0.04		0.03		0.33
Unrealized foreign currency fluctuation impact on deferred tax expense		–		(0.18)		0.15
Adjusted Earnings Per Share – Diluted (Non-GAAP)	$	9.48	$	11.83	$	8.94

⁽¹⁾  A non-cash write-down on the carrying value of our proved oil and gas property balances in Canada of $1.9 billion was recorded during 2012, for which a tax benefit of $474 million was recognized. The tax effect was calculated utilizing the Canadian statutory rate currently in effect.

⁽²⁾  Merger, acquisitions & transition costs recorded in 2012, 2011, and 2010, totaled $31 million, $20 million, and $183 million, respectively, for which a tax benefit of $13 million, $7 million, and $63 million was recognized, respectively. The tax effect was calculated utilizing the statutory rates in effect in each country where costs were incurred.

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⁽³⁾  Commodity derivative mark-to-market losses recorded in 2012 totaled $79 million, for which a tax benefit of $28 million was recognized.

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 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.

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, 2012, 2011, and 2010, 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,

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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 relate 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.

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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 because of unpredictable events such as economic growth or retraction, weather and political climate. In 2012, our average crude oil realizations have remained flat at $102.53 per barrel in 2012 compared to $102.19 per barrel in 2011. Our average natural gas price realizations decreased 13 percent in 2012 to $3.80 per Mcf from $4.37 per Mcf in 2011.

We periodically enter into derivative positions on a portion of our projected oil and natural gas production through a variety of financial and physical arrangements intended to manage fluctuations in cash flows resulting from changes in commodity prices. Apache typically uses futures contracts, swaps, and options to mitigate commodity price risk. In 2012 approximately 13 percent of our natural gas production and approximately 13 percent of our crude oil production was subject to financial derivative hedges, compared with 16 percent and 29 percent, respectively, in 2011.

On December 31, 2012, the Company had open natural gas derivatives in an asset position with a fair value of $48 million. A 10-percent increase in natural gas prices would reduce the fair value by approximately $5 million, while a 10-percent decrease in prices would increase the fair value by approximately $5 million. The Company also had open oil derivatives in a liability position with a fair value of $131 million. A 10-percent increase in oil prices would increase the liability by approximately $438 million, while a 10-percent decrease in prices would move the derivatives to an asset position of $296 million. These fair value changes assume volatility based on prevailing market parameters at December 31, 2012. 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.

Interest Rate Risk

The Company considers its interest rate risk exposure to be minimal as a result of fixing interest rates on approximately 95 percent of the Company’s debt. At December 31, 2012, total debt included $580 million of floating-rate debt. As a result, Apache’s annual interest costs will fluctuate based on short-term interest rates on approximately 5 percent of our total debt outstanding at December 31, 2012. A 10 percent change in floating interest rates on year-end floating debt balances would change annual interest expense by approximately $1.4 million.

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 under a combination of Australian dollar and U.S. dollar fixed-price 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

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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 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, 2012, would result in a foreign currency net loss or gain, respectively, of approximately $157 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, 2012, 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 derivative and 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;

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• the availability of goods and services;

• legislative or regulatory changes, including hydraulic-fracturing regulation and environmental regulation;

• the impact on our operations due to changes in the Egyptian government;

• 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.

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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-72 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, 2012, 2011, and 2010, included in this report, have been audited by Ernst & Young LLP, registered public accounting firm, as stated in their audit report appearing herein. There have been no changes in or disagreements with the accountants during the periods presented.

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, 2012, 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, 2012, 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 the “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, 2012, that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

ITEM 9B.   OTHER INFORMATION

None.

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PART III

ITEM 10.  DIRECTORS, EXECUTIVE OFFICERS 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 2013 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. Information on our website or any other website is not incorporated by reference into, and does not constitute a part of, this Annual Report on Form 10-K.

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.

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PART IV

ITEM 15.    EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a) Documents included in this report:

1. 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, 2012	F-4
Statement of consolidated comprehensive income for each of the three years in the period ended December 31, 2012	F-5
Statement of consolidated cash flows for each of the three years in the period ended December  31, 2012	F-6
Consolidated balance sheet as of December 31, 2012 and 2011	F-7
Statement of consolidated shareholders’ equity for each of the three years in the period ended December 31, 2012	F-8
Notes to consolidated financial statements	F-9

2. 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.

3. 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).

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EXHIBIT NO.		DESCRIPTION
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).
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).

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EXHIBIT NO.		DESCRIPTION
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).
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	–	Form of 1.75% Notes due 2017 (incorporated by reference to Exhibit 4.1 to Registrant’s Current Report on Form 8-K, dated April 3, 2012, filed on April 9, 2012, SEC File No. 001-4300).
4.7	–	Form of 3.25% Note due 2022 (incorporated by reference to Exhibit 4.2 to Registrant’s Current Report on Form 8-K, dated April 3, 2012, filed on April 9, 2012, SEC File No. 001-4300).
4.8	–	Form of 4.75% Notes due 2043 (incorporated by reference to Exhibit 4.3 to Registrant’s Current Report on Form 8-K, dated April 3, 2012, filed on April 9, 2012, SEC File No. 001-4300).
4.9	–	Form of 2.625% Notes due 2023 (incorporated by reference to Exhibit 4.1 to Registrant’s Current Report on Form 8-K, dated November 28, 2012, filed on December 4, 2012, SEC File No. 001-4300).
4.10	–	Form of 4.250% Notes due 2044 (incorporated by reference to Exhibit 4.2 to Registrant’s Current Report on Form 8-K, dated November 28, 2012, filed on December 4, 2012, SEC File No. 001-4300).
4.11	–	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).
4.12	–	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).

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EXHIBIT NO.		DESCRIPTION
4.13	–	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).
4.14	–	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).
4.15	–	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).
4.16	–	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).
4.17	–	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).
4.18	–	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).
4.19	–	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).

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EXHIBIT NO.		DESCRIPTION
4.20	–	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).
4.21	–	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).
4.22	–	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).
4.23	–	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).
4.24	–	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).

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EXHIBIT NO.		DESCRIPTION
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).
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).

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EXHIBIT NO.		DESCRIPTION
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, JPMorgan 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).
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	–	Credit Agreement, dated as of June 4, 2012, among Apache Corporation, the lenders party thereto, JPMorgan Chase Bank, N.A., as Global Administrative Agent, Bank of America, N.A. and Citibank, N.A., as Global Syndication Agents, and The Royal Bank of Scotland plc and Royal Bank of Canada, as Global Documentation Agents (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed June 7, 2012, SEC File No. 001-04300).
10.12	–	Credit Agreement, dated as of June 4, 2012, among Apache Canada Ltd., the lenders party thereto, JPMorgan Chase Bank, N.A., as Global Administrative Agent, Royal Bank of Canada, as Canadian Administrative Agent, Bank of America, N.A. and Citibank, N.A., as Global Syndication Agents, and The Royal Bank of Scotland plc and Royal Bank of Canada, as Global Documentation Agents (incorporated by reference to Exhibit 10.2 to Registrant’s Current Report on Form 8-K filed June 7, 2012, SEC File No. 001-04300).

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EXHIBIT NO.		DESCRIPTION
10.13	–	Syndicated Facility Agreement, dated as of June 4, 2012, among Apache Energy Limited (ACN 009 301 964), the lenders party thereto, JPMorgan Chase Bank, N.A., as Global Administrative Agent, Citisecurities Limited (ABN 51 008 489 610), as Australian Administrative Agent, Bank of America, N.A. and Citibank, N.A., as Global Syndication Agents, and The Royal Bank of Scotland plc and Royal Bank of Canada, as Global Documentation Agents (incorporated by reference to Exhibit 10.3 to Registrant’s Current Report on Form 8-K filed June 7, 2012, SEC File No. 001-04300).
†10.14	–	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).
†10.15	–	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).
†10.16	–	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).
†10.17	–	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).
†10.18	–	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).
†10.19	–	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).
†10.20	–	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).

78

EXHIBIT NO.		DESCRIPTION
†10.21	–	Amendment to Apache Corporation 401(k) Savings Plan, dated December 19, 2011, effective January 1, 2012, except as otherwise specified (incorporated by reference to Exhibit 10.18 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2011, SEC File No. 001-4300).
*†10.22	–	Amendment to Apache Corporation 401(k) Savings Plan, dated November 8, 2012, effective January 1, 2012.
†10.23	–	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).
†10.24	–	Amendment to Apache Corporation Non-Qualified Retirement/Savings Plan of Apache Corporation, dated December 19, 2011, effective January 1, 2012 (incorporated by reference to Exhibit 10.20 to Registrant’s Annual Report Form 10-K for year ended December 31, 2011, SEC File No. 001-4300).
*†10.25	–	Amendment to Non-Qualified Retirement/Savings Plan of Apache Corporation, dated November 8, 2012, effective January 1, 2013.
†10.26	–	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).
*†10.27	–	Amendment to Non-Qualified Restorative Retirement Savings Plan of Apache Corporation, dated November 8, 2012, effective January 1, 2013.
†10.28	–	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).
†10.29	–	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).
†10.30	–	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).
†10.31	–	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).

79

EXHIBIT NO.		DESCRIPTION
†10.32	–	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).
†10.33	–	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).
†10.34	–	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).
†10.35	–	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).
†10.36	–	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).
†10.37	–	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).
*†10.38	–	Apache Corporation Deferred Delivery Plan, as amended and restated February 5, 2013.
*†10.39	–	Apache Corporation Non-Employee Directors’ Compensation Plan, as amended and restated February 6, 2013.
*†10.40	–	Apache Corporation Outside Directors’ Retirement Plan, as amended and restated February 6, 2013.
†10.41	–	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).
†10.42	–	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).

80

EXHIBIT NO.		DESCRIPTION
†10.43	–	Apache Corporation Non-Employee Directors’ Restricted Stock Units Program Specifications, as amended and restated July 19, 2012, pursuant to Apache Corporation 2011 Omnibus Equity Compensation Plan (incorporated by reference to Exhibit 10.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2012, SEC File No. 001-4300).
†10.44	–	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).
†10.45	–	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).
†10.46	–	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).
†10.47	–	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).
†10.48	–	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).
†10.49	–	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).
†10.50	–	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).
†10.51	–	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).

81

EXHIBIT NO.		DESCRIPTION
†10.52	–	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).
†10.53	–	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).
†10.54	–	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).
†10.55	–	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).
†10.56	–	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).
†10.57	–	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).
†10.58	–	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).
†10.59	–	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).
†10.60	–	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).

82

EXHIBIT NO.		DESCRIPTION
†10.61	–	Form of 2013 Performance Program Agreement, dated January 9, 2013, between Registrant and each of G. Steven Farris, Rodney J. Eichler, Roger B. Plank, 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.
14.1	–	Code of Business Conduct, as amended and restated November 15, 2011 (incorporated by reference to Exhibit 14.1 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2011, SEC File No. 001-4300).
*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.

83

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, 2013

POWER OF ATTORNEY

The officers and directors of Apache Corporation, whose signatures appear below, hereby constitute and appoint G. Steven Farris, Thomas P. Chambers, P. Anthony Lannie and Rebecca A. Hoyt, and each of them (with full power to each of them to act alone), the true and lawful attorney-in-fact to sign and execute, on behalf of the undersigned, any amendment(s) to this report and each of the undersigned does hereby ratify and confirm all that said attorneys shall do or cause to be done by virtue thereof.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Name	Title	Date
/s/ G. STEVEN FARRIS G. Steven Farris	Chairman of the Board and Chief Executive Officer (principal executive officer)	February 28, 2013
/s/ THOMAS P. CHAMBERS Thomas P. Chambers	Executive Vice President and Chief Financial Officer (principal financial officer)	February 28, 2013
/s/ REBECCA A. HOYT Rebecca A. Hoyt	Vice President, Chief Accounting Officer and Controller (principal accounting officer)	February 28, 2013

84

Name	Title	Date
/s/ RANDOLPH M. FERLIC	Director	February 28, 2013
Randolph M. Ferlic
/s/ EUGENE C. FIEDOREK	Director	February 28, 2013
Eugene C. Fiedorek
/s/ A.D. FRAZIER, JR.	Director	February 28, 2013
A. D. Frazier, Jr.
/s/ PATRICIA ALBJERG GRAHAM	Director	February 28, 2013
Patricia Albjerg Graham
/s/ SCOTT D. JOSEY	Director	February 28, 2013
Scott D. Josey
/s/ CHANSOO JOUNG	Director	February 28, 2013
Chansoo Joung
/s/ JOHN A. KOCUR	Director	February 28, 2013
John A. Kocur
/s/ GEORGE D. LAWRENCE	Director	February 28, 2013
George D. Lawrence
/s/ WILLIAM C. MONTGOMERY	Director	February 28, 2013
William C. Montgomery
/s/ RODMAN D. PATTON	Director	February 28, 2013
Rodman D. Patton
/s/ CHARLES J. PITMAN	Director	February 28, 2013
Charles J. Pitman

85

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, 2012. 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, 2012.

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, 2013

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, 2012 and 2011, and the related consolidated statements of operations, comprehensive income, shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2012. 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, 2012 and 2011, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, in conformity with U.S. generally accepted accounting principles.

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, 2012, 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, 2013, expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Houston, Texas

February 28, 2013

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, 2012, 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, 2012, 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, 2012 and 2011, and the related consolidated statements of operations, comprehensive income, shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2012 of Apache Corporation and subsidiaries, and our report dated February 28, 2013, expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Houston, Texas

February 28, 2013

F-3

APACHE CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED OPERATIONS

	For the Year Ended December 31,
	2012		2011		2010
	(In millions, except per common share data)
REVENUES AND OTHER:
Oil and gas production revenues	$	16,947	$	16,810	$	12,183
Other		131		78		(91	)
		17,078		16,888		12,092
OPERATING EXPENSES:
Depreciation, depletion, and amortization:
Recurring		5,183		4,095		3,083
Additional		1,926		109		—
Asset retirement obligation accretion		232		154		111
Lease operating expenses		2,968		2,605		2,032
Gathering and transportation		303		296		178
Taxes other than income		862		899		690
General and administrative		531		459		380
Merger, acquisitions & transition		31		20		183
Financing costs, net		165		158		229
		12,201		8,795		6,886
INCOME BEFORE INCOME TAXES		4,877		8,093		5,206
Current income tax provision		2,199		2,263		1,222
Deferred income tax provision		677		1,246		952
NET INCOME		2,001		4,584		3,032
Preferred stock dividends		76		76		32
INCOME ATTRIBUTABLE TO COMMON STOCK	$	1,925	$	4,508	$	3,000
NET INCOME PER COMMON SHARE:
Basic	$	4.95	$	11.75	$	8.53
Diluted	$	4.92	$	11.47	$	8.46
WEIGHTED-AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
Basic		389		384		352
Diluted		391		400		359
DIVIDENDS DECLARED PER COMMON SHARE	$	0.68	$	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

	For the Year Ended December 31,
	2012			2011			2010
	(In millions)
NET INCOME	$	2,001		$	4,584		$	3,032
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and postretirement benefit plan, net of tax		(2	)		(1	)		(2	)
Commodity cash flow hedge activity, net of tax:
Reclassification of (gain) loss on settled derivative instruments		(199	)		19			(106	)
Change in fair value of derivative instruments		79			115			256
Derivative hedge ineffectiveness reclassified into earnings		—			(1	)		1
		(122	)		132			149
COMPREHENSIVE INCOME		1,879			4,716			3,181
Preferred stock dividends		76			76			32
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON STOCK	$	1,803		$	4,640		$	3,149

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,
	2012			2011			2010
	(In millions)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	2,001		$	4,584		$	3,032
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, and amortization		7,109			4,204			3,083
Asset retirement obligation accretion		232			154			111
Provision for deferred income taxes		677			1,246			952
Other		226			46			190
Changes in operating assets and liabilities:
Receivables		12			(759	)		(496	)
Inventories		(59	)		(37	)		35
Drilling advances		(343	)		26			(28	)
Deferred charges and other		61			27			(141	)
Accounts payable		(100	)		241			214
Accrued expenses		(1,142	)		90			(309	)
Deferred credits and noncurrent liabilities		(170	)		131			83
NET CASH PROVIDED BY OPERATING ACTIVITIES		8,504			9,953			6,726
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property		(8,781	)		(6,414	)		(4,407	)
Additions to gas gathering, transmission, and processing facilities		(750	)		(664	)		(515	)
Acquisition of Cordillera Energy Partners III, LLC		(2,666	)		—			—
Acquisition of Yara Pilbara Holdings Pty Limited		(439	)		—			—
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		(252	)		(567	)		(126	)
Proceeds from sale of oil and gas properties		27			422			—
Other, net		(563	)		(176	)		(121	)
NET CASH USED IN INVESTING ACTIVITIES		(13,424	)		(8,645	)		(13,403	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Commercial paper, credit facility and bank notes, net		549			(925	)		(32	)
Fixed rate debt borrowings		4,978			—			2,470
Payments on fixed rate debt		(400	)		—			(1,023	)
Proceeds from issuance of common stock		—			—			2,258
Proceeds from issuance of mandatory convertible preferred stock		—			—			1,227
Dividends paid		(332	)		(306	)		(226	)
Other		(10	)		84			89
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		4,785			(1,147	)		4,763
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(135	)		161			(1,914	)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR		295			134			2,048
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	160		$	295		$	134
SUPPLEMENTARY CASH FLOW DATA:
Interest paid, net of capitalized interest	$	146		$	156		$	187
Income taxes paid, net of refunds		2,590			1,686			1,170

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,
	2012			2011
	(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	160		$	295
Receivables, net of allowance		3,086			3,079
Inventories		908			655
Drilling advances		584			229
Derivative instruments		31			304
Prepaid assets and other		193			241
		4,962			4,803
PROPERTY AND EQUIPMENT:
Oil and gas, on the basis of full-cost accounting:
Proved properties		78,383			67,805
Unproved properties and properties under development, not being amortized		8,754			5,530
Gathering, transmission, and processing facilities		5,955			5,175
Other		1,055			709
		94,147			79,219
Less: Accumulated depreciation, depletion, and amortization		(40,867	)		(33,771	)
		53,280			45,448
OTHER ASSETS:
Goodwill		1,289			1,114
Deferred charges and other		1,206			686
	$	60,737		$	52,051
LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	1,092		$	1,048
Current debt		990			431
Current asset retirement obligation		478			447
Derivative instruments		116			113
Other current liabilities		2,860			2,924
		5,536			4,963
LONG-TERM DEBT		11,355			6,785
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes		8,024			7,197
Asset retirement obligation		4,100			3,440
Other		391			673
		12,515			11,310
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, 392,712,245 and 385,249,885 shares issued, respectively		245			241
Paid-in capital		9,859			9,066
Retained earnings		20,161			18,500
Treasury stock, at cost, 1,071,475 and 1,132,242 shares, respectively		(30	)		(32	)
Accumulated other comprehensive loss		(131	)		(9	)
		31,331			28,993
	$	60,737		$	52,051

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 D Preferred Stock		Common Stock		Paid-In Capital			Retained Earnings			Treasury Stock			Accumulated Other Comprehensive (Loss)			Total Shareholders’ Equity
	(In millions)
BALANCE AT DECEMBER 31, 2009	$	—	$	215	$	4,634		$	11,437		$	(217	)	$	(290	)	$	15,779
Net income		—		—		—			3,032			—			—			3,032
Postretirement, net of tax expense of $2		—		—		—			—			—			(2	)		(2	)
Commodity hedges, net of tax expense of $62		—		—		—			—			—			151			151
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 tax benefit of $7		—		—		—			—			—			(1	)		(1	)
Commodity hedges, net of tax expense of $66		—		—		—			—			—			133			133
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
Net income		—		—		—			2,001			—			—			2,001
Postretirement, net of income tax benefit of $5		—		—		—			—			—			(2	)		(2	)
Commodity hedges, net of tax benefit of $35		—		—		—			—			—			(120	)		(120	)
Dividends:
Preferred		—		—		—			(76	)		—			—			(76	)
Common ($0.68 per share)		—		—		—			(264	)		—			—			(264	)
Common shares issued		—		3		598			—			—			—			601
Common stock activity, net		—		1		(44	)		—			—			—			(43	)
Treasury stock activity, net		—		—		1			—			2			—			3
Compensation expense		—		—		238			—			—			—			238
BALANCE AT DECEMBER 31, 2012	$	1,227	$	245	$	9,859		$	20,161		$	(30	)	$	(131	)	$	31,331

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. Apache also pursues exploration interests in other countries that may over time result in reportable discoveries.

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 other 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), the assessment of asset retirement obligations (see Note 5 — Asset Retirement Obligation), and the valuation of income taxes (see Note 7 — Income Taxes).

Fair Value Measurements

Certain assets and liabilities are reported at fair value on a recurring basis in Apache’s consolidated balance sheet. Accounting Standards Codification (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

F-9

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

techniques to convert future amounts to a single present amount based on current market expectations, including present value techniques, option-pricing models, and the 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).

Fair value measurements are presented in further detail in Note 3 — Derivative Instruments, Hedging Activities, Note 6 — Debt, and Note 9 — Retirement and Deferred Compensation Plans.

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, 2012 and 2011, Apache had $160 million and $295 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 approximates 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 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, 2012 and 2011, the Company had an allowance for doubtful accounts of $82 million and $58 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 combinations, 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 $404 million, $335 million, and $321 million of internal costs in 2012, 2011, and 2010, respectively.

F-10

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 proved reserves), and asset retirement costs, 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 immediately. 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. In countries 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 2012, Apache’s statement of consolidated operations includes additional DD&A of $28 million related to exiting operations in New Zealand and $15 million of seismic costs incurred in countries where it has no established presence. In 2011, Apache recorded additional DD&A of $60 million related to exiting operations in Chile and $49 million of seismic costs incurred in countries where it has no established presence.

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. Future cash outflows associated with settling accrued asset retirement obligations are excluded from the calculation. 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. See Note 14 — Supplemental Oil and Gas Disclosures for a discussion of the calculation of estimated future net cash flows.

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. During 2012, the Company recorded a $1.9 billion ($1.4 billion net of tax) non-cash write-down of the carrying value of the Company’s Canadian proved oil and gas properties. Excluding the effects of cash flow hedges in calculating the ceiling limitation, the write-down for the full year would have been higher by $135 million ($101 million net of tax). As of December 31, 2011 and 2010, capitalized costs did not exceed the ceiling limitation, and no write-down was indicated. Cash flow hedges did not materially affect the 2011 or 2010 calculations.

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.

Gathering, Transmission, and Processing Facilities

Gathering, transmission, and processing facilities totaled $6.0 billion and $5.2 billion at December 31, 2012 and 2011, respectively. 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

F-11

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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. No impairment of gathering, transmission, and processing facilities was recognized during 2012, 2011, or 2010.

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 $1.9 billion and $1.5 billion at December 31, 2012 and 2011, respectively.

Asset Retirement Costs and Obligations

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.

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 for impairment annually and when impairment indicators arise. Goodwill totaled $1.3 billion and $1.1 billion at December 31, 2012 and 2011, respectively. Goodwill of $173 million was booked in the U.S. during 2012 as a result of the acquisition of Cordillera Energy Partners III, LLC, as discussed in Note 2 — Acquisitions and Divestitures. As of December 31, 2012 and 2011, $1.0 billion and $843 million was recorded in the U.S. and $84 million and $82 million in the North Sea, respectively. As of December 31, 2012 and 2011, $103 million and $86 million were recorded in Canada and Egypt, respectively. Each country was assessed as a reporting unit, and no impairment of goodwill was recognized during 2012, 2011, or 2010.

Accounts Payable

Included in accounts payable at December 31, 2012 and 2011, are liabilities of approximately $255 million and $207 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 collectability of the revenue is probable. Cash received relating to future revenues is deferred and recognized when all revenue recognition criteria are met.

F-12

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 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 $27 million, $28 million, and $33 million, for 2012, 2011, and 2010, 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.

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.

F-13

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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.

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 components of the provision for income taxes. In 2012, the Company recorded a net tax expense of $16 million, including a current tax expense of $26 million and deferred tax benefit of $10 million. Included in deferred tax benefit for 2012 is approximately $11 million of tax benefit attributable to realized foreign currency transactions. In 2011, the Company recorded a net tax benefit of $66 million, including a current tax expense of $1 million and deferred tax benefit of $67 million. Included in deferred tax benefit for 2011 is approximately $6 million of tax expense attributable to realized foreign currency transactions. In 2010, the Company recorded net tax expense of $111 million, including a current tax expense of $2 million and deferred tax expense of $109 million. Included in deferred tax expense for 2010 is approximately $57 million of tax expense attributable to realized foreign currency transactions. 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 2012 and 2011 of $24 million and $4 million, respectively, and a loss of $39 million in 2010.

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.

F-14

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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.

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. Additionally, the Company also grants cash-based stock appreciation rights. These plans and related accounting policies are defined and described more fully in Note 10 — 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 $4 million, $32 million, and $28 million as financing cash inflows in 2012, 2011, and 2010, respectively.

Treasury Stock

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

New Pronouncements Issued But Not Yet Adopted

In December 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (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 U.S. GAAP and International Financial Reporting Standards (IFRS) related to the offsetting of financial instruments. The existing U.S. GAAP guidance allowing balance sheet offsetting, including industry-specific guidance, remains unchanged. ASU No. 2013-01, released in January 2013, offers clarification on the scope of ASU No. 2011-11 as it applies to derivatives accounted for in accordance with Topic 815. The guidance in ASU No. 2011-11 and No. 2013-01 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 impact its consolidated financial statements.

In February 2013, the FASB issued ASU No. 2013-02, which requires preparers to report, in one place, information about reclassifications out of accumulated other comprehensive income (AOCI). The ASU also requires companies to report changes in AOCI balances. The guidance in ASU No. 2013-02 is effective for annual and interim periods beginning after December 15, 2012. The Company does not expect the adoption of this amendment to impact its consolidated financial statements.

F-15

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

2.    ACQUISITIONS AND DIVESTITURES

2012 Activity

Cordillera Energy Partners III, LLC Acquisition

On April 30, 2012, Apache completed the acquisition of Cordillera Energy Partners III, LLC (Cordillera), a privately-held exploration and production company, in a stock and cash transaction. Cordillera’s properties include approximately 312,000 net acres in the Granite Wash, Tonkawa, Cleveland, and Marmaton plays in western Oklahoma and the Texas Panhandle. The effective date of the transaction was September 1, 2011.

Apache issued 6,272,667 shares of common stock and paid approximately $2.7 billion of cash to the sellers as consideration for the transaction. The cash paid at closing was funded with a portion of the proceeds from the Company’s April 2012 public note offering. For further discussion of this equity issuance, please see Note 10 — Capital Stock of this Form 10-K. For further discussion of the note offering, please see Note 6 — Debt and Financing Costs of this Form 10-K.

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 final estimates of the assets acquired and liabilities assumed in the acquisition.

	(In millions)
Current assets	$	39
Proved properties		1,040
Unproved properties		2,299
Gathering, transmission, and processing facilities		1
Goodwill(1)		173
Deferred tax asset		64
Total assets acquired	$	3,616
Current liabilities		88
Deferred income tax liabilities		237
Other long-term obligations		5
Total liabilities assumed	$	330
Net assets acquired	$	3,286

⁽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.

Yara Pilbara Holdings Pty Limited Acquisition

On January 31, 2012, a subsidiary of Apache Energy Limited completed the acquisition of a 49-percent interest in Yara Pilbara Holdings Pty Limited (YPHPL, formerly Burrup Holdings Limited) for $439 million, including working capital adjustments. The transaction was funded with debt. YPHPL is the owner of an ammonia plant on the Burrup Peninsula of Western Australia. Apache has supplied gas to the plant since operations commenced in 2006. Yara Australia Pty Ltd (Yara) owns the remaining 51 percent of YPHPL and operates the plant. In addition, Apache also acquired an interest in a planned technical ammonia nitrate plant to

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

be developed with Yara and Orica Limited. The investment in YPHPL is accounted for under the equity method of accounting, with the balance recorded as a component of “Deferred charges and other” in Apache’s consolidated balance sheet and results of operations recorded as a component of “Other” under “Revenues and Other” in the Company’s statement of consolidated operations.

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. The following table summarizes the final estimates of the assets acquired and liabilities assumed in the acquisition.

	(In millions)
Current assets	$	219
Proved properties		2,341
Unproved properties		476
Gathering, transmission, and processing facilities		338
Goodwill(1)		84
Total assets acquired	$	3,458
Current liabilities		148
Asset retirement obligation		517
Deferred income tax liabilities		1,546
Other long-term obligations		1
Total liabilities assumed	$	2,212
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

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

date of the transactions was July 1, 2010. The acquisition of BP’s oil and gas operations, related infrastructure 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, 2010:

	For the Year  Ended December 31, 2010
	(In millions, except per share amounts)
Revenues and Other	$	13,780
Net Income (Loss)	$	3,364
Preferred Stock Dividends		76
Income (Loss) Attributable to Common Stock	$	3,288
Net Income (Loss) per Common Share — Basic	$	8.62
Net Income (Loss) per Common Share — Diluted	$	8.52

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

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

have been had the acquisitions and merger been completed on January 1, 2010. 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 2012, Apache recorded $31 million of expenses reflecting additional costs related to our 2011 acquisition of Mobil North Sea Limited and expenses associated with our 2012 acquisition of Cordillera. 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. 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.

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. Apache manages the variability in its cash flows by occasionally entering into derivative transactions 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.

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

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

institutions, for its derivative transactions. As of December 31, 2012, Apache had derivative positions with 15 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, 2012, Apache had the following open crude oil derivative positions:

	Fixed-Price Swaps				Collars
Production Period	Mbbls(2)		Weighted Average Fixed Price(1)		Mbbls(2)		Weighted Average Floor Price(1)		Weighted Average Ceiling Price(1)
2013		40,292	$	97.31		5,701	$	82.84	$	111.63
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 NYMEX WTI Cushing Index and Platts Dated Brent. Approximately 50 percent of 2013 contracts are settled against Dated Brent.

⁽²⁾  For 2013, fixed-price swaps of 38,320 Mbbls have not been designated as cash flow hedges, and changes in fair value are reflected directly in earnings. All other derivative positions have been designated as cash flow hedges.

As of December 31, 2012, Apache had the following open natural gas derivative positions which have all been designated as cash flow hedges:

	Fixed-Price Swaps				Collars
Production Period	MMBtu (in 000’s)		Weighted Average Fixed Price(1)		MMBtu (in 000’s)		Weighted Average Floor Price(1)		Weighted Average Ceiling Price(1)
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 against NYMEX Henry Hub.

Fair Value Measurements

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.

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table presents the Company’s derivative assets and liabilities measured at fair value on a recurring basis:

	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, 2012
Assets:
Commodity Derivative Instruments		$—	$	48		$—	$	48	$	(15	)	$	33
Liabilities:
Commodity Derivative Instruments		—		131		—		131		(15	)		116
December 31, 2011
Assets:
Commodity Derivative Instruments		$—	$	428		$—	$	428	$	(96	)	$	332
Liabilities:
Commodity Derivative Instruments		—		250		—		250		(96	)		154

⁽¹⁾  The derivative fair values are based on analysis of each contract on a gross basis, even where the legal right of offset exists.

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, 2012		December 31, 2011
	(In millions)
Current Assets: Derivative instruments	$	31	$	304
Other Assets: Deferred charges and other		2		28
Total Assets	$	33	$	332
Current Liabilities: Derivative instruments	$	116	$	113
Noncurrent Liabilities: Other		—		41
Total Liabilities	$	116	$	154

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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 Income	For the Year Ended December 31,
		2012			2011			2010
		(In millions)
Gain (loss) on cash flow hedges reclassified from accumulated other comprehensive loss	Oil and Gas Production Revenues	$	268		$	(13	)	$	165
Gain (loss) for ineffectiveness on cash flow hedges	Revenues and Other: Other	$	—		$	2		$	(2	)
Loss on derivatives not designated as cash flow hedges	Revenues and Other: Other	$	(79	)	$	—		$	—

Derivative Activity in Accumulated Other Comprehensive Income (Loss)

As of December 31, 2012, a portion of 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:

	For the Year Ended December 31,
	2012						2011						2010
	Before tax			After tax			Before tax			After tax			Before tax			After tax
	(In millions)
Unrealized gain (loss) on derivatives at beginning of year	$	145		$	114		$	(54	)	$	(19	)	$	(267	)	$	(170	)
Realized amounts reclassified into earnings		(268	)		(199	)		13			19			(165	)		(106	)
Net change in derivative fair value		113			79			188			115			376			256
Ineffectiveness reclassified into earnings		—			—			(2	)		(1	)		2			1
Unrealized gain (loss) on derivatives at end of period	$	(10	)	$	(6	)	$	145		$	114		$	(54	)	$	(19	)

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. Included in accumulated other comprehensive loss as of December 31, 2012, is a net loss of approximately $12 million ($7 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.

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

4.    OTHER CURRENT LIABILITIES

The following table provides detail of the Company’s other current liabilities at December 31, 2012 and 2011:

	December 31, 2012		December 31, 2011
	(In millions)
Accrued operating expenses	$	211	$	221
Accrued exploration and development		1,792		1,430
Accrued compensation and benefits		198		180
Accrued interest		160		135
Accrued income taxes		297		533
Accrued U.K. Petroleum Revenue Tax		53		284
Other		149		141
Total Other current liabilities	$	2,860	$	2,924

5.    ASSET RETIREMENT OBLIGATION

The following table describes changes to the Company’s asset retirement obligation (ARO) liability for the years ended December 31, 2012 and 2011:

	2012			2011
	(In millions)
Asset retirement obligation at beginning of year	$	3,887		$	2,872
Liabilities incurred		592			419
Liabilities acquired		72			592
Liabilities settled		(550	)		(549	)
Accretion expense		232			154
Revisions in estimated liabilities		345			399
Asset retirement obligation at end of year		4,578			3,887
Less current portion		(478	)		(447	)
Asset retirement obligation, long-term	$	4,100		$	3,440

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 2012, the company recorded $592 million in abandonment liabilities resulting from Apache’s active exploration and development capital program. An additional $72 million of abandonment obligations were recognized on properties acquired during the year. An additional $345 million of abandonment costs were recognized for upward revisions to prior-year estimates of timing and costs, particularly in Australia and Canada.

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Liabilities settled primarily relate to individual properties, platforms, and facilities plugged and abandoned during the period. Apache continues to have an active abandonment program that is focused in the U.S. Gulf of Mexico and Canada. The Company’s level of abandonment activity is expected to continue, and $478 million has been recorded as a current liability to reflect our estimated expenditures over the next 12 months.

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.

In April 2012 the Company issued $400 million principal amount of senior unsecured 1.75-percent notes maturing April 15, 2017, $1.1 billion principal amount of senior unsecured 3.25-percent notes maturing April 15, 2022, and $1.5 billion principal amount of senior unsecured 4.75-percent notes maturing April 15, 2043. The notes are redeemable, as a whole or in part, at Apache’s option, subject to a make-whole premium. The Company used the proceeds to fund the cash portion of the purchase price paid to acquire Cordillera, repay the $400 million 6.25-percent notes that matured on April 15, 2012, and for general corporate purposes.

In December 2012 the Company issued $1.2 billion principal amount of senior unsecured 2.625-percent notes maturing January 15, 2023 and $800 million principal amount of senior unsecured 4.25-percent notes maturing January 15, 2044. The notes are redeemable, as a whole or in part, at Apache’s option, subject to a make-whole premium. The Company used the proceeds to repay commercial paper borrowings and for general corporate purposes.

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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, 2012 and 2011:

	December 31,
	2012			2011
	(In millions)
U.S.:
Money market lines of credit	$	13		$	—
Commercial paper		489			—
6.25% notes due 2012(1)		—			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
1.75% notes due 2017(1)		400			—
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
3.25% notes due 2022(1)		1,100			—
2.625% notes due 2023(1)		1,200			—
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
4.75% notes due 2043(1)		1,500			—
4.25% notes due 2044(1)		800			—
7.375% debentures due 2047		150			150
7.625% debentures due 2096		150			150
		11,682			6,580
Subsidiary and other obligations:
Argentina overdraft lines of credit		69			31
Canada lines of credit		9			—
Apache Finance Canada 4.375% notes due 2015(1)		350			350
Notes due in 2016 and 2017		1			1
Apache Finance Canada 7.75% notes due 2029		300			300
		729			682
Debt before unamortized discount		12,411			7,262
Unamortized discount		(66	)		(46	)
Total debt	$	12,345		$	7,216
Current maturities	$	(990	)	$	(431	)
Long-term debt	$	11,355		$	6,785

⁽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.

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Debt maturities as of December 31, 2012, excluding discounts, are as follows:

	(In millions)
2013	$	991
2014		—
2015		350
2016		1
2017		1,389
Thereafter		9,680
Total Debt, excluding discounts	$	12,411

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 fair value measurement.

	December 31, 2012				December 31, 2011
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)
Money market lines of credit	$	91	$	91	$	31	$	31
Commercial paper		489		489		—		—
Notes and debentures		11,765		13,340		7,185		8,673
Total Debt	$	12,345	$	13,920	$	7,216	$	8,704

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, 2012, $91 million was drawn on facilities in the U.S., Argentina, and Canada. As of December 31, 2011, $31 million was drawn on facilities in Argentina.

Unsecured Committed Bank Credit Facilities

As of December 31, 2012, the Company had unsecured committed revolving syndicated bank credit facilities totaling $3.3 billion, of which $1.0 billion matures in August 2016 and $2.3 billion matures in June 2017. The facilities consist of a $1.7 billion facility and a $1.0 billion facility for the U.S., a $300 million facility in Australia, and a $300 million facility in Canada. As of December 31, 2012, available borrowing capacity under the Company’s credit facilities was $2.8 billion. The committed credit facilities are used to support Apache’s commercial paper program.

On June 4, 2012, the Company entered into a new Global Credit Facility consisting of a $1.7 billion revolving syndicated bank credit facility for the U.S., a $300 million revolving syndicated bank credit facility for Australia, and a $300 million revolving syndicated bank credit facility for Canada, which replaced the Company’s existing syndicated bank credit facilities that were scheduled to mature in May 2013. The new facilities are scheduled to mature on June 4, 2017. There were no changes to the Company’s $1.0 billion U.S. credit facility that matures on August 12, 2016.

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 $1.7 billion credit facility also allows the Company to borrow under competitive auctions.

At December 31, 2012, the margin over LIBOR for committed loans was 0.875 percent on the $1.0 billion U.S. credit facility and 0.90 percent on each of the $1.7 billion U.S. credit facility, the $300 million Australian credit facility, and the $300 million Canadian credit facility. The Company also pays quarterly facility fees of 0.125 percent on the total amount of the $1.0 billion U.S. facility and 0.10 percent on the total amount of the other three facilities. The facility fees vary based upon the Company’s senior long-term debt rating.

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, 2012, the Company’s debt-to-capitalization ratio was 28 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 5 percent of the Company’s consolidated assets, or approximately $3.0 billion as of December 31, 2012. 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 the stated thresholds noted in the agreements or has any unpaid, non-appealable judgment against it in excess of the stated thresholds noted in the agreements.

The Company was in compliance with the terms of the credit facilities as of December 31, 2012.

Commercial Paper Program

In June 2012, the Company increased the size of its commercial paper program from $2.95 billion to $3.0 billion. This program generally enables Apache to borrow funds for up to 270 days at competitive interest rates. Apache’s 2012 weighted-average interest rate for commercial paper was 0.43 percent. If the Company is unable to issue commercial paper following a significant credit downgrade or dislocation in the market, the Company’s committed credit facilities are available as a 100-percent backstop. The commercial paper program is fully supported by available borrowing capacity under committed credit facilities, which expire in 2016 and 2017. As of December 31, 2012, the Company had $489 million in commercial paper outstanding. There was no outstanding commercial paper at December 31, 2011.

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.

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Financing Costs, Net

Financing costs incurred during the periods are composed of the following:

	For the Year Ended December 31,
	2012			2011			2010
	(In millions)
Interest expense	$	509		$	433		$	345
Amortization of deferred loan costs		7			5			17
Capitalized interest		(334	)		(263	)		(120	)
Interest income		(17	)		(17	)		(13	)
Financing costs, net	$	165		$	158		$	229

The Company has $66 million of debt discounts as of December 31, 2012, which will be charged to interest expense over the life of the related debt issuances. Discount amortization of $3 million, $2 million, and $2 million were recorded as interest expense in 2012, 2011, and 2010, respectively.

As of December 31, 2012 and 2011, the Company had approximately $118 million and $48 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,
	2012		2011		2010
	(In millions)
U.S.	$	1,605	$	2,373	$	1,328
Foreign		3,272		5,720		3,878
Total	$	4,877	$	8,093	$	5,206

The total provision for income taxes consists of the following:

	For the Year Ended December 31,
	2012			2011		2010
	(In millions)
Current taxes:
Federal	$	(150	)	$	64	$	25
State		—			2		4
Foreign		2,349			2,197		1,193
		2,199			2,263		1,222
Deferred taxes:
Federal		596			656		431
State		10			17		7
Foreign		71			573		514
		677			1,246		952
Total	$	2,876		$	3,509	$	2,174

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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,
	2012			2011			2010
	(In millions)
Income tax expense at U.S. statutory rate	$	1,707		$	2,833		$	1,822
State income tax, less federal benefit		6			12			6
Taxes related to foreign operations		773			568			245
Tax credits		(4	)		(15	)		(8	)
Non-deductible merger costs		—			—			6
Current and deferred taxes related to currency fluctuations		16			(66	)		111
Increase in U.K. tax rate		118			218			—
Net change in tax contingencies		(115	)		(6	)		(2	)
Increase in valuation allowance		355			8			12
All other, net		20			(43	)		(18	)
	$	2,876		$	3,509		$	2,174

The net deferred tax liability consists of the following:

	December 31,
	2012			2011
	(In millions)
Deferred tax assets:
Deferred income	$	(33	)	$	(89	)
Federal and state net operating loss carryforwards		(932	)		(236	)
Foreign net operating loss carryforwards		(61	)		(55	)
Tax credits		(78	)		(66	)
Accrued expenses and liabilities		(2	)		(90	)
Total deferred tax assets		(1,106	)		(536	)
Valuation allowance		419			60
Net deferred tax assets		(687	)		(476	)
Deferred tax liabilities:
Other		23			21
Depreciation, depletion and amortization		8,536			7,443
Total deferred tax liabilities		8,559			7,464
Net deferred income tax liability	$	7,872		$	6,988

The Company has recorded a valuation allowance against the net deferred tax asset in Canada. The deferred tax position in Canada changed from a net deferred tax liability as of December 31, 2011 to a net deferred tax asset as of December 31, 2012 on $1.9 billion in non-cash ceiling test write-downs. The Company has assessed the realizability of the net deferred tax asset in Canada and has concluded that it is more likely than not that the net deferred tax asset in Canada will not be realized based on current economic conditions.

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, 2012, the

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undistributed earnings of the foreign subsidiaries amounted to approximately $15.9 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, 2012, the Company had net operating losses as follows:

	December 31, 2012
	Amount		Expiration
	(In millions)
Net operating losses:
U.S. — Federal	$	2,393	2027
U.S. — State		1,648	Various
Canada		6	2014
Australia		94	Indefinite
Argentina		55	2013

The Company has a federal net operating loss carryforward of $2.4 billion. Included in the federal net operating loss carryforward is $543 million of federal net operating losses related to the merger with Mariner and $183 million of federal net operating losses related to the Cordillera acquisition. The Mariner and Cordillera net operating loss carryforwards are subject to annual limitations under Section 382 of the Internal Revenue Code. The Company also had $170 million of capital loss carryforwards in Canada, which have an indefinite carryover period.

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 net operating losses, Argentinian net operating losses, 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:

	2012			2011			2010
	(In millions)
Balance at beginning of year	$	97		$	110		$	123
Additions based on tax positions related to the current year		—			13			(1	)
Reductions for tax positions of prior years		(29	)		(4	)		(12	)
Settlements		(65	)		(22	)		—
Balance at end of year	$	3		$	97		$	110

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, 2012,

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

2011, and 2010 the Company recorded tax expense of $5 million, $6 million, and $12 million, respectively, for interest and penalties. As of December 31, 2012 and 2011, the Company had approximately $6 million and $42 million, respectively, accrued for payment of interest and penalties.

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. In 2012, the Company reached an agreement with IRS Administrative Appeals office regarding the audits of tax years 2004 through 2008. As a result of this agreement, the Company has reduced the unrecognized tax benefit by $65 million. 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. 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
U.S.	2004
Canada	2008
Egypt	1998
Australia	2008
U.K.	2011
Argentina	2005

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 $12 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, results of operations, or liquidity after consideration of recorded accruals. For material matters that Apache believes an unfavorable outcome is reasonably possible, the Company has disclosed the nature of the matter and a range of potential exposure, unless an estimate cannot be made at this time. 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, results of operations, or liquidity.

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 lawsuit 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 known

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as ASSUPA, 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. ASSUPA has recently asserted similar lawsuits and claims against numerous oil and gas producers relating to other geographic areas of Argentina, including claims against a Company subsidiary relating to the Austral basin. While the plaintiffs will seek to make all oil and gas companies jointly liable for each other’s actions in each of these lawsuits, Company subsidiaries will defend on an individual basis and attempt to require the plaintiffs to delineate damages by company. Company subsidiaries intend to defend each case vigorously. It is not certain exactly what the courts will do in these matters as the lawsuit relating to the Neuquén basin is the first of its kind. While it is possible Company subsidiaries may incur liabilities related to the environmental claims, no reasonable prediction can be made as the Company subsidiaries’ exposure related to these lawsuits is not currently determinable.

U.S. Royalty Litigation

In Foster v. Apache Corporation, Civil Action No. CIV-10-0573-HE, in the United States District Court for the Western District of Oklahoma, on August 20, 2012, the United States District Court for the Western District of Oklahoma denied plaintiff’s motion for class certification. The plaintiff filed a motion for reconsideration, which was denied, and has petitioned the United States Court of Appeals for the Tenth Circuit to accept an appeal of the District Court’s ruling denying class certification. Plaintiffs in the Foster case have asserted 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. Apache intends to vigorously defend against these claims.

In 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, following a class certification hearing in the United States District Court for the Southern District of Texas, the parties resolved the matter with no material impact on the Company’s financial position, results of operations, or liquidity, and with the settlement providing for denial of class certification and dismissal of the case.

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, regardless of the value of the underlying property. 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 opined that the cost to restore plaintiffs’ property would be approximately $61 million. Prior to

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trial the court granted Apache’s motions to dismiss the plaintiffs’ claims against Apache. Plaintiffs then settled with the other defendant in the case, BP America, Inc. (BP). BP has demanded that Apache indemnify it for the amount of its settlement with plaintiffs, which is not material to Apache. Apache has rejected BP’s indemnity claim and, further, Apache has demanded that Wagner Oil Company (which purchased Apache’s interest in the subject property) indemnify Apache from and against BP’s claim.

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. Plaintiff’s experts estimated the cost of remediation to be approximately $87 million, and plaintiffs claimed additional damages for canal restoration, among other things, all of which is disputed by the Company’s subsidiary. The parties have resolved the matter with no material impact on the Company’s financial position, results of operations, or liquidity, and with the settlement providing for certain limited remediation activities on the property.

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 pre-empted by federal law, and punitive and exemplary damages. Apache is one of numerous defendants. The District Court has granted defendants’ motion to dismiss plaintiffs’ claims, and plaintiffs have appealed the decision to the United States Court of Appeals for the Fifth Circuit. The overall exposure related to this lawsuit is not currently determinable. While an adverse judgment against Apache is possible, Apache intends to vigorously defend the case. A similar action filed by Comer et al. was previously dismissed in 2011.

Australia Gas Pipeline Force Majeure

In June 2008, 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, Cause No. 2009-79834, 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 Agreement (GSA), interest, and court costs. The Company has filed a motion to dismiss on the ground of forum non conveniens, which is pending.

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On March 24, 2011, another customer, Alcoa of Australia 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. On June 20, 2012, the Supreme Court struck out Alcoa’s claim that the liquidated damages provisions under two long-term contracts are unenforceable as a penalty and also struck out Alcoa’s claim for damages for breach of statutory duty. The Company subsidiaries have filed an appeal in the Supreme Court of Western Australia Court of Appeal asking that Alcoa’s remaining tort claim for economic loss be dismissed or, alternatively, struck out. The appeal is pending.

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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 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 vigorously pursued its defenses, resulting in the dismissal of the prosecution notice by the Magistrates Court of Western Australia on March 29, 2012.

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. That report, prepared by the inspectors in June 2009, was made public by the State government on May 24, 2012. Company subsidiaries disagree with the inspectors’ June 2009 conclusions. Two other government reports were not published by the State and are not

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

referenced by the inspectors. The Magistrates Court of Western Australia subsequently ordered that both such reports could be released on the basis that the inspectors’ June 2009 report “came with some limitations” and the two other government reports “together were part and parcel if not the main reason or the only reason…certainly a significant contribution to the reason for the matter not proceeding to prosecution and trial.” In the first such report, the State’s senior investigator said in February 2009 that the prospects of a successful prosecution of Apache for failing to maintain the pipeline “would be slight.” In the second such report, the State’s lead corrosion expert concluded in July 2011 that Apache “had reasonable grounds to believe that the pipeline was in good repair” prior to the explosion.

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 of 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. On September 27, 2012, the court dismissed plaintiffs’ claims on various grounds, including for failure to state a claim upon which relief may be granted, while granting plaintiffs leave to amend their complaint within 30 days. On October 29, 2012, the plaintiffs filed an amended complaint. The exposure related to the re-filed 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 will examine its books and records and those of its subsidiaries and related entities to determine compliance with the Delaware Escheat Laws. The review is being 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. The exposure related to the audits is not currently determinable.

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. The Company has filed a motion to dismiss on the ground of forum non conveniens, which is pending. 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.

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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, except that the stay of the consolidated action has been lifted partially in order for the Texas court to consider the Company’s motions to dismiss on the ground of forum non conveniens.

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).

As part of the sale process described above, on January 31, 2012, a Company affiliate acquired a 49 percent interest in YPHPL, while Yara Australia Pty Ltd (Yara) increased its interest in YPHPL from 35 percent to 51 percent. Yara will operate the ammonia plant 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 YPHPL. YPHPL 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, delivery quantities, and term). The new gas supply agreement resolves counterclaims by Burrup Fertilisers against Apache and its affiliate in the Tap action. A Company subsidiary purchased Tap, which then modified its agreement to supply gas to the ammonia plant and resolved both Tap’s claims against Burrup Fertilisers and Burrup Fertilisers’ counterclaims against Tap in the Tap action. If Kufpec does 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 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

As of December 31, 2012, the Company had an undiscounted reserve for environmental remediation of approximately $104 million. Apache is not aware of any environmental claims existing as of December 31, 2012 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. 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 claim centered 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. The parties have resolved the matter on commercial terms with no material impact on the Company’s financial position, results of operations, or liquidity.

On May 25, 2011, a panel of the Bureau of Ocean Energy Management (BOEMRE, as it was then known) published a report dated May 23, 2011, and titled “OCS G-2580, Vermilion Block 380 Platform A, Incidents of Noncompliance.” 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 water as a result of the incident, and 13 workers were rescued after evacuating the platform. 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 Bureau of Safety and Environmental Enforcement (BSEE, successor to BOEMRE) issued several Incidents of Non-Compliance, which may provide the basis for the assessment of civil penalties against Mariner. The Company’s subsidiary Apache Deepwater LLC, which acquired Mariner effective November 10, 2010, filed an appeal on August 31, 2012, contesting several of the Incidents of Non-Compliance. It is management’s opinion that any loss arising from this matter will not have a material adverse effect on the Company’s financial position, results of operations, or liquidity.

Contractual Obligations

At December 31, 2012, contractual obligations for drilling rigs, purchase obligations, firm transportation agreements, and long-term operating leases are as follows:

Net Minimum Commitments	Total		2013		2014-2015		2016-2017		2018 & Beyond
	(In millions)
Drilling rig commitments(1)	$	896	$	602	$	289	$	3	$	2
Purchase obligations(2)		2,588		1,200		1,182		184		22
Firm transportation agreements(3)		763		148		264		134		217
Office and related equipment(4)		402		49		91		96		166
Other operating lease obligations(5)		754		209		316		205		24
Total Net Minimum Commitments	$	5,403	$	2,208	$	2,142	$	622	$	431

⁽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, LNG 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.

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(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 vessels (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 $76 million, $64 million, and $46 million for 2012, 2011, and 2010, respectively.

9.    RETIREMENT AND DEFERRED COMPENSATION PLANS

Apache Corporation provides retirement benefits to its U.S. employees through the use of multiple plans: a 401(k) savings plan, a money purchase retirement plan, a non-qualified 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, as defined, to the plan with the Company making matching contributions up to a maximum of 8 percent of each employee’s annual eligible compensation. In addition, the Company annually contributes 6 percent of each participating employee’s annual eligible compensation, as defined, to a money purchase retirement plan. The 401(k) savings plan and the money purchase retirement plan are subject to certain annually-adjusted, government-mandated restrictions that limit the amount of employee and Company contributions. For certain eligible employees, the Company also provides a non-qualified retirement/savings plan or a non-qualified restorative retirement savings plan that allows the deferral of up to 50 percent of each employee’s base 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 retirement savings plan and the non-qualified restorative retirement savings plan occurs at the rate of 20 percent for every completed 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 U.S. and International savings plans, the money purchase retirement plan, non-qualified retirement/savings plan, and non-qualified restorative retirement savings plan was $117 million, $93 million, and $80 million for 2012, 2011, and 2010, 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. Eligible 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.

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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, 2012, 2011, and 2010, 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.

	2012						2011						2010
	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	$	150		$	30		$	136		$	29		$	135		$	18
Service cost		5			4			5			3			5			2
Interest cost		7			1			7			1			7			1
Foreign currency exchange rate changes		7			—			(1	)		—			(4	)		—
Amendments		—			—			—			—			—			—
Actuarial losses (gains)		14			1			6			(2	)		(1	)		8
Effect of curtailment and settlements		—			—			—			—			—			—
Benefits paid		(6	)		(1	)		(3	)		(1	)		(6	)		—
Retiree contributions		—			—			—			—			—			—
Projected benefit obligation at end of year		177			35			150			30			136			29
Change in Plan Assets
Fair value of plan assets at beginning of year		145			—			135			—			118			—
Actual return on plan assets		14			—			4			—			14			—
Foreign currency exchange rates		6			—			(1	)		—			(3	)		—
Employer contributions		11			1			10			1			12			—
Benefits paid		(6	)		(1	)		(3	)		(1	)		(6	)		—
Retiree contributions		—			—			—			—			—			—
Fair value of plan assets at end of year		170			—			145			—			135			—
Funded status at end of year	$	(7	)	$	(35	)	$	(5	)	$	(30	)	$	(1	)	$	(29	)
Amounts recognized in Consolidated Balance Sheet
Current liability		—			(1	)		—			(1	)		—			(1	)
Non-current liability		(7	)		(34	)		(5	)		(29	)		(1	)		(28	)
	$	(7	)	$	(35	)	$	(5	)	$	(30	)	$	(1	)	$	(29	)
Pre-tax Amounts Recognized in Accumulated Other Comprehensive Income (Loss)
Accumulated (loss)		(32	)		(7	)		(25	)		(6	)		(15	)		(8	)
Prior service cost		—			—			—			—			—			—
Transition asset (obligation)		—			—			—			—			—			—
	$	(32	)	$	(7	)	$	(25	)	$	(6	)	$	(15	)	$	(8	)
Weighted Average Assumptions used as of December 31
Discount rate		4.30	%		3.43	%		4.70	%		4.04	%		5.40	%		4.93	%
Salary increases		4.60	%		N/A			4.60	%		N/A			5.00	%		N/A
Expected return on assets		4.70	%		N/A			4.85	%		N/A			6.25	%		N/A
Healthcare cost trend
Initial		N/A			7.25	%		N/A			7.50	%		N/A			8.00	%
Ultimate in 2022		N/A			5.00	%		N/A			5.00	%		N/A			5.00	%

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

As of December 31, 2012, 2011, and 2010, the accumulated benefit obligation for the pension plan was $139 million, $119 million, and $107 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
	2012			2012			2011
Asset Category
Equity securities:
U.K. quoted equities		17	%		16	%		17	%
Overseas quoted equities		33	%		33	%		31	%
Total equity securities		50	%		49	%		48	%
Debt securities:
U.K. Government bonds		30	%		30	%		30	%
U.K. corporate bonds		20	%		20	%		18	%
Debt securities		50	%		50	%		48	%
Cash		0	%		1	%		4	%
Total		100	%		100	%		100	%

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The plan’s assets do not include any direct ownership of 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 3 — Derivative Instruments And Hedging Activities. 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, 2012:

	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)	$	28	$	—	$	—	$	28
Overseas quoted equities(2)		56		—		—		56
Total equity securities		84		—		—		84
Debt securities:
U.K. Government bonds(3)		51		—		—		51
U.K. corporate bonds(4)		34		—		—		34
Total debt securities		85		—		—		85
Cash		1		—		—		1
Fair value of plan assets	$	170	$	—	$	—	$	170

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

⁽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: 33 percent benchmarked against iBoxx Sterling Overall Gilt Index, with a performance target of 0.75 percent per annum over the benchmark over a rolling three-year period; and 67 percent against the FTSE Actuaries Government Securities Index-Linked Over 5 Years Index.

⁽⁴⁾  This category comprises U.K. corporate bonds: 50 percent benchmarked against iBoxx Sterling Overall Non Gilt index with a performance target of 0.75 percent per annum over the benchmark over a rolling three-year period; and 50 percent benchmarked against the iBoxx Sterling Overall Non Gilt Index with a performance target of 0.75 percent per annum over the benchmark over a rolling five year period.

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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.

⁽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: 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.

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

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.

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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, 2012, 2011, and 2010:

	2012						2011						2010
	Pension Benefits			Postretirement Benefits			Pension Benefits			Postretirement Benefits			Pension Benefits			Postretirement Benefits
	(In millions)
Component of Net Periodic Benefit Costs
Service cost	$	5		$	4		$	5		$	3		$	5		$	2
Interest cost		7			1			7			1			7			1
Expected return on assets		(7	)		—			(8	)		—			(8	)		—
Amortization of actuarial gain (loss)		1			—			—			—			1			—
Net periodic benefit cost	$	6		$	5		$	4		$	4		$	5		$	3
Weighted Average Assumptions used to determine Net Period Benefit Cost for the Years ended 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		—			7.50	%		—			8.00	%		—			7.50	%
Ultimate in 2017		—			5.00	%		—			5.00	%		—			5.00	%

Assumed health care cost trend rates affect 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	$	(1	)
Effect on postretirement benefit obligation		8		(6	)

Apache expects to contribute approximately $5 million to its pension plan and $1 million to its postretirement benefit plan in 2013. The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:

	Pension Benefits		Postretirement Benefits
	(In millions)
2013	$	5	$	1
2014		6		1
2015		7		2
2016		7		2
2017		6		3
Years 2018 – 2022		49		18

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

10.    CAPITAL STOCK

Common Stock Outstanding

	2012		2011		2010
Balance, beginning of year		384,117,643		382,391,742		336,436,972
Shares issued for stock-based compensation plans:
Treasury shares issued		60,767		144,313		363,263
Common shares issued		1,189,693		1,581,588		1,864,498
Cordillera consideration		6,272,667		—		—
Equity offering (BP acquisitions)		—		—		26,450,000
Mariner consideration		—		—		17,277,009
Balance, end of year		391,640,770		384,117,643		382,391,742

Net Income per Common Share

A reconciliation of the components of basic and diluted net income per common share for the years ended December 31, 2012, 2011, and 2010 is presented in the table below.

	2012						2011						2010
	Income		Shares		Per Share		Income		Shares		Per Share		Income		Shares		Per Share
	(In millions, except per share amounts)
Basic:
Income attributable to common stock	$	1,925		389	$	4.95	$	4,508		384	$	11.75	$	3,000		352	$	8.53
Effect of Dilutive Securities:
Mandatory Convertible Preferred Stock	$	—		—			$	76		14			$	32		5
Stock options and other		—		2				—		2				—		2
Diluted:
Income attributable to common stock, including assumed conversions	$	1,925		391	$	4.92	$	4,584		400	$	11.47	$	3,032		359	$	8.46

The diluted EPS calculation excludes options and restricted shares that were anti-dilutive totaling 4.4 million, 2.5 million, and 2.3 million for the years ended December 31, 2012, 2011, and 2010, respectively. For the year ended December 31, 2012, 14.3 million shares related to the assumed conversion of the Mandatory Convertible Preferred Stock were also anti-dilutive.

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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 April 30, 2012, in conjunction with Apache’s acquisition of Cordillera, the Company issued 6,272,667 shares of common stock to the sellers.

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

Common Stock Dividend

The Company paid common stock dividends of $0.66 per share in 2012, and $0.60 per share in 2011 and 2010.

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 2012, 2011, and 2010, stock-based compensation expensed was $167 million, $113 million, and $164 million ($119 million, $73 million, and $106 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:

	2012		2011		2010
	(In millions)
Stock-based compensation expensed:
General and administrative	$	104	$	69	$	98
Lease operating expenses		63		44		66
Stock-based compensation capitalized		67		42		71
	$	234	$	155	$	235

Stock Options

As of December 31, 2012, 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 (collectively, the Stock Option Plans), as well as the 2007 Omnibus Equity Compensation Plan (the 2007 Plan), and the 2011 Plan discussed above (together, 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

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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. 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:

	2012
	Shares Under Option			Weighted Average Exercise Price
	(In thousands)
Outstanding, beginning of year		6,092		$	91.96
Granted		2,072			82.65
Exercised		(311	)		56.15
Forfeited or expired		(280	)		102.90
Outstanding, end of year(1)		7,573			90.47
Expected to vest(1)		2,900			96.23
Exercisable, end of year(1)		3,922			85.55
Available for grant, end of year		15,498
Weighted average fair value of options granted during the year	$	26.41

⁽¹⁾  As of December 31, 2012, the weighted average remaining contractual life for options outstanding, expected to vest, and exercisable is 6.7 years, 8.6 years, and 5.0 years, respectively. The aggregate intrinsic value of options outstanding, expected to vest, and exercisable at year-end was $19 million, $0, and $19 million, respectively. The weighted-average grant-date fair value of options granted during the years 2012, 2011, and 2010 was $26.41, $42.20, and $34.12, respectively.

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.

	2012			2011			2010
Expected volatility		34.94	%		34.47	%		35.02	%
Expected dividend yields		0.82	%		0.47	%		0.60	%
Expected term (in years)		5.5			5.5			5.5
Risk-free rate		0.78	%		1.95	%		2.31	%

The intrinsic value of options exercised during 2012, 2011, and 2010 was approximately $12 million, $50 million and $62 million, respectively. The cash received from exercise of options during 2012 was approximately $17 million. The Company realized an additional tax benefit of approximately $2 million for the amount of

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

intrinsic value in excess of compensation cost recognized in 2012. As of December 31, 2012, the total compensation cost related to non-vested options not yet recognized was $90 million, which will be recognized over the remaining vesting period of the options.

Stock Appreciation Rights

For some non-executive employees, the Company issued stock appreciation rights (SARs) in lieu of stock options. The SARs vest ratably over four years and are settled in cash upon exercise throughout their ten-year life. In 2012, the Company issued 180,555 SARs with a weighted-average exercise price of $82.63 under the 2011 Omnibus Plan. Additionally, in 2003 and 2004 the Company issued 1,809,060 SARs with a weighted-average exercise price of $42.68 and 1,334,300 SARs with a weighted-average exercise price of $28.78, respectively, under the 2003 Stock Appreciation Rights Plan. As of December 31, 2012, a total of 583,688 SARs were outstanding, of which 413,582 were exercisable. 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 $36.20 based on the Black-Scholes valuation methodology using assumptions comparable to those discussed above. During 2012, 60,523 SARs were exercised. The aggregate of cash payments made to settle SARs was $3 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 2012, the Company awarded 1,219,886 restricted stock units at a weighted-average per-share market price of $85.67. In 2011 and 2010, the Company awarded 887,851 and 1,143,989 restricted stock units at a weighted-average per-share market price of $124.16 and $103.88, 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 2012, 2011, and 2010, $74 million ($48 million after tax), $76 million ($49 million after tax), and $73 million ($47 million after tax), respectively, was charged to expense. In 2012, 2011, and 2010, $25 million, $28 million, and $28 million was capitalized, respectively. As of December 31, 2012, there was $151 million of total unrecognized compensation cost related to 2,163,564 unvested restricted stock units. The weighted-average remaining life of unvested restricted stock units is approximately 1.4 years.

The fair value of the awards vested during 2012, 2011 and 2010 was approximately $114 million, $85 million, and $69 million, respectively. A summary of restricted stock activity for the year ended December 31, 2012, is presented below.

	Shares			Weighted- Average Grant- Date Fair Value
	(In thousands)
Non-vested at January 1, 2012		2,115		$	109.63
Granted		1,220			85.67
Vested		(1,053	)		107.76
Forfeited		(118	)		102.82
Non-vested at December 31, 2012		2,164			97.34

Conditional Restricted Stock Units

To provide long-term incentives for Apache employees to deliver competitive returns to the Company’s stockholders, in January 2012, 2011, and 2010 the Company granted conditional restricted stock units to eligible

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

employees. 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. Three 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, pursuant to the 2007 Plan. In January 2010 eligible employees received initial conditional restricted stock unit awards totaling 541,440 units. Based on measurement of total shareholder return relative to the designated peer group at December 31, 2012, zero shares were awarded and all unvested conditional restricted stock units were cancelled.

• In November 2010 the Company’s Board of Directors approved the 2011 Performance Program, pursuant to the 2007 Plan. In January 2011 eligible employees received initial conditional restricted stock unit awards totaling 585,811 units. A total of 503,884 units were outstanding at December 31, 2012, from which a minimum of zero and a maximum of 1,259,710 units could be awarded.

• In January 2012 the Company’s Board of Directors approved the 2012 Performance Program, pursuant to the 2011 Plan. In January 2012 eligible employees received initial conditional restricted stock unit awards totaling 851,985 units. A total of 802,390 units were outstanding at December 31, 2012, from which a minimum of zero and a maximum of 2,005,975 units could be awarded.

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 2012, 2011, and 2010, $47 million ($31 million after tax), $12 million ($8 million after tax), and $7 million ($4 million after tax), respectively, was charged to expense. During 2012, 2011, and 2010, $21 million, $5 million, and $3 million was capitalized, respectively. As of December 31, 2012, there was $72 million of total unrecognized compensation cost related to 1,306,274 unvested conditional restricted stock units. The weighted-average remaining life of the unvested conditional restricted stock units is approximately 2.4 years.

	Shares			Weighted- Average Grant- Date Fair Value(1)
	(In thousands)
Non-vested at January 1, 2012		1,019		$	115.10
Granted		852			70.30
Vested		(1	)		100.81
Forfeited		(564	)		132.45
Non-vested at December 31, 2012		1,306			78.40

⁽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 2013 the Company’s Board of Directors approved the 2013 Performance Program, pursuant to the 2011 Plan, with terms similar to the 2012 Performance Program. Eligible employees received initial conditional restricted stock unit awards totaling 1,232,176 units, with the ultimate number of restricted stock units to be awarded ranging from zero to a maximum of 2,464,352 units.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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. The interim target of $162 was not met by the end of 2010, and the related awards were cancelled. The $216 share price target was not met by the end of 2012, and all remaining awards under the 2008 Share Appreciation Program were cancelled.

• 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. Apache’s share price exceeded the interim $81 threshold for the 10-day requirement as of June 14, 2007. Apache’s share price exceeded the $108 threshold for the 10-day requirement as of February 29, 2008. Awards under the plan were payable in four equal annual installments to eligible employees remaining with the Company.

A summary of the number of shares contingently issuable as of December 31, 2012, 2011, and 2010 for each plan is presented in the table below:

	Shares subject to Conditional Grants
	2012			2011			2010
	(In thousands)
2008 Share Appreciation Program
Outstanding, beginning of year		1,372			1,485			2,592
Granted		—			—			25
Forfeited or cancelled		(1,372	)		(113	)		(1,132	)
Outstanding, end of year(1)		—			1,372			1,485
Weighted-average value of grants outstanding(2)	$	—		$	71.28		$	71.16
2005 Share Appreciation Plan
Outstanding, beginning of year		—			400			1,103
Issued(3)		—			(398	)		(678	)
Forfeited or cancelled		—			(2	)		(25	)
Outstanding, end of year		—			—			400
Weighted-average value of grants outstanding(4)	$	—		$	—		$	21.64

⁽¹⁾  Represents shares issuable upon target achievement and vesting of awards related to the $216 and $162 per share price goals of zero shares at December 31, 2012; 1,372,190 and zero shares, respectively, at December 31, 2011; and 1,485,210 and zero shares, respectively, at December 31, 2010.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

⁽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 and 2010 was approximately $9 million and $18 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.

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 and $216 price targets of the 2008 Share Appreciation Program were not met prior to the end of the stated achievement periods, Apache recognized $27 million of unamortized expense and $14 million of unamortized capital costs on December 31, 2010, and $16 million of unamortized expense and $8 million of unamortized capital costs on December 31, 2012, respectively. The Company recognized total expense and capitalized costs for the 2008 Share Appreciation Program of $181 million and as of year-end 2012 had no unamortized cost remaining. As of March 2011, the Company had recognized $79 million of total expense and capitalized costs for the 2005 Share Appreciation Plan 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,
	2012		2011		2010
	(In millions)
2008 Share Appreciation Program
Compensation expense	$	22	$	8	$	49
Compensation expense, net of tax		14		5		31
Capitalized costs		12		5		27
2005 Share Appreciation Plan
Compensation expense		—	$	1	$	6
Compensation expense, net of tax		—		1		4
Capitalized costs		—		1		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).

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,

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 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 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, subject to adjustment, 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, each subject to adjustment, 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.

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

11.    ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

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

	For the Year Ended December 31,
	2012			2011			2010
	(In millions)
Currency translation adjustment(1)	$	(109	)	$	(109	)	$	(109	)
Unrealized gain (loss) on derivatives (Note 3)		(6	)		114			(19	)
Unfunded pension and postretirement benefit plan		(16	)		(14	)		(13	)
Accumulated other comprehensive loss	$	(131	)	$	(9	)	$	(141	)

⁽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).

12.    MAJOR CUSTOMERS

In 2012, 2011, and 2010, purchases by Royal Dutch Shell plc and its subsidiaries accounted for 20 percent, 11 percent, and 15 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.

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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, 2012, the Company had production in six countries: the United States, Canada, Egypt, Australia, offshore the United Kingdom (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)
2012
Oil and gas production revenues	$	6,226	$	1,322		$	4,554	$	1,575	$	2,751	$	519	$	—		$	16,947
Operating Expenses:
Depreciation, depletion, and amortization
Recurring		2,056		594			925		466		914		228		—			5,183
Additional		—		1,883			—		—		—		—		43			1,926
Asset retirement obligation accretion		112		41			—		17		58		4		—			232
Lease operating expenses		1,386		458			410		215		315		184		—			2,968
Gathering and transportation		69		163			39		—		24		8		—			303
Taxes other than income		292		50			14		11		451		44		—			862
Operating Income (Loss)(1)	$	2,311	$	(1,867	)	$	3,166	$	866	$	989	$	51	$	(43	)		5,473
Other Income (Expense):
Other																		131
General and administrative																		(531	)
Merger, acquisitions & transition																		(31	)
Financing costs, net																		(165	)
Income Before Income Taxes																	$	4,877
Net Property and Equipment	$	28,552	$	6,640		$	5,151	$	5,312	$	5,927	$	1,621	$	77		$	53,280
Total Assets	$	31,175	$	7,142		$	7,311	$	6,280	$	6,874	$	1,835	$	120		$	60,737
Additions to Net Property and Equipment	$	9,586	$	1,096		$	1,153	$	1,581	$	1,104	$	337	$	98		$	14,955
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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

⁽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. Canada’s operating loss for 2012 includes additional depletion of $1.9 billon to write-down the carrying value of oil and gas properties.

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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)
2012
Oil and gas production revenues	$	6,226	$	1,322		$	4,554	$	1,575	$	2,751	$	519	$	—		$	16,947
Operating cost:
Depreciation, depletion, and amortization
Recurring(1)		1,984		580			924		460		912		225		—			5,085
Additional		—		1,883			—		—		—		—		43			1,926
Asset retirement obligation accretion		112		41			—		17		58		4		—			232
Lease operating expenses		1,386		458			410		215		315		184		—			2,968
Gathering and transportation		69		163			39		—		24		8		—			303
Production taxes(2)		279		42			—		11		451		34		—			817
Income tax		851		(466	)		1,527		262		614		22		—			2,810
		4,681		2,701			2,900		965		2,374		477		43			14,141
Results of operation	$	1,545	$	(1,379	)	$	1,654	$	610	$	377	$	42	$	(43	)	$	2,806
Amortization rate per boe	$	17.24	$	11.66		$	13.81	$	17.67	$	32.65	$	12.39	$	—		$	16.88
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 operation	$	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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

⁽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-57

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)
2012
Acquisitions:
Proved	$	1,076	$	5	$	28		$	32	$	110	$	—	$	—	$	1,251
Unproved		2,329		—		—			—		26		—		—		2,355
Exploration		1,369		111		696			149		111		157		96		2,689
Development		4,465		762		394			915		837		161		2		7,536
Costs incurred(1)	$	9,239	$	878	$	1,118		$	1,096	$	1,084	$	318	$	98	$	13,831
(1) Includes capitalized interest and asset retirement costs as follows:
Capitalized interest	$	215	$	38	$	16		$	12	$	24	$	11	$	—	$	316
Asset retirement costs		473		245		—			207		89		18		—		1,032
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

F-58

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)
2012
Proved properties	$	40,163		$	13,477		$	7,165		$	6,319		$	8,401		$	2,706		$	152		$	78,383
Unproved properties		5,641			1,059			686			284			626			382			76			8,754
		45,804			14,536			7,851			6,603			9,027			3,088			228			87,137
Accumulated DD&A		(17,968	)		(8,899	)		(4,474	)		(2,478	)		(3,445	)		(1,562	)		(152	)		(38,978	)
	$	27,836		$	5,637		$	3,377		$	4,125		$	5,582		$	1,526		$	76		$	48,159
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

Costs Not Being Amortized

The following table sets forth a summary of oil and gas property costs not being amortized at December 31, 2012, 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		2012		2011		2010		2009 and Prior
	(In millions)
Property acquisition costs	$	6,998	$	3,558	$	981	$	2,146	$	313
Exploration and development		1,550		1,108		368		16		58
Capitalized interest		206		48		27		55		76
Total	$	8,754	$	4,714	$	1,376	$	2,217	$	447

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-59

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-60

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, 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
December 31, 2012		629,345			101,691			106,746			29,053			122,073			20,852			1,009,760			2,353,587			1,734,657			690,436			596,052			93,319			365,054			5,833,105			1,981,945
Proved undeveloped reserves:
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
December 31, 2012		263,957			82,908			17,288			34,808			28,399			3,857			431,217			832,320			403,227			205,055			1,074,018			18,985			97,496			2,631,101			869,734
Total proved reserves:
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
Purchase 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	)
Sale 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
Purchase 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	)
Sale 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
Extensions, discoveries and other additions		156,621			26,590			36,188			6,277			592			1,133			227,401			365,863			252,130			55,967			176,969			16,397			2,623			869,949			372,393
Purchase of minerals in-place		16,172			197			—			276			2,374			—			19,019			313,885			2,503			—			1,745			8,494			—			326,627			73,457
Revisions of previous estimates		(12,033	)		(7,146	)		(3,678	)		(66	)		(7,257	)		502			(29,678	)		(156,840	)		(1,443,989	)		(13,974	)		101			—			496			(1,614,206	)		(298,712	)
Production		(61,361	)		(8,083	)		(36,511	)		(10,571	)		(23,904	)		(4,666	)		(145,096	)		(312,600	)		(219,849	)		(129,468	)		(78,329	)		(21,029	)		(78,128	)		(839,403	)		(284,997	)
Sale of properties		(144	)		—			—			—			—			—			(144	)		(612	)		(422	)		—			—			—			—			(1,034	)		(316	)
Balance December 31, 2012		893,302			184,599			124,034			63,861			150,472			24,709			1,440,977			3,185,907			2,137,884			895,491			1,670,070			112,304			462,550			8,464,206			2,851,679

F-61

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

During 2012, Apache added 73 MMboe of estimated proved reserves through purchases of minerals in-place. The Company recorded 68 MMboe in connection with the acquisition of Cordillera. Other individually insignificant acquisitions added 6 MMboe across several regions. During 2012, Apache also added 372 MMboe from extensions, discoveries and other additions. In the U.S., the Company recorded 218 MMboe primarily associated with drilling successes in the Permian and Anadarko basins, which added 104 MMboe and 77 MMboe, respectively; 23 MMboe from appraisal drilling in the deepwater Gulf of Mexico; and 14 MMboe from various drilling programs in other U.S. regions. In Canada, additions of 69 MMboe were primarily a result of drilling activity for liquids-rich gas targets in the Kaybob field area and shallow oil drilling in Brownfield and Consort field areas. Egypt contributed 46 MMboe from exploration activity in the West Kalabsha, Matruh and Ras Kanayes concessions along with continued development of the Razzak and Abu Gharadig fields and several waterflood projects in the East Bahariya concession. Australia additions of 36 MMboe were primarily from two discoveries and two appraisal wells in the Carnarvon basin offshore Western Australia. Various drilling programs in Argentina and North Sea regions combined to contribute 5 MMboe.

Approximately 15 percent of Apache’s year-end 2012 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. 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.”

Driven by the significant decline in North America natural gas prices, a portion of our proved reserves fell below the threshold for economic development during 2012 and were removed from our proved reserves balance, resulting in negative revisions of 299 MMboe for the year.

Future Net Cash Flows

Future cash inflows as of December 31, 2012 and 2011 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.

F-62

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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)
2012
Cash inflows	$	84,060		$	20,512		$	16,210		$	20,823		$	16,732		$	3,010		$	161,347
Production costs		(27,230	)		(8,543	)		(2,126	)		(4,896	)		(8,451	)		(1,162	)		(52,408	)
Development costs		(6,768	)		(2,916	)		(1,756	)		(2,484	)		(3,053	)		(248	)		(17,225	)
Income tax expense		(12,740	)		(754	)		(4,246	)		(3,172	)		(3,163	)		(141	)		(24,216	)
Net cash flows		37,322			8,299			8,082			10,271			2,065			1,459			67,498
10 percent discount rate		(19,464	)		(4,472	)		(2,107	)		(6,361	)		(98	)		(443	)		(32,945	)
Discounted future net cash flows(1)	$	17,858		$	3,827		$	5,975		$	3,910		$	1,967		$	1,016		$	34,553
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

⁽¹⁾  Estimated future net cash flows before income tax expense, discounted at 10 percent per annum, totaled approximately $48.2 billion and $52.3 billion as of December 31, 2012 and 2011, respectively.

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

	For the Year Ended December 31,
	2012			2011			2010
	(In millions)
Sales, net of production costs	$	(12,589	)	$	(13,152	)	$	(9,152	)
Net change in prices and production costs		(1,941	)		12,167			13,006
Discoveries and improved recovery, net of related costs		6,742			6,751			5,147
Change in future development costs		(935	)		(2,250	)		(1,637	)
Previously estimated development costs incurred during the period		4,359			2,479			1,355
Revision of quantities		(4,065	)		(1,475	)		(1,905	)
Purchases of minerals in-place		1,181			2,139			7,794
Accretion of discount		5,234			4,161			2,439
Change in income taxes		2,711			(4,303	)		(4,535	)
Sales of properties		(3	)		(1,285	)		(3	)
Change in production rates and other		(2,088	)		273			182
	$	(1,394	)	$	5,505		$	12,691

F-63

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)
2012
Revenues and other	$	4,536	$	3,972	$	4,179	$	4,391	$	17,078
Expenses		3,739		3,616		3,999		3,723		15,077
Net income	$	797	$	356	$	180	$	668	$	2,001
Income attributable to common stock	$	778	$	337	$	161	$	649	$	1,925
Net income per common share(1):
Basic	$	2.02	$	0.87	$	0.41	$	1.66	$	4.95
Diluted	$	2.00	$	0.86	$	0.41	$	1.64	$	4.92
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

⁽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

In December 1999, Apache Finance Canada Corporation (Apache Finance Canada) issued approximately $300 million of publicly-traded notes due in 2029. In May 2003, Apache Finance Canada issued an additional $350 million of publicly-traded notes due in 2015. Both 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, these 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-64

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

For the Year Ended December 31, 2012

	Apache Corporation			Apache Finance Canada			All Other Subsidiaries of Apache Corporation		Reclassifications & Eliminations			Consolidated
	(In millions)
REVENUES AND OTHER:
Oil and gas production revenues	$	4,237		$	—		$	12,710	$	—		$	16,947
Equity in net income (loss) of affiliates		1,523			(737	)		248		(1,034	)		—
Other		(80	)		69			146		(4	)		131
		5,680			(668	)		13,104		(1,038	)		17,078
OPERATING EXPENSES:
Depreciation, depletion, and amortization		1,391			—			5,718		—			7,109
Asset retirement obligation accretion		76			—			156		—			232
Lease operating expenses		957			—			2,011		—			2,968
Gathering and transportation		51			—			252		—			303
Taxes other than income		185			—			677		—			862
General and administrative		425			—			110		(4	)		531
Merger, acquisitions & transition		25			—			6		—			31
Financing costs, net		94			(20	)		91		—			165
		3,204			(20	)		9,021		(4	)		12,201
INCOME (LOSS) BEFORE INCOME TAXES		2,476			(648	)		4,083		(1,034	)		4,877
Provision (benefit) for income taxes		475			(159	)		2,560		—			2,876
NET INCOME (LOSS)		2,001			(489	)		1,523		(1,034	)		2,001
Preferred stock dividends		76			—			—		—			76
INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	1,925		$	(489	)	$	1,523	$	(1,034	)	$	1,925
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	1,803		$	(489	)	$	1,523	$	(1,034	)	$	1,803

F-65

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 (LOSS) BEFORE INCOME TAXES		5,109		377			6,477			(3,870	)		8,093
Provision (benefit) for income taxes		525		97			2,887			—			3,509
NET INCOME (LOSS)		4,584		280			3,590			(3,870	)		4,584
Preferred stock dividends		76		—			—			—			76
INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	4,508	$	280		$	3,590		$	(3,870	)	$	4,508
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	4,640	$	280		$	3,590		$	(3,870	)	$	4,640

F-66

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 (LOSS) BEFORE INCOME TAXES		3,266		99			4,180			(2,339	)		5,206
Provision (benefit) for income taxes		234		25			1,915			—			2,174
NET INCOME (LOSS)		3,032		74			2,265			(2,339	)		3,032
Preferred stock dividends		32		—			—			—			32
INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	3,000	$	74		$	2,265		$	(2,339	)	$	3,000
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	3,149	$	74		$	2,265		$	(2,339	)	$	3,149

F-67

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

For the Year Ended December 31, 2012

	Apache Corporation			Apache Finance Canada			All Other Subsidiaries of Apache Corporation			Reclassifications & Eliminations			Consolidated
	(In millions)
CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	$	2,357		$	(40	)	$	6,187		$	—		$	8,504
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property		(3,313	)		—			(5,468	)		—			(8,781	)
Additions to gas gathering, transmission, and processing facilities		(48	)		—			(702	)		—			(750	)
Acquisition of Cordillera		(2,666	)		—			—			—			(2,666	)
Equity investment in Yara Pilbara Holdings Pty Limited		—			—			(439	)		—			(439	)
Acquisitions, other		(66	)		—			(186	)		—			(252	)
Proceeds from sale of oil and gas properties		25			—			2			—			27
Investment in subsidiaries, net		(657	)		—			—			657			—
Other		(450	)		—			(113	)		—			(563	)
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES		(7,175	)		—			(6,906	)		657			(13,424	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Commercial paper, credit facility, and bank notes, net		502			—			47			—			549
Intercompany borrowings		—			—			697			(697	)		—
Fixed rate debt borrowings		4,978			—			—			—			4,978
Payments on fixed rate debt		(400	)		—			—			—			(400	)
Dividends paid		(332	)		—			—			—			(332	)
Other		29			35			(114	)		40			(10	)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		4,777			35			630			(657	)		4,785
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(41	)		(5	)		(89	)		—			(135	)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR		41			5			249			—			295
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	—		$	—		$	160		$	—		$	160

F-68

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 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 gas gathering, transmission, and processing facilities		—			—			(664	)		—			(664	)
Acquisition of Mobil North Sea		—			—			(1,246	)		—			(1,246	)
Acquisitions, other		(448	)		—			(119	)		—			(567	)
Proceeds from sales of oil and gas properties		204			—			218			—			422
Investment in and advances to subsidiaries, net		772			—			—			(772	)		—
Other		(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	)
Other		108			(7	)		(25	)		8			84
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		(1,125	)		(8	)		(786	)		772			(1,147	)
NET INCREASE (DECREASE) 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 PERIOD	$	41		$	5		$	249		$	—		$	295

F-69

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 gas 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		(72	)		—			(49	)		—			(121	)
NET CASH PROVIDED BY (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	)
Other		49			96			75			(131	)		89
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		6,706			98			812			(2,853	)		4,763
NET INCREASE (DECREASE) 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 PERIOD	$	6		$	—		$	128		$	—		$	134

F-70

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

CONDENSED CONSOLIDATING BALANCE SHEET

December 31, 2012

	Apache Corporation		Apache Finance Canada		All Other Subsidiaries of Apache Corporation			Reclassifications & Eliminations			Consolidated
	(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	—	$	—	$	160		$	—		$	160
Receivables, net of allowance		876		—		2,210			—			3,086
Inventories		95		—		813			—			908
Drilling advances		21		1		562			—			584
Derivative instruments		31		—		—			—			31
Prepaid assets and other		3,868		—		(3,675	)		—			193
		4,891		1		70			—			4,962
PROPERTY AND EQUIPMENT, NET		18,517		—		34,763			—			53,280
OTHER ASSETS:
Intercompany receivable, net		4,628		—		(2,917	)		(1,711	)		—
Equity in affiliates		21,047		934		97			(22,078	)		—
Goodwill, net		173		—		1,116			—			1,289
Deferred charges and other		152		1,002		1,052			(1,000	)		1,206
	$	49,408	$	1,937	$	34,181		$	(24,789	)	$	60,737
LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	639	$	1	$	2,163		$	(1,711	)	$	1,092
Current debt		912		—		78			—			990
Asset retirement obligation		471		—		7			—			478
Derivative instruments		96		—		20			—			116
Other current liabilities		893		3		1,964			—			2,860
		3,011		4		4,232			(1,711	)		5,536
LONG-TERM DEBT		10,706		647		2			—			11,355
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes		2,990		5		5,029			—			8,024
Asset retirement obligation		992		—		3,108			—			4,100
Other		378		250		763			(1,000	)		391
		4,360		255		8,900			(1,000	)		12,515
COMMITMENTS AND CONTINGENCIES SHAREHOLDERS’ EQUITY		31,331		1,031		21,047			(22,078	)		31,331
	$	49,408	$	1,937	$	34,181		$	(24,789	)	$	60,737

F-71

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
Current debt		400		—		31			—			431
Asset retirement obligation		434		—		13			—			447
Derivative instruments		76		—		37			—			113
Other current liabilities		614		5		2,305			—			2,924
		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-72

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,	Thomas E. Voytovich
Warburg Pincus LLC	Executive Vice President — International Operations
John A. Kocur(1)(3)(4)	Matthew W. Dundrea
Attorney at Law; Former Vice Chairman of the Board,	Senior Vice President — Treasury and Administration
Apache Corporation
	Robert J. Dye
George D. Lawrence(1)(3)	Senior Vice President — Global Communication and
Private Investor; Former Chief Executive Officer,	Corporate Affairs
The Phoenix Resource Companies, Inc.
	Alfonso Leon
William C. Montgomery(3)(5)	Senior Vice President and Chief of Staff
Managing Director, Quantum Energy Partners
	Janine J. McArdle
Rodman D. Patton(2)	Senior Vice President — Gas Monetization
Former Managing Director,
Merrill Lynch Energy Group	Sarah B. Teslik
	Senior Vice President — Policy and Governance
Charles J. Pitman(4)(5)
Former Regional President — Middle East/	John R. Bedingfield
Caspian/Egypt/India, BP Amoco plc	Vice President — Worldwide Exploration and New Ventures
	David L. French
	Vice President — Business Development
	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
	Aaron S. G. Merrick
	Vice President — Information Technology
	Urban F. O’Brien
	Vice President — Government Affairs
	F. Brady Parish, Jr Vice President of Investor Relations
	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
2012
First Quarter	$	112.09	$	91.48	$	0.17	$	0.15
Second Quarter		102.13		77.93		0.17		0.17
Third Quarter		94.87		81.55		0.17		0.17
Fourth Quarter		89.08		74.50		0.17		0.17
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

The Company has paid cash dividends on its common stock for 48 consecutive years through December 31, 2012. 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, 2012, the Company’s shares of common stock outstanding were held by approximately 5,300 shareholders of record and 386,000 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 16, 2013, 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 F. Brady Parish, Jr., Vice President of Investor Relations, at (713) 296-6472.

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

Index to 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).
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).

EXHIBIT NO.		DESCRIPTION
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).
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	–	Form of 1.75% Notes due 2017 (incorporated by reference to Exhibit 4.1 to Registrant’s Current Report on Form 8-K, dated April 3, 2012, filed on April 9, 2012, SEC File No. 001-4300).
4.7	–	Form of 3.25% Note due 2022 (incorporated by reference to Exhibit 4.2 to Registrant’s Current Report on Form 8-K, dated April 3, 2012, filed on April 9, 2012, SEC File No. 001-4300).
4.8	–	Form of 4.75% Notes due 2043 (incorporated by reference to Exhibit 4.3 to Registrant’s Current Report on Form 8-K, dated April 3, 2012, filed on April 9, 2012, SEC File No. 001-4300).
4.9	–	Form of 2.625% Notes due 2023 (incorporated by reference to Exhibit 4.1 to Registrant’s Current Report on Form 8-K, dated November 28, 2012, filed on December 4, 2012, SEC File No. 001-4300).
4.10	–	Form of 4.250% Notes due 2044 (incorporated by reference to Exhibit 4.2 to Registrant’s Current Report on Form 8-K, dated November 28, 2012, filed on December 4, 2012, SEC File No. 001-4300).

EXHIBIT NO.		DESCRIPTION
4.11	–	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).
4.12	–	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).
4.13	–	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).
4.14	–	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).
4.15	–	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).
4.16	–	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).
4.17	–	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).

EXHIBIT NO.		DESCRIPTION
4.18	–	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).
4.19	–	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).
4.20	–	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).
4.21	–	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).
4.22	–	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).
4.23	–	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).
4.24	–	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).

EXHIBIT NO.		DESCRIPTION
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).
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).

EXHIBIT NO.		DESCRIPTION
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, JPMorgan 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).
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	–	Credit Agreement, dated as of June 4, 2012, among Apache Corporation, the lenders party thereto, JPMorgan Chase Bank, N.A., as Global Administrative Agent, Bank of America, N.A. and Citibank, N.A., as Global Syndication Agents, and The Royal Bank of Scotland plc and Royal Bank of Canada, as Global Documentation Agents (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed June 7, 2012, SEC File No. 001-04300).

EXHIBIT NO.		DESCRIPTION
10.12	–	Credit Agreement, dated as of June 4, 2012, among Apache Canada Ltd., the lenders party thereto, JPMorgan Chase Bank, N.A., as Global Administrative Agent, Royal Bank of Canada, as Canadian Administrative Agent, Bank of America, N.A. and Citibank, N.A., as Global Syndication Agents, and The Royal Bank of Scotland plc and Royal Bank of Canada, as Global Documentation Agents (incorporated by reference to Exhibit 10.2 to Registrant’s Current Report on Form 8-K filed June 7, 2012, SEC File No. 001-04300).
10.13	–	Syndicated Facility Agreement, dated as of June 4, 2012, among Apache Energy Limited (ACN 009 301 964), the lenders party thereto, JPMorgan Chase Bank, N.A., as Global Administrative Agent, Citisecurities Limited (ABN 51 008 489 610), as Australian Administrative Agent, Bank of America, N.A. and Citibank, N.A., as Global Syndication Agents, and The Royal Bank of Scotland plc and Royal Bank of Canada, as Global Documentation Agents (incorporated by reference to Exhibit 10.3 to Registrant’s Current Report on Form 8-K filed June 7, 2012, SEC File No. 001-04300).
†10.14	–	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).
†10.15	–	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).
†10.16	–	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).
†10.17	–	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).
†10.18	–	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).
†10.19	–	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).

EXHIBIT NO.		DESCRIPTION
†10.20	–	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).
†10.21	–	Amendment to Apache Corporation 401(k) Savings Plan, dated December 19, 2011, effective January 1, 2012, except as otherwise specified (incorporated by reference to Exhibit 10.18 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2011, SEC File No. 001-4300).
*†10.22	–	Amendment to Apache Corporation 401(k) Savings Plan, dated November 8, 2012, effective January 1, 2012.
†10.23	–	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).
†10.24	–	Amendment to Apache Corporation Non-Qualified Retirement/Savings Plan of Apache Corporation, dated December 19, 2011, effective January 1, 2012 (incorporated by reference to Exhibit 10.20 to Registrant’s Annual Report Form 10-K for year ended December 31, 2011, SEC File No. 001-4300).
*†10.25	–	Amendment to Non-Qualified Retirement/Savings Plan of Apache Corporation, dated November 8, 2012, effective January 1, 2013.
†10.26	–	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).
*†10.27	–	Amendment to Non-Qualified Restorative Retirement Savings Plan of Apache Corporation, dated November 8, 2012, effective January 1, 2013.
†10.28	–	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).
†10.29	–	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).
†10.30	–	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).
†10.31	–	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).

EXHIBIT NO.		DESCRIPTION
†10.32	–	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).
†10.33	–	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).
†10.34	–	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).
†10.35	–	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).
†10.36	–	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).
†10.37	–	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).
*†10.38	–	Apache Corporation Deferred Delivery Plan, as amended and restated February 5, 2013.
*†10.39	–	Apache Corporation Non-Employee Directors’ Compensation Plan, as amended and restated February 6, 2013.
*†10.40	–	Apache Corporation Outside Directors’ Retirement Plan, as amended and restated February 6, 2013.
†10.41	–	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).
†10.42	–	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
†10.43	–	Apache Corporation Non-Employee Directors’ Restricted Stock Units Program Specifications, as amended and restated July 19, 2012, pursuant to Apache Corporation 2011 Omnibus Equity Compensation Plan (incorporated by reference to Exhibit 10.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2012, SEC File No. 001-4300).
†10.44	–	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).
†10.45	–	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).
†10.46	–	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).
†10.47	–	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).
†10.48	–	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).
†10.49	–	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).
†10.50	–	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).
†10.51	–	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).

EXHIBIT NO.		DESCRIPTION
†10.52	–	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).
†10.53	–	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).
†10.54	–	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).
†10.55	–	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).
†10.56	–	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).
†10.57	–	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).
†10.58	–	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).
†10.59	–	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).
†10.60	–	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).

EXHIBIT NO.		DESCRIPTION
†10.61	–	Form of 2013 Performance Program Agreement, dated January 9, 2013, between Registrant and each of G. Steven Farris, Rodney J. Eichler, Roger B. Plank, 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.
14.1	–	Code of Business Conduct, as amended and restated November 15, 2011 (incorporated by reference to Exhibit 14.1 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2011, SEC File No. 001-4300).
*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.

EX-10.22

Exhibit 10.22

Apache Corporation 401(k) Savings Plan

Fourth Amendment Not Covered by the 2010 Determination Letter

Apache Corporation (“Apache”) sponsors the Apache Corporation 401(k) Savings Plan (the “Plan”). In section 10.4 of the Plan, Apache reserved the right to amend the Plan from time to time. Apache hereby exercises that right, (1) by modifying section 6.5(c)(i)(A) to reflect the revised statutory provision on deductible medical expenses, and (2) by eliminating the last sentence of section 6.5(c)(i), both effective as of January 1, 2012, so that section 6.5(c)(i) now states:

(i) Financial Need. The following expenses constitute an immediate and heavy financial need: (A) expenses for or necessary to obtain medical care, within the meaning of Code §213(d), (1) that would be deductible by the Employee under Code §213 (determined without regard to whether the expenses exceed the percentage of adjusted gross income specified in Code §213(a)), or (2) that apply to the Employee’s primary beneficiary (as determined pursuant to section 6.1); (B) costs directly related to the purchase of a principal residence of the Employee (excluding mortgage payments); (C) payment of tuition, related educational fees, and room and board expenses for up to the next 12 months of post-secondary education of the Employee, the Employee’s Spouse, the Employee’s children, the Employee’s dependents (within the meaning of Code §152, without regard to Code §152(b)(1), §152(b)(2), and §152(d)(1)(B)), or the Employee’s primary beneficiary (as determined pursuant to section 6.1); (D) payments necessary to prevent the Employee from being evicted from his or her principal residence; (E) payments necessary to prevent the mortgage on the Employee’s principal residence from being foreclosed; (F) payment of burial or funeral expenses for the Employee’s deceased parent, Spouse, child, other dependent (within the meaning of Code §152, without regard to Code §152(b)(1), §152(b)(2), and §152(d)(1)(B)), or primary beneficiary (as determined pursuant to section 6.1); (G) expenses for the repair of damage to the Employee’s principal residence that would qualify for the casualty deduction under Code §165 (determined without regard to whether the loss exceeds 10% of adjusted gross income); and (H) any other expense that, under IRS guidance of general applicability, is deemed to be on account of an immediate and heavy financial need.

EXECUTED this 8th day of November, 2012.

APACHE CORPORATION
By:	/s/ Margery M. Harris
	Margery M. Harris   Executive Vice President, Human Resources

Prepared November 6, 2012

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EX-10.25

Exhibit 10.25

Non-Qualified Retirement/Savings Plan of Apache Corporation

Apache Corporation (“Apache”) sponsors the Non-Qualified Retirement/Savings Plan of Apache Corporation (the “Plan”). In section 8.02 of the Plan, Apache reserved the right to amend the Plan from time to time. Apache hereby exercises that right, as follows, effective as of January 1, 2013, by adding a sentence to the end of section 2.01 to clarify the relationship of the Plan and the Apache Corporation Restorative Retirement Plan, so that section 2.01 shall read as follows:

The Committee shall from time to time in its sole discretion select those Employees who are eligible to participate in the Plan from those Employees who are among a select group of management or highly compensated employees. Furthermore, (a) an Employee is eligible to make Participant Deferrals to this Plan from his Compensation only if the Employee is not eligible to make similar deferrals to the Apache Corporation Non-Qualified Restorative Retirement Savings Plan (the “Restorative Plan”) from the same Compensation, and (b) an Employee is eligible to receive an allocation of Company Deferrals with respect to his Compensation only if he or she is not eligible to receive similar company deferrals attributable to the same Compensation in the Restorative Plan.

EXECUTED this 8th day of November, 2012.

APACHE CORPORATION
By:	/s/ Margery M. Harris
	Margery M. Harris Executive Vice President, Human Resources

Prepared November 7, 2012

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EX-10.27

Exhibit 10.27

Apache Corporation Non-Qualified Restorative Retirement Savings Plan

Apache Corporation (“Apache”) sponsors the Apache Corporation Non-Qualified Restorative Retirement Savings Plan (the “Plan”). In section 8.02(a) of the Plan, Apache reserved the right to amend the Plan from time to time. Apache hereby exercises that right, as follows, effective as of January 1, 2013, by revising section 2.01 to read as follows:

The Committee shall from time to time in its sole discretion select those Employees who are eligible to participate in the Plan from those Employees who are among a select group of management or highly compensated employees. Furthermore, (a) an Employee is eligible to make Participant Deferrals to this Plan from his Compensation only if the Employee is not eligible to make similar deferrals to the Non-Qualified Retirement\Savings Plan from the same Compensation, and (b) an Employee is eligible to receive an allocation of Company Deferrals with respect to his Compensation only if he or she is not eligible to receive similar company deferrals attributable to the same Compensation in the Non-Qualified Retirement\Savings Plan.

EXECUTED this 8th day of November, 2012.

APACHE CORPORATION
By:	/s/ Margery M. Harris
	Margery M. Harris Executive Vice President, Human Resources

Prepared November 7, 2012

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EX-10.38

Exhibit 10.38

APACHE CORPORATION

DEFERRED DELIVERY PLAN

As Amended and Restated February 5, 2013

APACHE CORPORATION

DEFERRED DELIVERY PLAN

Apache established this Plan effective as of February 10, 2000. Apache is now amending and restating the Plan in its entirety effective as of February 5, 2013.

Apache intends for this Plan to provide a select group of management or highly compensated employees of the Company with the opportunity to defer income, and, in conjunction with the 2007 and 2011 Omnibus Equity Compensation Plans, to be appropriately rewarded when Apache’s shares increase in value, to induce such employees to remain in the employ of the Company, and to reward those employees for their valuable services to the Companies.

Apache intends that the Plan not be treated as a “funded” plan for purposes of either the Code or ERISA. Apache also intends for this Plan to comply with the requirements of Code §409A, and the Plan shall be interpreted in that light.

ARTICLE I    DEFINITIONS

1.01 Definitions

Defined terms used in this Plan shall have the meanings set forth below:

(a) “Account” means the memorandum account maintained for each Participant that is credited with all Participant Deferrals and any contributions by the Company. Each Participant’s Account is divided into subaccounts, as determined by the Committee, and in general each award or deferral will be allocated to its own subaccount.

(b) “Apache” means Apache Corporation or any successor thereto.

(c) “Affiliated Entity” means any legal entity that is treated as a single employer with Apache pursuant to Code §414(b), §414(c), §414(m), or §414(o).

(d) “Beneficiary” means a Participant’s beneficiary, as determined in section 5.04.

(e) “Change of Control” means a change of control as defined in the Income Continuance Plan that is also described in Code §409A(a)(2)(A)(v).

(f) “Code” means the Internal Revenue Code of 1986, as amended. Any reference to a particular section of the Code or the regulations issued thereunder shall be treated as a reference to any successor section.

(g) “Committee” means the Stock Plan Committee of Apache’s Board of Directors. The Committee shall be constituted at all times so as to permit the Plan to be administered by “non-employee directors” (as defined in Rule 16b-3 of the Securities Exchange Act of 1934, as amended).

(h) “Company” means Apache and any Affiliated Entity that, with approval of the Board of Directors of Apache, has adopted the Plan.

(i) “Company Deferrals” means the allocations to a Participant’s Account made pursuant to section 3.02.

(j) “Compensation” means amounts deferrable under this Plan, as determined by the Committee. “Election Agreement” means an agreement made by an eligible employee whereby he elects the amount(s) to be withheld from his Compensation pursuant to section 3.01.

(k) “ERISA” means the Employee Retirement Income Security Act of 1974, as amended. Any reference to a particular section of ERISA or the regulations issued thereunder shall be treated as a reference to any successor section.

(l) “Fair Market Value” means the per share closing price of the Stock as reported on The New York Stock Exchange, Inc. Composite Transactions Reporting System for a particular date or, if the Stock is not so listed on such date, as reported on NASDAQ or on such other exchange or electronic trading system which, on the date in question, reports the largest number of traded shares of Stock, provided, however, that if on the date Fair Market Value is to be determined there are no transactions in the

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Stock, Fair Market Value shall be determined as of the immediately preceding date on which there were transactions in the Stock; provided further, however, that if the foregoing provisions are not applicable, the fair market value of a share of the Stock as determined by the Committee by the reasonable application of such reasonable valuation method, consistently applied, as the Committee deems appropriate. For purposes of the foregoing, a valuation prepared in accordance with any of the methods set forth in Treasury Regulation §1.409A-1(b)(5)(iv)(B)(2), consistently used, shall be rebuttably presumed to result in a reasonable valuation. This definition is intended to comply with the definition of “fair market value” contained in Treasury Regulation §1.409A-1(b)(5)(iv) and should be interpreted consistently therewith.

(m) “Participant” means any eligible employee selected to participate in the Plan.

(n) “Participant Deferrals” means the amounts of a Participant’s Compensation that elects to defer and have allocated to his Account pursuant to section 3.01.

(o) “Plan” means the plan set forth in this document, as amended.

(p) “Plan Year” means the calendar year.

(q) “Separation from Service” has the same meaning as the term “separation from service” in Code §409A(a)(2)(A)(i), determined using the default rules in the regulations and other guidance of general applicability issued pursuant to Code §409A, except that a Separation from Service occurs only if both the Company and the Participant expect the Participant’s level of services to permanently drop by more than half. A Participant who has a Separation from Service “Separates from Service.”

(r) “Spouse” means the individual of the opposite sex to whom a Participant is lawfully married according to the laws of the state of the Participant’s domicile.

(s) “Stock” means the $0.625 par value common stock of Apache.

(t) “Stock Units” mean investment units and any related units from dividend amounts. Each Stock Unit is equivalent to one share of Stock.

(u) “Trust” means the trust or trusts, if any, created by the Company to provide funding for the distribution of benefits in accordance with the provisions of the Plan. The assets of any such Trust remain subject to the claims of the Company’s general creditors in the event of the Company’s insolvency.

(v) “Trust Agreement” means the written instrument pursuant to which each separate Trust is created.

(w) “Trustee” means one or more banks, trust companies, or insurance companies designated by the Company to hold and invest the Trust fund and to pay benefits and expenses as authorized by the Committee in accordance with the terms and provisions of the Trust Agreement.

1.02 Headings; Gender and Number

The headings contained in the Plan are for reference purposes only and shall not affect in any way the meaning or interpretation of the Plan. Except when otherwise indicated by the context, the masculine gender shall also include the feminine gender, and the definition of any term herein in the singular shall also include the plural.

ARTICLE II    ELIGIBILITY AND PARTICIPATION

2.01 Eligibility and Participation

The Committee shall from time to time in its sole discretion select those employees of the Company who are eligible to participate in the Plan from among a select group of management or highly compensated employees.

2.02 Election

Participants shall complete the election procedures specified by the Committee. The election procedures may include form(s) for the Participant to designate a Beneficiary, elect Participant Deferrals by entering into an Election Agreement with the Company, select a payment option for the eventual distribution of his Account or any subaccount, and provide such other information as the Committee may reasonably require.

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2.03 Failure of Eligibility

The Committee shall have the authority to determine that a Participant is no longer eligible to participate in the Plan. When a Participant becomes ineligible, all outstanding Election Agreements shall be cancelled. The determination of the Committee with respect to the termination of participation in the Plan shall be final and binding on all parties affected thereby. Any benefits vested hereunder at the time the Participant becomes ineligible to continue participation shall be distributed in accordance with the provisions of Article V.

ARTICLE III    CONTRIBUTION DEFERRALS

3.01 Participant Deferrals

(a) General. A Participant may elect to defer a portion of his Compensation by filing the appropriate Election Agreement with the Committee’s designee. The Committee has complete discretion to establish procedures for the completion of Election Agreements, including the acceptable forms and formats of the deferral election. The Committee has complete discretion to establish the election periods during which Participants may make Election Agreements, within the bounds described in subsection (b). The Committee may establish different election periods for different types of Compensation, different grants of Compensation, or different groups of Participants.

(b) Deadlines for Election Agreements.

(i) Election Period. In order to make Participant Deferrals, a Participant must submit an Election Agreement during the election period established by the Committee. The election period must precede the Plan Year in which the services giving rise to the Compensation are performed, except in the following situations.

(A) Performance-Based Compensation. If the Compensation is “performance-based compensation based on services performed over a period of at least 12 months” (within the meaning of Code §409A(a)(4)(B)(iii)), the election period must end at least six months before the end of the performance period.

(B) New Participant. The election period for a new Participant must end no later than 30 days after he became eligible to participate in the Plan; the new Participant’s initial Election Agreement may only apply to Compensation for which he has not yet performed any services. However, a Participant who has a lapse in eligibility to participate in the Plan can only use this special 30-day election when he again becomes eligible to accrue benefits (other than investment earnings), (1) on the date of his new eligibility if he has received a complete payout of his benefits from his prior episode of participation, or (2) if his lapse in eligibility was at least 24 months in duration.

(C) Unvested Deferrals. The election period for any Compensation that is subject to the condition that the Participant continue to provide services for Apache and Affiliated Entities for at least 12 months, such as many grants of restricted stock units, must end within 30 days of the date the Compensation is awarded, provided that (1) the award does not vest for 12 months following the end of the election period, (2) no event other than the Participant’s death or disability (within the meaning of Code §409A(2)(C)), or a Change of Control can cause vesting within the 12 months following the end of the election period, and (3) if the Participant’s death or disability, or the Change of Control occurs before the first anniversary of the end of the election period, the Election Agreement shall be cancelled.

(ii) Duration of and Cancellation of Election Agreements. The Committee has full discretion to determine which Compensation is subject to each Election Agreement. The Election Agreement becomes irrevocable by the Participant at the end of the election period. The Committee shall determine, at the time the Election Agreement is made, the circumstances in which the Election

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Agreement shall be cancelled, such as upon the Participant’s disability (within the meaning of Code §409A(a)(2)(A)(ii)) or upon a Change of Control. An Election Agreement is not affected by a hardship withdrawal from the Non-Qualified Retirement/Savings Plan of Apache Corporation. However, if the Participant takes a hardship withdrawal from the Apache Corporation 401(k) Savings Plan, all outstanding Election Agreements that apply to Compensation that would have been paid to the Participant within six months after the hardship withdrawal (if the Election Agreements had not been in effect) shall be cancelled and no further Participant Deferrals made pursuant to such Election Agreements.

3.02 Company Deferrals

Upon prior approval of the Committee, the Company may credit any amount to a Participant’s Account at any time.

ARTICLE IV    INVESTMENT OF DEFERRALS AND ACCOUNTING; VOTING

4.01 Investments

All amounts credited to a Participant’s Account shall be invested in Stock Units, with the number of Stock Units determined using the Fair Market Value of the Stock for the date as of which the amount is credited to the Participant’s Account. Amounts equal to any cash dividends declared on the Stock shall be credited to the Participant’s Account as of the payment date for such dividend in proportion to the number of Stock Units in the Participant’s Account as of the record date for such dividend. Such dividend amounts shall be invested in Stock Units, with the number of Stock Units determined using the Fair Market Value of the Stock on the dividend payment date, and such Stock Units shall vest pursuant to section 5.01. Nothing contained in this section shall be construed to require the Company or the Committee to fund any Participant’s Account.

4.02 Voting

Participants shall have no right to vote any Stock Units prior to the date on which such Stock Units are subject to distribution and shares of Stock are issued therefor.

ARTICLE V    DISTRIBUTIONS

5.01 Vesting

(a) General. Each award of Compensation to a Participant shall vest in accordance with the terms of the award, which are determined by the Committee. Upon the death or disability of a Participant, the award shall specify whether no vesting occurs, whether the next tranche or some other portion of the award vests, or whether the entire award vests.

(b) Termination for Cause. If the employment of the Participant is terminated for cause as determined by the Company, the Participant’s entire Account balance, whether vested or not, shall be forfeited immediately. For this purpose, “cause” shall mean a gross violation, as determined by the Company, of the Company’s established policies and procedures.

(c) Earnings. Stock Units attributable to dividend amounts credited to a Participant’s Account shall vest as the Stock Units on which the dividend amounts are calculated vest.

(d) Change of Control. If a change of control, within the meaning of Apache’s Income Continuance Plan or any successor plan, of Apache occurs, all unvested Stock Units credited to Participants’ Accounts shall become automatically vested, without further action by the Committee or Apache’s board of directors.

5.02 Payouts of Company Deferrals.

(a) Timing of Payout. The Committee may specify the timing of the distribution of any grant of Company Deferrals, or the Committee may allow a Participant to make a payout election for his Company Deferrals. If the Participant is given the opportunity to make a payout election, the deadline for the election is 30 days after the grant of a Company Deferral unless the Committee specifies an earlier deadline.

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(b) Payout Alternatives. A Participant shall receive a lump sum distribution of the subaccount(s) containing Company Deferrals six months after he Separates from Service, unless the Committee permits him to elect five installments and he so elects, in which case the first installment will be paid six months after his Separation from Service, or as soon as convenient after that date, and subsequent installments will be paid on the anniversary of the first installment, or as near to that date as is administratively convenient.

(c) Death or Change of Control. If there is a Change of Control or the Participant dies before receiving all installments, the remaining vested benefits shall be paid as specified in section 5.04 or 5.05, rather than as provided for in this section.

(d) Disability. Each award of Compensation will specify whether the Participant’s disability (which shall fall within the meaning of the term in Code §409A(a)(2)(A)(ii)) will trigger a payout and when such payout(s) shall occur.

(e) Small Accounts. See section 5.03(d) for payouts of small accounts.

5.03 Payouts of Participant Deferrals

(a) Election. Each subaccount containing Participant Deferrals shall be paid in a lump sum six months after the Participant’s Separation from Service unless the Committee, in its sole discretion, allows a Participant to elect, and the Participant does elect, to have the Participant Deferrals under an Election Agreement paid to him in one of the following manners. Any payout election that the Participant is permitted make with respect to deferrals pursuant to an Election Agreement must be made by the end of the election period for that Election Agreement. The Committee has the discretion to reduce the possible payout alternatives from the three identified below.

(i) In-Service Withdrawal, Single Payment. The subaccount for Participant Deferrals from an Election Agreement will be paid in a lump sum five years after the Stock Units vest, or as near to that date as is administratively convenient. For example, if the Stock Units under a particular Election Agreement vest over four years, the Participant will receive four annual lump sums. If the Participant Separates from Service before receiving all lump sums with respect to an Election Agreement, (A), if a lump sum is scheduled to be paid during the six months after the Separation from Service, it will be paid as scheduled, and (B) if any lump sum is scheduled to be paid more than six months after the Separation from Service, it will instead be paid 6 months after his Separation from Service, or as soon thereafter as is administratively convenient.

(ii) In-Service Withdrawal, Limited Installments. This payout alternative is available only if all Stock Units relating to an Election Agreement either are vested at the time of the Election Agreement or are scheduled to vest on a single date; thus, for example, this alternative is not available for a restricted stock unit award where vesting is scheduled to occur over four years. The benefits will be paid in five annual installments, with the first installment paid five years after the Stock Units vest (or, if vested when granted, five years after the date of the grant), or as near to that date as is administratively convenient. Subsequent installments are paid on the anniversary of the first installment or as near to that date as is administratively convenient. The amount of each installment is equal to the number of remaining Stock Units associated the Election Agreement, divided by the number of remaining installments, rounded down to the nearest whole Stock Unit, except that the last installment is equal to the number of remaining vested Stock Units, with any fractional share paid in cash. If the Participant Separates from Service before receiving all installments with respect to an Election Agreement, (A), any installment payment scheduled to be paid during the six months after the Separation from Service will be paid as scheduled, and (B) any remaining installment(s) will instead be paid in a lump sum 6 months after his Separation from Service, or as soon thereafter as is administratively convenient.

(iii) No In-Service Withdrawal. The subaccount for the Participant Deferrals from each Election Agreement will be paid out in a single payment or in five annual installments. The single payment or the first installment payment will be paid six months after the Participant’s Separation from Service or as soon thereafter as is administratively convenient; subsequent

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installments will be paid on each anniversary of the first installment, or as near thereto as administratively convenient. Each installment will be equal to the balance in the subaccount measured as short a period of time before the installment is paid as is administratively convenient, divided by the number of remaining annual installments, rounded down to the nearest whole Stock Unit, except that the last installment shall be equal to the number of remaining Stock Units, with any fractional share paid in cash.

(b) Existing Elections. If a Participant made an Election Agreement before 2009 for an award that vested over more than one year and the Participant elected to defer such amounts for five years after vesting occurred with each amount paid in five installments, the payments scheduled to be made on or after January 1, 2009 will, in spite of the Participant’s previous election, be paid a lump sum on the fifth anniversary of date of the date such Stock Units vested, or, if later, in January of 2009. If the Participant Separates from Service before receiving all lump sums with respect to an Election Agreement, (i) if a lump sum is scheduled to be paid during the six months after the Separation from Service, it will be paid as scheduled, and (ii) if any lump sum is scheduled to be paid more than six months after the Separation from Service, it will instead be paid in January 2009 or if later six months after his Separation from Service, or as soon thereafter as is administratively convenient

(c) Death or Change of Control. If there is a Change of Control or the Participant dies before receiving all vested Stock Units, the remaining vested Stock Units shall be paid as specified in section 5.02(d), 5.04, or 5.05, rather than as originally scheduled.

(d) Small Accounts. If the Fair Market Value of a Participant’s vested Account six months after he Separates from Service is less than $100,000, he shall receive a lump sum payment of the vested Account balance six months after the Separation from Service or as soon thereafter as is administratively convenient.

5.04 Distributions After Participant’s Death

This section applies once a Participant dies.

(a) Immediate Payment. When a Participant dies, his remaining vested Account balance shall be paid to each beneficiary in one lump sum four months after the Participant’s death, which should give each beneficiary adequate time to decide whether to disclaim. However, no payment may be made before the Committee’s designee has been furnished with proof of death and such other information as it may reasonably require, including information needed for tax reporting purposes. Such distribution shall be paid in whole shares of Stock, with any fractional shares paid in cash.

(b) Designating Beneficiaries. Each Participant shall designate one or more persons, trusts, or other entities as his Beneficiary to receive any amounts distributable hereunder after the Participant’s death, by furnishing the Committee with a beneficiary designation form. In the absence of an effective Beneficiary designation as to part or all of a Participant’s interest in the Plan, such amount will be distributed to the Participant’s surviving Spouse, if any, otherwise to the Participant’s estate. Unless the Participant’s beneficiary designation form specifies otherwise, if a Beneficiary dies after the Participant but before being paid by the Plan, the Plan shall pay the Beneficiary’s estate.

(c) Changing Beneficiaries. A beneficiary designation may be changed by the Participant at any time and without the consent of any previously designated Beneficiary. However, if the Participant is married, his Spouse shall be his Beneficiary unless such Spouse has consented to the designation of a different Beneficiary. To be effective, the Spouse’s consent must be in writing, witnessed by a notary public, and filed with the Committee’s designee. If a Participant has designated his Spouse as a Beneficiary or as a contingent Beneficiary, and the Participant and that Spouse subsequently divorce, then the former Spouse will be treated as having pre-deceased the Participant for purposes of interpreting a beneficiary designation form completed prior to the divorce; this sentence shall apply only if the Committee’s designee is informed of the divorce before payment to the former Spouse is authorized.

(d) Disclaimers. Any individual or legal entity who is a Beneficiary may disclaim all or any portion of his interest in the Plan, provided that the disclaimer satisfies the requirements of applicable state law and Code §2518(b). The legal guardian of a minor or legally incompetent person may disclaim for such

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person. The personal representative (or the individual or legal entity acting in the capacity of the personal representative according to applicable state law) may disclaim on behalf of a Beneficiary who has died. The amount disclaimed shall be distributed as if the disclaimant had predeceased the Participant.

5.05 Change of Control

(a) Former Employees.

(i) Separated More than Six Months. Each Participant who is not a “specified employee” (defined below) and each Participant who Separated from Service more than six months before the date of a Change of Control, including those who are already receiving installment payments, will be paid a single payment of his entire remaining vested Account balance on the date of the Change of Control or as soon thereafter as is administratively practicable.

(ii) Recent Separations. Each Participant who is a specified employee and who Separated from Service less than six months before the Change of Control occurred will be paid a single payment of his entire Account balance six months after his Separation from Service, or as soon thereafter as is administratively practicable.

(iii) Specified Employee. The term “specified employee” has the same meaning as the term “specified employee” in Code §409A(a)(2)(B)(i), and is determined using the default rules in the regulations and other guidance of general applicability issued pursuant to Code §409A.

(b) Current Employees. Each Participant who is an employee on the date of a Change of Control will be paid a lump sum of his entire vested Account balance on the date of the Change of Control or as soon thereafter as is administratively practicable.

5.06 Rehires. If a Participant Separated from Service and then becomes eligible to again accrue benefits, the payment of his benefits from his first episode of participation will not be affected by his subsequent participation. He will be treated as a new Participant for making payout elections for benefits accruing during his second episode of participation, except as otherwise provided in section 3.01.

5.07 Form of Distribution. Subject to section 5.08, each payment shall be made in whole shares of Stock, with each Stock Unit being converted into one share of Stock. Any fractional Stock Units will be converted into cash based on the Fair Market Value of a share of Stock on the day preceding the day the payment is processed. Upon a change of control as defined in the Income Continuance Plan or its successor, the payment for each Stock Unit shall be one share of Stock unless the material characteristics of the Stock were affected by the Change of Control, in which case the payment for each Stock Unit shall be in the form of cash equal to the fair market value, determined as of the date of the Change of Control, of the property an Apache shareholder receives upon the change of control in exchange for one of his Shares.

5.08 Withholding

At the time of vesting or payment, as applicable, either the recipient shall pay the Plan cash sufficient to cover the required withholding or the Plan shall withhold from such payment any taxes or other amounts that are required to be withheld pursuant to any applicable law; any Stock Units withheld shall be converted into cash based on the Fair Market Value of a share of Stock (a) on the day preceding the day the payment is processed or (b) on the day the vesting occurs.

5.09 Divorce

(a) General. If a Participant has divorced his Spouse, all or a portion of his Account may be allocated to his former Spouse. The Participant may be a former or current employee of the Company.

(b) Contents of Order. The allocation will occur as soon as practicable after the Plan receives a judgment, decree, or order (collectively, an “order”) that (i) is made pursuant to a state domestic relations law or community property law, (ii) relates to the marital property rights of the former Spouse, (iii) unambiguously specifies the amount or percentage of the Participant’s Account that is to be allocated to the former Spouse, or unambiguously specifies the manner in which the amount or percentage is to be calculated, (iv) does not allocate any benefits that have already been allocated to a different former

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Spouse, (v) contains the name and last known mailing address of the Participant and eh former Spouse, (vi) the name of the Plan, (vii) does not contain any provision that violates subsections (c), (d), or (e), and (viii) contains the former Spouse’s Social Security number (or other similar taxpayer identification number) unless such number has been provided by the former Spouse to the Plan in a manner acceptable to the Committee.

(c) Payout Provisions. The vested portion of the amount allocated to the former Spouse will be paid to the former Spouse in a single payment as soon as administratively practicable after (i) the Plan has determined that the order meets the requirements of subsection (b), (ii) the Plan has communicated its interpretation of the order to the Participant and former Spouse, and given them a reasonable amount of time (such as 30 days) to object to the Plan’s interpretation, (and if there is a timely objection, the parties must submit a revised order or withdraw their objections), and (iii) the parties agree to the Plan’s interpretation of the order.

(d) Not Fully Vested. If the former Spouse is allocated any unvested amounts, the Plan will establish a separate account for the former Spouse. Unvested amounts are forfeited at the same time as the Participant’s unvested amounts are forfeited. If an amount allocated to the former Spouse subsequently become vested, the newly-vested amount will be paid to the former Spouse in a single payment as soon as administratively practicable following the additional vesting. If the former Spouse dies before award is fully vested, the unvested amounts shall be returned to the Participant’s Account.

(e) Source of Funds. The order may specify which subaccounts the former Spouse’s benefits shall be taken from; if the order is silent on this matter, the amount awarded to the former Spouse shall be taken from the Participant’s subaccounts in the order determined by the Committee and shall be taken on a pro rata basis from the vested portion of the Account and the unvested portion.

5.10 Timing of Payments

The previous sections in this Article specify when payments will be made pursuant to the Plan, and generally provide the Plan with some flexibility, for example by providing that the payment will occur on a specific date or as near to that date as is administratively convenient. Notwithstanding such flexibility, any payment that is scheduled to occur in one calendar year shall occur in that calendar year.

5.11 Administrative Delays in Payments

The Committee may delay any payment from this Plan for as short a period as is administratively necessary. For example, a delay may be imposed upon all payments when there is a change of recordkeeper or trustee, and a delay may be imposed on payments to any recipient until the recipient has provided (a) the information needed to determine the appropriate tax withholding and tax reporting and (b) any other information reasonably requested by the Committee. If possible, the delay will satisfy one of the conditions to be considered a permissible delay under Code §409A.

5.12 Noncompliance with Code §409A

To the extent that the Company or the Committee takes any action that causes a violation of Code §409A or fails to take any reasonable action required to comply with Code §409A, Apache shall pay an additional amount (the “gross-up”) to the individual(s) who are subject to the penalty tax under Code §409A(a)(1); the gross-up will be sufficient to put the individual in the same after-tax position he would have been in had there been no violation of Code §409A. The Company shall not pay a gross-up if the cause of the violation of Code §409A is the due to the recipient’s action or due to the recipient’s failure to take reasonable actions (such as failing to timely provide the information required for tax withholding or failing to timely provide other information reasonably requested by the Committee – with the result that the delay in payment violates Code §409A). Any gross-up will be paid as soon as administratively convenient after the Committee determines the gross-up is owed, and no later than the end of the calendar year immediately following the calendar year in which the additional taxes are remitted. However, if the gross-up is due to a tax audit or litigation addressing the existence or amount of a tax liability, the gross-up will be paid as soon as administratively convenient after the litigation or audit is completed, and no later than the end of the calendar year following the calendar year in which the audit is completed or there is a final and non-appealable settlement or other resolution of the litigation.

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ARTICLE VI    ADMINISTRATION

6.01 Committee to Administer and Interpret Plan

The Plan shall be administered by the Committee. The Committee shall have all discretion and powers necessary for administering the Plan, including, but not by way of limitation, full discretion and power to interpret the Plan, to determine the eligibility, status and rights of all persons under the Plan and, in general, to decide any dispute. The Committee shall direct the Company, the Trustee, or both, as the case may be, concerning distributions in accordance with the provisions of the Plan. The Committee’s designee shall maintain all Plan records except records of any Trust. The Committee may delegate any of its administrative duties to a designee.

6.02 Organization of Committee

The Committee shall adopt such rules as it deems desirable for the conduct of its affairs and for the administration of the Plan. The Committee may appoint a designee and/or agent (who need not be a member of the Committee or an employee of the Company) to assist the Committee in administration of the Plan and to whom it may delegate such powers as the Committee deems appropriate, except that the Committee shall determine any dispute. The Committee may make its determinations with or without meetings. The Committee may authorize one or more of its members, designees or agents to sign instructions, notices and determinations on its behalf. The action of a majority of the Committee’s members shall constitute the action of the Committee.

6.03 Agent for Process

Apache’s General Counsel and Apache’s Corporate Secretary shall each be an agent of the Plan for service of all process.

6.04 Determination of Committee Final

The decisions made by the Committee shall be final and conclusive on all persons.

ARTICLE VII    TRUST

7.01 Trust Agreement

The Company may, but shall not be required to, adopt a separate Trust Agreement for the holding and administration of the funds contributed to Accounts under the Plan. The Trustee shall maintain and allocate assets to a separate account for each Participant under the Plan. The assets of any such Trust shall remain subject to the claims of the Company’s general creditors in the event of the Company’s insolvency.

7.02 Expenses of Trust

The parties expect that any Trust created pursuant to section 7.01 will be treated as a “grantor” trust for federal and state income tax purposes and that, as a consequence, such Trust will not be subject to income tax with respect to its income. However, if the Trust is separately taxable, the Trustee shall pay all such taxes out of the Trust. All expenses of administering any such Trust shall be a charge against and shall be paid from the assets of such Trust.

ARTICLE VIII    AMENDMENT AND TERMINATION

8.01 Amendment

The Plan may be amended at any time and from time to time, retroactively or otherwise; however, no amendment shall reduce any vested benefit that has accrued on the effective date of such amendment. Each Plan amendment shall be in writing and shall be approved by the Committee and/or Apache’s Board of Directors. An officer of Apache to whom the Committee and/or Apache’s Board of Directors has delegated the authority to execute Plan amendments shall execute each such amendment or the Plan document restated to include all such Plan amendment(s).

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The Committee shall have the authority to adopt such modifications, procedures and subplans as may be necessary or desirable to comply with the provisions of the laws (including, but not limited to, tax laws and regulations) of countries other than the United States in which the Company may operate, so as to assure the viability of the benefits of the Plan to Participants employed in such countries. In only certain limited circumstances, as described in the Treasury Regulations and other guidance of general applicability issued pursuant to Code §409A, may the termination of a plan affect the timing of the payment of Plan benefits.

8.02 Successors and Assigns; Termination of Plan

The Plan is binding upon Apache and its successors and assigns. The Plan shall continue in effect from year to year unless and until terminated by Apache’s Board of Directors. Any such termination shall operate only prospectively and shall not reduce any vested benefit that has accrued on the effective date of such termination.

ARTICLE IX    STOCK SUBJECT TO THE PLAN

9.01 Number of Shares

Subject to Section 4.01, and to adjustment pursuant to Section 9.03 hereof, 350,000 shares of Stock (adjusted to 735,000 shares for (i) the Company’s five-percent stock dividend, record date March 12, 2003, paid April 2, 2003, and (ii) the Company’s two-for-one stock split, record date December 31, 2003, distributed January 14, 2004) are authorized for issuance under the Plan in accordance with the provisions of the Plan and subject to such restrictions or other provisions as the Committee may from time to time deem necessary. This authorization may be increased from time to time by approval of the Board and the stockholders of Apache if, in the opinion of counsel for the Company, such stockholder approval is required. Shares of Stock distributed under the terms of the Plan and shares of Stock equal to the number of Stock Units credited to Participants’ Accounts maintained under the Plan shall be applied to reduce the maximum number of shares of Stock remaining available for use under the Plan. However, shares of Stock represented by any Stock Units related to the deferral of income from any plan for which shares of Stock have been authorized for issuance, such as the 2007 Omnibus Equity Compensation Plan, shall retain their authorization under such plan, and shall not be applied to reduce the number of shares of Stock remaining available for use under the Plan. Apache, at all times during the existence of the Plan and while any Stock Units are credited to Participants’ Accounts maintained under the Plan, shall retain as Stock in Apache’s treasury at least the number of shares from time to time required under the provisions of the Plan, or otherwise assure itself of its ability to perform its obligations hereunder.

9.02 Other Shares of Stock

The shares of Stock represented by any Stock Units from dividend amounts that are forfeited, and any shares of Stock that for any other reason are not issued to a Participant or are forfeited, shall again become available for use under the Plan.

9.03 Adjustments for Stock Split, Stock Dividend, Etc.

If Apache shall at any time increase or decrease the number of its outstanding shares of Stock or change in any way the rights and privileges of such shares by means of the payment of a Stock dividend or any other distribution upon such shares payable in Stock, or through a Stock split, subdivision, consolidation, combination, reclassification or recapitalization involving the Stock, then in relation to the Stock that is affected by one or more of the above events, the numbers, rights and privileges of the following shall be increased, decreased or changed in like manner as if they had been issued and outstanding, fully paid and nonassessable at the time of such occurrence: (a) the shares of Stock remaining available for use under the Plan; and (b) the shares of Stock then represented by Stock Units credited to Participants’ Accounts maintained under the Plan.

9.04 Dividend Payable in Stock of Another Corporation, Etc.

If Apache shall at any time pay or make any dividend or other distribution upon the Stock payable in securities or other property (except cash or Stock), a proportionate part of such securities or other property

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shall be set aside for Stock Units credited to Participants’ Accounts maintained under the Plan and delivered to any Participant upon distribution pursuant to the terms of the Plan. Prior to the time that any such securities or other property are delivered to a Participant in accordance with the foregoing, Apache shall be the owner of such securities or other property and shall have the right to vote the securities, receive any dividends payable on such securities, and in all other respects shall be treated as the owner. If securities or other property which have been set aside by Apache in accordance with this Section are not delivered to a Participant because all or part of his Stock Units are forfeited pursuant to the terms of the Plan, then the applicable portion of such securities or other property shall remain the property of Apache and shall be dealt with by Apache as it shall determine in its sole discretion.

9.05 Other Changes in Stock

In the event there shall be any change, other than as specified in Sections 9.03 and 9.04 hereof, in the number or kind of outstanding shares of Stock or of any stock or other securities into which the Stock shall be changed or for which it shall have been exchanged, and if the Committee shall in its discretion determine that such change equitably requires an adjustment in the number or kind of shares (a) remaining available for use under the Plan and/or (b) represented by Stock Units credited to Participants’ Accounts maintained under the Plan, then such adjustments shall be made by the Committee and shall be effective for all purposes of the Plan.

9.06 Rights to Subscribe

If Apache shall at any time grant to the holders of its Stock rights to subscribe pro rata for additional shares thereof or for any other securities of Apache or of any other corporation, there shall be reserved with respect to the Stock Units credited to Participants’ Accounts maintained under the Plan the Stock or other securities which the Participant would have been entitled to subscribe for if immediately prior to such grant the shares of Stock represented by such Stock Units had been issued and outstanding. If, at the time of distribution under the terms of the Plan, the Participant subscribes for the additional shares or other securities, the price that is payable by the Participant for such additional shares or other securities shall be withheld from such distribution pursuant to Section 5.08 hereof.

9.07 General Adjustment Rules

No adjustment or substitution provided for in this Article IX shall require Apache to sell or otherwise issue a fractional share of Stock. All benefits payable under the Plan shall be distributed in whole shares of Stock, with any fractional shares paid in cash.

9.08 Determination by the Committee, Etc.

Adjustments under this Article IX shall be made by the Committee, whose determinations with regard thereto shall be final and binding upon all parties thereto.

ARTICLE X    REORGANIZATION OR LIQUIDATION

In the event that Apache is merged or consolidated with another corporation and Apache is not the surviving corporation, or if all or substantially all of the assets or more than 20 percent of the outstanding voting stock of Apache is acquired by any other corporation, business entity or person, or in case of a reorganization (other than a reorganization under the United States Bankruptcy Code) or liquidation of the Company, and if the provisions of Section 9.07 hereof do not apply, the Committee, or the board of directors of any corporation assuming the obligations of the Company, shall, as to the Plan and any Stock Units credited to Participants’ Accounts maintained under the Plan, either (i) make appropriate provision for the adoption and continuation of the Plan by the acquiring or successor corporation and for the protection of any Stock Units credited to Participants’ Accounts maintained under the Plan by the substitution on an equitable basis of appropriate stock of Apache or of the merged, consolidated or otherwise reorganized corporation which will be issuable with respect to the Stock, provided that no additional benefits shall be conferred upon the Participants with respect to such Stock Units as a result of such substitution or (ii) to the extent permitted by the distribution rules under Code §409A, upon written notice to the Participants, provide that all distributions from the Plan shall be made within a specified number of days of the date of such notice. In the latter event, the Committee shall accelerate the vesting of all unvested Stock Units credited to Participants’ Accounts so that all such Stock Units become fully vested and, to the extent permitted by the distribution rules under Code §409A, all Stock Units are payable prior to or upon any such event.

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ARTICLE XI    MISCELLANEOUS

11.01 Funding of Benefits—No Fiduciary Relationship

Benefits shall be paid either out of the Trust or, if no Trust is in existence or if the assets in the Trust are insufficient to provide fully for such benefits, then such benefits shall be distributed by the Company out of its general assets. Nothing contained in the Plan shall be deemed to create any fiduciary relationship between the Company and the Participants. Notwithstanding anything herein to the contrary, to the extent that any person acquires a right to receive benefits under the Plan, such right shall be no greater than the right of any unsecured general creditor of the Company, except to the extent provided in the Trust Agreement, if any.

11.02 Right to Terminate Employment

The Company may terminate the employment of any Participant as freely and with the same effect as if the Plan were not in existence.

11.03 Inalienability of Benefits

Except for disclaimers under section 5.04(d) and payments to a former Spouse pursuant to section 5.09, no Participant or Beneficiary has the right to assign, alienate, pledge, transfer, hypothecate, encumber, or anticipate his interest in any benefits under the Plan, nor are the benefits subject to garnishment by any creditor, nor may the benefits under the Plan be levied upon or attached. The preceding sentence does not apply to the enforcement of a federal tax levy made pursuant to Code §6331, the collection by the United States on a judgment resulting from an unpaid tax assessment, or any debt or obligation that is permitted to be collected from the Plan under federal law (such as the Federal Debt Collection Procedures Act of 1977).

11.04 Claims Procedure

(a) General. Each claim for benefits shall be processed in accordance with the procedures that may be established by the Committee. The procedures shall comply with the guidelines specified in this section. The Committee may delegate its duties under this section.

(b) Representatives. A claimant may appoint a representative to act on his behalf. The Plan shall only recognize a representative if the Plan has received a written authorization signed by the claimant and on a form prescribed by the Committee, with the following exceptions. The Plan shall recognize a claimant’s legal representative, once the Plan is provided with documentation of such representation. If the claimant is a minor child, the Plan shall recognize the claimant’s parent or guardian as the claimant’s representative. Once an authorized representative is appointed, the Plan shall direct all information and notification regarding the claim to the authorized representative and the claimant shall be copied on all notifications regarding decisions, unless the claimant provides specific written direction otherwise.

(c) Extension of Deadlines. The claimant may agree to an extension of any deadline that is mentioned in this section that applies to the Plan. The Committee or the relevant decision-maker may agree to an extension of any deadline that is mentioned in this section that applies to the claimant.

(d) Fees. The Plan may not charge any fees to a claimant for utilizing the claims process described in this section.

(e) Filing a Claim. A claim is made when the claimant files a claim in accordance with the procedures specified by the Committee. Any communication regarding benefits that is not made in accordance with the Plan’s procedures will not be treated as a claim.

(f) Initial Claims Decision. The Plan shall decide a claim within a reasonable time up to 90 days after receiving the claim. The Plan shall have a 90-day extension, but only if the Plan is unable to decide within 90 days for reasons beyond its control, the Plan notifies the claimant of the special circumstances requiring the need for the extension by the 90th day after receiving the claim, and the Plan notifies the claimant of the date by which the Plan expects to make a decision.

(g) Notification of Initial Decision. The Plan shall provide the claimant with written notification of the Plan’s full or partial denial of a claim, reduction of a previously approved benefit, or termination of a

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benefit. The notification shall include a statement of the reason(s) for the decision; references to the plan provision(s) on which the decision was based; a description of any additional material or information necessary to perfect the claim and why such information is needed; a description of the procedures and deadlines for appeal; a description of the right to obtain information about the appeal procedures; and a statement of the claimant’s right to sue.

(h) Appeal. The claimant may appeal any adverse or partially adverse decision. To appeal, the claimant must follow the procedures specified by the Committee. The appeal must be filed within 60 days of the date the claimant received notice of the initial decision. If the appeal is not timely and properly filed, the initial decision shall be the final decision of the Plan. The claimant may submit documents, written comments, and other information in support of the appeal. The claimant shall be given reasonable access at no charge to, and copies of, all documents, records, and other relevant information.

(i) Appellate Decision. The Plan shall decide the appeal of a claim within a reasonable time of no more than 60 days from the date the Plan receives the claimant’s appeal. The 60-day deadline shall be extended by an additional 60 days, but only if the Committee determines that special circumstances require an extension, the Plan notifies the claimant of the special circumstances requiring the need for the extension by the 60th day after receiving the appeal, and the Plan notifies the claimant of the date by which the Plan expects to make a decision. If an appeal is missing any information from the claimant that is needed to decide the appeal, the Plan shall notify the claimant of the missing information and grant the claimant a reasonable period to provide the missing information. If the missing information is not timely provided, the Plan shall deny the claim. If the missing information is timely provided, the 60-day deadline (or 120-day deadline with the extension) for the Plan to make its decision shall be increased by the length of time between the date the Plan requested the missing information and the date the Plan received it.

(j) Notification of Decision. The Plan shall provide the claimant with written notification of the Plan’s appellate decision (positive or adverse). The notification of any adverse or partially adverse decision shall include a statement of the reason(s) for the decision; reference to the plan provision(s) on which the decision was based; a description of the procedures and deadlines for a second appeal, if any; a description of the right to obtain information about the second-appeal procedures; a statement of the claimant’s right to sue; and a statement that the claimant is entitled to receive, free of charge and upon request, reasonable access to and copies of all documents, records, and other information relevant to the claim.

(k) Limitations on Bringing Actions in Court. Once an appellate decision that is adverse or partially adverse to the claimant has been made, the claimant may file suit in court only if he does so by the earlier of the following dates: (i) the one-year anniversary of the date of an appellate decision made on or before a Change of Control or the three-year anniversary of the date of an appellate decision made after a Change of Control, or (ii) the date on which the statute of limitations for such claim expires.

11.05 Disposition of Unclaimed Distributions

It is the affirmative duty of each Participant to inform the Plan of, and to keep on file with the Plan, his current mailing address and the mailing address of his Spouse and any Beneficiaries. If a Participant fails to inform the Plan of these current mailing addresses, neither the Plan nor the Company is responsible for any late payment of benefits or loss of benefits. The Plan, the Committee, and the Company have no duty to search for a missing individual until the date of a Change of Control, at which point the Company has the duty to undertake reasonable measures to search for the proper recipient of any payment under the Plan that is scheduled to be paid on or after the date of the Change of Control. If the missing individual is not found within a year after a payment should have been made to him, all his benefits will be forfeited. If the missing individual later is found, the exact number of Stock Units forfeited will be restored to the Account as soon as administratively convenient, without any adjustment for dividends paid in the interim.

11.06 Distributions due Infants or Incompetents

If any person entitled to a distribution under the Plan is an infant, or if the Committee determines that any such person is incompetent by reason of physical or mental disability, whether or not legally adjudicated an

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incompetent, the Committee shall have the power to cause the distributions becoming due to such person to be made to another for his benefit, without responsibility of the Committee to see to the application of such distributions. Distributions made pursuant to such power shall operate as a complete discharge of the Company, the Trustee, if any, and the Committee.

11.07 Addresses

Any notice, form, or election required or permitted to be given under the Plan shall be in writing and shall be given by first class mail, by Federal Express, UPS, or other carrier, by fax or other electronic means, or by personal delivery to the appropriate party, addressed:

(a) If to the Company, to Apache Corporation at its principal place of business at 2000 Post Oak Boulevard, Suite 100, Houston, Texas 77056-4400 (Attention: Corporate Secretary) or at such other address as may have been furnished in writing by the Company to a Participant; or

(b) If to a Participant, at the address the Participant has furnished to the Company in writing.

(c) If to a Beneficiary or former Spouse, at the address the Participant has furnished to the Company in writing, or at the address the Beneficiary or former Spouse subsequently provided in writing.

11.08 Statutory References

Any reference to a specific section of the Code or other statute shall be deemed to refer to the cited section or to the appropriate successor section.

11.09 Governing Law

The Plan and all Election Agreements shall be construed in accordance with the Code, ERISA (if applicable), and, to the extent applicable, the laws of the State of Texas excluding any conflicts-of-law provisions.

Dated February 5, 2013
ATTEST:	APACHE CORPORATION
/s/ Cheri L. Peper	/s/ Margery M. Harris
Cheri L. Peper Corporate Secretary	Margery M. Harris Executive Vice President, Human Resources

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EX-10.39

Exhibit 10.39

APACHE CORPORATION

NON-EMPLOYEE DIRECTORS’ COMPENSATION PLAN

As Amended and Restated February 6, 2013

PURPOSE

The purpose of the Non-Employee Directors’ Compensation Plan (the “Plan”) is to set forth certain of the compensation arrangements for members of the board of directors (the “Board”) of Apache Corporation (“Apache”) who are not also employees of Apache (“Non-Employee Directors”). The Plan does not supersede or amend in any way any other arrangements relating to Non-Employee Directors including specifically, without limitation, the Outside Directors’ Retirement Plan, the 2007 and 2011 Omnibus Equity Compensation Plans, indemnification provisions of Apache’s charter or bylaws, or policies with respect to reimbursement of expenses.

It is Apache’s express intention that this Plan comply with the requirements of Code §409A, and the Plan shall be interpreted in that light.

PLAN PROVISIONS

1. Board Retainer. Each Non-Employee Director shall be paid $37,500 at the end of each calendar quarter (or as soon thereafter as is administratively practicable) during which he or she served as a member of Apache’s Board (“Cash Retainer Fee”). If a Non-Employee Director serves as a member of Apache’s Board for less than an entire calendar quarter, the Cash Retainer Fee for that quarter shall be prorated on the basis of the number of weeks served during that calendar quarter.

2. Committee Chairperson Retainers. Each Non-Employee Director serving as chairperson of any committee of Apache’s Board shall be paid $3,750 at the end of each calendar quarter (or as soon thereafter as is administratively practicable) (“Committee Chairperson Retainer Fee”). If a Non-Employee Director serves as chairperson of any committee of Apache’s Board for less than an entire calendar quarter, the Committee Chairperson Retainer Fee for that quarter shall be prorated on the basis of the number of weeks as chairperson during that calendar quarter.

3. Attendance Fees. No attendance fee shall be paid to any Non-Employee Director for any meeting of the Board or any committee thereof attended in person or by teleconference, video conference, or other similar means.

4. Optional Deferral of Fees.

(a) Deferrable Fees. A Non-Employee Director may defer all or any portion of any unpaid Cash Retainer Fees and Committee Chairperson Retainer Fees (“Deferrable Fees”).

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(b) Election to Defer. A Non-Employee Director’s election to defer all or any portion of Deferrable Fees (“Deferral Election”) shall be effected by the completion of a Deferral Election form. A Deferral Election form must be executed by the deferring Non-Employee Director and received by Apache on or before December 31 of the year prior to the year in which the Deferrable Fees are earned, except that a new Non-Employee Director may enter into a Deferral Election within 30 days of becoming a Non-Employee Director. A Deferral Election shall apply only to Deferrable Fees paid for services rendered after the date of the Deferral Election. Each December 31, a Deferral Election made for the following year shall become irrevocable. A new Deferral Election must be made each year for the upcoming year.

(c) Memorandum Account. Apache shall maintain a separate account (“Memorandum Account”) for each deferring Non-Employee Director. Each Memorandum Account shall be subdivided into a “Cash Account” and a “Stock Account.” The Memorandum Accounts are merely for recordkeeping purposes, and do not represent any actual property that has been set aside for Non-Employee Directors. Nothing contained in this Plan shall be construed to require Apache to fund any Memorandum Account. Neither the deferring Non-Employee Director nor his or her Beneficiary shall have any property interest whatsoever in any specific assets of Apache. A Non-Employee Director shall have no ownership rights with respect to any balance in his or her Memorandum Account, and thus shall have no right to vote any Stock in his or her Stock Account.

(d) Crediting of Cash Accounts. Any deferred Cash Retainer Fees and deferred Committee Chairperson Retainer Fees shall be credited to the Cash Account. Any dividends paid on Stock in the Stock Accounts shall be credited to the Cash Account. All amounts credited to a Cash Account shall be credited with investment earnings at the rate of interest earned by Apache’s short-term marketable securities portfolio or an equivalent index or market rate for similar investments in short-term marketable securities.

(e) Crediting of Stock Accounts. No deferrals shall be credited to a Stock Account; however, see section 4(f) for transfers from the Cash Account to the Stock Account. All amounts credited to a Stock Account shall be treated as if such amounts were invested in Stock. Apache shall at all times have reserved from its treasury shares for issuance under this Plan a number of shares at least equal to the number of shares of Stock in the Stock Accounts.

(f) Transfers from Cash Account to Stock Account. Each year, a Non-Employee Director may elect to transfer all or a portion of his or her Cash Account to his or her Stock Account (but only in whole-share increments) by completing an election form that must be received by Apache on or before December 31. Any such transfer shall be made as of the first trading day of the following year, and shall be based on the per share closing price of the Stock as reported on the Composite Tape for the first trading day of the year. Transfers are not permitted from a Stock Account to a Cash Account.

(g) Payout Elections. If a Non-Employee Director’s directorship terminated before January 1, 2005, his or her benefit payments shall be determined under the terms of the Plan on December 31, 2004 and the payout elections in effect at the

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time his or her directorship terminated. If a Non-Employee Director had a Separation from Service after December 31, 2004 and before January 1, 2009, his or her benefits shall be determined under the terms of the Plan in effect at the time of his or her Separation from Service (defined in paragraph (v) below). The remainder of this section 4(g) shall only apply to individuals who continue as Non-Employee Directors after December 31, 2008, or who become Non-Employee Directors after December 31, 2008.

(i) Election. Each individual who is Non-Employee Director on January 1, 2009 has made a payout election for his or her Memorandum Account, which specified both the timing and form of distribution. A new Non-Employee Director shall make a payout election at the same time that he or she makes his or her first Deferral Election. If no payout election is timely made, the Non-Employee Director shall be deemed to have elected to be paid a single lump-sum payment in January after his or her Separation from Service. The payout election with respect to a Memorandum Account is irrevocable after the deadline for making the payout election. The payout election will not apply if there is a change of control (see section 4(h)) or the Non-Employee Director dies (see section 4(i)).

(ii) Form of Payout. A Non-Employee Director may elect to be paid out in a single lump-sum payment or in two to ten annual installments. Each installment from a Stock Account shall be equal to the number of shares in the Stock Account on the second trading day of that year, divided by the number of remaining installments, rounded down to the nearest whole share. For example, the first installment from a Stock Account payable in seven installments beginning in 2010 shall be one-seventh of the shares in the account on the second trading day of 2010; the second installment shall be one-sixth of the shares in the account on the second trading date of 2011; etc. Each installment from a Cash Account shall be equal to the balance of the Cash Account on the second trading day of the year, divided by the number of remaining installments, except that the last installment shall equal the balance of the Cash Account at the time the distribution is processed. Distributions from the Stock Account shall be paid in whole shares of Stock. Distributions from the Cash Account shall be paid in cash.

(iii) Timing of Payment(s). A Non-Employee Director may select a specific year in which the single lump-sum payment is made or the installment payments begin (“In-Service Distribution”), in which case the payment will be made as soon as administratively practicable in January of the earlier of the selected year or the year after the Non-Employee Director’s Separation from Service. Alternatively, a Non-Employee Director may elect for his or her single lump-sum payment or first installment to be paid as soon as administratively practicable in the January after his or her Separation from Service. Subsequent installment payments shall be made in January of each year, beginning with the year after the first installment was paid.

(iv) Special Rules Where Payments Begin While Still a Director. This paragraph (iv) applies to a Non-Employee Director who elected an In-Service Distribution. A second Memorandum Account shall be established for the Non-Employee Director for any amounts deferred into the Plan during or after the

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year in which the In-Service Distribution is scheduled to begin. Distributions from the second Memorandum Account shall be subject to the rules specified in this section 4(g), except that a Non-Employee Director must complete a payout election for the second Memorandum Account by the December 31 that immediately precedes the year in which amounts are first deferred into the second Memorandum Account.

(v) Definition of Separation from Service. The term “Separation from Service” has the same meaning as the term “separation from service” in Code §409A(a)(2)(A)(i), determined using the default rules in the regulations and other guidance of general applicability issued pursuant to Code §409A, including the special rules for members of a board of directors found in Treasury Regulation §1.409A-1(h)(5) and §1.409A-1(c)(2)(ii). In general, a Separation from Service will occur when a Non-Employee Director ceases to be a member of the Board.

(vi) Special Rules for Specified Employees.

If a Non-Employee Director is a Specified Employee, (A) any payments under paragraph (iii) above that are triggered by his or her Separation from Service and scheduled to occur within six months after the Separation from Service shall be delayed and paid six months after the Separation from Service, and (B) section 4(h) is modified for a Non-Employee Director whose Separation from Service preceded a change of control by less than six months to provide that the lump sum payment will not occur until six months after the Separation from Service.

The term “Specified Employee” has the same meaning as the term “specified employee” in Code §409A(a)(2)(B)(i), and is determined using the default rules in the regulations and other guidance of general applicability issued pursuant to Code §409A.

(h) Change of Control. If there is a change of control of Apache that is described in Code §409A(a)(2)(A)(v), each Memorandum Account shall be paid to the appropriate Non-Employee Director (or to the Beneficiary of a deceased Non-Employee Director) in a single lump-sum payment made on the date of the change of control or as soon thereafter as is administratively practicable and in no event later than the end of the calendar year in which the change of control occurs.

(i) Beneficiaries. If a Non-Employee Director dies while there is still a balance in his or her Memorandum Account, that amount shall be paid to his or her Beneficiary in a single lump-sum payment that is made as soon as administratively convenient four months after the Non-Employee Director’s death, but in no event later than the end of the calendar year that contains the day that is four months after the Non-Employee Director’s death. This four-month period is designed to provide the Beneficiary with a sufficient opportunity to disclaim all or part of the benefit, as explained in paragraph (iv) below. No payment shall be made until Apache has been furnished with proof of death and such other information as it may reasonably require.

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(i) Designation. Each Non-Employee Director shall designate one or more persons, trusts, or other entities as his or her beneficiary (“Beneficiary”). In the absence of an effective Beneficiary designation as to part or all of a Memorandum Account, such amount shall be distributed to the Non-Employee Director’s surviving Spouse, if any, otherwise to the Non-Employee Director’s estate. Unless the Non-Employee Director’s Beneficiary designation form specifies otherwise, if a Beneficiary dies after the Non-Employee Director but before being paid by the Plan, the Plan shall pay the Beneficiary’s estate.

(ii) Changing Beneficiaries. A Beneficiary designation may be changed by the Non-Employee Director at any time and without the consent of any previously designated Beneficiary. However, if the Non-Employee Director is married, the Non-Employee Director’s Spouse shall be the Beneficiary unless the Spouse has consented to the designation of a different Beneficiary. To be effective, the Spouse’s consent must have been made before January 1, 2005 or, if made on or after January 1, 2005, the Spouse’s consent must be in writing, witnessed by a notary public, and filed with Apache. If the Non-Employee Director has designated his or her Spouse as a primary or contingent Beneficiary, and the Non-Employee Director and Spouse later divorce (or their marriage is annulled), then the former Spouse will be treated as having pre-deceased the Non-Employee Director for purposes of interpreting a Beneficiary designation form completed prior to the divorce or annulment; this provision will apply only if Apache is notified of the divorce or annulment before payment to the former Spouse is made.

(iii) “Spouse” shall mean the individual to whom a Non-Employee Director is lawfully married according to the laws of the state of the Non-Employee Director’s domicile.

(iv) Disclaimers. Any individual or legal entity who is a Beneficiary may disclaim all or any portion of his or her interest in the Plan, provided that the disclaimer satisfies the requirements of Code §2518(b) and applicable state law. The legal guardian of a minor or legally incompetent person may disclaim for such person. The personal representative (or the individual or legal entity acting in the capacity of the personal representative according to applicable state law) may disclaim on behalf of a Beneficiary who has died. The amount disclaimed shall be distributed as if the disclaimant had predeceased the individual whose death caused the disclaimant to become a Beneficiary.

(j) Adjustments in Stock. In the event of any merger, consolidation, liquidation, dissolution, recapitalization, or reorganization of Apache, split, subdivision, or consolidation of shares of Stock, the payment of a stock dividend, or any other material change in Apache’s capital structure, the number of shares of Stock shown in each deferring Non-Employee Director’s Stock Account shall be adjusted to reflect that number of shares of Stock or such cash, securities, or other property to which such Non-Employee Director would have been entitled if, immediately prior thereto, such Non-Employee Director had been the holder of record of the number of shares of Stock shown in the Stock Account. Notwithstanding the foregoing, the issuance by Apache of Stock, rights, options, or warrants to acquire Stock, or securities convertible or exchangeable into Stock in consideration of cash, property, labor, or services, whether or not for fair value, shall not result in an adjustment pursuant to this section 4(j).

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5. Assignment and Transfer. The right of the Non-Employee Director or any other person to receive payments under the Plan shall not be assigned, transferred, pledged, or encumbered.

6. Amendment of Plan. The Plan may be amended from time to time or terminated by vote of the Board. Upon such amendment or termination, Non-Employee Directors shall not be entitled to receive pursuant to the Plan any compensation or other rights or benefits not accrued hereunder prior to the time of amendment or termination hereof; provided, however, that no such Plan amendment or termination shall impair any rights of Non-Employee Directors to amounts previously accrued pursuant to the Plan or accumulated in such Non-Employee Director’s Memorandum Account. A Plan termination shall not affect the timing of any benefit payments from a Memorandum Account; payment may occur substantially after the Plan is terminated.

7. Successors and Assigns. The Plan is binding upon Apache and its successors and assigns. The Plan shall continue in effect until terminated by the Board. Any such termination shall operate only prospectively and shall not affect the rights and obligations under elections previously made.

8. Administrative Delays. The Plan shall be administered by the Management Development and Compensation Committee (the “MD&C Committee”) of the Board. The MD&C Committee may delay any payment from this Plan for as short a period as is administratively necessary. For example, a delay may be imposed upon all payments from the Plan when there is a change of recordkeeper, and a delay may be imposed on payments to any recipient until they have provided the information needed for tax withholding and tax reporting, as well as any other information reasonably requested by the MD&C Committee. If possible, the delay will satisfy one of the conditions to be considered a permissible delay under Code §409A.

9. 409A Noncompliance. To the extent that Apache or the MD&C Committee takes any action that causes a violation of Code §409A or fails to take reasonable actions required to comply with Code §409A, Apache shall pay an additional amount (the “gross-up”) to the individual(s) who are subject to the penalty tax under Code §409A(a)(1) that is sufficient to put the individual in the same after-tax position he or she would have been in had there been no violation of Code §409A. Apache shall not pay a gross-up if the cause of the violation of Code §409A is the recipient’s failure to take reasonable actions (such as failing to timely provide the information required for tax withholding or failing to timely provide other information reasonably requested by the MD&C Committee—with the result that the delay in payment violates Code §409A). Any gross-up will be made as soon as administratively convenient after the MD&C Committee determines the gross-up is owed, and no later than the end of the calendar year immediately following the calendar year in which the additional taxes are remitted. However, if the gross-up is due to a tax audit or litigation addressing the existence or amount of a tax liability, the gross-up will be paid as soon as administratively convenient after the litigation or audit is completed, and no later than the end of the calendar year following the calendar year in which the audit is completed or there is a final and non-appealable settlement or other resolution of the litigation.

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10. Notices. Any notice, form, or election required or permitted to be given under the Plan shall be in writing and shall be given by first class mail, by Federal Express, UPS, or other carrier, by fax or other electronic means, or by personal delivery to the appropriate party, addressed:

(a) If to Apache, to Apache Corporation at its principal place of business at 2000 Post Oak Boulevard, Suite 100, Houston, Texas 77056-4400 (Attention: Corporate Secretary) or at such other address as may have been furnished in writing by Apache to a Non-Employee Director; or

(b) If to a Non-Employee Director or Spouse, at the address the Non-Employee Director has furnished to Apache in writing.

(c) If to a Beneficiary, at the address the Non-Employee Director has furnished to Apache in writing for such Beneficiary, unless the Beneficiary has furnished his or her own address in writing to Apache.

Any such notice to a Non-Employee Director, Spouse, or Beneficiary shall be deemed to have been given as of the third day after deposit in the United States Postal Service, postage prepaid, properly addressed as set forth above, in the case of a mailed notice, or as of the date delivered in the case of any other method of delivery.

11. Gender. Any term used herein in the singular shall also include the plural, and the masculine gender shall also include the feminine gender, and vice versa.

12. Statutory References. Any reference to a specific section of the Code shall be deemed to refer to that section or to the appropriate successor section.

13. Governing Law. The Plan shall be governed by the laws of the State of Texas, ignoring any conflicts-of-law provisions.

Dated: February 6, 2013

ATTEST:	APACHE CORPORATION
/s/ Cheri L. Peper	By:	/s/ Margery M. Harris
Cheri L. Peper	Margery M. Harris
Corporate Secretary	Executive Vice President,
	Human Resources

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EX-10.40

Exhibit 10.40

APACHE CORPORATION

OUTSIDE DIRECTORS’ RETIREMENT PLAN

(As Amended and Restated February 6, 2013)

APACHE CORPORATION (the “Company”) established the Apache Corporation Outside Directors’ Retirement Plan (the “Plan”), effective as of December 15, 1992, to provide non-employee Directors of the Company (“Outside Directors”) with certain retirement and death payments. The purpose of the Plan is to advance the interests of the Company, its subsidiaries, and its stockholders by continuing to attract and retain outstanding individuals as Outside Directors and to stimulate the efforts of such individuals by giving suitable recognition to services which will contribute materially to the success of the Company.

It is the Company’s express intention that this Plan comply with the requirements of Code §409A, and the Plan shall be interpreted in that light.

ARTICLE I

Eligibility, Participation and Contributions

1.1 Eligibility and Participation.

Each Outside Director begins to participate in the Plan as of the date his or her Service begins.

1.2 Contributions.

All amounts payable under the Plan shall be paid from the general assets of the Company. Nothing contained in the Plan shall be deemed to create any fiduciary relationship between the Company and the participating Outside Director (“Participant”). The rights of a Participant under the Plan are no greater than the rights of an unsecured general creditor of the Company.

ARTICLE II

Retirement Payments

2.1 Definitions.

The term “Separation from Service” has the same meaning as the term “separation from service” in Code §409A(a)(2)(A)(i). A Separation from Service is determined using the default rules in the regulations and other guidance of general applicability issued pursuant to Code §409A, including the special rules for a member of a board of directors found in Treasury Regulation §1.409A-1(h)(5) and §1.409A-1(c)(2)(ii). In general, a Separation from Service will occur when a Participant ceases to be a member of the Company’s Board of Directors.

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The term “Specified Employee” has the same meaning as the term “specified employee” in Code §409A(a)(2)(B)(i), and is determined using the default rules in the regulations and other guidance of general applicability issued pursuant to Code §409A.

2.2 Retirement Payments.

(a) Eligibility for Benefits. A Participant who Retires with four or more Quarters of Service is entitled to receive benefits under the Plan.

(b) Amount of Benefits. The amount of benefits under the Plan is equal to the value of a series of quarterly payments, with each payment equal in amount to one-fourth of the Participant’s Annual Director’s Retainer, and with the number of quarterly payments equal to the number of the Participant’s Quarters of Service. As a consequence, each Participant will generally receive an annual benefit of 100% of his or her Annual Director’s Retainer.

(c) “Annual Director’s Retainer” means the aggregate annual amount of an Outside Director’s board retainer fee payable pursuant to section 1 of the Company’s Non-Employee Directors’ Compensation Plan (or comparable section of any successor plan), whether or not all or a portion of such amount is deferred or delayed. Such amount will be determined as of the earlier of the date a Participant ceases to be an Outside Director or the date the Participant dies.

(d) “Quarter of Service” means the aggregate total full months of Service as an Outside Director divided by three and rounded up to the next whole number, up to a maximum of 40 Quarters of Service.

(e) “Retirement, Retired or Retires” means a Participant’s ceasing to hold office as an Outside Director, for any reason other than death.

(f) “Service” means the aggregate total, not to exceed 120, of (i) the number of full months beginning on or after July 1, 1992 (whether or not consecutive) that a Participant held office as an Outside Director, whether or not a Participant at the time, and (ii)  ¹/₂ the number of full months prior to July 1, 1992 (whether or not consecutive) that a Participant held office as an Outside Director; provided, however, that a Participant who, as of December 15, 1992, has held office as an Outside Director for an aggregate total of 15 years shall automatically be credited with 120 full months of Service.

(g) Episodic Participation. If a Participant has a Separation from Service and then becomes an Outside Director again, (i) the Participant’s benefits from his or her initial episode of participation shall be paid according to the terms of the Plan on the date of his or her Separation from Service and shall not be affected by any subsequent Service, and (ii) the Participant’s benefits from his or her later episodes of participation shall be calculated by ignoring his or her Service from earlier episodes of participation. In calculating the amount of benefits for the most recent episode of participation, the maximum Quarters of Service is 40, reduced by the number of Quarters of Service for which he or she earned benefits under this Plan from earlier episodes of participation.

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2.3 Retirement Payments Following a Change of Control.

In the event of a “change of control” of the Company, as defined in the Company’s Income Continuance Plan (as amended or the corresponding provisions of any successor plan), each then current Outside Director shall be eligible for the benefits described in section 2.2 even if the Outside Director has less than four Quarters of Service. If the change of control is a transaction described in §409A(a)(2)(A)(v) of the Internal Revenue Code of 1986, as amended (“Code”), each Participant shall be paid a single lump-sum payment on the date of the change of control, or as soon as practicable thereafter, equal to the net present value of the benefit to which the Participant is entitled, calculated in the manner described in section 2.5, as of the date of the change of control; however, if the Participant was a Specified Employee whose Separation from Service occurred less than six months before the change of control, he or she shall be paid a single lump-sum payment six months after the Separation from Service, or as soon as practicable thereafter, equal to the net present value of the benefit to which the Participant is entitled, calculated in the manner described in section 2.5, as of the date six months after the Separation from Service. If the change of control is not a transaction described in Code §409A(a)(2)(A)(v), each Participant shall be paid at the time(s) specified in section 2.4 or 2.5, whichever is applicable.

2.4 Quarterly Payments.

A Participant may elect to be paid quarterly installments that are paid on the last day of each calendar quarter (or as near to that date as administratively practicable, except that any installment scheduled to be paid during one calendar year shall be paid during such calendar year). See section 2.5 for the deadline for the Participant’s payout election. The first quarterly payment shall be made as of the last day of the calendar quarter after the date of the Participant’s Separates from Service, unless the Participant is a Specified Employee, in which case the first two quarterly payments shall be delayed until, and paid with, the third regularly scheduled quarterly payment.

2.5 Lump-Sum Payments.

A Participant shall receive a single lump-sum payment unless the Participant elects quarterly installments. Participants on December 31, 2008 have already made their payout election. A new Participant’s payout election must be made within 30 days after the individual becomes an Outside Director. Once the deadline for making a payout election has passed, the payout election is irrevocable.

The lump sum shall be paid as soon as administratively practicable after the Participant’s Separation from Service (and no later than the last day of the calendar year containing the day after the Separation from Service), unless the Participant is a

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Specified Employee, in which case the lump sum shall be paid as soon as administratively practicable after six months after the Participant’s Separation from Service (and no later than the last day of the calendar year containing the date that is six months after the Separation from Service). The amount of the lump sum shall be calculated by the Committee as of the date of the Participant’s Separation from Service. The amount of the lump sum shall be equal to the net present value of the quarterly payments to which the Participant would otherwise be entitled, determined using an annual interest rate equal to the rate on ten-year treasury bonds/notes as reported in The Wall Street Journal published on or most recently prior to the date of the Participant’s Separation from Service.

2.6 Retirement before This Restatement.

A Participant who Retired before January 1, 2005, shall receive his or her benefit in accordance with the terms of the Plan in effect at the time of the Retirement. A Participant whose Separation from Service occurred on or after January 1, 2005 shall receive his or her benefit in accordance with the terms of the Plan in effect at the time of the Separation from Service.

ARTICLE III

Death Payments

3.1 Death Benefits.

(a) Eligibility for Death Benefits. If a Participant dies before receiving all of his or her benefits under Article II, the Participant’s Beneficiary, as determined in section 3.2, shall receive the remaining benefits. If a Participant elected quarterly payments, the Participant’s Beneficiary shall be paid a lump sum equal to the net present value of any remaining payments, calculated as of the date of the Participant’s death, and calculated in the manner specified in section 2.5. If a Participant is scheduled to receive a single lump-sum payment, but dies before doing so, the Participant’s Beneficiary shall be paid the lump sum.

(b) Timing. Payment to the Beneficiary shall be made as soon as administratively practicable four months after the Participant’s death, but in no event later than the end of the calendar year that contains the day that is four months after the Participant’s death. This four-month period is designed to provide the Beneficiary with a sufficient opportunity to disclaim all or part of the benefit, as explained in section 3.2(e). No payment shall be made until the Company has been furnished with proof of death and such other information as it may reasonably require.

(c) Beneficiary in Pay Status. The Beneficiary of a Participant shall receive his or her death benefits in accordance with the terms of the Plan in effect on the date of the Participant’s death.

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3.2 Beneficiaries.

(a) “Beneficiary” means the recipient of the Participant’s death benefits under section 3.1.

(b) Designation. Each Participant shall designate one or more persons, trusts, or other entities as his or her Beneficiary. In the absence of an effective Beneficiary designation as to part or all of a Participant’s death benefits, the Participant’s surviving Spouse, if any, shall be the Participant’s Beneficiary, and in the absence of a surviving Spouse, the Participant’s estate shall be the Beneficiary. Unless the Participant’s Beneficiary designation form specifies otherwise, if a Beneficiary dies after the Participant but before being paid by the Plan, the Plan shall pay the Beneficiary’s estate.

(c) Changing Beneficiaries. A Beneficiary designation may be changed by the Participant at any time and without the consent of any previously designated Beneficiary. However, if the Participant is married, the Participant’s Spouse shall be the Participant’s Beneficiary unless the Spouse has consented to the designation of a different Beneficiary. To be effective, the Spouse’s consent must have been made before January 1, 2005 or, if made on or after January 1, 2005, the Spouse’s consent must be in writing, witnessed by a notary public, and filed with the Company. If the Participant has designated his or her Spouse as a primary or contingent Beneficiary, and the Participant and Spouse later divorce (or their marriage is annulled), then the former Spouse will be treated as having pre-deceased the Participant for purposes of interpreting a Beneficiary designation form completed prior to the divorce or annulment; this provision will apply only if the Company is notified of the divorce or annulment before payment to the former Spouse is made.

(d) “Spouse” shall mean the individual to whom a Participant is lawfully married according to the laws of the state of the Participant’s domicile.

(e) Disclaimers. Any individual or legal entity who is a Beneficiary may disclaim all or any portion of his or her interest in the Plan, provided that the disclaimer satisfies the requirements of Code §2518(b) and applicable state law. The legal guardian of a minor or legally incompetent person may disclaim for such person. The personal representative (or the individual or legal entity acting in the capacity of the personal representative according to applicable state law) may disclaim on behalf of a Beneficiary who has died. The amount disclaimed shall be distributed as if the disclaimant had predeceased the individual whose death caused the disclaimant to become a Beneficiary.

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ARTICLE IV

Administration, Amendment and Termination

4.1 The Management Development and Compensation Committee.

The Plan shall be administered by the Management Development and Compensation Committee (the “Committee”) of the Company’s Board of Directors. All administrative duties, including but not limited to, the power to interpret the Plan and to decide any dispute, shall be carried out by the Committee, which shall have full discretion and authority hereunder. All claims under the Plan shall be filed with the Company and shall be decided by the Committee. The decisions made by the Committee shall be final and binding on all persons having or claiming to have rights under the Plan.

4.2 Termination or Amendment of Plan.

The Plan may be terminated or amended at any time through action of the Company’s Board of Directors. No termination or amendment, however, shall reduce the payments (a) to a Participant or Beneficiary where a Participant has already died or reached Retirement, (b) to which a Participant is or may become entitled, based on such Participant’s Service and Annual Director’s Retainer as determined on the effective date of such termination or amendment, or (c) to which a Participant is or may become entitled pursuant to section 2.3 as a result of a change of control. The termination of the Plan shall not affect the timing of any benefit payments; payments after the Plan has terminated will be made at the time(s) specified in Articles II and III.

ARTICLE V

Miscellaneous

5.1 Inalienability of Payments.

No Participant shall have the right to assign, transfer, hypothecate, encumber or anticipate his or her interest in any payments under the Plan, nor shall the payments under the Plan be subject to any legal process to levy upon or attach such payments for any claim against the Participant, Spouse, or Beneficiary.

5.2 Notices.

Any notice, form, or election required or permitted to be given under the Plan shall be in writing and shall be given by first class mail, by Federal Express, UPS, or other carrier, by fax or other electronic means, or by personal delivery to the appropriate party, addressed:

(a) If to the Company, to Apache Corporation at its principal place of business at 2000 Post Oak Boulevard, Suite 100, Houston, Texas 77056-4400 (Attention: Corporate Secretary) or at such other address as may have been furnished in writing by the Company to a Participant; or

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(b) If to a Participant or Spouse, at the address the Participant has furnished to the Company in writing.

(c) If to a Beneficiary, at the address the Participant has furnished to the Company in writing for such Beneficiary, unless the Beneficiary has furnished his or her own address to the Company.

Any such notice to a Participant, Spouse, or Beneficiary shall be deemed to have been given as of the third day after deposit in the United States Postal Service, postage prepaid, properly addressed as set forth above, in the case of a mailed notice, or as of the date delivered in the case of any other method of delivery.

5.3 Disposition of Unclaimed Payments.

Any communication, statement or notice addressed to a Participant at his or her last post office address, as provided to the Company under section 5.2, will be binding on the Participant, Spouse, or Beneficiary for all purposes of the Plan. If the Company cannot ascertain the whereabouts of any person to whom a payment is due under the Plan within three years from the date such payment is due, such payment shall be cancelled on the records of the Plan and the amount thereof forfeited to the Company.

5.4 Administrative Delays.

The Committee may delay any payment from this Plan for as short a period as is administratively necessary. For example, a delay may be imposed upon all payments from the Plan when there is a change of recordkeeper, and a delay may be imposed on payments to any recipient until they have provided the information needed for tax withholding and tax reporting, as well as any other information reasonably requested by the Committee. If possible, the delay will satisfy one of the conditions to be considered a permissible delay under Code §409A.

5.5 409A Noncompliance.

To the extent that the Company takes any action that causes a violation of Code §409A or fails to take reasonable actions required to comply with Code §409A, the Company shall pay an additional amount (the “gross-up”) to the individual(s) who are subject to the penalty tax under Code §409A(a)(1) that is sufficient to put the individual in the same after-tax position he or she would have been in had there been no violation of Code §409A. The Company shall not pay a gross-up if the cause of the violation of Code §409A is the recipient’s failure to take reasonable actions (such as failing to timely provide the information required for tax withholding or failing to timely provide other information reasonably requested by the Committee—with the result that the delay in payment violates Code §409A). Any gross-up will be made as soon as administratively

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convenient after the Committee determines the gross-up is owed, and no later than the end of the calendar year immediately following the calendar year in which the additional taxes are remitted. However, if the gross-up is due to a tax audit or litigation addressing the existence or amount of a tax liability, the gross-up will be paid as soon as administratively convenient after the litigation or audit is completed, and no later than the end of the calendar year following the calendar year in which the audit is completed or there is a final and non-appealable settlement or other resolution of the litigation.

5.6 Gender.

Any term herein used in the singular shall also include the plural, and the masculine gender shall also include the feminine gender, and vice versa.

5.7 Statutory References.

Any reference to a specific section of the Code shall be deemed to refer to that section or to the appropriate successor section.

5.8 Governing Law.

The Plan shall be governed by the laws of the State of Texas, ignoring any conflicts-of-law provisions.

Dated: February 6, 2013

ATTEST:		APACHE CORPORATION
By:	/s/ Cheri L. Peper	By:	/s/ Margery M. Harris
	Cheri L. Peper Corporate Secretary		Margery M. Harris Executive Vice President, Human Resources

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EX-12.1

EXHIBIT 12.1

APACHE CORPORATION

STATEMENT OF COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES

AND COMBINED FIXED CHARGES AND PREFERRED STOCK DIVIDENDS

(In millions, except ratio data)

(Unaudited)	2012		2011		2010		2009		2008
EARNINGS
Pretax income from continuing operations	$	4,877	$	8,093	$	5,206	$	326		933
Add: Fixed charges excluding capitalized interest		255		246		306		286		214
Adjusted Earnings	$	5,132	$	8,339	$	5,512	$	612	$	1,147
FIXED CHARGES AND PREFERRED STOCK DIVIDENDS
Interest expense including capitalized interest (1)	$	509	$	433	$	345	$	310	$	281
Amortization of debt expense		7		6		18		5		4
Interest component of lease rental expenditures (2)		73		70		64		31		24
Fixed charges		589		509		427		346		309
Preferred stock dividend requirements (3)		185		134		55		12		7
Combined Fixed Charges and Preferred Stock Dividends (1)	$	774	$	643	$	482	$	358	$	316
Ratio of Earnings to Fixed Charges		8.71		16.39		12.93		1.77		3.72
Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends		6.63		12.97		11.44		1.71		3.63

⁽¹⁾  Interest expense related to the provisions for uncertainty in income taxes under ASC Topic 740, “Income Taxes” is not included in the computation of ratios of earnings to fixed charges and combined fixed charges and preferred stock dividends.

⁽²⁾  Represents the portion of rental expense assumed to be attributable to interest factors of related rental obligations determined at interest rates appropriate for the period during which the rental obligations were incurred. Approximately 25 to 35 percent of rental payments related to interest factors for all periods presented.

⁽³⁾  The Company does not receive a tax benefit for its preferred stock dividends. This amount represents the pre-tax earnings that would be required to cover its preferred stock dividends.

EX-21.1

Exhibit 21.1

Page 1 of 5

Apache Corporation (a Delaware corporation)

Listing of Subsidiaries as of February 20, 2013

Exact Name of Subsidiary and Name under which Subsidiary does Business	Jurisdiction of Incorporation or Organization
Apache Alaska Corporation	Delaware
Apache Corporation (New Jersey)	New Jersey
Apache CR Company	Delaware
Apache Crude Oil Marketing, Inc.	Delaware
Apache Deepwater LLC	Delaware
Apache Delaware V LLC	Delaware
Texas and New Mexico Exploration LLC	Delaware
Apache Finance Louisiana Corporation	Delaware
Apache Foundation	Minnesota
Apache Gathering Company	Delaware
Apache GOM Pipeline, Inc.	Delaware
Apache Holdings, Inc.	Delaware
Apache International Employment Inc.	Delaware
Apache International LLC	Delaware
Apache Louisiana Holdings, LLC	Delaware
Apache Louisiana Minerals LLC	Delaware
Apache Marketing, Inc.	Delaware
Apache MEI Finance, Inc.	Delaware
Apache Midstream Enterprises, Inc.	Delaware
Apache Midstream LLC	Delaware
Apache Natural Gas Transportation Fuels LLC	Delaware
Apache North America, Inc.	Delaware
Apache Caribbean Holdings Corporation	St. Lucia
Apache Finance Australia Pty Limited	Australian Capital Territory
Apache Finance Egypt I S.a.r.l.	Luxembourg
Apache Finance Egypt II S.a.r.l.	Luxembourg
Apache Luxembourg Holdings I S.a.r.l.	Luxembourg
Apache Luxembourg Holdings II S.a.r.l.	Luxembourg
Apache Luxembourg Holdings III LDC	Cayman Islands
Apache Luxembourg Holdings VI LDC	Cayman Islands
Apache Luxembourg Holdings IV S.a. r.l.	Luxembourg
Apache Finance Khalda Corporation LDC	Cayman Islands
Apache Finance Qarun Corporation LDC	Cayman Islands
Apache Finance Qarun Exploration Company LDC	Cayman Islands
Apache New Zealand Corporation LDC	Cayman Islands
Apache Oil Corporation	Texas

Page 2 of 5

Apache Corporation (a Delaware corporation)

Listing of Subsidiaries as of February 20, 2013

Exact Name of Subsidiary and Name under which Subsidiary does Business	Jurisdiction of Incorporation or Organization
Apache Overseas, Inc.	Delaware
Apache Argentina Corporation LDC	Cayman Islands
Apache Petrolera Argentina S.A.	Argentina
Apache Asia Holdings Corporation LDC	Cayman Islands
Apache Asia Pacific Corporation LDC	Cayman Islands
Apache Asyout Corporation LDC	Cayman Islands
Apache Darag Corporation LDC	Cayman Islands
Apache East Ras Budran Corporation LDC	Cayman Islands
Apache Egypt Investment Corporation LDC	Cayman Islands
Apache Egypt Holdings I Corporation LDC	Cayman Islands
Apache Egypt Holdings II Corporation LDC	Cayman Islands
Apache Abu Gharadig Corporation LDC	Cayman Islands
Apache Khalda Corporation LDC	Cayman Islands
Apache Egypt Midstream Holdings I LDC	Cayman Islands
Apache Khalda II Corporation LDC	Cayman Islands
Apache East Bahariya Corporation LDC	Cayman Islands
Apache El Diyur Corporation LDC	Cayman Islands
Apache Faiyum Corporation LDC	Cayman Islands
Apache Matruh Corporation LDC	Cayman Islands
Apache Mediterranean Corporation LDC	Cayman Islands
Apache North Bahariya Corporation LDC	Cayman Islands
Apache North El Diyur Corporation LDC	Cayman Islands
Apache North Tarek Corporation LDC	Cayman Islands
Apache Qarun Corporation LDC	Cayman Islands
Apache Qarun Exploration Company LDC	Cayman Islands
Apache Shushan Corporation LDC	Cayman Islands
Apache South Umbarka Corporation LDC	Cayman Islands
Apache Umbarka Corporation LDC	Cayman Islands
Apache West Kalabsha Corporation LDC	Cayman Islands
Apache West Kanayis Corporation LDC	Cayman Islands
Apache EMEA Corporation LDC	Cayman Islands
Apache Exploration LDC	Cayman Islands
Apache Fertilizer Holdings Corporation LDC	Cayman Islands
Apache (TAN) Pte. Ltd.	Singapore
Apache Finance East Bahariya Corporation LDC	Cayman Islands
Apache Finance Matruh Corporation LDC	Cayman Islands
Apache Finance Mediterranean Corporation LDC	Cayman Islands
Apache International Holdings S.a.r.l.	Luxembourg
Apache International Finance S.a.r.l.	Luxembourg
Apache International Finance II S.a.r.l.	Luxembourg
Apache Canada Argentina Holdings S.a.r.l.	Luxembourg
Apache Canada Argentina Investment S.a.r.l.	Luxembourg
Apache Natural Resources Petrolera Argentina S.R.L.	Argentina
Apache Energía Argentina S.R.L.	Argentina
Petrolera LF Company S.R.L.	Argentina
Petrolera TDF Company S.R.L.	Argentina

Page 3 of 5

Apache Corporation (a Delaware corporation)

Listing of Subsidiaries as of February 20, 2013

Exact Name of Subsidiary and Name under which Subsidiary does Business	Jurisdiction of Incorporation or Organization
Apache Energy Limited	Western Australia
Apache Australia Offshore Holdings Pty Ltd	Western Australia
Apache PVG Pty Ltd	Western Australia
Apache Colombia Exploration and Production LDC	Cayman Islands
Apache do Brasil Exploração e Produção de Petróleo e Gás Ltda.	Brazil
Apache East Spar Pty Limited	Western Australia
Apache Fertilisers Pty Ltd	Western Australia
Apache Julimar Holdings Pty Ltd	Western Australia
Apache Julimar Pty Ltd	Western Australia
Apache Kersail Pty Ltd	Victoria, Australia
Apache LNG Pty Ltd	Western Australia
Apache Macedon Holdings Pty Ltd	Western Australia
Apache Macedon Pty Ltd	Western Australia
Apache Northwest Pty Ltd.	Western Australia
Apache Oil Australia Pty Limited	New South Wales, Australia
Apache Permits Pty Ltd	Western Australia
Ningaloo Vision Holdings Pte. Ltd.	Republic of Singapore
Northwest Jetty Services Pty Ltd	Western Australia
Apache Finance Pty Limited	Australian Capital Territory
Apache Australia Management Pty Limited	Victoria, Australia
Apache Australia Holdings Pty Limited	Western Australia
Apache North Sea Limited	England and Wales
Apache North Sea Production Limited	England and Wales
Apache UK Investment Limited	England and Wales
Apache Beryl I Limited	Cayman Islands
Apache Beryl II Limited	England and Wales
Apache Beryl III Limited	England and Wales
Beryl North Sea II Limited	Cayman Islands
Apache Latin America II Corporation LDC	Cayman Islands
Apache Madera Corporation LDC	Cayman Islands
Apache Netherlands Investment B.V.	Amsterdam
Apache Suriname Corporation LDC	Cayman Islands
Apache Overseas Holdings, Inc.	Delaware
Apache Switzerland Holdings AG	Switzerland
Apache Kenya Holdings LLC	Delaware
Apache Kenya Limited	Kenya
Apache Overseas Holdings II, Inc.	Delaware
Onyx Acquisition Corporation LDC	Cayman Islands
Harriet (Onyx) Pty Ltd	Western Australia

Page 4 of 5

Apache Corporation (a Delaware corporation)

Listing of Subsidiaries as of February 20, 2013

Exact Name of Subsidiary and Name under which Subsidiary does Business	Jurisdiction of Incorporation or Organization
Apache Permian Basin Investment Corporation	Delaware
Apache Permian Basin Corporation	Delaware
Apache Permian Exploration and Production LLC	Delaware
LeaCo New Mexico Exploration and Production LLC	Delaware
Permian Basin Joint Venture LLC (95%)	Delaware
ZPZ Delaware I LLC	Delaware
Apache Ravensworth Corporation LDC	Cayman Islands
Apache Reagan LLC	Delaware
Apache Shady Lane Ranch Inc.	Delaware
Apache Shelf, Inc.	Delaware
Apache Stoneaxe Corporation LDC	Cayman Islands
Apache Texas LLC	Delaware
Apache Texas Property Holding Company LLC	Delaware
Apache WTX Holding Company LLC	Delaware
Apache Transfer Company	Delaware
Apache Transmission Corporation—Texas	Texas
Apache UK Limited	England and Wales
Apache Lowendal Pty Limited	Victoria, Australia
Apache Well Containment LLC	Delaware
Apache West Texas Acquisition Corporation	Delaware
Apache West Texas Holdings, Inc.	Delaware
Apache Delaware Investment LLC	Delaware
Apache West Texas Investment LLC	Delaware
Apache Western Exploration LLC	Delaware
BLPL Holdings LLC	Delaware
CDRL Holdings LLC	Delaware
Cordillera Energy Partners III, LLC	Colorado
Granite Operating Company	Texas
Clear Creek Hunting Preserve, Inc.	Wyoming
Cottonwood Aviation, Inc.	Delaware
CV Energy Corporation	Delaware
DEK Energy Company	Delaware
Apache Canada Ltd.	Alberta, Canada
Apache Canada Chile Holdings ULC	Alberta, Canada
Apache Chile Energìa SPA	Chile
Apache Canada Diego 2 ULC	Alberta, Canada
Apache Austria Investment LLC	Cayman Islands
Apache Canada KM ULC	Alberta, Canada
Apache Canada Properties Ltd.	Alberta, Canada
Apache Canada PTP Ltd.	Alberta, Canada
Apache Canada Zama Pipeline Ltd.	Federal – Canada
Apache FC Canada Enterprises Inc.	Alberta, Canada
Apache FC Capital Canada Inc.	Alberta, Canada
KM LNG Operating Ltd.	British Columbia

Page 5 of 5

Apache Corporation (a Delaware corporation)

Listing of Subsidiaries as of February 20, 2013

Exact Name of Subsidiary and Name under which Subsidiary does Business	Jurisdiction of Incorporation or Organization
Apache Finance Canada Corporation	Nova Scotia, Canada
Apache Canada Management Ltd	Alberta, Canada
Apache Canada Holdings Ltd	Alberta, Canada
Apache Canada Management II Ltd	Alberta, Canada
Apache Finance Canada III ULC	Alberta, Canada
Apache Finance Canada IV ULC	Alberta, Canada
Apache Finance Canada II Corporation	Nova Scotia, Canada
Dove Oil Corporation	Delaware
Edge Petroleum Exploration Company	Delaware
Edge Petroleum Operating Company, Inc.	Delaware
Edge Petroleum Production Company	Delaware
GOM Shelf, LLC	Delaware
Kitimat Development Inc.	Delaware
Mariner LP LLC	Delaware
MC Beltway 8, LLC	Delaware
Miller Exploration Company	Delaware
Miller Oil Corporation	Michigan
PBMRE Holdings LLC	Delaware
Phoenix Exploration Resources, Ltd.	Delaware
TEI Arctic Petroleum (1984) Ltd.	Alberta, Canada
Texas International Company	Delaware
Wheelco Energy LLC	Delaware
ZPZ Acquisitions, Inc.	Delaware
ZPZ Delaware II LLC	Delaware
Phoenix Exploration Louisiana C LLC (75%)	Delaware
ZPZ Delaware III LLC	Delaware

EX-23.1

Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

We consent to the incorporation by reference in the following Registration Statements:

(1) Registration Statements (Form S-3 Nos. 333-57785, 333-75633, 333-32580, 333-105536, 333-155884, and 333-174429) of Apache Corporation and in the related Prospectuses,

(2) Registration Statements (Form S-4 Nos. 333-107934 and 333-166964) of Apache Corporation and in the related Prospectuses, and

(3) Registration Statements (Form S-8 Nos. 33-59721, 33-63817, 333-26255, 333-32557, 333-36131, 333-31092, 333-48758, 333-97403, 333-102330, 333-103758, 333-106213, 333-125232, 333-125233, 333-135044, 333-143115, 333-170533, 333-175250, and 333-178672) of Apache Corporation;

of our reports dated February 28, 2013, with respect to the consolidated financial statements of Apache Corporation and the effectiveness of internal control over financial reporting of Apache Corporation, included in this Annual Report (Form 10-K) for the year ended December 31, 2012.

/s/ Ernst & Young LLP

Houston, Texas

February 28, 2013

EX-23.2

EXHIBIT 23.2

TBPE REGISTERED ENGINEERING FIRM F-1580	FAX (713) 651-0849
1100 LOUISIANA     SUITE 3800         HOUSTON, TEXAS 77002-5218	TELEPHONE (713) 651-9191

Consent of Ryder Scott Company, L.P.

As independent petroleum engineers, we hereby consent to the incorporation by reference in this Form 10-K of Apache Corporation to our Firm’s name and our Firm’s review of the proved oil and gas reserve quantities of Apache Corporation as of December 31, 2012, to the incorporation by reference of our Firm’s name and review into Apache Corporation’s previously filed Registration Statements on Form S-3 (Nos. 333-57785, 333-75633, 333-32580, 333-105536, 333-155884, and 333-174429), on Form S-4 (No. 333-107934 and 333-166964), and on Form S-8 (Nos. 33-59721, 33-63817, 333-26255, 333-32557, 333-36131, 333-31092, 333-48758, 333-97403, 333-102330, 333-103758, 333-106213, 333-125232, 333-125233, 333-135044, 333-143115, 333-170533, 333-175250, and 333-178672), and to the inclusion of our report, dated February 8, 2013, as an exhibit to this Form 10-K filed with the Securities and Exchange Commission.

/s/ Ryder Scott Company, L.P.

Ryder Scott Company, L.P.

TBPE Firm Registration No. F-1580

Houston, Texas

February 25, 2013

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

EX-31.1

EXHIBIT 31.1

CERTIFICATIONS

I, G. Steven Farris, certify that:

1. I have reviewed this annual report on Form 10-K of Apache Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ G. Steven Farris

G. Steven Farris

Chairman and Chief Executive Officer

(principal executive officer)

Date: February 28, 2013

EX-31.2

EXHIBIT 31.2

CERTIFICATIONS

I, Thomas P. Chambers, certify that:

1. I have reviewed this annual report on Form 10-K of Apache Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ Thomas P. Chambers

Thomas P. Chambers

Executive Vice President and Chief Financial Officer

(principal financial officer)

Date: February 28, 2013

EX-32.1

EXHIBIT 32.1

APACHE CORPORATION

Certification of Chief Executive Officer

and Principal Financial Officer

I, G. Steven Farris, certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to my knowledge, the annual report on Form 10-K of Apache Corporation for the period ending December 31, 2012, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. §78m or §78o (d)) and that information contained in such report fairly represents, in all material respects, the financial condition and results of operations of Apache Corporation.

/s/ G. Steven Farris
By:	G. Steven Farris
Title:	Chairman and Chief Executive Officer
	(principal executive officer)

Date: February 28, 2013

I, Thomas P. Chambers, certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to my knowledge, the annual report on Form 10-K of Apache Corporation for the period ending December 31, 2012, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. §78m or §78o (d)) and that information contained in such report fairly represents, in all material respects, the financial condition and results of operations of Apache Corporation.

/s/ Thomas P. Chambers
By:	Thomas P. Chambers
Title:	Executive Vice President and Chief Financial Officer
	(principal financial officer)

Date: February 28, 2013

EX-99.1

Exhibit 99.1

APACHE CORPORATION

Estimated

Future Reserves

Attributable to Certain

Leasehold and Royalty Interests

and

Derived Through Certain Production Sharing Contracts

SEC Parameters

As of

December 31, 2012

                    \s\ Jennifer Fitzgerald                    

Jennifer A. Fitzgerald, P.E.

TBPE License No. 100572

Vice President

[SEAL]

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

TBPE REGISTERED ENGINEERING FIRM F-1580	FAX	(713) 651-0849
1100  LOUISIANA SUITE 4600                 HOUSTON, TEXAS 77002-5294	TELEPHONE	(713) 651-9191

February 8, 2013

Apache Corporation

2000 Post Oak Boulevard, Suite 100

Houston, Texas 77056-4400

Gentlemen:

At the request of Apache Corporation (Apache), Ryder Scott Company, L.P. (Ryder Scott) has conducted a reserves audit of the estimates of the proved reserves as of December 31, 2012 prepared by Apache’s engineering and geological staff based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our third party reserves audit, completed on January 23, 2013 and presented herein, was prepared for public disclosure by Apache in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations. The estimated reserves shown herein represent Apache’s estimated net reserves attributable to the leasehold and royalty interests and derived through certain production sharing contracts in certain properties owned by Apache and the portion of those reserves reviewed by Ryder Scott, as of December 31, 2012. The properties reviewed by Ryder Scott incorporate Apache’s reserve determinations and are attributable to the interests of Apache Corporation (U.S.A), Apache Canada Ltd. (Canada), Apache Petrolera Argentina S.A. (Argentina), Apache Energy Limited (Australia), Apache Egypt Companies (Egypt), and Apache North Sea Limited (United Kingdom).

The properties reviewed by Ryder Scott account for a portion of Apache’s total net proved reserves as of December 31, 2012. Based on the estimates of total net proved reserves prepared by Apache, the reserves audit conducted by Ryder Scott addresses 89 percent of the total proved developed net liquid hydrocarbon reserves, 84 percent of the total proved developed net gas reserves, 62 percent of the total proved undeveloped net liquid hydrocarbon reserves, and 86 percent of the total proved undeveloped net gas reserves of Apache.

The wells or locations for which estimates of reserves were reviewed by Ryder Scott were selected by Apache. Apache informed Ryder Scott that the selected reserves for each country included at least 63 percent or more of the total discounted future net income at 10 percent attributable to the total interests of Apache (coverage) based on SEC hydrocarbon price parameters as of December 31, 2012. Total coverage of world-wide reserves is 87.9 percent of the total discounted future net income at 10 percent.

As prescribed by the Society of Petroleum Engineers in Paragraph 2.2(f) of the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (SPE auditing standards), a reserves audit is defined as “the process of reviewing certain of the pertinent facts interpreted and assumptions made that have resulted in an estimate of reserves prepared by others and the rendering of an opinion about (1) the appropriateness of the methodologies employed; (2) the adequacy and quality of the data relied upon; (3) the depth and thoroughness of the reserves estimation process; (4) the classification of reserves appropriate to the relevant definitions used; and (5) the reasonableness of the estimated reserve quantities.”

SUITE 600, 1015 4TH STREET, S.W.     CALGARY, ALBERTA T2R 1J4     TEL (403) 262-2799     FAX (403) 262-2790

621 17TH STREET, SUITE 1550     DENVER, COLORADO 80293-1501     TEL (303) 623-9147     FAX (303) 623-4258

Apache Corporation

February 8, 2013

Page 2

Based on our review, including the data, technical processes and interpretations presented by Apache, it is our opinion that the overall procedures and methodologies utilized by Apache in preparing their estimates of the proved reserves as of December 31, 2012 comply with the current SEC regulations and that the overall proved reserves for the reviewed properties as estimated by Apache are, in the aggregate, reasonable within the established audit tolerance guidelines of 10 percent as set forth in the SPE auditing standards.

The estimated reserves presented in this report are related to hydrocarbon prices. Apache has informed us that in the preparation of their reserve and income projections, as of December 31, 2012, they used average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered may differ significantly from the estimated quantities presented in this report. The net reserves as estimated by Apache attributable to Apache’s interest and entitlement in properties that we reviewed and the reserves of properties that we did not review are summarized as follows:

SEC PARAMETERS

Estimated Net Proved Reserves

Certain Leasehold and Royalty Interests and

Derived Through Certain Production Sharing Contracts of

Apache Corporation (Total All Regions)

As of December 31, 2012

	% Crude Oil & Condensate Reserves Reviewed		% Natural Gas Liquids Reserves Reviewed		% Gas Reserves Reviewed		Reviewed by Ryder Scott						Not Reviewed						Total
							Crude Oil  & Condensate MBarrels		Natural Gas Liquids MBarrels		Sales Gas MMCF		Crude Oil  & Condensate MBarrels		Natural Gas Liquids MBarrels		Sales Gas MMCF		Crude Oil  & Condensate MBarrels		Natural Gas Liquids MBarrels		Sales Gas MMCF
Developed		89.1		88.4		83.5		734,691		162,680		4,871,370		90,023		21,272		960,299		824,714		183,952		5,831,669
Undeveloped		60.0		73.2		85.7		214,854		54,436		2,255,954		143,058		19,968		376,583		357,912		74,404		2,632,537
Total Proved		80.3		84.0		84.2		949,545		217,116		7,127,324		233,081		41,240		1,336,882		1,182,626		258,356		8,464,206

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Apache Corporation

February 8, 2013

Page 3

SEC PARAMETERS

Estimated Net Proved Reserves

Certain Leasehold and Royalty Interests and

Derived Through Certain Production Sharing Contracts of

Apache Corporation (Summary by Region)

As of December 31, 2012

	% Crude		% Natural				Reviewed by Ryder Scott						Not Reviewed						Total
	Oil &		Gas						Natural						Natural						Natural
	Condensate		Liquids		% Gas		Crude Oil &		Gas		Sales		Crude Oil &		Gas		Sales		Crude Oil &		Gas		Sales
	Reserves		Reserves		Reserves		Condensate		Liquids		Gas		Condensate		Liquids		Gas		Condensate		Liquids		Gas
	Reviewed		Reviewed		Reviewed		MBarrels		MBarrels		MMCF		MBarrels		MBarrels		MMCF		MBarrels		MBarrels		MMCF
USA
Developed		90.8		88.2		78.9		430,068		136,287		1,856,307		43,672		18,222		495,843		473,740		154,509		2,352,150
Undeveloped		65.3		71.6		70.4		133,332		43,582		586,692		70,833		17,308		247,065		204,165		60,890		833,757
Total Proved		83.1		83.5		76.7		563,400		179,869		2,442,999		114,505		35,530		742,908		677,905		215,399		3,185,907
Canada
Developed		95.4		95.0		82.9		76,008		20,895		1,438,000		3,687		1,102		296,656		79,695		21,997		1,734,656
Undeveloped		27.3		82.7		80.4		19,276		10,143		324,368		51,374		2,115		78,858		70,650		12,258		403,226
Total Proved		63.4		90.6		82.4		95,284		31,038		1,762,368		55,061		3,217		375,514		150,345		34,255		2,137,882
Argentina
Developed		50.7		62.8		63.4		8,040		3,146		231,443		7,805		1,861		133,612		15,845		5,007		365,055
Undeveloped		78.5		69.1		73.2		2,340		605		71,401		641		271		26,095		2,981		876		97,496
Total Proved		55.1		63.8		65.5		10,380		3,751		302,844		8,446		2,132		159,707		18,826		5,883		462,551
Australia
Developed		97.4		N/A		98.8		28,295		0		588,931		759		0		7,121		29,054		0		596,052
Undeveloped		100.0		N/A		100.0		34,808		0		1,074,018		0		0		0		34,808		0		1,074,018
Total Proved		98.8		N/A		99.6		63,103		0		1,662,949		759		0		7,121		63,862		0		1,670,070
Egypt
Developed		74.3		NA		97.1		79,298		0		670,227		27,447		0		20,209		106,745		0		690,436
Undeveloped		38.8		N/A		95.8		6,701		0		196,429		10,588		0		8,626		17,289		0		205,055
Total Proved		69.3		N/A		96.8		85,999		0		866,656		38,035		0		28,835		124,034		0		895,491
United Kingdom
Developed		94.4		96.4		92.7		112,982		2,352		86,462		6,653		87		6,858		119,635		2,439		93,320
Undeveloped		65.7		27.9		16.0		18,397		106		3,046		9,622		274		15,939		28,019		380		18,985
Total Proved		89.0		87.2		79.7		131,379		2,458		89,508		16,275		361		22,797		147,654		2,819		112,305

Liquid hydrocarbons are expressed in standard 42 gallon barrels and shown herein as thousand of barrels (MBarrels). All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located.

Reserves Included in This Report

In our opinion, the proved reserves presented in this report conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum Reserves Definitions” is included as an attachment to this report.

The various proved reserve status categories are defined under the attachment entitled “Petroleum Reserves Status Definitions and Guidelines” in this report. The proved developed non-producing reserves included herein consist of the shut-in and behind pipe categories.

Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known

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accumulations.” All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At Apache’s request, this report addresses only the proved reserves attributable to the properties reviewed herein.

Proved oil and gas reserves are “those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward.” The proved reserves included herein were estimated using deterministic methods. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.”

Proved reserve estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, could be more or less than the estimated amounts.

Audit Data, Methodology, Procedure and Assumptions

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserve evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property.

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities

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actually recovered are much more likely than not to be achieved.” The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserve category must meet the SEC definitions as noted above.

Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserve categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

The proved reserves for the properties that we reviewed were estimated by performance methods, the volumetric method, analogy, or a combination of methods. Approximately 90 percent of the proved producing reserves attributable to producing wells and/or reservoirs that we reviewed were estimated by performance methods or a combination of methods. These performance methods include, but may not be limited to, decline curve analysis, material balance and/or reservoir simulation which utilized extrapolations of historical production and pressure data available through November, 2012, in those cases where such data were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by Apache or obtained from public data sources and were considered sufficient for the purpose thereof. The remaining 10 percent of the proved producing reserves that we reviewed were estimated by the volumetric method, analogy, or a combination of methods. These methods were used where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate.

Approximately 100 percent of the proved developed non-producing and undeveloped reserves that we reviewed were estimated by the volumetric method or analogy. The volumetric analysis utilized pertinent well and seismic data furnished to Ryder Scott by Apache for our review or which we have obtained from public data sources that were available through November, 2012. The data utilized from the analogues in conjunction with well and seismic data incorporated into the volumetric analysis were considered sufficient for the purpose thereof.

To estimate economically recoverable proved oil and gas reserves, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in conducting this review.

As stated previously, proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. To confirm that the proved reserves reviewed by us meet the SEC requirements to be economically producible, we have reviewed certain primary economic data utilized by Apache relating to hydrocarbon prices and costs as noted herein.

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The hydrocarbon prices furnished by Apache for the properties reviewed by us are based on SEC price parameters using the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described.

The initial SEC hydrocarbon prices in effect on December 31, 2012 for the properties reviewed by us were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used by Apache for the geographic areas reviewed by us. In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements. In cases where there are numerous contracts or price references within the same geographic area, the benchmark price is represented by the unweighted arithmetic average of the initial 12-month average first-day-of-the-month benchmark prices used.

The product prices which were actually used by Apache to determine the future gross revenue for each property reviewed by us reflect adjustments to the benchmark prices for gravity, quality, local conditions, and/or distance from market, referred to herein as “differentials.” The differentials used by Apache were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Apache.

The table below summarizes Apache’s net volume weighted benchmark prices adjusted for differentials for the properties reviewed by us and referred to herein as Apache’s “average realized prices.” The average realized prices shown in the table below were determined from Apache’s estimate of the total future gross revenue before production taxes for the properties reviewed by us and Apache’s estimate of the total net reserves for the properties reviewed by us for the geographic area. The data shown in the table on the following page is presented in accordance with SEC disclosure requirements for each of the geographic areas reviewed by us.

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Geographic Area	Product	Price Reference	Average Benchmark Prices	Average Realized Prices
North America
United States	Oil/Condensate	WTI Cushing	$94.84/Bbl	$95.96/Bbl
	NGLs	Mt. Belvieu Non-Tet Propane	$43.08/Bbl	$41.35/Bbl
	Gas	Henry Hub	$2.76/MMBTU	$3.13/MCF
Canada	Oil/Condensate	WTI Cushing	$94.84/Bbl	$87.42/Bbl
	NGLs	WTI Cushing	$94.84/Bbl	$40.65/Bbl
	Gas	AECO	$2.33/MMBTU	$2.32/MCF
Argentina	Oil/Condensate	Govt. Regulated	$74.48/Bbl	$74.95/Bbl
	NGLs	Nqn LPG	$30.93/Bbl	$30.21/Bbl
	Gas	Contracts	Contract	$3.49/MCF
Australia	Oil/Condensate	Tapis	$116.17/Bbl	$110.82/Bbl
	Gas	Contracts	Contract	$9.06/MCF
Egypt	Oil/Condensate	Brent	$111.13/Bbl	$109.14/Bbl
	Gas	Contracts	Contract	$3.00/MCF
United Kingdom	Oil/Condensate	Brent	$111.13/Bbl	$111.13/Bbl
	NGLs	Brent	$111.13/Bbl	$76.55/Bbl
	Gas	NBP	$9.19/MMBTU	$9.18/MCF

The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in Apache’s individual property evaluations.

Accumulated gas production imbalances, if any, were not taken into account in the proved gas reserve estimates reviewed. The proved gas volumes included herein do not attribute gas consumed in operations as reserves.

Operating costs furnished by Apache are based on the operating expense reports of Apache and include only those costs directly applicable to the leases or wells for the properties reviewed by us. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. For operated properties, the operating costs include an appropriate level of corporate general administrative and overhead costs. The operating costs for non-operated properties include the COPAS overhead costs that are allocated directly to the leases and wells under terms of operating agreements. Other costs include transportation and/or processing fees as deductions. The operating costs furnished by Apache were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Apache. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

Development costs furnished by Apache are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished by Apache were accepted as factual data and reviewed by us for their reasonableness; however, we have not

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conducted an independent verification of the data used by Apache. The estimated net cost of abandonment after salvage was included by Apache for properties where abandonment costs net of salvage were significant. Apache’s estimates of the net abandonment costs were accepted without independent verification.

The proved developed non-producing and undeveloped reserves for the properties reviewed by us have been incorporated herein in accordance with Apache’s plans to develop these reserves as of December 31, 2012. The implementation of Apache’s development plans as presented to us is subject to the approval process adopted by Apache’s management. As the result of our inquiries during the course of our review, Apache has informed us that the development activities for the properties reviewed by us have been subjected to and received the internal approvals required by Apache’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to Apache. Additionally, Apache has informed us that they are not aware of any legal, regulatory, political or economic obstacles that would significantly alter their plans.

Current costs used by Apache were held constant throughout the life of the properties.

Apache’s forecasts of future production rates are based on historical performance from wells currently on production. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.

Test data and other related information were used by Apache to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by Apache. Wells or locations that are not currently producing may start producing earlier or later than anticipated in Apache’s estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies.

The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

The proved reserves reported herein are limited to the period prior to expiration of current contracts providing the legal right to produce or a revenue interest in such production unless evidence indicates that contract renewal is reasonably certain.

The proved reserves for the properties located in Egypt are subject to the contractual fiscal terms contained in production sharing contracts. For these properties, Ryder Scott audited the gross economic inputs used by Apache in the economic models for Egypt through a comparison of Apache and Ryder Scott’s gross economic volumes. Apache’s gross economic volumes were then used as input to the economic models to generate the net interests used to determine the net reserves summarized in this report. Ryder Scott reviewed the fiscal terms of such contracts and discussed with Apache the net economic benefit attributed to such operations for the determination of the net

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hydrocarbon volumes and income thereof. Ryder Scott has not conducted an exhaustive audit or verification of such contractual information. Neither our review of such contractual information nor our acceptance of Apache’s representations regarding such contractual information should be construed as a legal opinion on this matter.

Ryder Scott did not evaluate the country and geopolitical risks in the countries where Apache operates or has interests. Apache’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons including the granting, extension or termination of production sharing contracts, the fiscal terms of various production sharing contracts, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax, and foreign trade and investment and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the quantities as estimated by Apache.

The estimates of proved reserves presented herein were based upon a detailed study of the properties in which Apache owns and derives an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included by Apache for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

Certain technical personnel of Apache are responsible for the preparation of reserve estimates on new properties and for the preparation of revised estimates, when necessary, on old properties. These personnel assembled the necessary data and maintained the data and workpapers in an orderly manner. We consulted with these technical personnel and had access to their workpapers and supporting data in the course of our audit.

Apache has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In performing our audit of Apache’s forecast of future proved production, we have relied upon data furnished by Apache with respect to property interests owned or derived, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, recompletion and development costs, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by Apache. We consider the factual data furnished to us by Apache to be appropriate and sufficient for the purpose of our review of Apache’s estimates of reserves. In summary, we consider the assumptions, data, methods and analytical procedures used by Apache and as reviewed by us appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate under the circumstances to render the conclusions set forth herein.

Audit Opinion

Based on our review, including the data, technical processes and interpretations presented by Apache, it is our opinion that the overall procedures and methodologies utilized by Apache in preparing their estimates of the proved reserves as of December 31, 2012 comply with the current SEC regulations and that the overall proved reserves for the reviewed properties as estimated by Apache are, in the aggregate, reasonable within the established audit tolerance guidelines of 10 percent as set forth in the SPE auditing standards.

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We were in reasonable agreement with Apache’s estimates of proved reserves for the properties which we reviewed. As a consequence, it is our opinion that on an aggregate basis the data presented herein for the properties that we reviewed fairly reflects the estimated net reserves owned by Apache.

Other Properties

Other properties, as used herein, are those properties of Apache which we did not review. The proved net reserves attributable to the other properties account for 11 percent of the total proved developed net liquid hydrocarbon reserves, 16 percent of the total proved developed net gas reserves, 38 percent of the total proved undeveloped net liquid hydrocarbon reserves, and 14 percent of the total proved undeveloped net gas reserves based on estimates prepared by Apache as of December 31, 2012. The other properties represent 12.1 percent of the total proved discounted future net income at 10 percent based on the unescalated pricing policy of the SEC as taken from reserve and income projections prepared by Apache as of December 31, 2012.

The same technical personnel of Apache were responsible for the preparation of the reserve estimates for the properties that we reviewed as well as for the properties not reviewed by Ryder Scott.

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over seventy-five years. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.

We are independent petroleum engineers with respect to Apache. Neither we nor any of our employees have any interest in the subject properties, and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

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The results of this audit, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing the review of the reserves information discussed in this report, are included as an attachment to this letter.

Terms of Usage

The results of our third party audit, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by Apache Corporation.

Apache makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, Apache has certain registration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 10-K is incorporated by reference. We have consented to the incorporation by reference in the registration statements on Form S-3, Form S-4, and Form S-8 of Apache of the references to our name as well as to the references to our third party report for Apache, which appears in the December 31, 2012 annual report on Form 10-K of Apache. Our written consent for such use is included as a separate exhibit to the filings made with the SEC by Apache.

We have provided Apache with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by Apache and the original signed report letter, the original signed report letter shall control and supersede the digital version.

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

Very truly yours,

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

\s\ Jennifer Fitzgerald

Jennifer A. Fitzgerald, P.E.

TBPE License No. 100572

Vice President

[SEAL]

JAF (DPR)/pl

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Jennifer A. Fitzgerald was the primary technical person responsible for overseeing the reserves audit conducted by Ryder Scott of the estimates of reserves presented herein.

Mrs. Fitzgerald, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 2006, is a Vice President responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mrs. Fitzgerald served in a number of engineering positions with ExxonMobil. For more information regarding Mrs. Fitzgerald’s geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Experience/Employees.

Mrs. Fitzgerald earned a Bachelor of Science degree in Chemical Engineering from University of Illinois Urbana-Champaign in 2001 and is a registered Professional Engineer in the State of Texas. She is also a member of the Society of Petroleum Evaluation Engineers and Society of Petroleum Engineers. She currently serves as the Chairman of the Houston Chapter of the Society of Petroleum Evaluation Engineers.

In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Mrs. Fitzgerald fulfills. As part of her 2012 continuing education hours, Mrs. Fitzgerald attended 9 hours of formalized training including the 2012 RSC Reserves Conference and various professional society presentations specifically relating to the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register. Mrs. Fitzgerald attended an additional 12.5 hours of formalized external training during 2012 covering such topics as reservoir engineering, geoscience and petroleum economics evaluation methods, procedures and software and ethics for consultants. She also presented presentations at the 2012 RSC Reserves Conference, the 2012 North American Petroleum Accounting Conference (NAPAC), and the 2012 National Oil and Gas Reserves Conference held by AICPA/PDI relating to the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register. Mrs. Fitzgerald also previously attended the one and two day short courses presented by Dr. John Lee specific to the new SEC regulations.

Based on her educational background, professional training and more than 11 years of practical experience in the estimation and evaluation of petroleum reserves, Mrs. Fitzgerald has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

PREAMBLE

On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.

Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.

Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale.

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Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.

Reserves do not include quantities of petroleum being held in inventory.

Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.

RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:

Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

PROVED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:

Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

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PROVED RESERVES (SEC DEFINITIONS) CONTINUED

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and

PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)

Sponsored and Approved by:

SOCIETY OF PETROLEUM ENGINEERS (SPE)

WORLD PETROLEUM COUNCIL (WPC)

AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)

SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)

Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).

DEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:

Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Developed Producing (SPE-PRMS Definitions)

While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.

Developed Producing Reserves

Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate.

Improved recovery reserves are considered producing only after the improved recovery project is in operation.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

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Developed Non-Producing

Developed Non-Producing Reserves include shut-in and behind-pipe reserves.

Shut-In

Shut-in Reserves are expected to be recovered from:

(1) completion intervals which are open at the time of the estimate, but which have not started producing;

(2) wells which were shut-in for market conditions or pipeline connections; or

(3) wells not capable of production for mechanical reasons.

Behind-Pipe

Behind-pipe Reserves are expected to be recovered from zones in existing wells, which will require additional completion work or future re-completion prior to start of production.

In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

UNDEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:

Undeveloped oil and gas reserves are reserves of any category 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.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can 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 the specific circumstances, justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

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SUPPLEMENTAL GUARANTOR INFORMATION (Tables)

12 Months Ended

Dec. 31, 2012

Supplemental Condensed Consolidating Statement of Operations

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

For the Year Ended December 31, 2012

	Apache Corporation			Apache Finance Canada			All Other Subsidiaries of Apache Corporation		Reclassifications & Eliminations			Consolidated
	(In millions)
REVENUES AND OTHER:
Oil and gas production revenues	$	4,237		$	—		$	12,710	$	—		$	16,947
Equity in net income (loss) of affiliates		1,523			(737	)		248		(1,034	)		—
Other		(80	)		69			146		(4	)		131
		5,680			(668	)		13,104		(1,038	)		17,078
OPERATING EXPENSES:
Depreciation, depletion, and amortization		1,391			—			5,718		—			7,109
Asset retirement obligation accretion		76			—			156		—			232
Lease operating expenses		957			—			2,011		—			2,968
Gathering and transportation		51			—			252		—			303
Taxes other than income		185			—			677		—			862
General and administrative		425			—			110		(4	)		531
Merger, acquisitions & transition		25			—			6		—			31
Financing costs, net		94			(20	)		91		—			165
		3,204			(20	)		9,021		(4	)		12,201
INCOME (LOSS) BEFORE INCOME TAXES		2,476			(648	)		4,083		(1,034	)		4,877
Provision (benefit) for income taxes		475			(159	)		2,560		—			2,876
NET INCOME (LOSS)		2,001			(489	)		1,523		(1,034	)		2,001
Preferred stock dividends		76			—			—		—			76
INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	1,925		$	(489	)	$	1,523	$	(1,034	)	$	1,925
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	1,803		$	(489	)	$	1,523	$	(1,034	)	$	1,803

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 (LOSS) BEFORE INCOME TAXES		5,109		377			6,477			(3,870	)		8,093
Provision (benefit) for income taxes		525		97			2,887			—			3,509
NET INCOME (LOSS)		4,584		280			3,590			(3,870	)		4,584
Preferred stock dividends		76		—			—			—			76
INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	4,508	$	280		$	3,590		$	(3,870	)	$	4,508
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	4,640	$	280		$	3,590		$	(3,870	)	$	4,640

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 (LOSS) BEFORE INCOME TAXES		3,266		99			4,180			(2,339	)		5,206
Provision (benefit) for income taxes		234		25			1,915			—			2,174
NET INCOME (LOSS)		3,032		74			2,265			(2,339	)		3,032
Preferred stock dividends		32		—			—			—			32
INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	3,000	$	74		$	2,265		$	(2,339	)	$	3,000
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	3,149	$	74		$	2,265		$	(2,339	)	$	3,149

Supplemental Condensed Consolidating Statement of Cash Flows

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

For the Year Ended December 31, 2012

	Apache Corporation			Apache Finance Canada			All Other Subsidiaries of Apache Corporation			Reclassifications & Eliminations			Consolidated
	(In millions)
CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	$	2,357		$	(40	)	$	6,187		$	—		$	8,504
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property		(3,313	)		—			(5,468	)		—			(8,781	)
Additions to gas gathering, transmission, and processing facilities		(48	)		—			(702	)		—			(750	)
Acquisition of Cordillera		(2,666	)		—			—			—			(2,666	)
Equity investment in Yara Pilbara Holdings Pty Limited		—			—			(439	)		—			(439	)
Acquisitions, other		(66	)		—			(186	)		—			(252	)
Proceeds from sale of oil and gas properties		25			—			2			—			27
Investment in subsidiaries, net		(657	)		—			—			657			—
Other		(450	)		—			(113	)		—			(563	)
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES		(7,175	)		—			(6,906	)		657			(13,424	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Commercial paper, credit facility, and bank notes, net		502			—			47			—			549
Intercompany borrowings		—			—			697			(697	)		—
Fixed rate debt borrowings		4,978			—			—			—			4,978
Payments on fixed rate debt		(400	)		—			—			—			(400	)
Dividends paid		(332	)		—			—			—			(332	)
Other		29			35			(114	)		40			(10	)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		4,777			35			630			(657	)		4,785
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(41	)		(5	)		(89	)		—			(135	)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR		41			5			249			—			295
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	—		$	—		$	160		$	—		$	160

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 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 gas gathering, transmission, and processing facilities		—			—			(664	)		—			(664	)
Acquisition of Mobil North Sea		—			—			(1,246	)		—			(1,246	)
Acquisitions, other		(448	)		—			(119	)		—			(567	)
Proceeds from sales of oil and gas properties		204			—			218			—			422
Investment in and advances to subsidiaries, net		772			—			—			(772	)		—
Other		(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	)
Other		108			(7	)		(25	)		8			84
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		(1,125	)		(8	)		(786	)		772			(1,147	)
NET INCREASE (DECREASE) 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 PERIOD	$	41		$	5		$	249		$	—		$	295

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 gas 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		(72	)		—			(49	)		—			(121	)
NET CASH PROVIDED BY (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	)
Other		49			96			75			(131	)		89
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		6,706			98			812			(2,853	)		4,763
NET INCREASE (DECREASE) 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 PERIOD	$	6		$	—		$	128		$	—		$	134

Supplemental Condensed Consolidating Balance Sheet

CONDENSED CONSOLIDATING BALANCE SHEET

December 31, 2012

	Apache Corporation		Apache Finance Canada		All Other Subsidiaries of Apache Corporation			Reclassifications & Eliminations			Consolidated
	(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	—	$	—	$	160		$	—		$	160
Receivables, net of allowance		876		—		2,210			—			3,086
Inventories		95		—		813			—			908
Drilling advances		21		1		562			—			584
Derivative instruments		31		—		—			—			31
Prepaid assets and other		3,868		—		(3,675	)		—			193
		4,891		1		70			—			4,962
PROPERTY AND EQUIPMENT, NET		18,517		—		34,763			—			53,280
OTHER ASSETS:
Intercompany receivable, net		4,628		—		(2,917	)		(1,711	)		—
Equity in affiliates		21,047		934		97			(22,078	)		—
Goodwill, net		173		—		1,116			—			1,289
Deferred charges and other		152		1,002		1,052			(1,000	)		1,206
	$	49,408	$	1,937	$	34,181		$	(24,789	)	$	60,737
LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	639	$	1	$	2,163		$	(1,711	)	$	1,092
Current debt		912		—		78			—			990
Asset retirement obligation		471		—		7			—			478
Derivative instruments		96		—		20			—			116
Other current liabilities		893		3		1,964			—			2,860
		3,011		4		4,232			(1,711	)		5,536
LONG-TERM DEBT		10,706		647		2			—			11,355
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes		2,990		5		5,029			—			8,024
Asset retirement obligation		992		—		3,108			—			4,100
Other		378		250		763			(1,000	)		391
		4,360		255		8,900			(1,000	)		12,515
COMMITMENTS AND CONTINGENCIES SHAREHOLDERS’ EQUITY		31,331		1,031		21,047			(22,078	)		31,331
	$	49,408	$	1,937	$	34,181		$	(24,789	)	$	60,737

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
Current debt		400		—		31			—			431
Asset retirement obligation		434		—		13			—			447
Derivative instruments		76		—		37			—			113
Other current liabilities		614		5		2,305			—			2,924
		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

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Debt - Additional Information (Detail) (USD $)	12 Months Ended												12 Months Ended										1 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2012 Unsecured Committed Bank Credit Facilities in U.S. [Member]	Dec. 31, 2012 Unsecured Committed Bank Credit Facilities in Australia [Member]	Dec. 31, 2012 Unsecured Committed Bank Credit Facilities in Canada [Member]	Dec. 31, 2012 Unsecured Committed Bank Credit Facilities [Member]	Dec. 31, 2012 Revolving Credit Facility Due August Two Thousand Sixteen [Member]	Dec. 31, 2012 Revolving Credit Facility Due June Two Thousand Seventeen [Member]	Dec. 31, 2012 United States [Member]	Dec. 31, 2012 Australia [Member]	Dec. 31, 2012 Canada [Member]	Dec. 31, 2012 Notes Payable, Other Payables [Member]	Dec. 31, 2012 Money Market Lines of Credit [Member]	Dec. 31, 2011 Money Market Lines of Credit [Member]	Dec. 31, 2012 Apache finance Canada 7.75% notes due 2029 [Member]	Dec. 31, 2011 Apache finance Canada 7.75% notes due 2029 [Member]	Dec. 31, 2012 Apache Finance Canada 4.375% notes due 2015 [Member]	Dec. 31, 2011 Apache Finance Canada 4.375% notes due 2015 [Member]	Dec. 31, 2012 Maturing 2017 [Member]	Dec. 31, 2012 Maturing 2022 [Member]	Dec. 31, 2012 Maturing 2043 [Member]	Apr. 30, 2012 Maturing on 2012 [Member]	Dec. 31, 2012 2.625% Senior Unsecured Notes Due January 15, 2023 [Member]	Dec. 31, 2012 Four Point Two Five Percent Senior Unsecured Notes Due January Fifteen Two Thousand Fourty Four [Member]	Dec. 31, 2012 Maximum [Member]	Dec. 31, 2012 Minimum [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	$ 12,411,000,000	$ 7,262,000,000														$ 300,000,000	$ 300,000,000	$ 350,000,000	$ 350,000,000	$ 400,000,000	$ 1,100,000,000	$ 1,500,000,000		$ 1,200,000,000
Margin over LIBOR for committed loans				0.90%	0.90%	0.90%	0.875%									7.75%	7.75%	4.375%	4.375%	1.75%	3.25%	4.75%	6.25%	2.625%	4.25%
Repayment of current debt																							400,000,000
2017	1,389,000,000																								800
Outstanding balance under the facility secured revolving syndicated	91,000,000	31,000,000												91,000,000	31,000,000
Unsecured credit facility available to Company	3,300,000,000							1,000,000,000	2,300,000,000
Revolving bank facility	1,700,000,000			1,700,000,000	300,000,000	300,000,000	1,000,000,000			1,000,000,000	300,000,000	300,000,000
Credit facility maturity date								Aug. 31, 2016	Jun. 30, 2017
Line of Credit Facility, Remaining Borrowing Capacity	2,800,000,000
Maturing date of credit facilities				Jun. 04, 2017	Jun. 04, 2017	Jun. 04, 2017	Aug. 12, 2012
Quarterly facility fees				0.10 percent on the total amount	0.10 percent on the total amount	0.10 percent on the total amount	0.125 percent on the total amount
Line of Credit Facility, Interest Rate Description	At December 31, 2012, the margin over LIBOR for committed loans was 0.875 percent on the $1.0 billion U.S. credit facility and 0.90 percent on each of the $1.7 billion U.S. credit facility, the $300 million facility in Australia, and the $300 million credit facility in Canada. The Company also pays quarterly facility fees of 0.125 percent on the total amount of the $1.0 billion facility and 0.10 percent on the total amount of the other three facilities. The facility fees vary based upon the Company’s senior long-term debt rating.
Debt to Capitalization ratio	0.28																									0.60
Debt Instrument Covenant Description	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.
Percentage of liens of companies consolidated asset	5.00%
Maximum potential lien on assets located in specified regions	3,000,000,000
Commercial paper program																										2,950,000,000	3,000,000,000
Period For Borrowing Funds													270 days
Weighted average interest rate for commercial paper	0.43%
Available backstops	100.00%
Carrying Amount, Commercial paper	489,000,000	0
Unamortized discount	66,000,000	46,000,000
Amortization of Debt Discount (Premium)	3,000,000	2,000,000	2,000,000
Unamortized deferred loan costs associated with its various debt obligations	$ 118,000,000	$ 48,000,000

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Derivative Instruments and Hedging Activities - Fair Values of Derivative Instruments Recorded in Consolidated Balance Sheet (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total Assets	$ 33	$ 332
Total Liabilities	116	154
Derivative Instruments [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Current Assets: Derivative instruments	31	304
Current Liabilities: Derivative instruments	116	113
Deferred Charges And Other [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Other Assets: Deferred charges and other	2	28
Other Liabilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Noncurrent Liabilities: Other		$ 41

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Retirement and Deferred Compensation Plans - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Commitment And Contingencies [Line Items]
Maximum percentage of compensation contributed by the company	8.00%
Portion of employee's salary, employee contributions under non-qualified retirement savings plan	50.00%
Maximum percentage of eligible compensation contributed by the participating employees	50.00%
Percentage of additional contribution to money purchase retirement plan	6.00%
Portion of employee's annual bonus, employee contributions under non-qualified retirement savings plan, vested	75.00%
Portion occurring as money purchase retirement plan and the non-qualified retirement/savings plan, vested	20.00%
Annual cost of retirement benefit plans	$ 117	$ 93	$ 80
Targeted ongoing funding level of pension plan policy, percent	100.00%
Outperformance relative to gilts for equities	3.50%
Pension Benefits [Member]
Commitment And Contingencies [Line Items]
Accumulated benefit obligation for pension plans	139	119	107
Expected contribution towards pension and postretirement plans	5
Postretirement Benefits [Member]
Commitment And Contingencies [Line Items]
Expected contribution towards pension and postretirement plans	$ 1

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Debt - Debt for Apache and Subsidiaries (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Debt Instrument [Line Items]
Debt before unamortized discount	$ 12,411	$ 7,262
Debt before unamortized discount	(66)	(46)
Total debt	12,345	7,216
Current maturities	(990)	(431)
Long-term debt	11,355	6,785
Money Market Lines of Credit [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	13
Commercial Paper [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	489
6.25% notes due 2012 [Member]
Debt Instrument [Line Items]
Debt before unamortized discount		400
5.25% notes due 2013 [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	500	500
6.0% notes due 2013 [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	400	400
5.625% notes due 2017 [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	500	500
One Point Seven Five Percentage Notes Due Twenty Seventeen [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	400
6.9% notes due 2018 [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	400	400
7.0% notes due 2018 [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	150	150
7.625% notes due 2019 [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	150	150
3.625% notes due 2021 [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	500	500
Three Point Two Five Percentage Notes Due Twenty Twenty Two [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	1,100
Two Point Six Two Five Percentage Notes Due Twenty Twenty Three [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	1,200
7.7% notes due 2026 [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	100	100
7.95% notes due 2026 [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	180	180
6.0% notes due 2037 [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	1,000	1,000
5.1% notes due 2040 [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	1,500	1,500
5.25% notes due 2042 [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	500	500
Four Point Seven Five Percentage Notes Due Twenty Forty Three [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	1,500
Four Point Two Five Percentage Notes Due Twenty Forty Four [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	800
7.375% debentures due 2047 [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	150	150
7.625% debentures due 2096 [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	150	150
United States [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	11,682	6,580
Argentina Overdraft Lines of Credit [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	69	31
Foreign Line of Credit [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	9
Apache Finance Canada 4.375% notes due 2015 [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	350	350
Notes Due In Twenty Sixteen And Twenty Seventeen [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	1	1
Apache finance Canada 7.75% notes due 2029 [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	300	300
Subsidiary And Other Obligations [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	$ 729	$ 682

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Capital Stock - Common Stock Outstanding (Detail)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Class of Stock [Line Items]
Balance, beginning of year	384,117,643	382,391,742	336,436,972
Shares issued for stock-based compensation plans:
Treasury shares issued	60,767	144,313	363,263
Common shares issued	1,189,693	1,581,588	1,864,498
Balance, end of year	391,640,770	384,117,643	382,391,742
Cordillera Energy Partners [Member]
Shares issued for stock-based compensation plans:
Stock issued during period, pursuant to acquisitions	6,272,667
Bp Permian Basin [Member]
Shares issued for stock-based compensation plans:
Stock issued during period, pursuant to acquisitions			26,450,000
Mariner Energy [Member]
Shares issued for stock-based compensation plans:
Stock issued during period, pursuant to acquisitions			17,277,009

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Supplemental Quarterly Financial Data - Supplemental Quarterly Financial Data (Detail) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Schedule Of Quarterly Financial Data [Line Items]
Revenues and other	$ 4,391	$ 4,179	$ 3,972	$ 4,536	$ 4,297	$ 4,328	$ 4,338	$ 3,925	$ 17,078	$ 16,888	$ 12,092
Expenses	3,723	3,999	3,616	3,739	3,108	3,326	3,079	2,791	15,077	12,304
NET INCOME	668	180	356	797	1,189	1,002	1,259	1,134	2,001	4,584	3,032
Income attributable to common stock	$ 649	$ 161	$ 337	$ 778	$ 1,170	$ 983	$ 1,240	$ 1,115	$ 1,925	$ 4,508	$ 3,000
NET INCOME PER COMMON SHARE:
Basic	$ 1.66	$ 0.41	$ 0.87	$ 2.02	$ 3.05	$ 2.56	$ 3.23	$ 2.91	$ 4.95	$ 11.75	$ 8.53
Diluted	$ 1.64	$ 0.41	$ 0.86	$ 2.00	$ 2.98	$ 2.50	$ 3.17	$ 2.86	$ 4.92	$ 11.47	$ 8.46

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Derivative Instrument and Hedging Activities - Open Crude and Natural Gas Derivative Instruments (Parenthetical) (Detail) (USD $)	12 Months Ended
	Dec. 31, 2012
2013 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Percentage of collars derivative settled	50.00%
Derivatives Not Designated As Cash Flow Hedging Instruments [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fixed Price swaps not designated as cash flow hedges	38,320

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RETIREMENT AND DEFERRED COMPENSATION PLANS (Tables)

12 Months Ended

Dec. 31, 2012

Changes in Benefit Obligation, Fair Value of Plan Assets and Funded Status of Pension and Postretirement Benefit Plans

The following tables set forth the benefit obligation, fair value of plan assets and funded status as of December 31, 2012, 2011, and 2010, 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.

	2012						2011						2010
	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	$	150		$	30		$	136		$	29		$	135		$	18
Service cost		5			4			5			3			5			2
Interest cost		7			1			7			1			7			1
Foreign currency exchange rate changes		7			—			(1	)		—			(4	)		—
Amendments		—			—			—			—			—			—
Actuarial losses (gains)		14			1			6			(2	)		(1	)		8
Effect of curtailment and settlements		—			—			—			—			—			—
Benefits paid		(6	)		(1	)		(3	)		(1	)		(6	)		—
Retiree contributions		—			—			—			—			—			—
Projected benefit obligation at end of year		177			35			150			30			136			29
Change in Plan Assets
Fair value of plan assets at beginning of year		145			—			135			—			118			—
Actual return on plan assets		14			—			4			—			14			—
Foreign currency exchange rates		6			—			(1	)		—			(3	)		—
Employer contributions		11			1			10			1			12			—
Benefits paid		(6	)		(1	)		(3	)		(1	)		(6	)		—
Retiree contributions		—			—			—			—			—			—
Fair value of plan assets at end of year		170			—			145			—			135			—
Funded status at end of year	$	(7	)	$	(35	)	$	(5	)	$	(30	)	$	(1	)	$	(29	)
Amounts recognized in Consolidated Balance Sheet
Current liability		—			(1	)		—			(1	)		—			(1	)
Non-current liability		(7	)		(34	)		(5	)		(29	)		(1	)		(28	)
	$	(7	)	$	(35	)	$	(5	)	$	(30	)	$	(1	)	$	(29	)
Pre-tax Amounts Recognized in Accumulated Other Comprehensive Income (Loss)
Accumulated (loss)		(32	)		(7	)		(25	)		(6	)		(15	)		(8	)
Prior service cost		—			—			—			—			—			—
Transition asset (obligation)		—			—			—			—			—			—
	$	(32	)	$	(7	)	$	(25	)	$	(6	)	$	(15	)	$	(8	)
Weighted Average Assumptions used as of December 31
Discount rate		4.30	%		3.43	%		4.70	%		4.04	%		5.40	%		4.93	%
Salary increases		4.60	%		N/A			4.60	%		N/A			5.00	%		N/A
Expected return on assets		4.70	%		N/A			4.85	%		N/A			6.25	%		N/A
Healthcare cost trend
Initial		N/A			7.25	%		N/A			7.50	%		N/A			8.00	%
Ultimate in 2022		N/A			5.00	%		N/A			5.00	%		N/A			5.00	%

Allocations for Plan Asset Holding and Target Allocation for Company's Plan Asset

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
	2012			2012			2011
Asset Category
Equity securities:
U.K. quoted equities		17	%		16	%		17	%
Overseas quoted equities		33	%		33	%		31	%
Total equity securities		50	%		49	%		48	%
Debt securities:
U.K. Government bonds		30	%		30	%		30	%
U.K. corporate bonds		20	%		20	%		18	%
Debt securities		50	%		50	%		48	%
Cash		0	%		1	%		4	%
Total		100	%		100	%		100	%

Fair Values of Plan Assets for Each Major Asset Category Based on Nature and Significant Concentration of Risks in Plan Assets

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, 2012:

	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)	$	28	$	—	$	—	$	28
Overseas quoted equities(2)		56		—		—		56
Total equity securities		84		—		—		84
Debt securities:
U.K. Government bonds(3)		51		—		—		51
U.K. corporate bonds(4)		34		—		—		34
Total debt securities		85		—		—		85
Cash		1		—		—		1
Fair value of plan assets	$	170	$	—	$	—	$	170

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

(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: 33 percent benchmarked against iBoxx Sterling Overall Gilt Index, with a performance target of 0.75 percent per annum over the benchmark over a rolling three-year period; and 67 percent against the FTSE Actuaries Government Securities Index-Linked Over 5 Years Index.

(4) This category comprises U.K. corporate bonds: 50 percent benchmarked against iBoxx Sterling Overall Non Gilt index with a performance target of 0.75 percent per annum over the benchmark over a rolling three-year period; and 50 percent benchmarked against the iBoxx Sterling Overall Non Gilt Index with a performance target of 0.75 percent per annum over the benchmark over a rolling five year period.

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.

(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: 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.

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

Components of Net Periodic Cost and Underlying Weighted Average Actuarial Assumptions Used for Pension and Postretirement Benefit Plans

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, 2012, 2011, and 2010:

	2012						2011						2010
	Pension Benefits			Postretirement Benefits			Pension Benefits			Postretirement Benefits			Pension Benefits			Postretirement Benefits
	(In millions)
Component of Net Periodic Benefit Costs
Service cost	$	5		$	4		$	5		$	3		$	5		$	2
Interest cost		7			1			7			1			7			1
Expected return on assets		(7	)		—			(8	)		—			(8	)		—
Amortization of actuarial gain (loss)		1			—			—			—			1			—
Net periodic benefit cost	$	6		$	5		$	4		$	4		$	5		$	3
Weighted Average Assumptions used to determine Net Period Benefit Cost for the Years ended 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		—			7.50	%		—			8.00	%		—			7.50	%
Ultimate in 2017		—			5.00	%		—			5.00	%		—			5.00	%

Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates

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	$	(1	)
Effect on postretirement benefit obligation		8		(6	)

Expected Future Benefit Payment

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:

	Pension Benefits		Postretirement Benefits
	(In millions)
2013	$	5	$	1
2014		6		1
2015		7		2
2016		7		2
2017		6		3
Years 2018 – 2022		49		18

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Capital Stock - Net Income Per Common Share (Detail) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Earnings Per Share [Line Items]
Income attributable to common stock	$ 649	$ 161	$ 337	$ 778	$ 1,170	$ 983	$ 1,240	$ 1,115	$ 1,925	$ 4,508	$ 3,000
Mandatory Convertible Preferred Stock										76	32
Income attributable to common stock, including assumed conversions									$ 1,925	$ 4,584	$ 3,032
Income attributable to common stock, shares									389	384	352
Mandatory Convertible Preferred Stock										14	5
Stock options and other									2	2	2
Income attributable to common stock, including assumed conversions, shares									391	400	359
Income attributable to common stock, per share	$ 1.66	$ 0.41	$ 0.87	$ 2.02	$ 3.05	$ 2.56	$ 3.23	$ 2.91	$ 4.95	$ 11.75	$ 8.53
Income attributable to common stock, including assumed conversions, per share	$ 1.64	$ 0.41	$ 0.86	$ 2.00	$ 2.98	$ 2.50	$ 3.17	$ 2.86	$ 4.92	$ 11.47	$ 8.46

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Retirement and Deferred Compensation Plans - Fair Values of Plan Assets for Each Major Asset Category Based on Nature and Significant Concentration of Risks in Plan Assets (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 170	$ 145
Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	84	70
Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	85	69
Quoted Price in Active Markets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	170	145
Quoted Price in Active Markets (Level 1) [Member] | Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	84	70
Quoted Price in Active Markets (Level 1) [Member] | Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	85	69
Significant Other Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets
Significant Other Inputs (Level 2) [Member] | Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets
Significant Other Inputs (Level 2) [Member] | Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets
Unobservable Inputs (Level 3) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets
Unobservable Inputs (Level 3) [Member] | Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets
Unobservable Inputs (Level 3) [Member] | Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets
Overseas Quoted Equities [Member] | Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	56	46
Overseas Quoted Equities [Member] | Quoted Price in Active Markets (Level 1) [Member] | Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	56	46
Overseas Quoted Equities [Member] | Significant Other Inputs (Level 2) [Member] | Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets
Overseas Quoted Equities [Member] | Unobservable Inputs (Level 3) [Member] | Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets
U.K. Government Bonds [Member] | Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	51	43
U.K. Government Bonds [Member] | Quoted Price in Active Markets (Level 1) [Member] | Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	51	43
U.K. Government Bonds [Member] | Significant Other Inputs (Level 2) [Member] | Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets
U.K. Government Bonds [Member] | Unobservable Inputs (Level 3) [Member] | Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets
U.K. Corporate Bonds [Member] | Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	34	26
U.K. Corporate Bonds [Member] | Quoted Price in Active Markets (Level 1) [Member] | Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	34	26
U.K. Corporate Bonds [Member] | Significant Other Inputs (Level 2) [Member] | Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets
U.K. Corporate Bonds [Member] | Unobservable Inputs (Level 3) [Member] | Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets
UK Quoted Equities [Member] | Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	28	24
UK Quoted Equities [Member] | Quoted Price in Active Markets (Level 1) [Member] | Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	28	24
UK Quoted Equities [Member] | Significant Other Inputs (Level 2) [Member] | Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets
UK Quoted Equities [Member] | Unobservable Inputs (Level 3) [Member] | Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets
Cash [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1	6
Cash [Member] | Quoted Price in Active Markets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1	6
Cash [Member] | Significant Other Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets
Cash [Member] | Unobservable Inputs (Level 3) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets

XML

Capital Stock - Summary of Amounts Recognized as Expense and Capitalized Cost for Each Plan (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Summary of amounts recognized as expense and capitalized cost
Compensation expense	$ 167	$ 113	$ 164
Capitalized costs	67	42	71
Share Appreciation Program 2008 [Member]
Summary of amounts recognized as expense and capitalized cost
Compensation expense	22	8	49
Compensation expense, net of tax	14	5	31
Capitalized costs	12	5	27
Share Appreciation Plan 2005 [Member]
Summary of amounts recognized as expense and capitalized cost
Compensation expense		1	6
Compensation expense, net of tax		1	4
Capitalized costs		$ 1	$ 3

XML

Debt - Schedule of Long Term Debt by Maturity (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Long Term Debt Excluding Discount By Maturities [Line Items]
2013	$ 991
2014
2015	350
2016	1
2017	1,389
Thereafter	9,680
Total Debt, excluding discounts	$ 12,411	$ 7,262

XML

Retirement and Deferred Compensation Plans - Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates (Detail) (Postretirement Benefits [Member], USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012
Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Effect on service and interest cost components, 1% Increase	$ 1
Effect on postretirement benefit obligation, 1% Increase	8
Effect on service and interest cost components, 1% Decrease	(1)
Effect on postretirement benefit obligation, 1% Decrease	$ (6)

XML

Capital Stock - Conditional Restricted Stock (Detail) (Conditional Restricted Stock [Member], USD $)	12 Months Ended
	Dec. 31, 2012
Conditional Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted Shares, nonvested, Beginning Balance, Shares	1,019,000
Granted, Shares	852,000
Vested, Shares	(1,000)
Forfeited or cancelled, Shares	(564,000)
Restricted Shares, nonvested, Ending Balance, Shares	1,306,000
Non-vested at January 1, 2012, Weighted Average Grant Date Fair Value	$ 115.10
Granted, Weighted Average Grant-Date Fair Value	$ 70.30
Vested, Weighted Average Grant-Date Fair Value	$ 100.81
Forfeited, Weighted Average Grant-Date Fair Value	$ 132.45
Non-vested at December 31, 2012, Weighted Average Grant Date Fair Value	$ 78.40

XML

Capital Stock - Description of Stock Based Compensation Plans and Related Costs (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Stock-based compensation expensed:
Allocated Share-based Compensation Expense	$ 167	$ 113	$ 164
Restricted stock, capitalized	67	42	71
Total	234	155	235
General and Administrative Expense [Member]
Stock-based compensation expensed:
Allocated Share-based Compensation Expense	104	69	98
Lease Operating Expenses [Member]
Stock-based compensation expensed:
Allocated Share-based Compensation Expense	$ 63	$ 44	$ 66

XML

Capital Stock - Number of Shares Contingently Issuable (Detail) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Share Appreciation Program 2008 [Member]
Number of shares contingently issuable
Restricted Shares, nonvested, Beginning Balance, Shares	1,372,000	1,485,000	2,592,000
Granted, Shares			25,000
Forfeited or cancelled, Shares	(1,372,000)	(113,000)	(1,132,000)
Restricted Shares, nonvested, Ending Balance, Shares	0	1,372,000	1,485,000
Weighted-average fair value of grants outstanding		$ 71.28	$ 71.16
Share Appreciation Plan 2005 [Member]
Number of shares contingently issuable
Restricted Shares, nonvested, Beginning Balance, Shares		400,000	1,103,000
Forfeited or cancelled, Shares		(2,000)	(25,000)
Restricted Shares, nonvested, Ending Balance, Shares			400,000
Issued, Shares		(398,000)	(678,000)
Weighted-average fair value of grants outstanding			$ 21.64

XML

Retirement and Deferred Compensation Plans - Expected Future Benefit Payment (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
2013	$ 5
2014	6
2015	7
2016	7
2017	6
Years 2018 - 2022	49
Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
2013	1
2014	1
2015	2
2016	2
2017	3
Years 2018 - 2022	$ 18

XML

Retirement and Deferred Compensation Plans - Changes in Benefit Obligation Fair Value of Plan Assets and Funded Status of Pension and Postretirement Benefit Plans (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Change in Plan Assets
Fair value of plan assets at end of year	$ 170	$ 145
Pension Benefits [Member]
Change in Projected Benefit Obligation
Projected benefit obligation beginning of year	150	136	135
Service cost	5	5	5
Interest cost	7	7	7
Foreign currency exchange rate changes	7	(1)	(4)
Amendments
Actuarial losses (gains)	14	6	(1)
Effect of curtailment and settlements
Benefits paid	(6)	(3)	(6)
Retiree contributions
Projected benefit obligation at end of year	177	150	136
Change in Plan Assets
Fair value of plan assets at beginning of year	145	135	118
Actual return on plan assets	14	4	14
Foreign currency exchange rates	6	(1)	(3)
Employer contributions	11	10	12
Benefits paid	(6)	(3)	(6)
Retiree contributions
Fair value of plan assets at end of year	170	145	135
Funded status at end of year	(7)	(5)	(1)
Amounts recognized in Consolidated Balance Sheet
Non-current liability	(7)	(5)	(1)
Defined Benefit Plans, Liabilities, Total	(7)	(5)	(1)
Pre-tax Amounts Recognized in Accumulated Other Comprehensive Income (Loss)
Accumulated (loss)	(32)	(25)	(15)
Prior service cost
Transition asset (obligation)
Pretax Amounts Recognized in Accumulated Other Comprehensive Income, Total	(32)	(25)	(15)
Weighted Average Assumptions used as of December 31
Discount rate	4.30%	4.70%	5.40%
Salary increases	4.60%	4.60%	5.00%
Expected return on assets	4.70%	4.85%	6.25%
Postretirement Benefits [Member]
Change in Projected Benefit Obligation
Projected benefit obligation beginning of year	30	29	18
Service cost	4	3	2
Interest cost	1	1	1
Amendments
Actuarial losses (gains)	1	(2)	8
Effect of curtailment and settlements
Benefits paid	(1)	(1)
Retiree contributions
Projected benefit obligation at end of year	35	30	29
Change in Plan Assets
Employer contributions	1	1
Benefits paid	(1)	(1)
Retiree contributions
Funded status at end of year	(35)	(30)	(29)
Amounts recognized in Consolidated Balance Sheet
Current liability	(1)	(1)	(1)
Non-current liability	(34)	(29)	(28)
Defined Benefit Plans, Liabilities, Total	(35)	(30)	(29)
Pre-tax Amounts Recognized in Accumulated Other Comprehensive Income (Loss)
Accumulated (loss)	(7)	(6)	(8)
Prior service cost
Transition asset (obligation)
Pretax Amounts Recognized in Accumulated Other Comprehensive Income, Total	$ (7)	$ (6)	$ (8)
Weighted Average Assumptions used as of December 31
Discount rate	3.43%	4.04%	4.93%
Healthcare cost trend
Initial	7.25%	7.50%	8.00%
Ultimate in 2022	5.00%	5.00%	5.00%

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

12 Months Ended

Dec. 31, 2012

Principles of Consolidation

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 other investments in which the Company, either through direct or indirect ownership, has more than a 50-percent voting interest.

Use of Estimates

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), the assessment of asset retirement obligations (see Note 5 — Asset Retirement Obligation), and the valuation of income taxes (see Note 7 — Income Taxes).

Fair Value Measurements

Fair Value Measurements

Certain assets and liabilities are reported at fair value on a recurring basis in Apache’s consolidated balance sheet. Accounting Standards Codification (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 the 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).

Fair value measurements are presented in further detail in Note 3 — Derivative Instruments, Hedging Activities, Note 6 — Debt, and Note 9 — Retirement and Deferred Compensation Plans.

Cash Equivalents

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, 2012 and 2011, Apache had $160 million and $295 million, respectively, of cash and cash equivalents.

Accounts Receivable and Allowance for Doubtful Accounts

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 approximates 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 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, 2012 and 2011, the Company had an allowance for doubtful accounts of $82 million and $58 million, respectively.

Inventories

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

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 combinations, property and equipment cost is based on the fair values at the acquisition date.

Oil and Gas Property

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 $404 million, $335 million, and $321 million of internal costs in 2012, 2011, and 2010, 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 proved reserves), and asset retirement costs, 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 immediately. 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. In countries 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 2012, Apache’s statement of consolidated operations includes additional DD&A of $28 million related to exiting operations in New Zealand and $15 million of seismic costs incurred in countries where it has no established presence. In 2011, Apache recorded additional DD&A of $60 million related to exiting operations in Chile and $49 million of seismic costs incurred in countries where it has no established presence.

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. Future cash outflows associated with settling accrued asset retirement obligations are excluded from the calculation. 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. See Note 14 — Supplemental Oil and Gas Disclosures for a discussion of the calculation of estimated future net cash flows.

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. During 2012, the Company recorded a $1.9 billion ($1.4 billion net of tax) non-cash write-down of the carrying value of the Company’s Canadian proved oil and gas properties. Excluding the effects of cash flow hedges in calculating the ceiling limitation, the write-down for the full year would have been higher by $135 million ($101 million net of tax). As of December 31, 2011 and 2010, capitalized costs did not exceed the ceiling limitation, and no write-down was indicated. Cash flow hedges did not materially affect the 2011 or 2010 calculations.

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.

Gathering, Transmission, and Processing Facilities

Gathering, Transmission, and Processing Facilities

Gathering, transmission, and processing facilities totaled $6.0 billion and $5.2 billion at December 31, 2012 and 2011, respectively. 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. No impairment of gathering, transmission, and processing facilities was recognized during 2012, 2011, or 2010.

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 $1.9 billion and $1.5 billion at December 31, 2012 and 2011, respectively.

Asset Retirement Costs and Obligations

Asset Retirement Costs and Obligations

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.

Goodwill

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 for impairment annually and when impairment indicators arise. Goodwill totaled $1.3 billion and $1.1 billion at December 31, 2012 and 2011, respectively. Goodwill of $173 million was booked in the U.S. during 2012 as a result of the acquisition of Cordillera Energy Partners III, LLC, as discussed in Note 2 — Acquisitions and Divestitures. As of December 31, 2012 and 2011, $1.0 billion and $843 million was recorded in the U.S. and $84 million and $82 million in the North Sea, respectively. As of December 31, 2012 and 2011, $103 million and $86 million were recorded in Canada and Egypt, respectively. Each country was assessed as a reporting unit, and no impairment of goodwill was recognized during 2012, 2011, or 2010.

Accounts Payable

Accounts Payable

Included in accounts payable at December 31, 2012 and 2011, are liabilities of approximately $255 million and $207 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

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

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 collectability 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 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 $27 million, $28 million, and $33 million, for 2012, 2011, and 2010, 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.

Derivative Instruments and Hedging Activities

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 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

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.

Foreign Currency Transaction Gains and Losses

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 components of the provision for income taxes. In 2012, the Company recorded a net tax expense of $16 million, including a current tax expense of $26 million and deferred tax benefit of $10 million. Included in deferred tax benefit for 2012 is approximately $11 million of tax benefit attributable to realized foreign currency transactions. In 2011, the Company recorded a net tax benefit of $66 million, including a current tax expense of $1 million and deferred tax benefit of $67 million. Included in deferred tax benefit for 2011 is approximately $6 million of tax expense attributable to realized foreign currency transactions. In 2010, the Company recorded net tax expense of $111 million, including a current tax expense of $2 million and deferred tax expense of $109 million. Included in deferred tax expense for 2010 is approximately $57 million of tax expense attributable to realized foreign currency transactions. 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 2012 and 2011 of $24 million and $4 million, respectively, and a loss of $39 million in 2010.

Insurance Coverage

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

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.

Stock-Based Compensation

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. Additionally, the Company also grants cash-based stock appreciation rights. These plans and related accounting policies are defined and described more fully in Note 10 — 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 $4 million, $32 million, and $28 million as financing cash inflows in 2012, 2011, and 2010, respectively.

Treasury Stock

Treasury Stock

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

New Pronouncements Issued But Not Yet Adopted

New Pronouncements Issued But Not Yet Adopted

In December 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (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 U.S. GAAP and International Financial Reporting Standards (IFRS) related to the offsetting of financial instruments. The existing U.S. GAAP guidance allowing balance sheet offsetting, including industry-specific guidance, remains unchanged. ASU No. 2013-01, released in January 2013, offers clarification on the scope of ASU No. 2011-11 as it applies to derivatives accounted for in accordance with Topic 815. The guidance in ASU No. 2011-11 and No. 2013-01 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 impact its consolidated financial statements.

In February 2013, the FASB issued ASU No. 2013-02, which requires preparers to report, in one place, information about reclassifications out of accumulated other comprehensive income (AOCI). The ASU also requires companies to report changes in AOCI balances. The guidance in ASU No. 2013-02 is effective for annual and interim periods beginning after December 15, 2012. The Company does not expect the adoption of this amendment to impact its consolidated financial statements.

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Derivative Instruments and Hedging Activities - Commodity Derivative Activity in Accumulated Other Comprehensive Income (Loss) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Unrealized gain (loss) on derivatives at beginning of period, Before tax	$ 145	$ (54)	$ (267)
Realized amounts reclassified into earnings, Before tax	(268)	13	(165)
Net change in derivative fair value, Before tax	113	188	376
Ineffectiveness reclassified into earnings, Before tax		(2)	2
Unrealized gain on derivatives at end of period, Before tax	(10)	145	(54)
Unrealized gain (loss) on derivatives at beginning of period, After tax	(6)	114	(19)
Realized amounts reclassified into earnings, After tax	(199)	19	(106)
Net change in derivative fair value, After tax	79	115	256
Ineffectiveness reclassified into earnings, After tax		(1)	1
Unrealized gain on derivatives at end of period, After tax	$ (6)	$ 114	$ (19)

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Acquisitions and Divestitures - Assets Acquired and Liabilities Assumed as of Acquisition Date (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Business Acquisition [Line Items]
Proved properties	$ 78,383	$ 67,805
Unproved properties	8,754	5,530
Cordillera Energy Partners [Member]
Business Acquisition [Line Items]
Current assets	39
Proved properties	1,040
Unproved properties	2,299
Gathering, transmission, and processing facilities	1
Goodwill	173
Deferred tax asset	64
Total assets acquired	3,616
Current liabilities	88
Deferred income tax liabilities	237
Other long-term obligations	5
Total liabilities assumed	330
Net assets acquired	3,286
Mobil North Sea Limited [Member]
Business Acquisition [Line Items]
Current assets	219
Proved properties	2,341
Unproved properties	476
Gathering, transmission, and processing facilities	338
Goodwill	84
Total assets acquired	3,458
Current liabilities	148
Asset retirement obligation	517
Deferred income tax liabilities	1,546
Other long-term obligations	1
Total liabilities assumed	2,212
Net assets acquired	$ 1,246

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Retirement and Deferred Compensation Plans - Components of Net Periodic Cost and Underlying Weighted Average Actuarial Assumptions Used for Pension and Postretirement Benefit Plans (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Pension Benefits [Member]
Component of Net Periodic Benefit Costs
Service cost	$ 5	$ 5	$ 5
Interest cost	7	7	7
Expected return on assets	(7)	(8)	(8)
Amortization of actuarial gain (loss)	1		1
Net periodic benefit cost	6	4	5
Weighted Average Assumptions used to determine Net Periodic Benefit Costs for the Years ended December 31
Discount rate	4.70%	5.40%	5.70%
Salary increases	4.60%	5.00%	5.30%
Expected return on assets	4.85%	6.25%	6.65%
Postretirement Benefits [Member]
Component of Net Periodic Benefit Costs
Service cost	4	3	2
Interest cost	1	1	1
Net periodic benefit cost	$ 5	$ 4	$ 3
Weighted Average Assumptions used to determine Net Periodic Benefit Costs for the Years ended December 31
Discount rate	4.04%	4.93%	5.56%
Healthcare cost trend
Initial	7.25%	7.50%	8.00%
Ultimate in 2017	5.00%	5.00%	5.00%

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Supplemental Oil and Gas Disclosures - Costs Incurred in Oil and Gas Property Acquisitions, Exploration and Development Activities (Parenthetical) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Capitalized interest	$ 316	$ 243	$ 111
Asset retirement costs	1,032	1,411	1,306
United States [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Capitalized interest	215	152	52
Asset retirement costs	473	380	1,099
Canada [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Capitalized interest	38	47	23
Asset retirement costs	245	228	98
Egypt [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Capitalized interest	16	18	10
Australia [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Capitalized interest	12	14	15
Asset retirement costs	207	125	93
North Sea [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Capitalized interest	24
Asset retirement costs	89	678
Argentina [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Capitalized interest	11	12	11
Asset retirement costs	$ 18		$ 16

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SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2012

Revenue and Direct Cost Information Relating to Company's Oil and Gas Exploration and Production Activities

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)
2012
Oil and gas production revenues	$	6,226	$	1,322		$	4,554	$	1,575	$	2,751	$	519	$	—		$	16,947
Operating cost:
Depreciation, depletion, and amortization
Recurring(1)		1,984		580			924		460		912		225		—			5,085
Additional		—		1,883			—		—		—		—		43			1,926
Asset retirement obligation accretion		112		41			—		17		58		4		—			232
Lease operating expenses		1,386		458			410		215		315		184		—			2,968
Gathering and transportation		69		163			39		—		24		8		—			303
Production taxes(2)		279		42			—		11		451		34		—			817
Income tax		851		(466	)		1,527		262		614		22		—			2,810
		4,681		2,701			2,900		965		2,374		477		43			14,141
Results of operation	$	1,545	$	(1,379	)	$	1,654	$	610	$	377	$	42	$	(43	)	$	2,806
Amortization rate per boe	$	17.24	$	11.66		$	13.81	$	17.67	$	32.65	$	12.39	$	—		$	16.88
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 operation	$	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 operation	$	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

(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.

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

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)
2012
Acquisitions:
Proved	$	1,076	$	5	$	28		$	32	$	110	$	—	$	—	$	1,251
Unproved		2,329		—		—			—		26		—		—		2,355
Exploration		1,369		111		696			149		111		157		96		2,689
Development		4,465		762		394			915		837		161		2		7,536
Costs incurred(1)	$	9,239	$	878	$	1,118		$	1,096	$	1,084	$	318	$	98	$	13,831
(1) Includes capitalized interest and asset retirement costs as follows:
Capitalized interest	$	215	$	38	$	16		$	12	$	24	$	11	$	—	$	316
Asset retirement costs		473		245		—			207		89		18		—		1,032
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

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)
2012
Proved properties	$	40,163		$	13,477		$	7,165		$	6,319		$	8,401		$	2,706		$	152		$	78,383
Unproved properties		5,641			1,059			686			284			626			382			76			8,754
		45,804			14,536			7,851			6,603			9,027			3,088			228			87,137
Accumulated DD&A		(17,968	)		(8,899	)		(4,474	)		(2,478	)		(3,445	)		(1,562	)		(152	)		(38,978	)
	$	27,836		$	5,637		$	3,377		$	4,125		$	5,582		$	1,526		$	76		$	48,159
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

Summary of Oil and Gas Property Costs Not Being Amortized

The following table sets forth a summary of oil and gas property costs not being amortized at December 31, 2012, 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		2012		2011		2010		2009 and Prior
	(In millions)
Property acquisition costs	$	6,998	$	3,558	$	981	$	2,146	$	313
Exploration and development		1,550		1,108		368		16		58
Capitalized interest		206		48		27		55		76
Total	$	8,754	$	4,714	$	1,376	$	2,217	$	447

Proved Reserve Data

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, 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
December 31, 2012		629,345			101,691			106,746			29,053			122,073			20,852			1,009,760			2,353,587			1,734,657			690,436			596,052			93,319			365,054			5,833,105			1,981,945
Proved undeveloped reserves:
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
December 31, 2012		263,957			82,908			17,288			34,808			28,399			3,857			431,217			832,320			403,227			205,055			1,074,018			18,985			97,496			2,631,101			869,734
Total proved reserves:
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
Purchase 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	)
Sale 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
Purchase 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	)
Sale 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
Extensions, discoveries and other additions		156,621			26,590			36,188			6,277			592			1,133			227,401			365,863			252,130			55,967			176,969			16,397			2,623			869,949			372,393
Purchase of minerals in-place		16,172			197			—			276			2,374			—			19,019			313,885			2,503			—			1,745			8,494			—			326,627			73,457
Revisions of previous estimates		(12,033	)		(7,146	)		(3,678	)		(66	)		(7,257	)		502			(29,678	)		(156,840	)		(1,443,989	)		(13,974	)		101			—			496			(1,614,206	)		(298,712	)
Production		(61,361	)		(8,083	)		(36,511	)		(10,571	)		(23,904	)		(4,666	)		(145,096	)		(312,600	)		(219,849	)		(129,468	)		(78,329	)		(21,029	)		(78,128	)		(839,403	)		(284,997	)
Sale of properties		(144	)		—			—			—			—			—			(144	)		(612	)		(422	)		—			—			—			—			(1,034	)		(316	)
Balance December 31, 2012		893,302			184,599			124,034			63,861			150,472			24,709			1,440,977			3,185,907			2,137,884			895,491			1,670,070			112,304			462,550			8,464,206			2,851,679

Unaudited Information of Future Net Cash Flows For Oil and Gas Reserves, Net of Income Tax Expense

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)
2012
Cash inflows	$	84,060		$	20,512		$	16,210		$	20,823		$	16,732		$	3,010		$	161,347
Production costs		(27,230	)		(8,543	)		(2,126	)		(4,896	)		(8,451	)		(1,162	)		(52,408	)
Development costs		(6,768	)		(2,916	)		(1,756	)		(2,484	)		(3,053	)		(248	)		(17,225	)
Income tax expense		(12,740	)		(754	)		(4,246	)		(3,172	)		(3,163	)		(141	)		(24,216	)
Net cash flows		37,322			8,299			8,082			10,271			2,065			1,459			67,498
10 percent discount rate		(19,464	)		(4,472	)		(2,107	)		(6,361	)		(98	)		(443	)		(32,945	)
Discounted future net cash flows(1)	$	17,858		$	3,827		$	5,975		$	3,910		$	1,967		$	1,016		$	34,553
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

(1) Estimated future net cash flows before income tax expense, discounted at 10 percent per annum, totaled approximately $48.2 billion and $52.3 billion as of December 31, 2012 and 2011, respectively.

Principal Sources of Change In Discounted Future Net Cash Flows

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

	For the Year Ended December 31,
	2012			2011			2010
	(In millions)
Sales, net of production costs	$	(12,589	)	$	(13,152	)	$	(9,152	)
Net change in prices and production costs		(1,941	)		12,167			13,006
Discoveries and improved recovery, net of related costs		6,742			6,751			5,147
Change in future development costs		(935	)		(2,250	)		(1,637	)
Previously estimated development costs incurred during the period		4,359			2,479			1,355
Revision of quantities		(4,065	)		(1,475	)		(1,905	)
Purchases of minerals in-place		1,181			2,139			7,794
Accretion of discount		5,234			4,161			2,439
Change in income taxes		2,711			(4,303	)		(4,535	)
Sales of properties		(3	)		(1,285	)		(3	)
Change in production rates and other		(2,088	)		273			182
	$	(1,394	)	$	5,505		$	12,691

XML

Asset Retirement Obligation - Asset Retirement Obligation (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Asset Retirement Obligation [Line Items]
Asset retirement obligation at beginning of year	$ 3,887	$ 2,872
Liabilities incurred	592	419
Liabilities acquired	72	592
Liabilities settled	(550)	(549)
Accretion expense	232	154	111
Revisions in estimated liabilities	345	399
Asset retirement obligation at end of year	4,578	3,887	2,872
Less current portion	(478)	(447)
Asset retirement obligation, long-term	$ 4,100	$ 3,440

XML

Income Taxes - Key Jurisdictions of Company's Earliest Open Tax Years (Detail)	12 Months Ended
	Dec. 31, 2012
United States [Member]
Open Tax Years By Major Jurisdiction [Line Items]
Open Tax Years by Major Tax Jurisdiction	2004
Canada [Member]
Open Tax Years By Major Jurisdiction [Line Items]
Open Tax Years by Major Tax Jurisdiction	2008
Egypt [Member]
Open Tax Years By Major Jurisdiction [Line Items]
Open Tax Years by Major Tax Jurisdiction	1998
Australia [Member]
Open Tax Years By Major Jurisdiction [Line Items]
Open Tax Years by Major Tax Jurisdiction	2008
United Kingdom [Member]
Open Tax Years By Major Jurisdiction [Line Items]
Open Tax Years by Major Tax Jurisdiction	2011
Argentina [Member]
Open Tax Years By Major Jurisdiction [Line Items]
Open Tax Years by Major Tax Jurisdiction	2005

XML

Income Taxes - Total Provision for Income Taxes (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Current taxes:
Federal	$ (150)	$ 64	$ 25
State		2	4
Foreign	2,349	2,197	1,193
Current tax, net	2,199	2,263	1,222
Deferred taxes:
Federal	596	656	431
State	10	17	7
Foreign	71	573	514
Deferred taxes, net	677	1,246	952
Total	$ 2,876	$ 3,509	$ 2,174

XML

Derivative Instrument and Hedging Activities - Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity Derivative Instruments, Assets	$ 33	$ 332
Recurring [Member] | Quoted Price in Active Markets (Level 1) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity Derivative Instruments, Assets
Commodity Derivative Instruments, Liabilities
Recurring [Member] | Significant Other Inputs (Level 2) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity Derivative Instruments, Assets	48	428
Commodity Derivative Instruments, Liabilities	131	250
Recurring [Member] | Unobservable Inputs (Level 3) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity Derivative Instruments, Assets
Commodity Derivative Instruments, Liabilities
Recurring [Member] | Total Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity Derivative Instruments, Assets	48	428
Commodity Derivative Instruments, Liabilities	131	250
Recurring [Member] | Netting [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity Derivative Instruments, Assets	(15)	(96)
Commodity Derivative Instruments, Liabilities	(15)	(96)
Recurring [Member] | Carrying Amount [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity Derivative Instruments, Assets	33	332
Commodity Derivative Instruments, Liabilities	$ 116	$ 154

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

12 Months Ended

Dec. 31, 2012

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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 other 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), the assessment of asset retirement obligations (see Note 5 — Asset Retirement Obligation), and the valuation of income taxes (see Note 7 — Income Taxes).

Fair Value Measurements

Certain assets and liabilities are reported at fair value on a recurring basis in Apache’s consolidated balance sheet. Accounting Standards Codification (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 the 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).

Fair value measurements are presented in further detail in Note 3 — Derivative Instruments, Hedging Activities, Note 6 — Debt, and Note 9 — Retirement and Deferred Compensation Plans.

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, 2012 and 2011, Apache had $160 million and $295 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 approximates 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 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, 2012 and 2011, the Company had an allowance for doubtful accounts of $82 million and $58 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 combinations, 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 $404 million, $335 million, and $321 million of internal costs in 2012, 2011, and 2010, 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 proved reserves), and asset retirement costs, 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 immediately. 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. In countries 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 2012, Apache’s statement of consolidated operations includes additional DD&A of $28 million related to exiting operations in New Zealand and $15 million of seismic costs incurred in countries where it has no established presence. In 2011, Apache recorded additional DD&A of $60 million related to exiting operations in Chile and $49 million of seismic costs incurred in countries where it has no established presence.

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. Future cash outflows associated with settling accrued asset retirement obligations are excluded from the calculation. 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. See Note 14 — Supplemental Oil and Gas Disclosures for a discussion of the calculation of estimated future net cash flows.

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. During 2012, the Company recorded a $1.9 billion ($1.4 billion net of tax) non-cash write-down of the carrying value of the Company’s Canadian proved oil and gas properties. Excluding the effects of cash flow hedges in calculating the ceiling limitation, the write-down for the full year would have been higher by $135 million ($101 million net of tax). As of December 31, 2011 and 2010, capitalized costs did not exceed the ceiling limitation, and no write-down was indicated. Cash flow hedges did not materially affect the 2011 or 2010 calculations.

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.

Gathering, Transmission, and Processing Facilities

Gathering, transmission, and processing facilities totaled $6.0 billion and $5.2 billion at December 31, 2012 and 2011, respectively. 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. No impairment of gathering, transmission, and processing facilities was recognized during 2012, 2011, or 2010.

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 $1.9 billion and $1.5 billion at December 31, 2012 and 2011, respectively.

Asset Retirement Costs and Obligations

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.

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 for impairment annually and when impairment indicators arise. Goodwill totaled $1.3 billion and $1.1 billion at December 31, 2012 and 2011, respectively. Goodwill of $173 million was booked in the U.S. during 2012 as a result of the acquisition of Cordillera Energy Partners III, LLC, as discussed in Note 2 — Acquisitions and Divestitures. As of December 31, 2012 and 2011, $1.0 billion and $843 million was recorded in the U.S. and $84 million and $82 million in the North Sea, respectively. As of December 31, 2012 and 2011, $103 million and $86 million were recorded in Canada and Egypt, respectively. Each country was assessed as a reporting unit, and no impairment of goodwill was recognized during 2012, 2011, or 2010.

Accounts Payable

Included in accounts payable at December 31, 2012 and 2011, are liabilities of approximately $255 million and $207 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 collectability 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 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 $27 million, $28 million, and $33 million, for 2012, 2011, and 2010, 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.

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.

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 components of the provision for income taxes. In 2012, the Company recorded a net tax expense of $16 million, including a current tax expense of $26 million and deferred tax benefit of $10 million. Included in deferred tax benefit for 2012 is approximately $11 million of tax benefit attributable to realized foreign currency transactions. In 2011, the Company recorded a net tax benefit of $66 million, including a current tax expense of $1 million and deferred tax benefit of $67 million. Included in deferred tax benefit for 2011 is approximately $6 million of tax expense attributable to realized foreign currency transactions. In 2010, the Company recorded net tax expense of $111 million, including a current tax expense of $2 million and deferred tax expense of $109 million. Included in deferred tax expense for 2010 is approximately $57 million of tax expense attributable to realized foreign currency transactions. 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 2012 and 2011 of $24 million and $4 million, respectively, and a loss of $39 million in 2010.

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.

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. Additionally, the Company also grants cash-based stock appreciation rights. These plans and related accounting policies are defined and described more fully in Note 10 — 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 $4 million, $32 million, and $28 million as financing cash inflows in 2012, 2011, and 2010, respectively.

Treasury Stock

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

New Pronouncements Issued But Not Yet Adopted

In December 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (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 U.S. GAAP and International Financial Reporting Standards (IFRS) related to the offsetting of financial instruments. The existing U.S. GAAP guidance allowing balance sheet offsetting, including industry-specific guidance, remains unchanged. ASU No. 2013-01, released in January 2013, offers clarification on the scope of ASU No. 2011-11 as it applies to derivatives accounted for in accordance with Topic 815. The guidance in ASU No. 2011-11 and No. 2013-01 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 impact its consolidated financial statements.

In February 2013, the FASB issued ASU No. 2013-02, which requires preparers to report, in one place, information about reclassifications out of accumulated other comprehensive income (AOCI). The ASU also requires companies to report changes in AOCI balances. The guidance in ASU No. 2013-02 is effective for annual and interim periods beginning after December 15, 2012. The Company does not expect the adoption of this amendment to impact its consolidated financial statements.

XML

Income Taxes - Reconciliation of Tax of Income Before Income Taxes and Total Tax Expense (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Effective Income Tax Rate Continuing Operations Tax Rate Reconciliation [Line Items]
Income tax expense at U.S. statutory rate	$ 1,707	$ 2,833	$ 1,822
State income tax, less federal benefit	6	12	6
Taxes related to foreign operations	773	568	245
Tax credits	(4)	(15)	(8)
Non-deductible merger costs			6
Current and deferred taxes related to currency fluctuations	16	(66)	111
Increase in U.K. tax rate	118	218
Net change in tax contingencies	(115)	(6)	(2)
Increase in valuation allowance	355	8	12
All other, net	20	(43)	(18)
Total	$ 2,876	$ 3,509	$ 2,174

XML

Acquisitions and Divestitures - Pro- Forma Information for Company as if Acquisition of Properties (Detail) (USD $) In Millions, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2010
Business Acquisition Pro Forma Information [Line Items]
Revenues and Other	$ 13,780
Net Income (Loss)	3,364
Preferred Stock Dividends	76
Income (Loss) Attributable to Common Stock	$ 3,288
Net Income (Loss) per Common Share - Basic	$ 8.62
Net Income (Loss) per Common Share - Diluted	$ 8.52

XML

ASSET RETIREMENT OBLIGATION (Tables)

12 Months Ended

Dec. 31, 2012

Asset Retirement Obligation

The following table describes changes to the Company’s asset retirement obligation (ARO) liability for the years ended December 31, 2012 and 2011:

	2012			2011
	(In millions)
Asset retirement obligation at beginning of year	$	3,887		$	2,872
Liabilities incurred		592			419
Liabilities acquired		72			592
Liabilities settled		(550	)		(549	)
Accretion expense		232			154
Revisions in estimated liabilities		345			399
Asset retirement obligation at end of year		4,578			3,887
Less current portion		(478	)		(447	)
Asset retirement obligation, long-term	$	4,100		$	3,440

XML

OTHER CURRENT LIABILITIES (Tables)

12 Months Ended

Dec. 31, 2012

Detail of Other Current Liabilities

The following table provides detail of the Company’s other current liabilities at December 31, 2012 and 2011:

	December 31, 2012		December 31, 2011
	(In millions)
Accrued operating expenses	$	211	$	221
Accrued exploration and development		1,792		1,430
Accrued compensation and benefits		198		180
Accrued interest		160		135
Accrued income taxes		297		533
Accrued U.K. Petroleum Revenue Tax		53		284
Other		149		141
Total Other current liabilities	$	2,860	$	2,924

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Supplemental Oil and Gas Disclosures - Proved Reserve Data (Detail)	12 Months Ended
	Dec. 31, 2012 MBoe	Dec. 31, 2011 MBoe	Dec. 31, 2010 MBoe	Dec. 31, 2009 MBoe
Reserve Quantities [Line Items]
Proved developed reserves	1,981,945	1,992,327	1,984,991	1,635,565
Proved undeveloped reserves	869,734	997,527	968,274	731,021
Extensions, discoveries and other additions	372
Purchase of minerals in-place	73
Balance	2,989,854	2,953,265	2,366,586
Extensions, discoveries and other additions	372,393	342,078	245,108
Purchases of minerals in-place	73,457	80,420	593,051
Revisions of previous estimates	(298,712)	(59,086)	(11,370)
Production	(284,997)	(273,074)	(240,037)
Sale of properties	(316)	(53,749)	(73)
Balance	2,851,679	2,989,854	2,953,265
Oil Reserves [Member]
Reserve Quantities [Line Items]
Balance	1,369,475	1,308,735	1,067,248
Proved developed reserves	1,009,760	950,091	924,422	762,688
Proved undeveloped reserves	431,217	419,384	384,313	304,560
Extensions, discoveries and other additions	227,401	178,412	129,210
Purchase of minerals in-place	19,019	50,238	248,832
Revisions of previous estimates	(29,678)	(29,487)	(11,339)
Production	(145,096)	(135,446)	(125,143)
Sale of properties	(144)	(2,977)	(73)
Balance	1,440,977	1,369,475	1,308,735	1,067,248
Natural Gas Reserves [Member]
Reserve Quantities [Line Items]
Balance	9,722,273	9,867,182	7,796,031
Proved developed reserves	5,833,105	6,253,418	6,363,417	5,237,265
Proved undeveloped reserves	2,631,101	3,468,855	3,503,765	2,558,766
Extensions, discoveries and other additions	869,949	981,993	695,383
Purchase of minerals in-place	326,627	181,091	2,065,316
Revisions of previous estimates	(1,614,206)	(177,591)	(186)
Production	(839,403)	(825,770)	(689,361)
Sale of properties	(1,034)	(304,632)	(1)
Balance	8,464,206	9,722,273	9,867,182	7,796,031
United States [Member]
Reserve Quantities [Line Items]
Extensions, discoveries and other additions	218
United States [Member] | Oil Reserves [Member]
Reserve Quantities [Line Items]
Balance	794,047	759,015	523,637
Proved developed reserves	629,345	535,741	514,537	373,010
Proved undeveloped reserves	263,957	258,306	244,478	150,627
Extensions, discoveries and other additions	156,621	89,591	72,928
Purchase of minerals in-place	16,172	5,683	195,131
Revisions of previous estimates	(12,033)	(7,191)	7,597
Production	(61,361)	(51,658)	(40,278)
Sale of properties	(144)	(1,393)
Balance	893,302	794,047	759,015	523,637
United States [Member] | Natural Gas Reserves [Member]
Reserve Quantities [Line Items]
Balance	2,976,211	3,272,985	2,437,921
Proved developed reserves	2,353,587	2,215,973	2,284,116	1,785,155
Proved undeveloped reserves	832,320	760,238	988,869	652,766
Extensions, discoveries and other additions	365,863	169,506	102,180
Purchase of minerals in-place	313,885	67,595	951,654
Revisions of previous estimates	(156,840)	(7,716)	47,989
Production	(312,600)	(315,631)	(266,759)
Sale of properties	(612)	(210,528)
Balance	3,185,907	2,976,211	3,272,985	2,437,921
Canada [Member]
Reserve Quantities [Line Items]
Extensions, discoveries and other additions	69
Canada [Member] | Oil Reserves [Member]
Reserve Quantities [Line Items]
Balance	173,041	174,990	146,774
Proved developed reserves	101,691	105,102	113,993	89,222
Proved undeveloped reserves	82,908	67,939	60,997	57,552
Extensions, discoveries and other additions	26,590	22,602	6,816
Purchase of minerals in-place	197	752	42,440
Revisions of previous estimates	(7,146)	(16,343)	(14,592)
Production	(8,083)	(7,376)	(6,375)
Sale of properties		(1,584)	(73)
Balance	184,599	173,041	174,990	146,774
Canada [Member] | Natural Gas Reserves [Member]
Reserve Quantities [Line Items]
Balance	3,547,511	3,491,967	2,305,348
Proved developed reserves	1,734,657	2,108,801	2,181,615	1,436,151
Proved undeveloped reserves	403,227	1,438,710	1,310,352	869,197
Extensions, discoveries and other additions	252,130	505,049	274,755
Purchase of minerals in-place	2,503	8,838	1,064,618
Revisions of previous estimates	(1,443,989)	(133,359)	(8,211)
Production	(219,849)	(230,880)	(144,542)
Sale of properties	(422)	(94,104)	(1)
Balance	2,137,884	3,547,511	3,491,967	2,305,348
Egypt [Member]
Reserve Quantities [Line Items]
Extensions, discoveries and other additions	46
Egypt [Member] | Oil Reserves [Member]
Reserve Quantities [Line Items]
Balance	128,035	127,127	115,593
Proved developed reserves	106,746	105,840	109,657	97,787
Proved undeveloped reserves	17,288	22,195	17,470	17,806
Extensions, discoveries and other additions	36,188	45,039	41,205
Purchase of minerals in-place			11,261
Revisions of previous estimates	(3,678)	(6,185)	(4,723)
Production	(36,511)	(37,946)	(36,209)
Balance	124,034	128,035	127,127	115,593
Egypt [Member] | Natural Gas Reserves [Member]
Reserve Quantities [Line Items]
Balance	982,966	1,076,917	1,159,141
Proved developed reserves	690,436	700,866	748,573	838,000
Proved undeveloped reserves	205,055	282,100	328,344	321,141
Extensions, discoveries and other additions	55,967	77,049	46,692
Purchase of minerals in-place			49,044
Revisions of previous estimates	(13,974)	(37,623)	(41,137)
Production	(129,468)	(133,377)	(136,823)
Balance	895,491	982,966	1,076,917	1,159,141
Australia [Member]
Reserve Quantities [Line Items]
Extensions, discoveries and other additions	36
Australia [Member] | Oil Reserves [Member]
Reserve Quantities [Line Items]
Balance	67,945	66,136	78,441
Proved developed reserves	29,053	35,725	48,072	34,662
Proved undeveloped reserves	34,808	32,220	18,064	43,779
Extensions, discoveries and other additions	6,277	15,762	4,452
Purchase of minerals in-place	276
Revisions of previous estimates	(66)
Production	(10,571)	(13,953)	(16,757)
Balance	63,861	67,945	66,136	78,441
Australia [Member] | Natural Gas Reserves [Member]
Reserve Quantities [Line Items]
Balance	1,569,584	1,488,498	1,361,441
Proved developed reserves	596,052	675,618	682,763	699,963
Proved undeveloped reserves	1,074,018	893,966	805,735	661,478
Extensions, discoveries and other additions	176,969	148,640	199,958
Purchase of minerals in-place	1,745
Revisions of previous estimates	101
Production	(78,329)	(67,554)	(72,901)
Balance	1,670,070	1,569,584	1,488,498	1,361,441
North Sea [Member] | Oil Reserves [Member]
Reserve Quantities [Line Items]
Balance	178,667	154,368	171,714
Proved developed reserves	122,073	145,743	115,705	142,022
Proved undeveloped reserves	28,399	32,924	38,663	29,692
Extensions, discoveries and other additions	592	404	3,383
Purchase of minerals in-place	2,374	43,803
Revisions of previous estimates	(7,257)
Production	(23,904)	(19,908)	(20,729)
Balance	150,472	178,667	154,368	171,714
North Sea [Member] | Natural Gas Reserves [Member]
Reserve Quantities [Line Items]
Balance	108,442	4,144	4,851
Proved developed reserves	93,319	105,028	4,144	4,851
Proved undeveloped reserves	18,985	3,414
Extensions, discoveries and other additions	16,397	475	166
Purchase of minerals in-place	8,494	104,658
Production	(21,029)	(835)	(873)
Balance	112,304	108,442	4,144	4,851
Argentina [Member] | Oil Reserves [Member]
Reserve Quantities [Line Items]
Balance	27,740	27,099	31,089
Proved developed reserves	20,852	21,940	22,458	25,985
Proved undeveloped reserves	3,857	5,800	4,641	5,104
Extensions, discoveries and other additions	1,133	5,014	426
Revisions of previous estimates	502	232	379
Production	(4,666)	(4,605)	(4,795)
Balance	24,709	27,740	27,099	31,089
Argentina [Member] | Natural Gas Reserves [Member]
Reserve Quantities [Line Items]
Balance	537,559	532,671	527,329
Proved developed reserves	365,054	447,132	462,206	473,145
Proved undeveloped reserves	97,496	90,427	70,465	54,184
Extensions, discoveries and other additions	2,623	81,274	71,632
Revisions of previous estimates	496	1,107	1,173
Production	(78,128)	(77,493)	(67,463)
Balance	462,550	537,559	532,671	527,329

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Debt - Debt for Apache and Subsidiaries (Parenthetical) (Detail)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
6.25% notes due 2012 [Member]
Debt Instrument [Line Items]
Notes interest rate	6.25%	6.25%
Debt maturity year	2012	2012
5.25% notes due 2013 [Member]
Debt Instrument [Line Items]
Notes interest rate	5.25%	5.25%
Debt maturity year	2013	2013
6.0% notes due 2013 [Member]
Debt Instrument [Line Items]
Notes interest rate	6.00%	6.00%
Debt maturity year	2013	2013
5.625% notes due 2017 [Member]
Debt Instrument [Line Items]
Notes interest rate	5.625%	5.625%
Debt maturity year	2017	2017
One Point Seven Five Percentage Notes Due Twenty Seventeen [Member]
Debt Instrument [Line Items]
Notes interest rate	1.75%	1.75%
Debt maturity year	2017	2017
6.9% notes due 2018 [Member]
Debt Instrument [Line Items]
Notes interest rate	6.90%	6.90%
Debt maturity year	2018	2018
7.0% notes due 2018 [Member]
Debt Instrument [Line Items]
Notes interest rate	7.00%	7.00%
Debt maturity year	2018	2018
7.625% notes due 2019 [Member]
Debt Instrument [Line Items]
Notes interest rate	7.625%	7.625%
Debt maturity year	2019	2019
3.625% notes due 2021 [Member]
Debt Instrument [Line Items]
Notes interest rate	3.625%	3.625%
Debt maturity year	2021	2021
Three Point Two Five Percentage Notes Due Twenty Twenty Two [Member]
Debt Instrument [Line Items]
Notes interest rate	3.25%	3.25%
Debt maturity year	2022	2022
Two Point Six Two Five Percentage Notes Due Twenty Twenty Three [Member]
Debt Instrument [Line Items]
Notes interest rate	2.625%	2.625%
Debt maturity year	2023	2023
7.7% notes due 2026 [Member]
Debt Instrument [Line Items]
Notes interest rate	7.70%	7.70%
Debt maturity year	2026	2026
7.95% notes due 2026 [Member]
Debt Instrument [Line Items]
Notes interest rate	7.95%	7.95%
Debt maturity year	2026	2026
6.0% notes due 2037 [Member]
Debt Instrument [Line Items]
Notes interest rate	6.00%	6.00%
Debt maturity year	2037	2037
5.1% notes due 2040 [Member]
Debt Instrument [Line Items]
Notes interest rate	5.10%	5.10%
Debt maturity year	2040	2040
5.25% notes due 2042 [Member]
Debt Instrument [Line Items]
Notes interest rate	5.25%	5.25%
Debt maturity year	2042	2042
Four Point Seven Five Percentage Notes Due Twenty Forty Three [Member]
Debt Instrument [Line Items]
Notes interest rate	4.75%	4.75%
Debt maturity year	2043	2043
Four Point Two Five Percentage Notes Due Twenty Forty Four [Member]
Debt Instrument [Line Items]
Notes interest rate	4.25%	4.25%
Debt maturity year	2044	2044
7.375% debentures due 2047 [Member]
Debt Instrument [Line Items]
Notes interest rate	7.375%	7.375%
Debt maturity year	2047	2047
7.625% debentures due 2096 [Member]
Debt Instrument [Line Items]
Notes interest rate	7.625%	7.625%
Debt maturity year	2096	2096
Apache Finance Canada 4.375% notes due 2015 [Member]
Debt Instrument [Line Items]
Notes interest rate	4.375%	4.375%
Debt maturity year	2015	2015
Notes Due In Twenty Sixteen And Twenty Seventeen [Member]
Debt Instrument [Line Items]
Debt maturity year	2016	2017
Apache finance Canada 7.75% notes due 2029 [Member]
Debt Instrument [Line Items]
Notes interest rate	7.75%	7.75%
Debt maturity year	2029	2029

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Derivative Instruments and Hedging Activities - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012 Counterparty
Derivative [Line Items]
Number of counterparties	15
Net gain included in accumulated other comprehensive loss, before tax applied to next twelve months	$ 12
Net gain included in accumulated other comprehensive loss, after tax	$ 7

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DEBT (Tables)

12 Months Ended

Dec. 31, 2012

Debt for Apache and Subsidiaries

The following table presents the carrying value of the Company’s debt at December 31, 2012 and 2011:

	December 31,
	2012			2011
	(In millions)
U.S.:
Money market lines of credit	$	13		$	—
Commercial paper		489			—
6.25% notes due 2012(1)		—			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
1.75% notes due 2017(1)		400			—
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
3.25% notes due 2022(1)		1,100			—
2.625% notes due 2023(1)		1,200			—
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
4.75% notes due 2043(1)		1,500			—
4.25% notes due 2044(1)		800			—
7.375% debentures due 2047		150			150
7.625% debentures due 2096		150			150
		11,682			6,580
Subsidiary and other obligations:
Argentina overdraft lines of credit		69			31
Canada lines of credit		9			—
Apache Finance Canada 4.375% notes due 2015(1)		350			350
Notes due in 2016 and 2017		1			1
Apache Finance Canada 7.75% notes due 2029		300			300
		729			682
Debt before unamortized discount		12,411			7,262
Unamortized discount		(66	)		(46	)
Total debt	$	12,345		$	7,216
Current maturities	$	(990	)	$	(431	)
Long-term debt	$	11,355		$	6,785

(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.

Schedule of Long Term Debt by Maturity

Debt maturities as of December 31, 2012, excluding discounts, are as follows:

	(In millions)
2013	$	991
2014		—
2015		350
2016		1
2017		1,389
Thereafter		9,680
Total Debt, excluding discounts	$	12,411

Non-Recurring Fair Value Measurement

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 fair value measurement.

	December 31, 2012				December 31, 2011
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)
Money market lines of credit	$	91	$	91	$	31	$	31
Commercial paper		489		489		—		—
Notes and debentures		11,765		13,340		7,185		8,673
Total Debt	$	12,345	$	13,920	$	7,216	$	8,704

Financing Costs, Net

Financing costs incurred during the periods are composed of the following:

	For the Year Ended December 31,
	2012			2011			2010
	(In millions)
Interest expense	$	509		$	433		$	345
Amortization of deferred loan costs		7			5			17
Capitalized interest		(334	)		(263	)		(120	)
Interest income		(17	)		(17	)		(13	)
Financing costs, net	$	165		$	158		$	229

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INCOME TAXES (Tables)

12 Months Ended

Dec. 31, 2012

Income Before Income Taxes

Income before income taxes is composed of the following:

	For the Year Ended December 31,
	2012		2011		2010
	(In millions)
U.S.	$	1,605	$	2,373	$	1,328
Foreign		3,272		5,720		3,878
Total	$	4,877	$	8,093	$	5,206

Total Provision for Income Taxes

The total provision for income taxes consists of the following:

	For the Year Ended December 31,
	2012			2011		2010
	(In millions)
Current taxes:
Federal	$	(150	)	$	64	$	25
State		—			2		4
Foreign		2,349			2,197		1,193
		2,199			2,263		1,222
Deferred taxes:
Federal		596			656		431
State		10			17		7
Foreign		71			573		514
		677			1,246		952
Total	$	2,876		$	3,509	$	2,174

Reconciliation of Tax of Income Before Income Taxes and Total Tax Expense

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,
	2012			2011			2010
	(In millions)
Income tax expense at U.S. statutory rate	$	1,707		$	2,833		$	1,822
State income tax, less federal benefit		6			12			6
Taxes related to foreign operations		773			568			245
Tax credits		(4	)		(15	)		(8	)
Non-deductible merger costs		—			—			6
Current and deferred taxes related to currency fluctuations		16			(66	)		111
Increase in U.K. tax rate		118			218			—
Net change in tax contingencies		(115	)		(6	)		(2	)
Increase in valuation allowance		355			8			12
All other, net		20			(43	)		(18	)
	$	2,876		$	3,509		$	2,174

Net Deferred Tax Liability

The net deferred tax liability consists of the following:

	December 31,
	2012			2011
	(In millions)
Deferred tax assets:
Deferred income	$	(33	)	$	(89	)
Federal and state net operating loss carryforwards		(932	)		(236	)
Foreign net operating loss carryforwards		(61	)		(55	)
Tax credits		(78	)		(66	)
Accrued expenses and liabilities		(2	)		(90	)
Total deferred tax assets		(1,106	)		(536	)
Valuation allowance		419			60
Net deferred tax assets		(687	)		(476	)
Deferred tax liabilities:
Other		23			21
Depreciation, depletion and amortization		8,536			7,443
Total deferred tax liabilities		8,559			7,464
Net deferred income tax liability	$	7,872		$	6,988

Net Operating Losses

On December 31, 2012, the Company had net operating losses as follows:

	December 31, 2012
	Amount		Expiration
	(In millions)
Net operating losses:
U.S. — Federal	$	2,393	2027
U.S. — State		1,648	Various
Canada		6	2014
Australia		94	Indefinite
Argentina		55	2013

Reconciliation of Beginning and Ending Amount of Unrecognized Tax Benefits

A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:

	2012			2011			2010
	(In millions)
Balance at beginning of year	$	97		$	110		$	123
Additions based on tax positions related to the current year		—			13			(1	)
Reductions for tax positions of prior years		(29	)		(4	)		(12	)
Settlements		(65	)		(22	)		—
Balance at end of year	$	3		$	97		$	110

Key Jurisdictions of Company's Earliest Open Tax Years

Apache’s earliest open tax years in its key jurisdictions are as follows:

Jurisdiction
U.S.	2004
Canada	2008
Egypt	1998
Australia	2008
U.K.	2011
Argentina	2005

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STATEMENT OF CONSOLIDATED SHAREHOLDERS' EQUITY (Parenthetical) (USD $) In Millions, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Income tax benefit (expense) to post retirement	$ 5	$ 7	$ (2)
Tax (benefit) expense to commodity hedges	(35)	66	62
Common stock, dividends, per share	$ 0.68	$ 0.60	$ 0.60
Retained Earnings [Member]
Common stock, dividends, per share	$ 0.68	$ 0.60	$ 0.60
Accumulated Other Comprehensive (Loss) [Member]
Income tax benefit (expense) to post retirement	5	7	(2)
Tax (benefit) expense to commodity hedges	$ (35)	$ 66	$ 62

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COMMITMENTS AND CONTINGENCIES (Tables)

12 Months Ended

Dec. 31, 2012

Contractual Obligations

At December 31, 2012, contractual obligations for drilling rigs, purchase obligations, firm transportation agreements, and long-term operating leases are as follows:

Net Minimum Commitments	Total		2013		2014-2015		2016-2017		2018 & Beyond
	(In millions)
Drilling rig commitments(1)	$	896	$	602	$	289	$	3	$	2
Purchase obligations(2)		2,588		1,200		1,182		184		22
Firm transportation agreements(3)		763		148		264		134		217
Office and related equipment(4)		402		49		91		96		166
Other operating lease obligations(5)		754		209		316		205		24
Total Net Minimum Commitments	$	5,403	$	2,208	$	2,142	$	622	$	431

(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, LNG 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 vessels (FPSOs), compressors, helicopters, and boats.

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Capital Stock - Summary of Stock Options Issued Under Stock Option Plans (Parenthetical) (Detail) (USD $) In Millions, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average remaining contractual life for options outstanding	6 years 8 months 12 days
Weighted average remaining contractual life for expected to vest	8 years 7 months 6 days
Weighted average remaining contractual life for exercisable	5 years
Aggregate intrinsic value of options outstanding	$ 19
Aggregate intrinsic value of expected to vest	0
Aggregate intrinsic value of exercisable	$ 19
Weighted average fair value of options granted during the year	$ 26.41	$ 42.20	$ 34.12

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Summary of Significant Accounting Policies - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Summary Of Significant Accounting Policies [Line Items]
Cash and cash equivalents	$ 160,000,000	$ 295,000,000	$ 134,000,000	$ 2,048,000,000
Allowance for Doubtful Accounts	82,000,000	58,000,000
Capitalized internal costs	48,159,000,000	41,081,000,000
Impairment of operations	1,926,000,000	109,000,000
Seismic costs	15,000,000	49,000,000
Write-down of the carrying value of Oil and Gas properties	1,900,000,000
Significant portion of reserve quantity	Greater than 25 percent
Gathering, transmission and processing facilities	5,955,000,000	5,175,000,000
Accumulated depreciation	40,867,000,000	33,771,000,000
Goodwill	1,289,000,000	1,114,000,000
Impairment of goodwill	0	0	0
Accounts payable	255,000,000	207,000,000
Net cost of third party gas	27,000,000	28,000,000	33,000,000
Maximum percentage of production available to contract partners	40.00%
Additional net tax expense related to foreign currency translation gains and losses	16,000,000	(66,000,000)	111,000,000
Current tax benefit (expense) related to foreign currency translation gains and losses	(26,000,000)	(1,000,000)	(2,000,000)
Deferred tax expense (benefit) related to foreign currency translation gains and losses	(10,000,000)	(67,000,000)	109,000,000
Realized foreign currency transactions tax expense	(11,000,000)	6,000,000	57,000,000
Other foreign currency gains and losses	24,000,000	4,000,000	(39,000,000)
Benefit of tax deductions in excess of recognized compensation cost	4,000,000	32,000,000	28,000,000
Gas Gathering Transmission And Processing Facilities [Member]
Summary Of Significant Accounting Policies [Line Items]
Accumulated depreciation	1,900,000,000	1,500,000,000
Canada [Member]
Summary Of Significant Accounting Policies [Line Items]
Capitalized internal costs	5,637,000,000	7,206,000,000
Impairment of operations	1,883,000,000
Write-down of the carrying value of Oil and Gas properties	1,900,000,000
Write-down of the carrying value of Oil and Gas properties, net of tax	1,400,000,000
Write down of oil and gas property Excluding the effect of cash flow hedge Before Tax	135,000,000
Write down of oil and gas property Excluding the effect of cash flow hedge Net of Tax	101,000,000
Goodwill	103,000,000	103,000,000
United States [Member]
Summary Of Significant Accounting Policies [Line Items]
Capitalized internal costs	27,836,000,000	20,582,000,000
Goodwill	1,000,000,000	843,000,000
United States [Member] | Cordillera Energy Partners [Member]
Summary Of Significant Accounting Policies [Line Items]
Goodwill	173,000,000
Mobil North Sea Limited [Member]
Summary Of Significant Accounting Policies [Line Items]
Goodwill	84,000,000	82,000,000
Egypt [Member]
Summary Of Significant Accounting Policies [Line Items]
Capitalized internal costs	3,377,000,000	3,060,000,000
Goodwill	86,000,000	86,000,000
NEW ZEALAND [Member]
Summary Of Significant Accounting Policies [Line Items]
Impairment of operations	28,000,000
Chile [Member]
Summary Of Significant Accounting Policies [Line Items]
Impairment of operations		60,000,000
Minimum [Member]
Summary Of Significant Accounting Policies [Line Items]
Voting interest required for consolidation of investments	50.00%
Minimum [Member] | Gas Gathering Transmission And Processing Facilities [Member]
Summary Of Significant Accounting Policies [Line Items]
Useful lives of gas gathering, transmission and processing facilities	3 years
Maximum [Member] | Gas Gathering Transmission And Processing Facilities [Member]
Summary Of Significant Accounting Policies [Line Items]
Useful lives of gas gathering, transmission and processing facilities	25 years
Apache Corporation [Member]
Summary Of Significant Accounting Policies [Line Items]
Cash and cash equivalents		41,000,000	6,000,000	647,000,000
Capitalized internal costs	404,000,000	335,000,000	321,000,000
Goodwill	$ 173,000,000

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Asset Retirement Obligation - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Asset Retirement Obligation [Line Items]
Additional abandonment liabilities related to the properties acquired	$ 72	$ 592
Additional abandonment liabilities associated with its drilling and development program	592	419
Increases in offshore abandonment costs	345	399
Liability related to abandonment activity	$ 478	$ 447

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Retirement and Deferred Compensation Plans - Allocations for Plan Asset Holding and Target Allocation for Company's Plan Asset (Detail)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	100.00%
Percentage of Plan Assets at Year-End	100.00%	100.00%
Cash [Member]
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	0.00%
Percentage of Plan Assets at Year-End	1.00%	4.00%
Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	50.00%
Percentage of Plan Assets at Year-End	49.00%	48.00%
Equity Securities [Member] | UK Quoted Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	17.00%
Percentage of Plan Assets at Year-End	16.00%	17.00%
Equity Securities [Member] | Overseas Quoted Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	33.00%
Percentage of Plan Assets at Year-End	33.00%	31.00%
Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	50.00%
Percentage of Plan Assets at Year-End	50.00%	48.00%
Debt Securities [Member] | U.K. Government Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	30.00%
Percentage of Plan Assets at Year-End	30.00%	30.00%
Debt Securities [Member] | U.K. Corporate Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	20.00%
Percentage of Plan Assets at Year-End	20.00%	18.00%

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STATEMENT OF CONSOLIDATED OPERATIONS (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
REVENUES AND OTHER:
Oil and gas production revenues									$ 16,947	$ 16,810	$ 12,183
Other									131	78	(91)
Total revenues and other	4,391	4,179	3,972	4,536	4,297	4,328	4,338	3,925	17,078	16,888	12,092
Depreciation, depletion, and amortization:
Recurring									5,183	4,095	3,083
Additional									1,926	109
Asset retirement obligation accretion									232	154	111
Lease operating expenses									2,968	2,605	2,032
Gathering and transportation									303	296	178
Taxes other than income									862	899	690
General and administrative									531	459	380
Merger, acquisitions & transition									31	20	183
Financing costs, net									165	158	229
Total operating expenses									12,201	8,795	6,886
INCOME BEFORE INCOME TAXES									4,877	8,093	5,206
Current income tax provision									2,199	2,263	1,222
Deferred income tax provision									677	1,246	952
NET INCOME	668	180	356	797	1,189	1,002	1,259	1,134	2,001	4,584	3,032
Preferred stock dividends									76	76	32
INCOME ATTRIBUTABLE TO COMMON STOCK	$ 649	$ 161	$ 337	$ 778	$ 1,170	$ 983	$ 1,240	$ 1,115	$ 1,925	$ 4,508	$ 3,000
NET INCOME PER COMMON SHARE:
Basic	$ 1.66	$ 0.41	$ 0.87	$ 2.02	$ 3.05	$ 2.56	$ 3.23	$ 2.91	$ 4.95	$ 11.75	$ 8.53
Diluted	$ 1.64	$ 0.41	$ 0.86	$ 2.00	$ 2.98	$ 2.50	$ 3.17	$ 2.86	$ 4.92	$ 11.47	$ 8.46
WEIGHTED-AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
Basic									389	384	352
Diluted									391	400	359
DIVIDENDS DECLARED PER COMMON SHARE									$ 0.68	$ 0.60	$ 0.60

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Derivative Instrument and Hedging Activities - Open Crude and Natural Gas Derivative Instruments (Detail)	Dec. 31, 2012 MMBTU
Fixed-Price Swaps [Member] | 2013 [Member] | Open Natural Gas Derivative Positions [Member] | Currency Swap [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Open positions	10,095,000
Weighted Average Fixed Price	6.74
Fixed-Price Swaps [Member] | 2013 [Member] | Open Crude Oil Derivative Positions [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Open positions	40,292,000
Weighted Average Fixed Price	97.31
Fixed-Price Swaps [Member] | 2014 [Member] | Open Natural Gas Derivative Positions [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Open positions	1,295,000
Weighted Average Fixed Price	6.72
Fixed-Price Swaps [Member] | 2014 [Member] | Open Crude Oil Derivative Positions [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Open positions	76,000
Weighted Average Fixed Price	74.50
Collars [Member] | 2013 [Member] | Open Natural Gas Derivative Positions [Member] | Currency Swap [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Open positions	6,825,000
Collars Weighted Average Floor Price	5.35
Weighted Average Ceiling Price	6.67
Collars [Member] | 2013 [Member] | Open Crude Oil Derivative Positions [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Open positions	5,701
Collars Weighted Average Floor Price	82.84
Weighted Average Ceiling Price	111.63
Collars [Member] | 2014 [Member] | Open Crude Oil Derivative Positions [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Open positions
Collars Weighted Average Floor Price
Weighted Average Ceiling Price

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Supplemental Oil and Gas Disclosures - Costs Incurred in Oil and Gas Property Acquisitions, Exploration and Development Activities (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved	$ 1,251	$ 2,755	$ 8,681
Unproved	2,355	688	3,216
Exploration	2,689	1,762	1,584
Development	7,536	5,587	3,727
Costs incurred	13,831	10,792	17,208
Proved properties	78,383	67,805
Unproved properties	8,754	5,530
Capitalized costs, gross	87,137	73,335
Accumulated DD&A	(38,978)	(32,254)
Capitalized costs, net	48,159	41,081
United States [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved	1,076	368	5,604
Unproved	2,329	116	2,497
Exploration	1,369	418	261
Development	4,465	2,832	1,724
Costs incurred	9,239	3,734	10,086
Proved properties	40,163	33,905
Unproved properties	5,641	2,690
Capitalized costs, gross	45,804	36,595
Accumulated DD&A	(17,968)	(16,013)
Capitalized costs, net	27,836	20,582
Canada [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved	5		2,752
Unproved		33	542
Exploration	111	209	312
Development	762	883	611
Costs incurred	878	1,125	4,217
Proved properties	13,477	12,619
Unproved properties	1,059	1,093
Capitalized costs, gross	14,536	13,712
Accumulated DD&A	(8,899)	(6,506)
Capitalized costs, net	5,637	7,206
Egypt [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved	28	(12)	325
Unproved		2	145
Exploration	696	570	477
Development	394	344	290
Costs incurred	1,118	904	1,237
Proved properties	7,165	6,117
Unproved properties	686	615
Capitalized costs, gross	7,851	6,732
Accumulated DD&A	(4,474)	(3,672)
Capitalized costs, net	3,377	3,060
Australia [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved	32
Unproved		48	32
Exploration	149	286	236
Development	915	429	496
Costs incurred	1,096	763	764
Proved properties	6,319	5,183
Unproved properties	284	270
Capitalized costs, gross	6,603	5,453
Accumulated DD&A	(2,478)	(2,061)
Capitalized costs, net	4,125	3,392
North Sea [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved	110	2,399
Unproved	26	476
Exploration	111	18	142
Development	837	941	475
Costs incurred	1,084	3,834	617
Proved properties	8,401	7,430
Unproved properties	626	513
Capitalized costs, gross	9,027	7,943
Accumulated DD&A	(3,445)	(2,550)
Capitalized costs, net	5,582	5,393
Argentina [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Exploration	157	202	136
Development	161	156	131
Costs incurred	318	358	267
Proved properties	2,706	2,442
Unproved properties	382	327
Capitalized costs, gross	3,088	2,769
Accumulated DD&A	(1,562)	(1,343)
Capitalized costs, net	1,526	1,426
Other International [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Unproved		13
Exploration	96	59	20
Development	2	2
Costs incurred	98	74	20
Proved properties	152	109
Unproved properties	76	22
Capitalized costs, gross	228	131
Accumulated DD&A	(152)	(109)
Capitalized costs, net	$ 76	$ 22

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CONSOLIDATED BALANCE SHEET (Parenthetical) (USD $)	Dec. 31, 2012	Dec. 31, 2011
Preferred stock, par value
Preferred stock, shares authorized	10,000,000	10,000,000
Preferred stock, shares issued	1,265,000	1,265,000
Preferred stock, shares outstanding	1,265,000	1,265,000
Preferred stock, liquidation preference per share	$ 1,000	$ 1,000
Cumulative preferred stock interest rate	6.00%	6.00%
Common stock, par value	$ 0.625	$ 0.625
Common stock, shares authorized	860,000,000	860,000,000
Common stock, shares issued	392,712,245	385,249,885
Treasury stock, shares	1,071,475	1,132,242

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Business Segment Information - Financial Segment Information (Parenthetical) (Detail) (USD $) In Billions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012
Segment Reporting Information [Line Items]
Write-down of oil and gas properties	$ 1.9

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Debt - Financing Costs, Net (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Long Term Debt And Equity Financings [Line Items]
Interest expense	$ 509	$ 433	$ 345
Amortization of deferred loan costs	7	5	17
Capitalized interest	(334)	(263)	(120)
Interest income	(17)	(17)	(13)
Financing costs, net	$ 165	$ 158	$ 229

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Supplemental Oil and Gas Disclosures - Summary of Oil and Gas Property Costs Not Being Amortized (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Property acquisition costs	$ 6,998
Exploration and development	1,550
Capitalized interest	206
Costs incurred	8,754
2012 [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Property acquisition costs	3,558
Exploration and development	1,108
Capitalized interest	48
Costs incurred	4,714
2011 [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Property acquisition costs	981
Exploration and development	368
Capitalized interest	27
Costs incurred	1,376
2010 [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Property acquisition costs	2,146
Exploration and development	16
Capitalized interest	55
Costs incurred	2,217
2009 and Prior [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Property acquisition costs	313
Exploration and development	58
Capitalized interest	76
Costs incurred	$ 447

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ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (Tables)

12 Months Ended

Dec. 31, 2012

Components of Accumulated Other Comprehensive Income (Loss)

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

	For the Year Ended December 31,
	2012			2011			2010
	(In millions)
Currency translation adjustment(1)	$	(109	)	$	(109	)	$	(109	)
Unrealized gain (loss) on derivatives (Note 3)		(6	)		114			(19	)
Unfunded pension and postretirement benefit plan		(16	)		(14	)		(13	)
Accumulated other comprehensive loss	$	(131	)	$	(9	)	$	(141	)

(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).

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Income Taxes - Net Operating Losses (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012
United States [Member]
Net operating losses:
Net operating losses	$ 2,393
Net operating losses, Expiration	2027
United States State [Member]
Net operating losses:
Net operating losses	1,648
Net operating losses, Expiration	Various
Canada [Member]
Net operating losses:
Net operating losses	6
Net operating losses, Expiration	2014
Australia [Member]
Net operating losses:
Net operating losses	94
Net operating losses, Expiration	Indefinite
Argentina [Member]
Net operating losses:
Net operating losses	$ 55
Net operating losses, Expiration	2013

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SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited)

12 Months Ended

Dec. 31, 2012

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited)

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)
2012
Oil and gas production revenues	$	6,226	$	1,322		$	4,554	$	1,575	$	2,751	$	519	$	—		$	16,947
Operating cost:
Depreciation, depletion, and amortization
Recurring(1)		1,984		580			924		460		912		225		—			5,085
Additional		—		1,883			—		—		—		—		43			1,926
Asset retirement obligation accretion		112		41			—		17		58		4		—			232
Lease operating expenses		1,386		458			410		215		315		184		—			2,968
Gathering and transportation		69		163			39		—		24		8		—			303
Production taxes(2)		279		42			—		11		451		34		—			817
Income tax		851		(466	)		1,527		262		614		22		—			2,810
		4,681		2,701			2,900		965		2,374		477		43			14,141
Results of operation	$	1,545	$	(1,379	)	$	1,654	$	610	$	377	$	42	$	(43	)	$	2,806
Amortization rate per boe	$	17.24	$	11.66		$	13.81	$	17.67	$	32.65	$	12.39	$	—		$	16.88
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 operation	$	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 operation	$	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

(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.

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)
2012
Acquisitions:
Proved	$	1,076	$	5	$	28		$	32	$	110	$	—	$	—	$	1,251
Unproved		2,329		—		—			—		26		—		—		2,355
Exploration		1,369		111		696			149		111		157		96		2,689
Development		4,465		762		394			915		837		161		2		7,536
Costs incurred(1)	$	9,239	$	878	$	1,118		$	1,096	$	1,084	$	318	$	98	$	13,831
(1) Includes capitalized interest and asset retirement costs as follows:
Capitalized interest	$	215	$	38	$	16		$	12	$	24	$	11	$	—	$	316
Asset retirement costs		473		245		—			207		89		18		—		1,032
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

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)
2012
Proved properties	$	40,163		$	13,477		$	7,165		$	6,319		$	8,401		$	2,706		$	152		$	78,383
Unproved properties		5,641			1,059			686			284			626			382			76			8,754
		45,804			14,536			7,851			6,603			9,027			3,088			228			87,137
Accumulated DD&A		(17,968	)		(8,899	)		(4,474	)		(2,478	)		(3,445	)		(1,562	)		(152	)		(38,978	)
	$	27,836		$	5,637		$	3,377		$	4,125		$	5,582		$	1,526		$	76		$	48,159
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

Costs Not Being Amortized

The following table sets forth a summary of oil and gas property costs not being amortized at December 31, 2012, 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		2012		2011		2010		2009 and Prior
	(In millions)
Property acquisition costs	$	6,998	$	3,558	$	981	$	2,146	$	313
Exploration and development		1,550		1,108		368		16		58
Capitalized interest		206		48		27		55		76
Total	$	8,754	$	4,714	$	1,376	$	2,217	$	447

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.

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.

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, 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
December 31, 2012		629,345			101,691			106,746			29,053			122,073			20,852			1,009,760			2,353,587			1,734,657			690,436			596,052			93,319			365,054			5,833,105			1,981,945
Proved undeveloped reserves:
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
December 31, 2012		263,957			82,908			17,288			34,808			28,399			3,857			431,217			832,320			403,227			205,055			1,074,018			18,985			97,496			2,631,101			869,734
Total proved reserves:
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
Purchase 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	)
Sale 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
Purchase 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	)
Sale 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
Extensions, discoveries and other additions		156,621			26,590			36,188			6,277			592			1,133			227,401			365,863			252,130			55,967			176,969			16,397			2,623			869,949			372,393
Purchase of minerals in-place		16,172			197			—			276			2,374			—			19,019			313,885			2,503			—			1,745			8,494			—			326,627			73,457
Revisions of previous estimates		(12,033	)		(7,146	)		(3,678	)		(66	)		(7,257	)		502			(29,678	)		(156,840	)		(1,443,989	)		(13,974	)		101			—			496			(1,614,206	)		(298,712	)
Production		(61,361	)		(8,083	)		(36,511	)		(10,571	)		(23,904	)		(4,666	)		(145,096	)		(312,600	)		(219,849	)		(129,468	)		(78,329	)		(21,029	)		(78,128	)		(839,403	)		(284,997	)
Sale of properties		(144	)		—			—			—			—			—			(144	)		(612	)		(422	)		—			—			—			—			(1,034	)		(316	)
Balance December 31, 2012		893,302			184,599			124,034			63,861			150,472			24,709			1,440,977			3,185,907			2,137,884			895,491			1,670,070			112,304			462,550			8,464,206			2,851,679

During 2012, Apache added 73 MMboe of estimated proved reserves through purchases of minerals in-place. The Company recorded 68 MMboe in connection with the acquisition of Cordillera. Other individually insignificant acquisitions added 6 MMboe across several regions. During 2012, Apache also added 372 MMboe from extensions, discoveries and other additions. In the U.S., the Company recorded 218 MMboe primarily associated with drilling successes in the Permian and Anadarko basins, which added 104 MMboe and 77 MMboe, respectively; 23 MMboe from appraisal drilling in the deepwater Gulf of Mexico; and 14 MMboe from various drilling programs in other U.S. regions. In Canada, additions of 69 MMboe were primarily a result of drilling activity for liquids-rich gas targets in the Kaybob field area and shallow oil drilling in Brownfield and Consort field areas. Egypt contributed 46 MMboe from exploration activity in the West Kalabsha, Matruh and Ras Kanayes concessions along with continued development of the Razzak and Abu Gharadig fields and several waterflood projects in the East Bahariya concession. Australia additions of 36 MMboe were primarily from two discoveries and two appraisal wells in the Carnarvon basin offshore Western Australia. Various drilling programs in Argentina and North Sea regions combined to contribute 5 MMboe.

Approximately 15 percent of Apache’s year-end 2012 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. 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.”

Driven by the significant decline in North America natural gas prices, a portion of our proved reserves fell below the threshold for economic development during 2012 and were removed from our proved reserves balance, resulting in negative revisions of 299 MMboe for the year.

Future Net Cash Flows

Future cash inflows as of December 31, 2012 and 2011 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)
2012
Cash inflows	$	84,060		$	20,512		$	16,210		$	20,823		$	16,732		$	3,010		$	161,347
Production costs		(27,230	)		(8,543	)		(2,126	)		(4,896	)		(8,451	)		(1,162	)		(52,408	)
Development costs		(6,768	)		(2,916	)		(1,756	)		(2,484	)		(3,053	)		(248	)		(17,225	)
Income tax expense		(12,740	)		(754	)		(4,246	)		(3,172	)		(3,163	)		(141	)		(24,216	)
Net cash flows		37,322			8,299			8,082			10,271			2,065			1,459			67,498
10 percent discount rate		(19,464	)		(4,472	)		(2,107	)		(6,361	)		(98	)		(443	)		(32,945	)
Discounted future net cash flows(1)	$	17,858		$	3,827		$	5,975		$	3,910		$	1,967		$	1,016		$	34,553
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

(1) Estimated future net cash flows before income tax expense, discounted at 10 percent per annum, totaled approximately $48.2 billion and $52.3 billion as of December 31, 2012 and 2011, respectively.

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

	For the Year Ended December 31,
	2012			2011			2010
	(In millions)
Sales, net of production costs	$	(12,589	)	$	(13,152	)	$	(9,152	)
Net change in prices and production costs		(1,941	)		12,167			13,006
Discoveries and improved recovery, net of related costs		6,742			6,751			5,147
Change in future development costs		(935	)		(2,250	)		(1,637	)
Previously estimated development costs incurred during the period		4,359			2,479			1,355
Revision of quantities		(4,065	)		(1,475	)		(1,905	)
Purchases of minerals in-place		1,181			2,139			7,794
Accretion of discount		5,234			4,161			2,439
Change in income taxes		2,711			(4,303	)		(4,535	)
Sales of properties		(3	)		(1,285	)		(3	)
Change in production rates and other		(2,088	)		273			182
	$	(1,394	)	$	5,505		$	12,691

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BUSINESS SEGMENT INFORMATION (Tables)

12 Months Ended

Dec. 31, 2012

Financial Segment Information

Financial information for each country is presented below:

	United States		Canada			Egypt		Australia		North Sea		Argentina		Other International			Total
	(In millions)
2012
Oil and gas production revenues	$	6,226	$	1,322		$	4,554	$	1,575	$	2,751	$	519	$	—		$	16,947
Operating Expenses:
Depreciation, depletion, and amortization
Recurring		2,056		594			925		466		914		228		—			5,183
Additional		—		1,883			—		—		—		—		43			1,926
Asset retirement obligation accretion		112		41			—		17		58		4		—			232
Lease operating expenses		1,386		458			410		215		315		184		—			2,968
Gathering and transportation		69		163			39		—		24		8		—			303
Taxes other than income		292		50			14		11		451		44		—			862
Operating Income (Loss)(1)	$	2,311	$	(1,867	)	$	3,166	$	866	$	989	$	51	$	(43	)		5,473
Other Income (Expense):
Other																		131
General and administrative																		(531	)
Merger, acquisitions & transition																		(31	)
Financing costs, net																		(165	)
Income Before Income Taxes																	$	4,877
Net Property and Equipment	$	28,552	$	6,640		$	5,151	$	5,312	$	5,927	$	1,621	$	77		$	53,280
Total Assets	$	31,175	$	7,142		$	7,311	$	6,280	$	6,874	$	1,835	$	120		$	60,737
Additions to Net Property and Equipment	$	9,586	$	1,096		$	1,153	$	1,581	$	1,104	$	337	$	98		$	14,955
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 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

(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. Canada’s operating loss for 2012 includes additional depletion of $1.9 billon to write-down the carrying value of oil and gas properties.

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Supplemental Oil and Gas Disclosures - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2012 MBbls MMBoe	Dec. 31, 2011 MBbls	Dec. 31, 2010 MBbls
Reserve Quantities [Line Items]
Anticipated Timing of Inclusion of Costs in Amortization Calculation	Five to ten years
Purchases of minerals in-place	73
Extensions, discoveries and other additions	372
Percentage of estimated proved developed reserves classified as proved not producing	15.00%
Proved reserve balance	(298,712)	(59,086)	(11,370)
United States [Member]
Reserve Quantities [Line Items]
Extensions, discoveries and other additions	218
Permian and GOM [Member]
Reserve Quantities [Line Items]
Extensions, discoveries and other additions	23
Other Us Regions [Member]
Reserve Quantities [Line Items]
Extensions, discoveries and other additions	14
Canada [Member]
Reserve Quantities [Line Items]
Extensions, discoveries and other additions	69
Egypt [Member]
Reserve Quantities [Line Items]
Extensions, discoveries and other additions	46
Australia [Member]
Reserve Quantities [Line Items]
Extensions, discoveries and other additions	36
Argentina and North Sea [ Member]
Reserve Quantities [Line Items]
Extensions, discoveries and other additions	5
Cordillera Energy Partners [Member]
Reserve Quantities [Line Items]
Purchases of minerals in-place	68
Other Acquisitions [Member]
Reserve Quantities [Line Items]
Purchases of minerals in-place	6
Permian Basin [Member]
Reserve Quantities [Line Items]
Extensions, discoveries and other additions	104
Anadarko Basin [Member]
Reserve Quantities [Line Items]
Extensions, discoveries and other additions	77

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SUPPLEMENTAL GUARANTOR INFORMATION

12 Months Ended

Dec. 31, 2012

SUPPLEMENTAL GUARANTOR INFORMATION

16.    SUPPLEMENTAL GUARANTOR INFORMATION

In December 1999, Apache Finance Canada Corporation (Apache Finance Canada) issued approximately $300 million of publicly-traded notes due in 2029. In May 2003, Apache Finance Canada issued an additional $350 million of publicly-traded notes due in 2015. Both 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, these 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.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

For the Year Ended December 31, 2012

	Apache Corporation			Apache Finance Canada			All Other Subsidiaries of Apache Corporation		Reclassifications & Eliminations			Consolidated
	(In millions)
REVENUES AND OTHER:
Oil and gas production revenues	$	4,237		$	—		$	12,710	$	—		$	16,947
Equity in net income (loss) of affiliates		1,523			(737	)		248		(1,034	)		—
Other		(80	)		69			146		(4	)		131
		5,680			(668	)		13,104		(1,038	)		17,078
OPERATING EXPENSES:
Depreciation, depletion, and amortization		1,391			—			5,718		—			7,109
Asset retirement obligation accretion		76			—			156		—			232
Lease operating expenses		957			—			2,011		—			2,968
Gathering and transportation		51			—			252		—			303
Taxes other than income		185			—			677		—			862
General and administrative		425			—			110		(4	)		531
Merger, acquisitions & transition		25			—			6		—			31
Financing costs, net		94			(20	)		91		—			165
		3,204			(20	)		9,021		(4	)		12,201
INCOME (LOSS) BEFORE INCOME TAXES		2,476			(648	)		4,083		(1,034	)		4,877
Provision (benefit) for income taxes		475			(159	)		2,560		—			2,876
NET INCOME (LOSS)		2,001			(489	)		1,523		(1,034	)		2,001
Preferred stock dividends		76			—			—		—			76
INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	1,925		$	(489	)	$	1,523	$	(1,034	)	$	1,925
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	1,803		$	(489	)	$	1,523	$	(1,034	)	$	1,803

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 (LOSS) BEFORE INCOME TAXES		5,109		377			6,477			(3,870	)		8,093
Provision (benefit) for income taxes		525		97			2,887			—			3,509
NET INCOME (LOSS)		4,584		280			3,590			(3,870	)		4,584
Preferred stock dividends		76		—			—			—			76
INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	4,508	$	280		$	3,590		$	(3,870	)	$	4,508
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	4,640	$	280		$	3,590		$	(3,870	)	$	4,640

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 (LOSS) BEFORE INCOME TAXES		3,266		99			4,180			(2,339	)		5,206
Provision (benefit) for income taxes		234		25			1,915			—			2,174
NET INCOME (LOSS)		3,032		74			2,265			(2,339	)		3,032
Preferred stock dividends		32		—			—			—			32
INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	3,000	$	74		$	2,265		$	(2,339	)	$	3,000
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	3,149	$	74		$	2,265		$	(2,339	)	$	3,149

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

For the Year Ended December 31, 2012

	Apache Corporation			Apache Finance Canada			All Other Subsidiaries of Apache Corporation			Reclassifications & Eliminations			Consolidated
	(In millions)
CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	$	2,357		$	(40	)	$	6,187		$	—		$	8,504
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property		(3,313	)		—			(5,468	)		—			(8,781	)
Additions to gas gathering, transmission, and processing facilities		(48	)		—			(702	)		—			(750	)
Acquisition of Cordillera		(2,666	)		—			—			—			(2,666	)
Equity investment in Yara Pilbara Holdings Pty Limited		—			—			(439	)		—			(439	)
Acquisitions, other		(66	)		—			(186	)		—			(252	)
Proceeds from sale of oil and gas properties		25			—			2			—			27
Investment in subsidiaries, net		(657	)		—			—			657			—
Other		(450	)		—			(113	)		—			(563	)
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES		(7,175	)		—			(6,906	)		657			(13,424	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Commercial paper, credit facility, and bank notes, net		502			—			47			—			549
Intercompany borrowings		—			—			697			(697	)		—
Fixed rate debt borrowings		4,978			—			—			—			4,978
Payments on fixed rate debt		(400	)		—			—			—			(400	)
Dividends paid		(332	)		—			—			—			(332	)
Other		29			35			(114	)		40			(10	)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		4,777			35			630			(657	)		4,785
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(41	)		(5	)		(89	)		—			(135	)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR		41			5			249			—			295
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	—		$	—		$	160		$	—		$	160

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 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 gas gathering, transmission, and processing facilities		—			—			(664	)		—			(664	)
Acquisition of Mobil North Sea		—			—			(1,246	)		—			(1,246	)
Acquisitions, other		(448	)		—			(119	)		—			(567	)
Proceeds from sales of oil and gas properties		204			—			218			—			422
Investment in and advances to subsidiaries, net		772			—			—			(772	)		—
Other		(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	)
Other		108			(7	)		(25	)		8			84
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		(1,125	)		(8	)		(786	)		772			(1,147	)
NET INCREASE (DECREASE) 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 PERIOD	$	41		$	5		$	249		$	—		$	295

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 gas 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		(72	)		—			(49	)		—			(121	)
NET CASH PROVIDED BY (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	)
Other		49			96			75			(131	)		89
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		6,706			98			812			(2,853	)		4,763
NET INCREASE (DECREASE) 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 PERIOD	$	6		$	—		$	128		$	—		$	134

CONDENSED CONSOLIDATING BALANCE SHEET

December 31, 2012

	Apache Corporation		Apache Finance Canada		All Other Subsidiaries of Apache Corporation			Reclassifications & Eliminations			Consolidated
	(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	—	$	—	$	160		$	—		$	160
Receivables, net of allowance		876		—		2,210			—			3,086
Inventories		95		—		813			—			908
Drilling advances		21		1		562			—			584
Derivative instruments		31		—		—			—			31
Prepaid assets and other		3,868		—		(3,675	)		—			193
		4,891		1		70			—			4,962
PROPERTY AND EQUIPMENT, NET		18,517		—		34,763			—			53,280
OTHER ASSETS:
Intercompany receivable, net		4,628		—		(2,917	)		(1,711	)		—
Equity in affiliates		21,047		934		97			(22,078	)		—
Goodwill, net		173		—		1,116			—			1,289
Deferred charges and other		152		1,002		1,052			(1,000	)		1,206
	$	49,408	$	1,937	$	34,181		$	(24,789	)	$	60,737
LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	639	$	1	$	2,163		$	(1,711	)	$	1,092
Current debt		912		—		78			—			990
Asset retirement obligation		471		—		7			—			478
Derivative instruments		96		—		20			—			116
Other current liabilities		893		3		1,964			—			2,860
		3,011		4		4,232			(1,711	)		5,536
LONG-TERM DEBT		10,706		647		2			—			11,355
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes		2,990		5		5,029			—			8,024
Asset retirement obligation		992		—		3,108			—			4,100
Other		378		250		763			(1,000	)		391
		4,360		255		8,900			(1,000	)		12,515
COMMITMENTS AND CONTINGENCIES SHAREHOLDERS’ EQUITY		31,331		1,031		21,047			(22,078	)		31,331
	$	49,408	$	1,937	$	34,181		$	(24,789	)	$	60,737

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
Current debt		400		—		31			—			431
Asset retirement obligation		434		—		13			—			447
Derivative instruments		76		—		37			—			113
Other current liabilities		614		5		2,305			—			2,924
		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

XML

Commitments and Contingencies - Additional Information (Detail)	1 Months Ended	12 Months Ended
	May 31, 2010 USD ($)	Dec. 31, 2012 USD ($) Contract	Dec. 31, 2012 AUD	Dec. 31, 2011 USD ($)	Dec. 31, 2010 USD ($)	May 29, 2009 AUD	Dec. 31, 2012 Alcoa [Member] USD ($) Contract	Dec. 31, 2012 Oswal [Member] USD ($)	Aug. 31, 2011 Phoenix [Member] acre	Jan. 31, 2012 Burrup Holdings Limited (Yara Pilbara Holdings Pty Limited ) [Member]	Jan. 31, 2012 Yara International [Member]
Contingencies And Commitments [Line Items]
Accrued liability for legal contingencies		$ 12,000,000
Damages sought by plaintiffs		100,000,000
Cost for the restoration of plaintiffs' property	87,000,000	61,000,000
Percentage of general partner interest acquired									75.00%
Percentage of limited partner interest acquired									75.00%
Area of Land									3,000
Maximum Expected contractual general damages under long term contracts							158,000,000	491,000,000
Number of Contract							2
Maximum expected contractual liquidated damages under long term contracts		5,700,000	200,000,000
Long term contracts unenforceable as penalty		2	2
Approximate percentage of natural gas volumes sold under long-term contracts that have liquidated damages provisions		90.00%	90.00%
Range of estimates for macroeconomic impact			300,000,000
Range of estimates for macroeconomic impact			2,500,000,000
Compensation related gas shortage			20,000,000
Pure economic losses			1,300,000,000
Property damage settlement amount			32,500,000
Maximum fine associated with the alleged offense						50,000
Validity of pipeline license		21 years	21 years
Percentage of combined ownership held by the plaintiff in the company		65.00%	65.00%
Percentage of acquisition										49.00%	51.00%
Maximum cost considered to be recognized for additional reserve		300,000
Undiscounted reserve for environmental remediation		104,000,000
Net rental expenses		$ 76,000,000		$ 64,000,000	$ 46,000,000
Lease Expiration		2035	2035

XML

Supplemental Guarantor Information - Supplemental Condensed Consolidating Balance Sheet (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
CURRENT ASSETS:
Cash and cash equivalents	$ 160	$ 295	$ 134	$ 2,048
Receivables, net of allowance	3,086	3,079
Inventories	908	655
Drilling advances	584	229
Derivative instruments	31	304
Prepaid assets and other	193	241
Total current assets	4,962	4,803
PROPERTY AND EQUIPMENT, NET	53,280	45,448	38,151
OTHER ASSETS:
Goodwill, net	1,289	1,114
Deferred charges and other	1,206	686
Total Assets	60,737	52,051	43,425
CURRENT LIABILITIES:
Accounts payable	1,092	1,048
Current debt	990	431
Asset retirement obligation	478	447
Derivative instruments	116	113
Other current liabilities	2,860	2,924
Total current liabilities	5,536	4,963
LONG-TERM DEBT	11,355	6,785
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes	8,024	7,197
Asset retirement obligation	4,100	3,440
Other	391	673
Total deferred credits other noncurrent liabilities	12,515	11,310
COMMITMENTS AND CONTINGENCIES
SHAREHOLDERS' EQUITY	31,331	28,993	24,377	15,779
Total liabilities and shareholders' equity	60,737	52,051
Apache Corporation [Member]
CURRENT ASSETS:
Cash and cash equivalents		41	6	647
Receivables, net of allowance	876	773
Inventories	95	51
Drilling advances	21	11
Derivative instruments	31	113
Prepaid assets and other	3,868	3,859
Total current assets	4,891	4,848
PROPERTY AND EQUIPMENT, NET	18,517	12,262
OTHER ASSETS:
Intercompany receivable, net	4,628	3,931
Equity in affiliates	21,047	20,214
Goodwill, net	173
Deferred charges and other	152	158
Total Assets	49,408	41,413
CURRENT LIABILITIES:
Accounts payable	639	609
Current debt	912	400
Asset retirement obligation	471	434
Derivative instruments	96	76
Other current liabilities	893	614
Total current liabilities	3,011	2,133
LONG-TERM DEBT	10,706	6,137
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes	2,990	2,622
Asset retirement obligation	992	936
Other	378	592
Total deferred credits other noncurrent liabilities	4,360	4,150
COMMITMENTS AND CONTINGENCIES
SHAREHOLDERS' EQUITY	31,331	28,993
Total liabilities and shareholders' equity	49,408	41,413
Apache Finance Canada [Member]
CURRENT ASSETS:
Cash and cash equivalents		5		2
Drilling advances	1
Total current assets	1	5
OTHER ASSETS:
Equity in affiliates	934	1,372
Deferred charges and other	1,002	1,002
Total Assets	1,937	2,379
CURRENT LIABILITIES:
Accounts payable	1	1
Other current liabilities	3	5
Total current liabilities	4	6
LONG-TERM DEBT	647	647
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes	5	5
Other	250	250
Total deferred credits other noncurrent liabilities	255	255
COMMITMENTS AND CONTINGENCIES
SHAREHOLDERS' EQUITY	1,031	1,471
Total liabilities and shareholders' equity	1,937	2,379
All Other Subsidiaries of Apache Corporation [Member]
CURRENT ASSETS:
Cash and cash equivalents	160	249	128	1,399
Receivables, net of allowance	2,210	2,306
Inventories	813	604
Drilling advances	562	218
Derivative instruments		191
Prepaid assets and other	(3,675)	(3,618)
Total current assets	70	(50)
PROPERTY AND EQUIPMENT, NET	34,763	33,186
OTHER ASSETS:
Intercompany receivable, net	(2,917)	(1,908)
Equity in affiliates	97	99
Goodwill, net	1,116	1,114
Deferred charges and other	1,052	526
Total Assets	34,181	32,967
CURRENT LIABILITIES:
Accounts payable	2,163	2,461
Current debt	78	31
Asset retirement obligation	7	13
Derivative instruments	20	37
Other current liabilities	1,964	2,305
Total current liabilities	4,232	4,847
LONG-TERM DEBT	2	1
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes	5,029	4,570
Asset retirement obligation	3,108	2,504
Other	763	831
Total deferred credits other noncurrent liabilities	8,900	7,905
COMMITMENTS AND CONTINGENCIES
SHAREHOLDERS' EQUITY	21,047	20,214
Total liabilities and shareholders' equity	34,181	32,967
Reclassifications & Eliminations [Member]
OTHER ASSETS:
Intercompany receivable, net	(1,711)	(2,023)
Equity in affiliates	(22,078)	(21,685)
Deferred charges and other	(1,000)	(1,000)
Total Assets	(24,789)	(24,708)
CURRENT LIABILITIES:
Accounts payable	(1,711)	(2,023)
Total current liabilities	(1,711)	(2,023)
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Other	(1,000)	(1,000)
Total deferred credits other noncurrent liabilities	(1,000)	(1,000)
COMMITMENTS AND CONTINGENCIES
SHAREHOLDERS' EQUITY	(22,078)	(21,685)
Total liabilities and shareholders' equity	$ (24,789)	$ (24,708)

XML

STATEMENT OF CONSOLIDATED SHAREHOLDERS' EQUITY (USD $) In Millions, unless otherwise specified	Total	Series D Preferred Stock [Member]	Common Stock [Member]	Paid-in Capital [Member]	Retained Earnings [Member]	Treasury Stock [Member]	Accumulated Other Comprehensive (Loss) [Member]
Balance at Dec. 31, 2009	$ 15,779		$ 215	$ 4,634	$ 11,437	$ (217)	$ (290)
NET INCOME	3,032				3,032
Postretirement, net of income tax benefit (expense)of $2, 7 and 5 for 2010, 2011 and 2012 respectively	(2)						(2)
Commodity hedges, net of tax benefit (expense) of $62, 66 and 35 for 2010, 2011 and 2012 respectively	151						151
Dividends:
Preferred	(32)				(32)
Common ($0.60,$0.60 and $0.68 per share for 2010, 2011 and 2012 respectively)	(214)				(214)
Mandatory convertible preferred stock issued	1,227	1,227
Common shares issued	4,163		24	3,969		170
Common stock activity, net	27		1	26
Treasury stock activity, net	12			1		11
Compensation expense	225			225
Other	9			9
Balance at Dec. 31, 2010	24,377	1,227	240	8,864	14,223	(36)	(141)
NET INCOME	4,584				4,584
Postretirement, net of income tax benefit (expense)of $2, 7 and 5 for 2010, 2011 and 2012 respectively	(1)						(1)
Commodity hedges, net of tax benefit (expense) of $62, 66 and 35 for 2010, 2011 and 2012 respectively	133						133
Dividends:
Preferred	(76)				(76)
Common ($0.60,$0.60 and $0.68 per share for 2010, 2011 and 2012 respectively)	(231)				(231)
Common stock activity, net	36		1	35
Treasury stock activity, net	6			2		4
Compensation expense	167			167
Other	(2)			(2)
Balance at Dec. 31, 2011	28,993	1,227	241	9,066	18,500	(32)	(9)
NET INCOME	2,001				2,001
Postretirement, net of income tax benefit (expense)of $2, 7 and 5 for 2010, 2011 and 2012 respectively	(2)						(2)
Commodity hedges, net of tax benefit (expense) of $62, 66 and 35 for 2010, 2011 and 2012 respectively	(120)						(120)
Dividends:
Preferred	(76)				(76)
Common ($0.60,$0.60 and $0.68 per share for 2010, 2011 and 2012 respectively)	(264)				(264)
Common shares issued	601		3	598
Common stock activity, net	(43)		1	(44)
Treasury stock activity, net	3			1		2
Compensation expense	238			238
Balance at Dec. 31, 2012	$ 31,331	$ 1,227	$ 245	$ 9,859	$ 20,161	$ (30)	$ (131)

XML

STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
NET INCOME	$ 2,001	$ 4,584	$ 3,032
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and postretirement benefit plan, net of tax	(2)	(1)	(2)
Commodity cash flow hedge activity, net of tax:
Reclassification of (gain) loss on settled derivative instruments	(199)	19	(106)
Change in fair value of derivative instruments	79	115	256
Derivative hedge ineffectiveness reclassified into earnings		(1)	1
Other Comprehensive income (Loss), Net of Tax, Total	(122)	132	149
COMPREHENSIVE INCOME	1,879	4,716	3,181
Preferred stock dividends	76	76	32
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON STOCK	$ 1,803	$ 4,640	$ 3,149

XML

RETIREMENT AND DEFERRED COMPENSATION PLANS

12 Months Ended

Dec. 31, 2012

RETIREMENT AND DEFERRED COMPENSATION PLANS

9.    RETIREMENT AND DEFERRED COMPENSATION PLANS

Apache Corporation provides retirement benefits to its U.S. employees through the use of multiple plans: a 401(k) savings plan, a money purchase retirement plan, a non-qualified 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, as defined, to the plan with the Company making matching contributions up to a maximum of 8 percent of each employee’s annual eligible compensation. In addition, the Company annually contributes 6 percent of each participating employee’s annual eligible compensation, as defined, to a money purchase retirement plan. The 401(k) savings plan and the money purchase retirement plan are subject to certain annually-adjusted, government-mandated restrictions that limit the amount of employee and Company contributions. For certain eligible employees, the Company also provides a non-qualified retirement/savings plan or a non-qualified restorative retirement savings plan that allows the deferral of up to 50 percent of each employee’s base 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 retirement savings plan and the non-qualified restorative retirement savings plan occurs at the rate of 20 percent for every completed 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 U.S. and International savings plans, the money purchase retirement plan, non-qualified retirement/savings plan, and non-qualified restorative retirement savings plan was $117 million, $93 million, and $80 million for 2012, 2011, and 2010, 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. Eligible 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.

The following tables set forth the benefit obligation, fair value of plan assets and funded status as of December 31, 2012, 2011, and 2010, 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.

	2012						2011						2010
	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	$	150		$	30		$	136		$	29		$	135		$	18
Service cost		5			4			5			3			5			2
Interest cost		7			1			7			1			7			1
Foreign currency exchange rate changes		7			—			(1	)		—			(4	)		—
Amendments		—			—			—			—			—			—
Actuarial losses (gains)		14			1			6			(2	)		(1	)		8
Effect of curtailment and settlements		—			—			—			—			—			—
Benefits paid		(6	)		(1	)		(3	)		(1	)		(6	)		—
Retiree contributions		—			—			—			—			—			—
Projected benefit obligation at end of year		177			35			150			30			136			29
Change in Plan Assets
Fair value of plan assets at beginning of year		145			—			135			—			118			—
Actual return on plan assets		14			—			4			—			14			—
Foreign currency exchange rates		6			—			(1	)		—			(3	)		—
Employer contributions		11			1			10			1			12			—
Benefits paid		(6	)		(1	)		(3	)		(1	)		(6	)		—
Retiree contributions		—			—			—			—			—			—
Fair value of plan assets at end of year		170			—			145			—			135			—
Funded status at end of year	$	(7	)	$	(35	)	$	(5	)	$	(30	)	$	(1	)	$	(29	)
Amounts recognized in Consolidated Balance Sheet
Current liability		—			(1	)		—			(1	)		—			(1	)
Non-current liability		(7	)		(34	)		(5	)		(29	)		(1	)		(28	)
	$	(7	)	$	(35	)	$	(5	)	$	(30	)	$	(1	)	$	(29	)
Pre-tax Amounts Recognized in Accumulated Other Comprehensive Income (Loss)
Accumulated (loss)		(32	)		(7	)		(25	)		(6	)		(15	)		(8	)
Prior service cost		—			—			—			—			—			—
Transition asset (obligation)		—			—			—			—			—			—
	$	(32	)	$	(7	)	$	(25	)	$	(6	)	$	(15	)	$	(8	)
Weighted Average Assumptions used as of December 31
Discount rate		4.30	%		3.43	%		4.70	%		4.04	%		5.40	%		4.93	%
Salary increases		4.60	%		N/A			4.60	%		N/A			5.00	%		N/A
Expected return on assets		4.70	%		N/A			4.85	%		N/A			6.25	%		N/A
Healthcare cost trend
Initial		N/A			7.25	%		N/A			7.50	%		N/A			8.00	%
Ultimate in 2022		N/A			5.00	%		N/A			5.00	%		N/A			5.00	%

As of December 31, 2012, 2011, and 2010, the accumulated benefit obligation for the pension plan was $139 million, $119 million, and $107 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
	2012			2012			2011
Asset Category
Equity securities:
U.K. quoted equities		17	%		16	%		17	%
Overseas quoted equities		33	%		33	%		31	%
Total equity securities		50	%		49	%		48	%
Debt securities:
U.K. Government bonds		30	%		30	%		30	%
U.K. corporate bonds		20	%		20	%		18	%
Debt securities		50	%		50	%		48	%
Cash		0	%		1	%		4	%
Total		100	%		100	%		100	%

The plan’s assets do not include any direct ownership of 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 3 — Derivative Instruments And Hedging Activities. 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, 2012:

	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)	$	28	$	—	$	—	$	28
Overseas quoted equities(2)		56		—		—		56
Total equity securities		84		—		—		84
Debt securities:
U.K. Government bonds(3)		51		—		—		51
U.K. corporate bonds(4)		34		—		—		34
Total debt securities		85		—		—		85
Cash		1		—		—		1
Fair value of plan assets	$	170	$	—	$	—	$	170

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

(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: 33 percent benchmarked against iBoxx Sterling Overall Gilt Index, with a performance target of 0.75 percent per annum over the benchmark over a rolling three-year period; and 67 percent against the FTSE Actuaries Government Securities Index-Linked Over 5 Years Index.

(4) This category comprises U.K. corporate bonds: 50 percent benchmarked against iBoxx Sterling Overall Non Gilt index with a performance target of 0.75 percent per annum over the benchmark over a rolling three-year period; and 50 percent benchmarked against the iBoxx Sterling Overall Non Gilt Index with a performance target of 0.75 percent per annum over the benchmark over a rolling five year period.

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.

(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: 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.

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

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 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, 2012, 2011, and 2010:

	2012						2011						2010
	Pension Benefits			Postretirement Benefits			Pension Benefits			Postretirement Benefits			Pension Benefits			Postretirement Benefits
	(In millions)
Component of Net Periodic Benefit Costs
Service cost	$	5		$	4		$	5		$	3		$	5		$	2
Interest cost		7			1			7			1			7			1
Expected return on assets		(7	)		—			(8	)		—			(8	)		—
Amortization of actuarial gain (loss)		1			—			—			—			1			—
Net periodic benefit cost	$	6		$	5		$	4		$	4		$	5		$	3
Weighted Average Assumptions used to determine Net Period Benefit Cost for the Years ended 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		—			7.50	%		—			8.00	%		—			7.50	%
Ultimate in 2017		—			5.00	%		—			5.00	%		—			5.00	%

Assumed health care cost trend rates affect 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	$	(1	)
Effect on postretirement benefit obligation		8		(6	)

Apache expects to contribute approximately $5 million to its pension plan and $1 million to its postretirement benefit plan in 2013. The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:

	Pension Benefits		Postretirement Benefits
	(In millions)
2013	$	5	$	1
2014		6		1
2015		7		2
2016		7		2
2017		6		3
Years 2018 – 2022		49		18

XML

Supplemental Oil and Gas Disclosures - Principal Sources of Change in Discounted Future Net Cash Flows (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Schedule Of Changes In Standardized Measure Of Discounted Future Net Cash Flows [Line Items]
Sales, net of production costs	$ (12,589)	$ (13,152)	$ (9,152)
Net change in prices and production costs	(1,941)	12,167	13,006
Discoveries and improved recovery, net of related costs	6,742	6,751	5,147
Change in future development costs	(935)	(2,250)	(1,637)
Previously estimated development costs incurred during the period	4,359	2,479	1,355
Revision of quantities	(4,065)	(1,475)	(1,905)
Purchases of minerals in-place	1,181	2,139	7,794
Accretion of discount	5,234	4,161	2,439
Change in income taxes	2,711	(4,303)	(4,535)
Sales of properties	(3)	(1,285)	(3)
Change in production rates and other	(2,088)	273	182
Change in the discounted future net cash flows, total	$ (1,394)	$ 5,505	$ 12,691

XML

Business Segment Information - Financial Segment Information (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Segment Reporting Information [Line Items]
Oil and gas production revenues	$ 16,947	$ 16,810	$ 12,183
Depreciation, depletion, and amortization
Recurring	5,183	4,095	3,083
Additional	1,926	109
Asset retirement obligation accretion	232	154	111
Lease operating expenses	2,968	2,605	2,032
Gathering and transportation	303	296	178
Taxes other than income	862	899	690
Operating Income (Loss)	5,473	8,652	6,089
Other Income (Expense):
Other	131	78	(91)
General and administrative	(531)	(459)	(380)
Merger, acquisitions & transition	(31)	(20)	(183)
Financing costs, net	(165)	(158)	(229)
INCOME BEFORE INCOME TAXES	4,877	8,093	5,206
Net Property and Equipment	53,280	45,448	38,151
Total Assets	60,737	52,051	43,425
Additions to Net Property and Equipment	14,955	11,919	19,056
United States [Member]
Segment Reporting Information [Line Items]
Oil and gas production revenues	6,226	6,103	4,300
Depreciation, depletion, and amortization
Recurring	2,056	1,684	1,163
Asset retirement obligation accretion	112	97	62
Lease operating expenses	1,386	1,167	924
Gathering and transportation	69	64	42
Taxes other than income	292	259	190
Operating Income (Loss)	2,311	2,832	1,919
Other Income (Expense):
Net Property and Equipment	28,552	21,038	19,069
Total Assets	31,175	23,499	21,326
Additions to Net Property and Equipment	9,586	3,854	10,371
Canada [Member]
Segment Reporting Information [Line Items]
Oil and gas production revenues	1,322	1,617	1,074
Depreciation, depletion, and amortization
Recurring	594	546	294
Additional	1,883
Asset retirement obligation accretion	41	26	23
Lease operating expenses	458	470	334
Gathering and transportation	163	165	75
Taxes other than income	50	51	35
Operating Income (Loss)	(1,867)	359	313
Other Income (Expense):
Net Property and Equipment	6,640	8,022	7,497
Total Assets	7,142	8,816	8,273
Additions to Net Property and Equipment	1,096	1,288	5,277
Egypt [Member]
Segment Reporting Information [Line Items]
Oil and gas production revenues	4,554	4,791	3,372
Depreciation, depletion, and amortization
Recurring	925	818	754
Lease operating expenses	410	398	298
Gathering and transportation	39	35	31
Taxes other than income	14	13	10
Operating Income (Loss)	3,166	3,527	2,279
Other Income (Expense):
Net Property and Equipment	5,151	4,923	4,726
Total Assets	7,311	6,656	6,036
Additions to Net Property and Equipment	1,153	1,015	1,569
Australia [Member]
Segment Reporting Information [Line Items]
Oil and gas production revenues	1,575	1,734	1,459
Depreciation, depletion, and amortization
Recurring	466	440	408
Asset retirement obligation accretion	17	10	9
Lease operating expenses	215	197	185
Taxes other than income	11	9	11
Operating Income (Loss)	866	1,078	846
Other Income (Expense):
Net Property and Equipment	5,312	4,194	3,495
Total Assets	6,280	4,681	3,831
Additions to Net Property and Equipment	1,581	1,140	925
North Sea [Member]
Segment Reporting Information [Line Items]
Oil and gas production revenues	2,751	2,091	1,606
Depreciation, depletion, and amortization
Recurring	914	409	304
Asset retirement obligation accretion	58	17	15
Lease operating expenses	315	208	168
Gathering and transportation	24	25	25
Taxes other than income	451	539	422
Operating Income (Loss)	989	893	672
Other Income (Expense):
Net Property and Equipment	5,927	5,737	1,970
Total Assets	6,874	6,600	2,362
Additions to Net Property and Equipment	1,104	4,175	620
Argentina [Member]
Segment Reporting Information [Line Items]
Oil and gas production revenues	519	474	372
Depreciation, depletion, and amortization
Recurring	228	198	160
Asset retirement obligation accretion	4	4	2
Lease operating expenses	184	165	123
Gathering and transportation	8	7	5
Taxes other than income	44	28	22
Operating Income (Loss)	51	72	60
Other Income (Expense):
Net Property and Equipment	1,621	1,512	1,336
Total Assets	1,835	1,766	1,537
Additions to Net Property and Equipment	337	374	274
Other International [Member]
Depreciation, depletion, and amortization
Additional	43	109
Operating Income (Loss)	(43)	(109)
Other Income (Expense):
Net Property and Equipment	77	22	58
Total Assets	120	33	60
Additions to Net Property and Equipment	$ 98	$ 73	$ 20

XML

Major Customers - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Shell Plc [Member]
Entity Wide Portfolio Carrying Amount, Major Customer [Line Items]
Entity wide revenue major customer percentage	20.00%	11.00%	15.00%
Vitol Group [Member]
Entity Wide Portfolio Carrying Amount, Major Customer [Line Items]
Entity wide revenue major customer percentage	13.00%

XML

Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2012	Jan. 31, 2013	Jun. 30, 2012
Entity Information [Line Items]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2012
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	FY
Trading Symbol	APA
Entity Registrant Name	APACHE CORP
Entity Central Index Key	0000006769
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		391,758,883
Entity Public Float			$ 34,382,410,237

XML

CAPITAL STOCK

12 Months Ended

Dec. 31, 2012

CAPITAL STOCK

10.    CAPITAL STOCK

Common Stock Outstanding

	2012		2011		2010
Balance, beginning of year		384,117,643		382,391,742		336,436,972
Shares issued for stock-based compensation plans:
Treasury shares issued		60,767		144,313		363,263
Common shares issued		1,189,693		1,581,588		1,864,498
Cordillera consideration		6,272,667		—		—
Equity offering (BP acquisitions)		—		—		26,450,000
Mariner consideration		—		—		17,277,009
Balance, end of year		391,640,770		384,117,643		382,391,742

Net Income per Common Share

A reconciliation of the components of basic and diluted net income per common share for the years ended December 31, 2012, 2011, and 2010 is presented in the table below.

	2012						2011						2010
	Income		Shares		Per Share		Income		Shares		Per Share		Income		Shares		Per Share
	(In millions, except per share amounts)
Basic:
Income attributable to common stock	$	1,925		389	$	4.95	$	4,508		384	$	11.75	$	3,000		352	$	8.53
Effect of Dilutive Securities:
Mandatory Convertible Preferred Stock	$	—		—			$	76		14			$	32		5
Stock options and other		—		2				—		2				—		2
Diluted:
Income attributable to common stock, including assumed conversions	$	1,925		391	$	4.92	$	4,584		400	$	11.47	$	3,032		359	$	8.46

The diluted EPS calculation excludes options and restricted shares that were anti-dilutive totaling 4.4 million, 2.5 million, and 2.3 million for the years ended December 31, 2012, 2011, and 2010, respectively. For the year ended December 31, 2012, 14.3 million shares related to the assumed conversion of the Mandatory Convertible Preferred Stock were also anti-dilutive.

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 April 30, 2012, in conjunction with Apache’s acquisition of Cordillera, the Company issued 6,272,667 shares of common stock to the sellers.

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

Common Stock Dividend

The Company paid common stock dividends of $0.66 per share in 2012, and $0.60 per share in 2011 and 2010.

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 2012, 2011, and 2010, stock-based compensation expensed was $167 million, $113 million, and $164 million ($119 million, $73 million, and $106 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:

	2012		2011		2010
	(In millions)
Stock-based compensation expensed:
General and administrative	$	104	$	69	$	98
Lease operating expenses		63		44		66
Stock-based compensation capitalized		67		42		71
	$	234	$	155	$	235

Stock Options

As of December 31, 2012, 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 (collectively, the Stock Option Plans), as well as the 2007 Omnibus Equity Compensation Plan (the 2007 Plan), and the 2011 Plan discussed above (together, 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. 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:

	2012
	Shares Under Option			Weighted Average Exercise Price
	(In thousands)
Outstanding, beginning of year		6,092		$	91.96
Granted		2,072			82.65
Exercised		(311	)		56.15
Forfeited or expired		(280	)		102.90
Outstanding, end of year(1)		7,573			90.47
Expected to vest(1)		2,900			96.23
Exercisable, end of year(1)		3,922			85.55
Available for grant, end of year		15,498
Weighted average fair value of options granted during the year	$	26.41

(1) As of December 31, 2012, the weighted average remaining contractual life for options outstanding, expected to vest, and exercisable is 6.7 years, 8.6 years, and 5.0 years, respectively. The aggregate intrinsic value of options outstanding, expected to vest, and exercisable at year-end was $19 million, $0, and $19 million, respectively. The weighted-average grant-date fair value of options granted during the years 2012, 2011, and 2010 was $26.41, $42.20, and $34.12, respectively.

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.

	2012			2011			2010
Expected volatility		34.94	%		34.47	%		35.02	%
Expected dividend yields		0.82	%		0.47	%		0.60	%
Expected term (in years)		5.5			5.5			5.5
Risk-free rate		0.78	%		1.95	%		2.31	%

The intrinsic value of options exercised during 2012, 2011, and 2010 was approximately $12 million, $50 million and $62 million, respectively. The cash received from exercise of options during 2012 was approximately $17 million. The Company realized an additional tax benefit of approximately $2 million for the amount of intrinsic value in excess of compensation cost recognized in 2012. As of December 31, 2012, the total compensation cost related to non-vested options not yet recognized was $90 million, which will be recognized over the remaining vesting period of the options.

Stock Appreciation Rights

For some non-executive employees, the Company issued stock appreciation rights (SARs) in lieu of stock options. The SARs vest ratably over four years and are settled in cash upon exercise throughout their ten-year life. In 2012, the Company issued 180,555 SARs with a weighted-average exercise price of $82.63 under the 2011 Omnibus Plan. Additionally, in 2003 and 2004 the Company issued 1,809,060 SARs with a weighted-average exercise price of $42.68 and 1,334,300 SARs with a weighted-average exercise price of $28.78, respectively, under the 2003 Stock Appreciation Rights Plan. As of December 31, 2012, a total of 583,688 SARs were outstanding, of which 413,582 were exercisable. 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 $36.20 based on the Black-Scholes valuation methodology using assumptions comparable to those discussed above. During 2012, 60,523 SARs were exercised. The aggregate of cash payments made to settle SARs was $3 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 2012, the Company awarded 1,219,886 restricted stock units at a weighted-average per-share market price of $85.67. In 2011 and 2010, the Company awarded 887,851 and 1,143,989 restricted stock units at a weighted-average per-share market price of $124.16 and $103.88, 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 2012, 2011, and 2010, $74 million ($48 million after tax), $76 million ($49 million after tax), and $73 million ($47 million after tax), respectively, was charged to expense. In 2012, 2011, and 2010, $25 million, $28 million, and $28 million was capitalized, respectively. As of December 31, 2012, there was $151 million of total unrecognized compensation cost related to 2,163,564 unvested restricted stock units. The weighted-average remaining life of unvested restricted stock units is approximately 1.4 years.

The fair value of the awards vested during 2012, 2011 and 2010 was approximately $114 million, $85 million, and $69 million, respectively. A summary of restricted stock activity for the year ended December 31, 2012, is presented below.

	Shares			Weighted- Average Grant- Date Fair Value
	(In thousands)
Non-vested at January 1, 2012		2,115		$	109.63
Granted		1,220			85.67
Vested		(1,053	)		107.76
Forfeited		(118	)		102.82
Non-vested at December 31, 2012		2,164			97.34

Conditional Restricted Stock Units

To provide long-term incentives for Apache employees to deliver competitive returns to the Company’s stockholders, in January 2012, 2011, and 2010 the Company granted conditional restricted stock units to eligible employees. 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. Three 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, pursuant to the 2007 Plan. In January 2010 eligible employees received initial conditional restricted stock unit awards totaling 541,440 units. Based on measurement of total shareholder return relative to the designated peer group at December 31, 2012, zero shares were awarded and all unvested conditional restricted stock units were cancelled.

• In November 2010 the Company’s Board of Directors approved the 2011 Performance Program, pursuant to the 2007 Plan. In January 2011 eligible employees received initial conditional restricted stock unit awards totaling 585,811 units. A total of 503,884 units were outstanding at December 31, 2012, from which a minimum of zero and a maximum of 1,259,710 units could be awarded.

• In January 2012 the Company’s Board of Directors approved the 2012 Performance Program, pursuant to the 2011 Plan. In January 2012 eligible employees received initial conditional restricted stock unit awards totaling 851,985 units. A total of 802,390 units were outstanding at December 31, 2012, from which a minimum of zero and a maximum of 2,005,975 units could be awarded.

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 2012, 2011, and 2010, $47 million ($31 million after tax), $12 million ($8 million after tax), and $7 million ($4 million after tax), respectively, was charged to expense. During 2012, 2011, and 2010, $21 million, $5 million, and $3 million was capitalized, respectively. As of December 31, 2012, there was $72 million of total unrecognized compensation cost related to 1,306,274 unvested conditional restricted stock units. The weighted-average remaining life of the unvested conditional restricted stock units is approximately 2.4 years.

	Shares			Weighted- Average Grant- Date Fair Value(1)
	(In thousands)
Non-vested at January 1, 2012		1,019		$	115.10
Granted		852			70.30
Vested		(1	)		100.81
Forfeited		(564	)		132.45
Non-vested at December 31, 2012		1,306			78.40

(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 2013 the Company’s Board of Directors approved the 2013 Performance Program, pursuant to the 2011 Plan, with terms similar to the 2012 Performance Program. Eligible employees received initial conditional restricted stock unit awards totaling 1,232,176 units, with the ultimate number of restricted stock units to be awarded ranging from zero to a maximum of 2,464,352 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. The interim target of $162 was not met by the end of 2010, and the related awards were cancelled. The $216 share price target was not met by the end of 2012, and all remaining awards under the 2008 Share Appreciation Program were cancelled.

• 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. Apache’s share price exceeded the interim $81 threshold for the 10-day requirement as of June 14, 2007. Apache’s share price exceeded the $108 threshold for the 10-day requirement as of February 29, 2008. Awards under the plan were payable in four equal annual installments to eligible employees remaining with the Company.

A summary of the number of shares contingently issuable as of December 31, 2012, 2011, and 2010 for each plan is presented in the table below:

	Shares subject to Conditional Grants
	2012			2011			2010
	(In thousands)
2008 Share Appreciation Program
Outstanding, beginning of year		1,372			1,485			2,592
Granted		—			—			25
Forfeited or cancelled		(1,372	)		(113	)		(1,132	)
Outstanding, end of year(1)		—			1,372			1,485
Weighted-average value of grants outstanding(2)	$	—		$	71.28		$	71.16
2005 Share Appreciation Plan
Outstanding, beginning of year		—			400			1,103
Issued(3)		—			(398	)		(678	)
Forfeited or cancelled		—			(2	)		(25	)
Outstanding, end of year		—			—			400
Weighted-average value of grants outstanding(4)	$	—		$	—		$	21.64

(1) Represents shares issuable upon target achievement and vesting of awards related to the $216 and $162 per share price goals of zero shares at December 31, 2012; 1,372,190 and zero shares, respectively, at December 31, 2011; and 1,485,210 and zero shares, respectively, at December 31, 2010.

(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 and 2010 was approximately $9 million and $18 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.

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 and $216 price targets of the 2008 Share Appreciation Program were not met prior to the end of the stated achievement periods, Apache recognized $27 million of unamortized expense and $14 million of unamortized capital costs on December 31, 2010, and $16 million of unamortized expense and $8 million of unamortized capital costs on December 31, 2012, respectively. The Company recognized total expense and capitalized costs for the 2008 Share Appreciation Program of $181 million and as of year-end 2012 had no unamortized cost remaining. As of March 2011, the Company had recognized $79 million of total expense and capitalized costs for the 2005 Share Appreciation Plan 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,
	2012		2011		2010
	(In millions)
2008 Share Appreciation Program
Compensation expense	$	22	$	8	$	49
Compensation expense, net of tax		14		5		31
Capitalized costs		12		5		27
2005 Share Appreciation Plan
Compensation expense		—	$	1	$	6
Compensation expense, net of tax		—		1		4
Capitalized costs		—		1		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).

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 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 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, subject to adjustment, 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, each subject to adjustment, 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.

XML

Capital Stock - Additional Information (Detail)	1 Months Ended		12 Months Ended							12 Months Ended															12 Months Ended										12 Months Ended				1 Months Ended	12 Months Ended
	Apr. 30, 2012	Jul. 31, 2010 USD ($)	Dec. 31, 2012 USD ($) D Y	Dec. 31, 2011 USD ($)	Dec. 31, 2010 USD ($)	Jul. 28, 2010 USD ($)	Feb. 29, 2008	Jun. 14, 2007	May 05, 2005 USD ($)	Dec. 31, 2012 Maximum [Member]	Dec. 31, 2012 Stock Options [Member] CAD	Dec. 31, 2012 Restricted Stock [Member] USD ($)	Dec. 31, 2011 Restricted Stock [Member] USD ($)	Dec. 31, 2010 Restricted Stock [Member] USD ($)	Dec. 31, 2012 Stock Appreciation Rights (SARs) [Member] USD ($)	Dec. 31, 2011 Stock Appreciation Rights (SARs) [Member] USD ($)	Dec. 31, 2010 Stock Appreciation Rights (SARs) [Member] USD ($)	Dec. 31, 2004 Stock Appreciation Rights (SARs) [Member] USD ($)	Dec. 31, 2003 Stock Appreciation Rights (SARs) [Member] USD ($)	Dec. 31, 2012 Conditional Restricted Stock [Member] USD ($) Y	Dec. 31, 2011 Conditional Restricted Stock [Member] USD ($)	Dec. 31, 2010 Conditional Restricted Stock [Member] USD ($)	Dec. 31, 2012 Non Employee Director [Member]	Nov. 10, 2010 Mariner Energy Inc [Member] USD ($)	Dec. 31, 2012 Convertible Preferred Stock [Member]	Dec. 31, 2012 Series A Preferred Stock [Member]	Dec. 31, 2012 Series D Preferred Stock [Member]	Dec. 31, 2012 Performance Program 2010 [Member]	Dec. 31, 2011 Performance Program 2011 [Member]	Dec. 31, 2012 Performance Program 2012 [Member]	Dec. 31, 2012 Performance Program 2013 [Member]	May 07, 2008 2008 SAR plan [Member] USD ($)	May 07, 2008 2005 Plan [Member] USD ($)	May 05, 2005 2005 SAR Plan [Member] USD ($)	Dec. 31, 2012 Share Appreciation Program 2008 [Member] USD ($)	Dec. 31, 2011 Share Appreciation Program 2008 [Member] USD ($)	Dec. 31, 2010 Share Appreciation Program 2008 [Member] USD ($)	Dec. 31, 2009 Share Appreciation Program 2008 [Member]	Mar. 31, 2011 Share Appreciation Plan 2005 [Member] USD ($)	Dec. 31, 2011 Share Appreciation Plan 2005 [Member] USD ($)	Dec. 31, 2010 Share Appreciation Plan 2005 [Member] USD ($)	Dec. 31, 2009 Share Appreciation Plan 2005 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options and restricted stock, anti-dilutive			4,400,000	2,500,000	2,300,000																				14,300,000
Common stock, shares issued			392,712,245	385,249,885		26,450,000																		17,280,000
Underwritten public offering price per share						$ 88
Underwritten public offering price value						$ 2,300,000,000
Closing price per share of Mariner common stock in Stock Exchange																								$ 110.25
Total value of stock consideration related to Mariner Merger																								1,900,000,000
Public offering of common stock underwritten	6,272,667
Dividends, Common stock			$ 0.66	$ 0.60	$ 0.60
Compensation expense			167,000,000	113,000,000	164,000,000										74,000,000	76,000,000	73,000,000			47,000,000	12,000,000	7,000,000													22,000,000	8,000,000	49,000,000			1,000,000	6,000,000
Stock-based compensation expenses, after tax			119,000,000	73,000,000	106,000,000							48,000,000	49,000,000	47,000,000						31,000,000	8,000,000	4,000,000
Period in which stock options become exercisable											4 years				4 years
Period in which stock options expires after grant date											10 years
Intrinsic value of options exercised			12,000,000	50,000,000	62,000,000
Cash received from exercise of options			17,000,000
Additional tax benefit for the amount of intrinsic value in excess of compensation cost			2,000,000
Total compensation cost related to non-vested options not yet recognized											90,000,000	151,000,000								72,000,000
Settlement period for SARs			10 years
Issuance of stock appreciation rights to non-executive employees															180,555			1,334,300	1,809,060
Weighted-average exercise price of SARs															$ 82.63			$ 28.78	$ 42.68
Nonvested shares outstanding												2,164,000	2,115,000		583,688					1,306,000	1,019,000								503,884	802,390					0	1,372,000	1,485,000	2,592,000			400,000	1,103,000
Nonvested shares exercisable															413,582
Weighted-average fair value of SARs outstanding															$ 36.20
SARs exercised															60,523
Aggregate cash payments made to settle SARs															3,000,000
Restricted stock units awarded												1,220,000	887,851	1,143,989						852,000																	25,000
Granted, Weighted Average Grant-Date Fair Value												$ 85.67	$ 124.16	$ 103.88						$ 70.30																$ 71.28	$ 71.16				$ 21.64
Restricted stock capitalized			67,000,000	42,000,000	71,000,000							25,000,000	28,000,000	28,000,000						21,000,000	5,000,000	3,000,000													12,000,000	5,000,000	27,000,000			1,000,000	3,000,000
Weighted-average remaining life of unvested restricted stock units			1.4																	2.4
Total fair value of restricted stock awards vested												114,000,000	85,000,000	69,000,000
Restricted stock units, vested (Percentage)																							50.00%
Percentage of additional vest on succeeding anniversaries				25.00%
Initial conditional restricted stock unit awards granted to eligible employees																												541,440	585,811	851,985	1,232,176
Number of restricted stock units awarded																												0
Minimum units awarded based upon measurement																													0	0	0
Maximum units awarded based upon measurement																													1,259,710	2,005,975	2,464,352
Range of ultimate number of restricted stock units awarded																													zero to 1,259,710 units	zero to 2,005,975 units	zero to 2,464,352 units
Consecutive trading days			30
Target to increase share price																																$ 216		$ 108
Interim target to increase share price									$ 81																								$ 162
Installments were awarded, if share price exceeded the interim goal							108	81
Recognized amortized expense																																			16,000,000		27,000,000
Total expense for share appreciation program																																			181,000,000				79,000,000
Preferred stock, shares authorized			10,000,000	10,000,000																							1,265,000
Shares designated as Series A Junior Participating Preferred Stock			25,000
Mandatory convertibles preferred stock, Series D		6.00%	6.00%																								6.00%
Series B Preferred Stock Description			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 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.
Dividend declared for Series A preferred stock																										One right for each 2.31 shares Adjusted for susequent stock divident and two for one stock Split
Purchase Price of series A Preferred stock per One - thousand share under rights Granted			100
Number of Days to exercise Right after Public announcement for entities acquiring more than 20% of outstanding shares																										10 days
Number of days To exercise right after commencement of offer for 30% or more outstanding shares			10 days
Price for exercising rights as above Percentage of market price of common share			50.00%
Percentage acquired by Apache shareholders on contingency			20.00%
Redemption of right shares			$ 0.01
Depositary shares in separate underwriting		25,300,000
Depositary shares each representing		1/20th interest	1/20th interest
Preferred stock, shares issued			1,265,000	1,265,000		1,265,000
Net proceeds of sale of mandatory convertible preferred stock		$ 1,200,000,000
Preferred stock, liquidation preference per share			$ 1,000	$ 1,000
Liquidation preference per share, depository share			50
Preferred Stock Dividend Payment Terms			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.
Conversion of preferred stock to equity shares ratio			9.164							11.364
Minimum Common Shares Issued To Convertible Preferred Stock Holders			11,600,000
Maximum Common Shares Issued To Convertible Preferred Stock			14,400,000

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Accumulated Other Comprehensive Income (Loss) - Components of Accumulated Other Comprehensive Income (Loss) (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
Components Of Accumulated Other Comprehensive Income Loss Line Items
Currency translation adjustment	$ (109)	[1]	$ (109)	[1]	$ (109)	[1]
Unrealized gain (loss) on derivatives (Note 3)	(6)		114		(19)
Unfunded pension and postretirement benefit plan	(16)		(14)		(13)
Accumulated other comprehensive loss	$ (131)		$ (9)		$ (141)

[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).

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STATEMENT OF CONSOLIDATED CASH FLOWS (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME	$ 2,001	$ 4,584	$ 3,032
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, and amortization	7,109	4,204	3,083
Asset retirement obligation accretion	232	154	111
Provision for deferred income taxes	677	1,246	952
Other	226	46	190
Changes in operating assets and liabilities:
Receivables	12	(759)	(496)
Inventories	(59)	(37)	35
Drilling advances	(343)	26	(28)
Deferred charges and other	61	27	(141)
Accounts payable	(100)	241	214
Accrued expenses	(1,142)	90	(309)
Deferred credits and noncurrent liabilities	(170)	131	83
NET CASH PROVIDED BY OPERATING ACTIVITIES	8,504	9,953	6,726
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property	(8,781)	(6,414)	(4,407)
Additions to gas gathering, transmission, and processing facilities	(750)	(664)	(515)
Acquisition of Cordillera Energy Partners III, LLC	(2,666)
Acquisition of Yara Pilbara Holdings Pty Limited	(439)
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	(252)	(567)	(126)
Proceeds from sale of oil and gas properties	27	422
Other, net	(563)	(176)	(121)
NET CASH USED IN INVESTING ACTIVITIES	(13,424)	(8,645)	(13,403)
CASH FLOWS FROM FINANCING ACTIVITIES:
Commercial paper, credit facility and bank notes, net	549	(925)	(32)
Fixed rate debt borrowings	4,978		2,470
Payments on fixed rate debt	(400)		(1,023)
Proceeds from issuance of common stock			2,258
Proceeds from issuance of mandatory convertible preferred stock			1,227
Dividends paid	(332)	(306)	(226)
Other	(10)	84	89
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES	4,785	(1,147)	4,763
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(135)	161	(1,914)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	295	134	2,048
CASH AND CASH EQUIVALENTS AT END OF PERIOD	160	295	134
SUPPLEMENTARY CASH FLOW DATA:
Interest paid, net of capitalized interest	146	156	187
Income taxes paid, net of refunds	$ 2,590	$ 1,686	$ 1,170

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OTHER CURRENT LIABILITIES

12 Months Ended

Dec. 31, 2012

OTHER CURRENT LIABILITIES

4.    OTHER CURRENT LIABILITIES

The following table provides detail of the Company’s other current liabilities at December 31, 2012 and 2011:

	December 31, 2012		December 31, 2011
	(In millions)
Accrued operating expenses	$	211	$	221
Accrued exploration and development		1,792		1,430
Accrued compensation and benefits		198		180
Accrued interest		160		135
Accrued income taxes		297		533
Accrued U.K. Petroleum Revenue Tax		53		284
Other		149		141
Total Other current liabilities	$	2,860	$	2,924

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DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

12 Months Ended

Dec. 31, 2012

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

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. Apache manages the variability in its cash flows by occasionally entering into derivative transactions 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.

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, 2012, Apache had derivative positions with 15 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, 2012, Apache had the following open crude oil derivative positions:

	Fixed-Price Swaps				Collars
Production Period	Mbbls(2)		Weighted Average Fixed Price(1)		Mbbls(2)		Weighted Average Floor Price(1)		Weighted Average Ceiling Price(1)
2013		40,292	$	97.31		5,701	$	82.84	$	111.63
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 NYMEX WTI Cushing Index and Platts Dated Brent. Approximately 50 percent of 2013 contracts are settled against Dated Brent.

(2) For 2013, fixed-price swaps of 38,320 Mbbls have not been designated as cash flow hedges, and changes in fair value are reflected directly in earnings. All other derivative positions have been designated as cash flow hedges.

As of December 31, 2012, Apache had the following open natural gas derivative positions which have all been designated as cash flow hedges:

	Fixed-Price Swaps				Collars
Production Period	MMBtu (in 000’s)		Weighted Average Fixed Price(1)		MMBtu (in 000’s)		Weighted Average Floor Price(1)		Weighted Average Ceiling Price(1)
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 against NYMEX Henry Hub.

Fair Value Measurements

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.

The following table presents the Company’s derivative assets and liabilities measured at fair value on a recurring basis:

	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, 2012
Assets:
Commodity Derivative Instruments		$—	$	48		$—	$	48	$	(15	)	$	33
Liabilities:
Commodity Derivative Instruments		—		131		—		131		(15	)		116
December 31, 2011
Assets:
Commodity Derivative Instruments		$—	$	428		$—	$	428	$	(96	)	$	332
Liabilities:
Commodity Derivative Instruments		—		250		—		250		(96	)		154

(1) The derivative fair values are based on analysis of each contract on a gross basis, even where the legal right of offset exists.

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, 2012		December 31, 2011
	(In millions)
Current Assets: Derivative instruments	$	31	$	304
Other Assets: Deferred charges and other		2		28
Total Assets	$	33	$	332
Current Liabilities: Derivative instruments	$	116	$	113
Noncurrent Liabilities: Other		—		41
Total Liabilities	$	116	$	154

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 Income	For the Year Ended December 31,
		2012			2011			2010
		(In millions)
Gain (loss) on cash flow hedges reclassified from accumulated other comprehensive loss	Oil and Gas Production Revenues	$	268		$	(13	)	$	165
Gain (loss) for ineffectiveness on cash flow hedges	Revenues and Other: Other	$	—		$	2		$	(2	)
Loss on derivatives not designated as cash flow hedges	Revenues and Other: Other	$	(79	)	$	—		$	—

Derivative Activity in Accumulated Other Comprehensive Income (Loss)

As of December 31, 2012, a portion of 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:

	For the Year Ended December 31,
	2012						2011						2010
	Before tax			After tax			Before tax			After tax			Before tax			After tax
	(In millions)
Unrealized gain (loss) on derivatives at beginning of year	$	145		$	114		$	(54	)	$	(19	)	$	(267	)	$	(170	)
Realized amounts reclassified into earnings		(268	)		(199	)		13			19			(165	)		(106	)
Net change in derivative fair value		113			79			188			115			376			256
Ineffectiveness reclassified into earnings		—			—			(2	)		(1	)		2			1
Unrealized gain (loss) on derivatives at end of period	$	(10	)	$	(6	)	$	145		$	114		$	(54	)	$	(19	)

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. Included in accumulated other comprehensive loss as of December 31, 2012, is a net loss of approximately $12 million ($7 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.

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SUPPLEMENTAL QUARTERLY FINANCIAL DATA

12 Months Ended

Dec. 31, 2012

SUPPLEMENTAL QUARTERLY FINANCIAL DATA

15.    SUPPLEMENTAL QUARTERLY FINANCIAL DATA (Unaudited)

	First		Second		Third		Fourth		Total
	(In millions, except per share amounts)
2012
Revenues and other	$	4,536	$	3,972	$	4,179	$	4,391	$	17,078
Expenses		3,739		3,616		3,999		3,723		15,077
Net income	$	797	$	356	$	180	$	668	$	2,001
Income attributable to common stock	$	778	$	337	$	161	$	649	$	1,925
Net income per common share(1):
Basic	$	2.02	$	0.87	$	0.41	$	1.66	$	4.95
Diluted	$	2.00	$	0.86	$	0.41	$	1.64	$	4.92
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

(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.

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ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

12 Months Ended

Dec. 31, 2012

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

11.    ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

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

	For the Year Ended December 31,
	2012			2011			2010
	(In millions)
Currency translation adjustment(1)	$	(109	)	$	(109	)	$	(109	)
Unrealized gain (loss) on derivatives (Note 3)		(6	)		114			(19	)
Unfunded pension and postretirement benefit plan		(16	)		(14	)		(13	)
Accumulated other comprehensive loss	$	(131	)	$	(9	)	$	(141	)

(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).

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Capital Stock - Risk-Free Rate Based on U S Treasury Yield Curve (Detail)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Share Based Payment Award Stock Options Valuation Assumptions [Line Items]
Expected volatility	34.94%	34.47%	35.02%
Expected dividend yields	0.82%	0.47%	0.60%
Expected term (in years)	5 years 6 months	5 years 6 months	5 years 6 months
Risk-free rate	0.78%	1.95%	2.31%

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INCOME TAXES

12 Months Ended

Dec. 31, 2012

INCOME TAXES

7.    INCOME TAXES

Income before income taxes is composed of the following:

	For the Year Ended December 31,
	2012		2011		2010
	(In millions)
U.S.	$	1,605	$	2,373	$	1,328
Foreign		3,272		5,720		3,878
Total	$	4,877	$	8,093	$	5,206

The total provision for income taxes consists of the following:

	For the Year Ended December 31,
	2012			2011		2010
	(In millions)
Current taxes:
Federal	$	(150	)	$	64	$	25
State		—			2		4
Foreign		2,349			2,197		1,193
		2,199			2,263		1,222
Deferred taxes:
Federal		596			656		431
State		10			17		7
Foreign		71			573		514
		677			1,246		952
Total	$	2,876		$	3,509	$	2,174

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,
	2012			2011			2010
	(In millions)
Income tax expense at U.S. statutory rate	$	1,707		$	2,833		$	1,822
State income tax, less federal benefit		6			12			6
Taxes related to foreign operations		773			568			245
Tax credits		(4	)		(15	)		(8	)
Non-deductible merger costs		—			—			6
Current and deferred taxes related to currency fluctuations		16			(66	)		111
Increase in U.K. tax rate		118			218			—
Net change in tax contingencies		(115	)		(6	)		(2	)
Increase in valuation allowance		355			8			12
All other, net		20			(43	)		(18	)
	$	2,876		$	3,509		$	2,174

The net deferred tax liability consists of the following:

	December 31,
	2012			2011
	(In millions)
Deferred tax assets:
Deferred income	$	(33	)	$	(89	)
Federal and state net operating loss carryforwards		(932	)		(236	)
Foreign net operating loss carryforwards		(61	)		(55	)
Tax credits		(78	)		(66	)
Accrued expenses and liabilities		(2	)		(90	)
Total deferred tax assets		(1,106	)		(536	)
Valuation allowance		419			60
Net deferred tax assets		(687	)		(476	)
Deferred tax liabilities:
Other		23			21
Depreciation, depletion and amortization		8,536			7,443
Total deferred tax liabilities		8,559			7,464
Net deferred income tax liability	$	7,872		$	6,988

The Company has recorded a valuation allowance against the net deferred tax asset in Canada. The deferred tax position in Canada changed from a net deferred tax liability as of December 31, 2011 to a net deferred tax asset as of December 31, 2012 on $1.9 billion in non-cash ceiling test write-downs. The Company has assessed the realizability of the net deferred tax asset in Canada and has concluded that it is more likely than not that the net deferred tax asset in Canada will not be realized based on current economic conditions.

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, 2012, the undistributed earnings of the foreign subsidiaries amounted to approximately $15.9 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, 2012, the Company had net operating losses as follows:

	December 31, 2012
	Amount		Expiration
	(In millions)
Net operating losses:
U.S. — Federal	$	2,393	2027
U.S. — State		1,648	Various
Canada		6	2014
Australia		94	Indefinite
Argentina		55	2013

The Company has a federal net operating loss carryforward of $2.4 billion. Included in the federal net operating loss carryforward is $543 million of federal net operating losses related to the merger with Mariner and $183 million of federal net operating losses related to the Cordillera acquisition. The Mariner and Cordillera net operating loss carryforwards are subject to annual limitations under Section 382 of the Internal Revenue Code. The Company also had $170 million of capital loss carryforwards in Canada, which have an indefinite carryover period.

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 net operating losses, Argentinian net operating losses, 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:

	2012			2011			2010
	(In millions)
Balance at beginning of year	$	97		$	110		$	123
Additions based on tax positions related to the current year		—			13			(1	)
Reductions for tax positions of prior years		(29	)		(4	)		(12	)
Settlements		(65	)		(22	)		—
Balance at end of year	$	3		$	97		$	110

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, 2012, 2011, and 2010 the Company recorded tax expense of $5 million, $6 million, and $12 million, respectively, for interest and penalties. As of December 31, 2012 and 2011, the Company had approximately $6 million and $42 million, respectively, accrued for payment of interest and penalties.

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. In 2012, the Company reached an agreement with IRS Administrative Appeals office regarding the audits of tax years 2004 through 2008. As a result of this agreement, the Company has reduced the unrecognized tax benefit by $65 million. 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. 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
U.S.	2004
Canada	2008
Egypt	1998
Australia	2008
U.K.	2011
Argentina	2005

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Income Taxes - Income Before Income Taxes (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Schedule Of Income Tax [Line Items]
United States	$ 1,605	$ 2,373	$ 1,328
Foreign	3,272	5,720	3,878
INCOME BEFORE INCOME TAXES	$ 4,877	$ 8,093	$ 5,206

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ASSET RETIREMENT OBLIGATION

12 Months Ended

Dec. 31, 2012

ASSET RETIREMENT OBLIGATION

5.    ASSET RETIREMENT OBLIGATION

The following table describes changes to the Company’s asset retirement obligation (ARO) liability for the years ended December 31, 2012 and 2011:

	2012			2011
	(In millions)
Asset retirement obligation at beginning of year	$	3,887		$	2,872
Liabilities incurred		592			419
Liabilities acquired		72			592
Liabilities settled		(550	)		(549	)
Accretion expense		232			154
Revisions in estimated liabilities		345			399
Asset retirement obligation at end of year		4,578			3,887
Less current portion		(478	)		(447	)
Asset retirement obligation, long-term	$	4,100		$	3,440

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 2012, the company recorded $592 million in abandonment liabilities resulting from Apache’s active exploration and development capital program. An additional $72 million of abandonment obligations were recognized on properties acquired during the year. An additional $345 million of abandonment costs were recognized for upward revisions to prior-year estimates of timing and costs, particularly in Australia and Canada.

Liabilities settled primarily relate to individual properties, platforms, and facilities plugged and abandoned during the period. Apache continues to have an active abandonment program that is focused in the U.S. Gulf of Mexico and Canada. The Company’s level of abandonment activity is expected to continue, and $478 million has been recorded as a current liability to reflect our estimated expenditures over the next 12 months.

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DEBT

12 Months Ended

Dec. 31, 2012

DEBT

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.

In April 2012 the Company issued $400 million principal amount of senior unsecured 1.75-percent notes maturing April 15, 2017, $1.1 billion principal amount of senior unsecured 3.25-percent notes maturing April 15, 2022, and $1.5 billion principal amount of senior unsecured 4.75-percent notes maturing April 15, 2043. The notes are redeemable, as a whole or in part, at Apache’s option, subject to a make-whole premium. The Company used the proceeds to fund the cash portion of the purchase price paid to acquire Cordillera, repay the $400 million 6.25-percent notes that matured on April 15, 2012, and for general corporate purposes.

In December 2012 the Company issued $1.2 billion principal amount of senior unsecured 2.625-percent notes maturing January 15, 2023 and $800 million principal amount of senior unsecured 4.25-percent notes maturing January 15, 2044. The notes are redeemable, as a whole or in part, at Apache’s option, subject to a make-whole premium. The Company used the proceeds to repay commercial paper borrowings and for general corporate purposes.

The following table presents the carrying value of the Company’s debt at December 31, 2012 and 2011:

	December 31,
	2012			2011
	(In millions)
U.S.:
Money market lines of credit	$	13		$	—
Commercial paper		489			—
6.25% notes due 2012(1)		—			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
1.75% notes due 2017(1)		400			—
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
3.25% notes due 2022(1)		1,100			—
2.625% notes due 2023(1)		1,200			—
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
4.75% notes due 2043(1)		1,500			—
4.25% notes due 2044(1)		800			—
7.375% debentures due 2047		150			150
7.625% debentures due 2096		150			150
		11,682			6,580
Subsidiary and other obligations:
Argentina overdraft lines of credit		69			31
Canada lines of credit		9			—
Apache Finance Canada 4.375% notes due 2015(1)		350			350
Notes due in 2016 and 2017		1			1
Apache Finance Canada 7.75% notes due 2029		300			300
		729			682
Debt before unamortized discount		12,411			7,262
Unamortized discount		(66	)		(46	)
Total debt	$	12,345		$	7,216
Current maturities	$	(990	)	$	(431	)
Long-term debt	$	11,355		$	6,785

(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.

Debt maturities as of December 31, 2012, excluding discounts, are as follows:

	(In millions)
2013	$	991
2014		—
2015		350
2016		1
2017		1,389
Thereafter		9,680
Total Debt, excluding discounts	$	12,411

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 fair value measurement.

	December 31, 2012				December 31, 2011
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)
Money market lines of credit	$	91	$	91	$	31	$	31
Commercial paper		489		489		—		—
Notes and debentures		11,765		13,340		7,185		8,673
Total Debt	$	12,345	$	13,920	$	7,216	$	8,704

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, 2012, $91 million was drawn on facilities in the U.S., Argentina, and Canada. As of December 31, 2011, $31 million was drawn on facilities in Argentina.

Unsecured Committed Bank Credit Facilities

As of December 31, 2012, the Company had unsecured committed revolving syndicated bank credit facilities totaling $3.3 billion, of which $1.0 billion matures in August 2016 and $2.3 billion matures in June 2017. The facilities consist of a $1.7 billion facility and a $1.0 billion facility for the U.S., a $300 million facility in Australia, and a $300 million facility in Canada. As of December 31, 2012, available borrowing capacity under the Company’s credit facilities was $2.8 billion. The committed credit facilities are used to support Apache’s commercial paper program.

On June 4, 2012, the Company entered into a new Global Credit Facility consisting of a $1.7 billion revolving syndicated bank credit facility for the U.S., a $300 million revolving syndicated bank credit facility for Australia, and a $300 million revolving syndicated bank credit facility for Canada, which replaced the Company’s existing syndicated bank credit facilities that were scheduled to mature in May 2013. The new facilities are scheduled to mature on June 4, 2017. There were no changes to the Company’s $1.0 billion U.S. credit facility that matures on August 12, 2016.

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 $1.7 billion credit facility also allows the Company to borrow under competitive auctions.

At December 31, 2012, the margin over LIBOR for committed loans was 0.875 percent on the $1.0 billion U.S. credit facility and 0.90 percent on each of the $1.7 billion U.S. credit facility, the $300 million Australian credit facility, and the $300 million Canadian credit facility. The Company also pays quarterly facility fees of 0.125 percent on the total amount of the $1.0 billion U.S. facility and 0.10 percent on the total amount of the other three facilities. The facility fees vary based upon the Company’s senior long-term debt rating.

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, 2012, the Company’s debt-to-capitalization ratio was 28 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 5 percent of the Company’s consolidated assets, or approximately $3.0 billion as of December 31, 2012. 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 the stated thresholds noted in the agreements or has any unpaid, non-appealable judgment against it in excess of the stated thresholds noted in the agreements.

The Company was in compliance with the terms of the credit facilities as of December 31, 2012.

Commercial Paper Program

In June 2012, the Company increased the size of its commercial paper program from $2.95 billion to $3.0 billion. This program generally enables Apache to borrow funds for up to 270 days at competitive interest rates. Apache’s 2012 weighted-average interest rate for commercial paper was 0.43 percent. If the Company is unable to issue commercial paper following a significant credit downgrade or dislocation in the market, the Company’s committed credit facilities are available as a 100-percent backstop. The commercial paper program is fully supported by available borrowing capacity under committed credit facilities, which expire in 2016 and 2017. As of December 31, 2012, the Company had $489 million in commercial paper outstanding. There was no outstanding commercial paper at December 31, 2011.

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,
	2012			2011			2010
	(In millions)
Interest expense	$	509		$	433		$	345
Amortization of deferred loan costs		7			5			17
Capitalized interest		(334	)		(263	)		(120	)
Interest income		(17	)		(17	)		(13	)
Financing costs, net	$	165		$	158		$	229

The Company has $66 million of debt discounts as of December 31, 2012, which will be charged to interest expense over the life of the related debt issuances. Discount amortization of $3 million, $2 million, and $2 million were recorded as interest expense in 2012, 2011, and 2010, respectively.

As of December 31, 2012 and 2011, the Company had approximately $118 million and $48 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.

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COMMITMENTS AND CONTINGENCIES

12 Months Ended

Dec. 31, 2012

COMMITMENTS AND CONTINGENCIES

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 $12 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, results of operations, or liquidity after consideration of recorded accruals. For material matters that Apache believes an unfavorable outcome is reasonably possible, the Company has disclosed the nature of the matter and a range of potential exposure, unless an estimate cannot be made at this time. 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, results of operations, or liquidity.

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 lawsuit 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 known as ASSUPA, 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. ASSUPA has recently asserted similar lawsuits and claims against numerous oil and gas producers relating to other geographic areas of Argentina, including claims against a Company subsidiary relating to the Austral basin. While the plaintiffs will seek to make all oil and gas companies jointly liable for each other’s actions in each of these lawsuits, Company subsidiaries will defend on an individual basis and attempt to require the plaintiffs to delineate damages by company. Company subsidiaries intend to defend each case vigorously. It is not certain exactly what the courts will do in these matters as the lawsuit relating to the Neuquén basin is the first of its kind. While it is possible Company subsidiaries may incur liabilities related to the environmental claims, no reasonable prediction can be made as the Company subsidiaries’ exposure related to these lawsuits is not currently determinable.

U.S. Royalty Litigation

In Foster v. Apache Corporation, Civil Action No. CIV-10-0573-HE, in the United States District Court for the Western District of Oklahoma, on August 20, 2012, the United States District Court for the Western District of Oklahoma denied plaintiff’s motion for class certification. The plaintiff filed a motion for reconsideration, which was denied, and has petitioned the United States Court of Appeals for the Tenth Circuit to accept an appeal of the District Court’s ruling denying class certification. Plaintiffs in the Foster case have asserted 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. Apache intends to vigorously defend against these claims.

In 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, following a class certification hearing in the United States District Court for the Southern District of Texas, the parties resolved the matter with no material impact on the Company’s financial position, results of operations, or liquidity, and with the settlement providing for denial of class certification and dismissal of the case.

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, regardless of the value of the underlying property. 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 opined that the cost to restore plaintiffs’ property would be approximately $61 million. Prior to trial the court granted Apache’s motions to dismiss the plaintiffs’ claims against Apache. Plaintiffs then settled with the other defendant in the case, BP America, Inc. (BP). BP has demanded that Apache indemnify it for the amount of its settlement with plaintiffs, which is not material to Apache. Apache has rejected BP’s indemnity claim and, further, Apache has demanded that Wagner Oil Company (which purchased Apache’s interest in the subject property) indemnify Apache from and against BP’s claim.

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. Plaintiff’s experts estimated the cost of remediation to be approximately $87 million, and plaintiffs claimed additional damages for canal restoration, among other things, all of which is disputed by the Company’s subsidiary. The parties have resolved the matter with no material impact on the Company’s financial position, results of operations, or liquidity, and with the settlement providing for certain limited remediation activities on the property.

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 pre-empted by federal law, and punitive and exemplary damages. Apache is one of numerous defendants. The District Court has granted defendants’ motion to dismiss plaintiffs’ claims, and plaintiffs have appealed the decision to the United States Court of Appeals for the Fifth Circuit. The overall exposure related to this lawsuit is not currently determinable. While an adverse judgment against Apache is possible, Apache intends to vigorously defend the case. A similar action filed by Comer et al. was previously dismissed in 2011.

Australia Gas Pipeline Force Majeure

In June 2008, 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, Cause No. 2009-79834, 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 Agreement (GSA), interest, and court costs. The Company has filed a motion to dismiss on the ground of forum non conveniens, which is pending.

On March 24, 2011, another customer, Alcoa of Australia 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. On June 20, 2012, the Supreme Court struck out Alcoa’s claim that the liquidated damages provisions under two long-term contracts are unenforceable as a penalty and also struck out Alcoa’s claim for damages for breach of statutory duty. The Company subsidiaries have filed an appeal in the Supreme Court of Western Australia Court of Appeal asking that Alcoa’s remaining tort claim for economic loss be dismissed or, alternatively, struck out. The appeal is pending.

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 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 vigorously pursued its defenses, resulting in the dismissal of the prosecution notice by the Magistrates Court of Western Australia on March 29, 2012.

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. That report, prepared by the inspectors in June 2009, was made public by the State government on May 24, 2012. Company subsidiaries disagree with the inspectors’ June 2009 conclusions. Two other government reports were not published by the State and are not referenced by the inspectors. The Magistrates Court of Western Australia subsequently ordered that both such reports could be released on the basis that the inspectors’ June 2009 report “came with some limitations” and the two other government reports “together were part and parcel if not the main reason or the only reason…certainly a significant contribution to the reason for the matter not proceeding to prosecution and trial.” In the first such report, the State’s senior investigator said in February 2009 that the prospects of a successful prosecution of Apache for failing to maintain the pipeline “would be slight.” In the second such report, the State’s lead corrosion expert concluded in July 2011 that Apache “had reasonable grounds to believe that the pipeline was in good repair” prior to the explosion.

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 of 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. On September 27, 2012, the court dismissed plaintiffs’ claims on various grounds, including for failure to state a claim upon which relief may be granted, while granting plaintiffs leave to amend their complaint within 30 days. On October 29, 2012, the plaintiffs filed an amended complaint. The exposure related to the re-filed 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 will examine its books and records and those of its subsidiaries and related entities to determine compliance with the Delaware Escheat Laws. The review is being 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. The exposure related to the audits is not currently determinable.

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. The Company has filed a motion to dismiss on the ground of forum non conveniens, which is pending. 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, except that the stay of the consolidated action has been lifted partially in order for the Texas court to consider the Company’s motions to dismiss on the ground of forum non conveniens.

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).

As part of the sale process described above, on January 31, 2012, a Company affiliate acquired a 49 percent interest in YPHPL, while Yara Australia Pty Ltd (Yara) increased its interest in YPHPL from 35 percent to 51 percent. Yara will operate the ammonia plant 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 YPHPL. YPHPL 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, delivery quantities, and term). The new gas supply agreement resolves counterclaims by Burrup Fertilisers against Apache and its affiliate in the Tap action. A Company subsidiary purchased Tap, which then modified its agreement to supply gas to the ammonia plant and resolved both Tap’s claims against Burrup Fertilisers and Burrup Fertilisers’ counterclaims against Tap in the Tap action. If Kufpec does 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 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, 2012, the Company had an undiscounted reserve for environmental remediation of approximately $104 million. Apache is not aware of any environmental claims existing as of December 31, 2012 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. 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 claim centered 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. The parties have resolved the matter on commercial terms with no material impact on the Company’s financial position, results of operations, or liquidity.

On May 25, 2011, a panel of the Bureau of Ocean Energy Management (BOEMRE, as it was then known) published a report dated May 23, 2011, and titled “OCS G-2580, Vermilion Block 380 Platform A, Incidents of Noncompliance.” 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 water as a result of the incident, and 13 workers were rescued after evacuating the platform. 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 Bureau of Safety and Environmental Enforcement (BSEE, successor to BOEMRE) issued several Incidents of Non-Compliance, which may provide the basis for the assessment of civil penalties against Mariner. The Company’s subsidiary Apache Deepwater LLC, which acquired Mariner effective November 10, 2010, filed an appeal on August 31, 2012, contesting several of the Incidents of Non-Compliance. It is management’s opinion that any loss arising from this matter will not have a material adverse effect on the Company’s financial position, results of operations, or liquidity.

Contractual Obligations

At December 31, 2012, contractual obligations for drilling rigs, purchase obligations, firm transportation agreements, and long-term operating leases are as follows:

Net Minimum Commitments	Total		2013		2014-2015		2016-2017		2018 & Beyond
	(In millions)
Drilling rig commitments(1)	$	896	$	602	$	289	$	3	$	2
Purchase obligations(2)		2,588		1,200		1,182		184		22
Firm transportation agreements(3)		763		148		264		134		217
Office and related equipment(4)		402		49		91		96		166
Other operating lease obligations(5)		754		209		316		205		24
Total Net Minimum Commitments	$	5,403	$	2,208	$	2,142	$	622	$	431

(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, LNG 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 vessels (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 $76 million, $64 million, and $46 million for 2012, 2011, and 2010, respectively.

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Income Taxes - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Income Tax [Line Items]
Write-down of oil and gas properties	$ 1,900,000,000
Undistributed earnings of the foreign subsidiaries	15,900,000,000
Tax expenses recorded	5,000,000	6,000,000	12,000,000
Accrued for payment of interest and penalties	6,000,000	42,000,000
Settlements	65,000,000	22,000,000
United States [Member]
Income Tax [Line Items]
Operating loss carryforwards	2,393,000,000
Mariner Energy Inc [Member]
Income Tax [Line Items]
Operating loss carryforwards	543,000,000
Cordillera Energy Partners [Member]
Income Tax [Line Items]
Operating loss carryforwards	183,000,000
Canada [Member]
Income Tax [Line Items]
Operating loss carryforwards	6,000,000
Capital loss carryforwards	$ 170,000,000

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Capital Stock - Restricted Stock (Detail) (Restricted Stock [Member], USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted Shares, nonvested, Beginning Balance, Shares	2,115,000
Granted, Shares	1,220,000	887,851	1,143,989
Vested, Shares	(1,053,000)
Forfeited or cancelled, Shares	(118,000)
Restricted Shares, nonvested, Ending Balance, Shares	2,164,000	2,115,000
Non-vested at January 1, 2012, Weighted Average Grant Date Fair Value	$ 109.63
Granted, Weighted Average Grant-Date Fair Value	$ 85.67	$ 124.16	$ 103.88
Vested, Weighted Average Grant-Date Fair Value	$ 107.76
Forfeited, Weighted Average Grant-Date Fair Value	$ 102.82
Non-vested at December 31, 2012, Weighted Average Grant Date Fair Value	$ 97.34	$ 109.63

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Income Taxes - Reconciliation of Beginning and Ending Amount of Unrecognized Tax Benefits (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Unrecognized Tax Benefits [Line Items]
Balance at beginning of year	$ 97	$ 110	$ 123
Additions based on tax positions related to the current year		13	(1)
Reductions for tax positions of prior years	(29)	(4)	(12)
Settlements	(65)	(22)
Balance at end of year	$ 3	$ 97	$ 110

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Supplemental Oil and Gas Disclosures - Unaudited Information of Future Net Cash Flows for Oil and Gas Reserves, Net of Income Tax Expense (Parenthetical) (Detail) (USD $) In Billions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Schedule Of Changes In Standardized Measure Of Discounted Future Net Cash Flows [Line Items]
Estimated future net cash flow before income tax expenses	10.00%
Total estimated future net cash flows before income tax expense discounted at 10 percent per annum	$ 48.2	$ 52.3

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Income Taxes - Net Deferred Tax Liability (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Deferred tax assets:
Deferred income	$ (33)	$ (89)
Federal and state net operating loss carryforwards	(932)	(236)
Foreign net operating loss carryforwards	(61)	(55)
Tax credits	(78)	(66)
Accrued expenses and liabilities	(2)	(90)
Total deferred tax assets	(1,106)	(536)
Valuation allowance	419	60
Net deferred tax assets	(687)	(476)
Deferred tax liabilities:
Other	23	21
Depreciation, depletion and amortization	8,536	7,443
Total deferred tax liabilities	8,559	7,464
Net deferred income tax liability	$ 7,872	$ 6,988

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Business Segment Information - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2012 Country
Segment Reporting Information [Line Items]
Production in number of countries	6

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CAPITAL STOCK (Tables)

12 Months Ended

Dec. 31, 2012

Common Stock Outstanding

Common Stock Outstanding

	2012		2011		2010
Balance, beginning of year		384,117,643		382,391,742		336,436,972
Shares issued for stock-based compensation plans:
Treasury shares issued		60,767		144,313		363,263
Common shares issued		1,189,693		1,581,588		1,864,498
Cordillera consideration		6,272,667		—		—
Equity offering (BP acquisitions)		—		—		26,450,000
Mariner consideration		—		—		17,277,009
Balance, end of year		391,640,770		384,117,643		382,391,742

Net Income Per Common Share

A reconciliation of the components of basic and diluted net income per common share for the years ended December 31, 2012, 2011, and 2010 is presented in the table below.

	2012						2011						2010
	Income		Shares		Per Share		Income		Shares		Per Share		Income		Shares		Per Share
	(In millions, except per share amounts)
Basic:
Income attributable to common stock	$	1,925		389	$	4.95	$	4,508		384	$	11.75	$	3,000		352	$	8.53
Effect of Dilutive Securities:
Mandatory Convertible Preferred Stock	$	—		—			$	76		14			$	32		5
Stock options and other		—		2				—		2				—		2
Diluted:
Income attributable to common stock, including assumed conversions	$	1,925		391	$	4.92	$	4,584		400	$	11.47	$	3,032		359	$	8.46

Description of Stock Based Compensation Plans and Related Costs

based on the nature of each employee’s activities. A description of the Company’s stock-based compensation plans and related costs follows:

	2012		2011		2010
	(In millions)
Stock-based compensation expensed:
General and administrative	$	104	$	69	$	98
Lease operating expenses		63		44		66
Stock-based compensation capitalized		67		42		71
	$	234	$	155	$	235

Summary of Stock Options Issued Under Stock Option Plans

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:

	2012
	Shares Under Option			Weighted Average Exercise Price
	(In thousands)
Outstanding, beginning of year		6,092		$	91.96
Granted		2,072			82.65
Exercised		(311	)		56.15
Forfeited or expired		(280	)		102.90
Outstanding, end of year(1)		7,573			90.47
Expected to vest(1)		2,900			96.23
Exercisable, end of year(1)		3,922			85.55
Available for grant, end of year		15,498
Weighted average fair value of options granted during the year	$	26.41

(1) As of December 31, 2012, the weighted average remaining contractual life for options outstanding, expected to vest, and exercisable is 6.7 years, 8.6 years, and 5.0 years, respectively. The aggregate intrinsic value of options outstanding, expected to vest, and exercisable at year-end was $19 million, $0, and $19 million, respectively. The weighted-average grant-date fair value of options granted during the years 2012, 2011, and 2010 was $26.41, $42.20, and $34.12, respectively.

Risk-Free Rate Based on the U S Treasury Yield Curve

The risk-free rate is based on the U.S. Treasury yield curve in effect at the time of grant.

	2012			2011			2010
Expected volatility		34.94	%		34.47	%		35.02	%
Expected dividend yields		0.82	%		0.47	%		0.60	%
Expected term (in years)		5.5			5.5			5.5
Risk-free rate		0.78	%		1.95	%		2.31	%

Restricted Stock

$114 million, $85 million, and $69 million, respectively. A summary of restricted stock activity for the year ended December 31, 2012, is presented below.

	Shares			Weighted- Average Grant- Date Fair Value
	(In thousands)
Non-vested at January 1, 2012		2,115		$	109.63
Granted		1,220			85.67
Vested		(1,053	)		107.76
Forfeited		(118	)		102.82
Non-vested at December 31, 2012		2,164			97.34

Conditional Restricted Stock

conditional restricted stock units. The weighted-average remaining life of the unvested conditional restricted stock units is approximately 2.4 years.

	Shares			Weighted- Average Grant- Date Fair Value(1)
	(In thousands)
Non-vested at January 1, 2012		1,019		$	115.10
Granted		852			70.30
Vested		(1	)		100.81
Forfeited		(564	)		132.45
Non-vested at December 31, 2012		1,306			78.40

(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.

Number of Shares Contingently Issuable

A summary of the number of shares contingently issuable as of December 31, 2012, 2011, and 2010 for each plan is presented in the table below:

	Shares subject to Conditional Grants
	2012			2011			2010
	(In thousands)
2008 Share Appreciation Program
Outstanding, beginning of year		1,372			1,485			2,592
Granted		—			—			25
Forfeited or cancelled		(1,372	)		(113	)		(1,132	)
Outstanding, end of year(1)		—			1,372			1,485
Weighted-average value of grants outstanding(2)	$	—		$	71.28		$	71.16
2005 Share Appreciation Plan
Outstanding, beginning of year		—			400			1,103
Issued(3)		—			(398	)		(678	)
Forfeited or cancelled		—			(2	)		(25	)
Outstanding, end of year		—			—			400
Weighted-average value of grants outstanding(4)	$	—		$	—		$	21.64

(1) Represents shares issuable upon target achievement and vesting of awards related to the $216 and $162 per share price goals of zero shares at December 31, 2012; 1,372,190 and zero shares, respectively, at December 31, 2011; and 1,485,210 and zero shares, respectively, at December 31, 2010.

(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 and 2010 was approximately $9 million and $18 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.

Summary of Amounts Recognized as Expense and Capitalized Cost for Each Plan

Plan 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,
	2012		2011		2010
	(In millions)
2008 Share Appreciation Program
Compensation expense	$	22	$	8	$	49
Compensation expense, net of tax		14		5		31
Capitalized costs		12		5		27
2005 Share Appreciation Plan
Compensation expense		—	$	1	$	6
Compensation expense, net of tax		—		1		4
Capitalized costs		—		1		3

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Other Current Liabilities - Details of Other Current Liabilities (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Schedule Of Accrued Liabilities [Line Items]
Accrued operating expenses	$ 211	$ 221
Accrued exploration and development	1,792	1,430
Accrued compensation and benefits	198	180
Accrued interest	160	135
Accrued income taxes	297	533
Accrued U.K. Petroleum Revenue Tax	53	284
Other	149	141
Total Other current liabilities	$ 2,860	$ 2,924

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BUSINESS SEGMENT INFORMATION

12 Months Ended

Dec. 31, 2012

BUSINESS SEGMENT INFORMATION

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, 2012, the Company had production in six countries: the United States, Canada, Egypt, Australia, offshore the United Kingdom (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)
2012
Oil and gas production revenues	$	6,226	$	1,322		$	4,554	$	1,575	$	2,751	$	519	$	—		$	16,947
Operating Expenses:
Depreciation, depletion, and amortization
Recurring		2,056		594			925		466		914		228		—			5,183
Additional		—		1,883			—		—		—		—		43			1,926
Asset retirement obligation accretion		112		41			—		17		58		4		—			232
Lease operating expenses		1,386		458			410		215		315		184		—			2,968
Gathering and transportation		69		163			39		—		24		8		—			303
Taxes other than income		292		50			14		11		451		44		—			862
Operating Income (Loss)(1)	$	2,311	$	(1,867	)	$	3,166	$	866	$	989	$	51	$	(43	)		5,473
Other Income (Expense):
Other																		131
General and administrative																		(531	)
Merger, acquisitions & transition																		(31	)
Financing costs, net																		(165	)
Income Before Income Taxes																	$	4,877
Net Property and Equipment	$	28,552	$	6,640		$	5,151	$	5,312	$	5,927	$	1,621	$	77		$	53,280
Total Assets	$	31,175	$	7,142		$	7,311	$	6,280	$	6,874	$	1,835	$	120		$	60,737
Additions to Net Property and Equipment	$	9,586	$	1,096		$	1,153	$	1,581	$	1,104	$	337	$	98		$	14,955
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 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

(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. Canada’s operating loss for 2012 includes additional depletion of $1.9 billon to write-down the carrying value of oil and gas properties.

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ACQUISITIONS AND DIVESTITURES (Tables)

12 Months Ended

Dec. 31, 2012

Pro- Forma Information for Company as if Acquisition of Properties

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, 2010:

	For the Year  Ended December 31, 2010
	(In millions, except per share amounts)
Revenues and Other	$	13,780
Net Income (Loss)	$	3,364
Preferred Stock Dividends		76
Income (Loss) Attributable to Common Stock	$	3,288
Net Income (Loss) per Common Share — Basic	$	8.62
Net Income (Loss) per Common Share — Diluted	$	8.52

Two Thousand Eleven Acquisitions [Member]

Assets Acquired and Liabilities Assumed as of Acquisition Date

The transaction was accounted for using the acquisition method of accounting. The following table summarizes the final estimates of the assets acquired and liabilities assumed in the acquisition.

	(In millions)
Current assets	$	219
Proved properties		2,341
Unproved properties		476
Gathering, transmission, and processing facilities		338
Goodwill(1)		84
Total assets acquired	$	3,458
Current liabilities		148
Asset retirement obligation		517
Deferred income tax liabilities		1,546
Other long-term obligations		1
Total liabilities assumed	$	2,212
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.

Two Thousand Twelve Acquisitions [Member]

Assets Acquired and Liabilities Assumed as of Acquisition Date

The following table summarizes the final estimates of the assets acquired and liabilities assumed in the acquisition.

	(In millions)
Current assets	$	39
Proved properties		1,040
Unproved properties		2,299
Gathering, transmission, and processing facilities		1
Goodwill(1)		173
Deferred tax asset		64
Total assets acquired	$	3,616
Current liabilities		88
Deferred income tax liabilities		237
Other long-term obligations		5
Total liabilities assumed	$	330
Net assets acquired	$	3,286

(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.

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Supplemental Oil and Gas Disclosures - Revenue and Direct Cost Information Relating to Company's Oil and Gas Exploration and Production Activities (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Oil and gas production revenues	$ 16,947		$ 16,810		$ 12,183
Depreciation, depletion, and amortization
Recurring	5,085	[1]	4,024	[1]	3,028	[1]
Additional	1,926		109
Asset retirement obligation accretion	232		154		111
Lease operating expenses	2,968		2,605		2,032
Gathering and transportation	303		296		178
Production taxes	817	[2]	865	[2]	656	[2]
Income tax	2,810		3,730		2,497
Oil and gas properties production expense	14,141		11,783		8,502
Results of operation	2,806		5,027		3,681
Amortization rate per boe	16.88		13.97		11.92
United States [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Oil and gas production revenues	6,226		6,103		4,300
Depreciation, depletion, and amortization
Recurring	1,984	[1]	1,634	[1]	1,126	[1]
Asset retirement obligation accretion	112		97		62
Lease operating expenses	1,386		1,167		924
Gathering and transportation	69		64		42
Production taxes	279	[2]	255	[2]	177	[2]
Income tax	851		1,025		699
Oil and gas properties production expense	4,681		4,242		3,030
Results of operation	1,545		1,861		1,270
Amortization rate per boe	17.24		15.55		13.23
Canada [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Oil and gas production revenues	1,322		1,617		1,074
Depreciation, depletion, and amortization
Recurring	580	[1]	537	[1]	287	[1]
Additional	1,883
Asset retirement obligation accretion	41		26		23
Lease operating expenses	458		470		334
Gathering and transportation	163		165		75
Production taxes	42	[2]	44	[2]	31	[2]
Income tax	(466)		95		82
Oil and gas properties production expense	2,701		1,337		832
Results of operation	(1,379)		280		242
Amortization rate per boe	11.66		10.44		8.13
Egypt [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Oil and gas production revenues	4,554		4,791		3,372
Depreciation, depletion, and amortization
Recurring	924	[1]	818	[1]	754	[1]
Lease operating expenses	410		398		298
Gathering and transportation	39		35		31
Income tax	1,527		1,699		1,099
Oil and gas properties production expense	2,900		2,950		2,182
Results of operation	1,654		1,841		1,190
Amortization rate per boe	13.81		11.63		11.05
Australia [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Oil and gas production revenues	1,575		1,734		1,459
Depreciation, depletion, and amortization
Recurring	460	[1]	435	[1]	403	[1]
Asset retirement obligation accretion	17		10		9
Lease operating expenses	215		197		185
Production taxes	11	[2]	9	[2]	11	[2]
Income tax	262		325		255
Oil and gas properties production expense	965		976		863
Results of operation	610		758		596
Amortization rate per boe	17.67		16.59		13.38
North Sea [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Oil and gas production revenues	2,751		2,091		1,606
Depreciation, depletion, and amortization
Recurring	912	[1]	405	[1]	301	[1]
Asset retirement obligation accretion	58		17		15
Lease operating expenses	315		208		168
Gathering and transportation	24		25		25
Production taxes	451	[2]	538	[2]	423	[2]
Income tax	614		557		337
Oil and gas properties production expense	2,374		1,750		1,269
Results of operation	377		341		337
Amortization rate per boe	32.65		20.21		14.42
Argentina [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Oil and gas production revenues	519		474		372
Depreciation, depletion, and amortization
Recurring	225	[1]	195	[1]	157	[1]
Asset retirement obligation accretion	4		4		2
Lease operating expenses	184		165		123
Gathering and transportation	8		7		5
Production taxes	34	[2]	19	[2]	14	[2]
Income tax	22		29		25
Oil and gas properties production expense	477		419		326
Results of operation	42		55		46
Amortization rate per boe	12.39		10.87		9.56
Other International [Member]
Depreciation, depletion, and amortization
Additional	43		109
Oil and gas properties production expense	43		109
Results of operation	$ (43)		$ (109)

[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.

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Derivative Instruments and Hedging Activities - Commodity Derivative Activity Recorded in Statement of Consolidated Operations (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Oil and Gas Production Revenues [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gain (loss) on cash flow hedges reclassified from accumulated other comprehensive loss	$ 268	$ (13)	$ 165
Revenues and Other [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Gain (loss) for ineffectiveness on cash flow hedges		2	(2)
Loss on derivatives not designated as cash flow hedges	$ (79)

XML

Supplemental Guarantor Information - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012
Notes Due 2029 [Member]
Condensed Financial Statements, Captions [Line Items]
Publicly traded notes	$ 300
Publicly-traded notes maturity date	Dec. 31, 2029
Notes Due 2015 [Member]
Condensed Financial Statements, Captions [Line Items]
Publicly traded notes	$ 350
Publicly-traded notes maturity date	Dec. 31, 2015

XML

Acquisitions and Divestitures - Additional Information (Detail) (USD $)	1 Months Ended		12 Months Ended							12 Months Ended		12 Months Ended					12 Months Ended			12 Months Ended
	Apr. 30, 2012 acre	Jul. 31, 2010	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Nov. 10, 2010	Aug. 10, 2010	Jul. 28, 2010	Jul. 20, 2010 Agreement	Dec. 31, 2012 Senior Unsecured Debt [Member]	Jan. 31, 2012 Yara International [Member]	Dec. 31, 2012 Burrup Holdings Limited (Yara Pilbara Holdings Pty Limited ) [Member]	Dec. 31, 2010 Gulf of Mexico, Devon [Member]	Aug. 10, 2010 BP's Oil And Gas Operations [Member]	Oct. 08, 2010 Western Canada Sedimentary Basin [Member]	Nov. 04, 2010 Western Desert, Egypt [Member]	Dec. 31, 2012 Bp Acquisitions [Member]	Dec. 31, 2010 Bp Acquisitions [Member]	Jul. 31, 2010 Bp Acquisitions [Member]	Dec. 31, 2010 Mariner Energy Inc [Member]	Nov. 10, 2010 Mariner Energy Inc [Member]
Business Acquisition [Line Items]
Cordillera's properties include approximately 312,000 net acres	312,000
Depositary shares in separate underwriting	6,272,667																25,300,000
Cash paid to seller			$ 2,700,000,000			$ 2,700,000,000															$ 1,700,000,000
Percentage of ownership											49.00%
Ownership percentage by other party												51.00%
Amount paid for acquisition		6,400,000,000									439,000,000			3,100,000,000	3,250,000,000	650,000,000			7,000,000,000
Acquisition of oil and gas properties													1,050,000,000
Number of acquisition agreements									3
Preferential purchase right							658,000,000
Revenues attributable to acquisition and merger													197,000,000					308,000,000		95,000,000
Direct expenses attributable to acquisitions			6,998,000,000										39,000,000					78,000,000		26,000,000
Debt before unamortized discount			12,411,000,000	7,262,000,000						1,500,000,000
Notes interest rate										5.10%
Debt instrument maturity date										Sep. 01, 2040
Public offerings of common stock underwritten			392,712,245	385,249,885				26,450,000										26,450,000		17,300,000
Depositary shares each representing		1/20th interest	1/20th interest
Mandatory convertibles preferred stock, Series D		6.00%	6.00%
Expenses in connection with Apache's merger, transition and acquisition activity			31,000,000	20,000,000	183,000,000
Business combination separation and other costs				20,000,000	114,000,000
Investment banking fees					42,000,000
Business combination other expenses					$ 27,000,000

XML

Supplemental Guarantor Information - Supplemental Condensed Consolidating Statement of Cash Flows (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Condensed Financial Statements, Captions [Line Items]
CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	$ 8,504	$ 9,953	$ 6,726
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property	(8,781)	(6,414)	(4,407)
Additions to gas gathering, transmission, and processing facilities	(750)	(664)	(515)
Acquisitions of Devon properties			(1,018)
Acquisition of Cordillera	(2,666)
Acquisition of Mobil North Sea		(1,246)
Acquisitions of BP properties			(6,429)
Equity investment in Yara Pilbara Holdings Pty Limited	(439)
Mariner Energy, Inc. merger			(787)
Acquisitions, other	(252)	(567)	(126)
Proceeds from sale of oil and gas properties	27	422
Other	(563)	(176)	(121)
NET CASH USED IN INVESTING ACTIVITIES	(13,424)	(8,645)	(13,403)
CASH FLOWS FROM FINANCING ACTIVITIES:
Commercial paper, credit facility and bank notes, net	549	(925)	(32)
Fixed rate debt borrowings	4,978		2,470
Payments on fixed rate debt	(400)		(1,023)
Proceeds from issuance of common stock			2,258
Proceeds from issuance of mandatory convertible preferred stock			1,227
Dividends paid	(332)	(306)	(226)
Other	(10)	84	89
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES	4,785	(1,147)	4,763
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(135)	161	(1,914)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	295	134	2,048
CASH AND CASH EQUIVALENTS AT END OF PERIOD	160	295	134
Apache Corporation [Member]
Condensed Financial Statements, Captions [Line Items]
CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	2,357		(1,848)
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property	(3,313)	(1,478)	(1,552)
Additions to gas gathering, transmission, and processing facilities	(48)		(4)
Acquisitions of Devon properties			(1,018)
Acquisition of Cordillera	(2,666)
Acquisitions, other	(66)	(448)
Proceeds from sale of oil and gas properties	25	204
Investment in and advances to subsidiaries, net	(657)	772	(2,853)
Other	(450)	(81)	(72)
NET CASH USED IN INVESTING ACTIVITIES	(7,175)	(1,031)	(5,499)
CASH FLOWS FROM FINANCING ACTIVITIES:
Commercial paper, credit facility and bank notes, net	502	(927)	928
Fixed rate debt borrowings	4,978		2,470
Payments on fixed rate debt	(400)
Proceeds from issuance of common stock			2,258
Proceeds from issuance of mandatory convertible preferred stock			1,227
Dividends paid	(332)	(306)	(226)
Other	29	108	49
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES	4,777	(1,125)	6,706
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(41)	35	(641)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	41	6	647
CASH AND CASH EQUIVALENTS AT END OF PERIOD		41	6
Apache Finance Canada [Member]
Condensed Financial Statements, Captions [Line Items]
CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	(40)		(100)
CASH FLOWS FROM FINANCING ACTIVITIES:
Intercompany borrowings		(1)	2
Other	35	(7)	96
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES	35	(8)	98
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(5)	5	(2)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	5		2
CASH AND CASH EQUIVALENTS AT END OF PERIOD		5
All Other Subsidiaries of Apache Corporation [Member]
Condensed Financial Statements, Captions [Line Items]
CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	6,187		8,674
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property	(5,468)	(4,936)	(2,855)
Additions to gas gathering, transmission, and processing facilities	(702)	(664)	(511)
Acquisition of Mobil North Sea		(1,246)
Acquisitions of BP properties			(6,429)
Equity investment in Yara Pilbara Holdings Pty Limited	(439)
Mariner Energy, Inc. merger			(787)
Acquisitions, other	(186)	(119)	(126)
Proceeds from sale of oil and gas properties	2	218
Other	(113)	(95)	(49)
NET CASH USED IN INVESTING ACTIVITIES	(6,906)	(6,842)	(10,757)
CASH FLOWS FROM FINANCING ACTIVITIES:
Commercial paper, credit facility and bank notes, net	47	2	(960)
Intercompany borrowings	697	(763)	2,720
Payments on fixed rate debt			(1,023)
Other	(114)	(25)	75
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES	630	(786)	812
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(89)	121	(1,271)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	249	128	1,399
CASH AND CASH EQUIVALENTS AT END OF PERIOD	160	249	128
Reclassifications & Eliminations [Member]
CASH FLOWS FROM INVESTING ACTIVITIES:
Investment in and advances to subsidiaries, net	657	(772)	2,853
NET CASH USED IN INVESTING ACTIVITIES	657	(772)	2,853
CASH FLOWS FROM FINANCING ACTIVITIES:
Intercompany borrowings	(697)	764	(2,722)
Other	40	8	(131)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES	$ (657)	$ 772	$ (2,853)

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CONSOLIDATED BALANCE SHEET (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
CURRENT ASSETS:
Cash and cash equivalents	$ 160	$ 295
Receivables, net of allowance	3,086	3,079
Inventories	908	655
Drilling advances	584	229
Derivative instruments	31	304
Prepaid assets and other	193	241
Total current assets	4,962	4,803
Oil and gas, on the basis of full-cost accounting:
Proved properties	78,383	67,805
Unproved properties and properties under development, not being amortized	8,754	5,530
Gathering, transmission, and processing facilities	5,955	5,175
Other	1,055	709
Property plant and equipment, gross	94,147	79,219
Less: Accumulated depreciation, depletion, and amortization	(40,867)	(33,771)
Property plant and equipment, net	53,280	45,448
OTHER ASSETS:
Goodwill	1,289	1,114
Deferred charges and other	1,206	686
Total Assets	60,737	52,051
CURRENT LIABILITIES:
Accounts payable	1,092	1,048
Current debt	990	431
Current asset retirement obligation	478	447
Derivative instruments	116	113
Other current liabilities	2,860	2,924
Total current liabilities	5,536	4,963
LONG-TERM DEBT	11,355	6,785
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes	8,024	7,197
Asset retirement obligation	4,100	3,440
Other	391	673
Total deferred credits other noncurrent liabilities	12,515	11,310
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, 392,712,245 and 385,249,885 shares issued, respectively	245	241
Paid-in capital	9,859	9,066
Retained earnings	20,161	18,500
Treasury stock, at cost, 1,071,475 and 1,132,242 shares, respectively	(30)	(32)
Accumulated other comprehensive loss	(131)	(9)
Total shareholders' liabilities	31,331	28,993
Total liabilities and shareholders' equity	$ 60,737	$ 52,051

XML

Capital Stock - Number of Shares Contingently Issuable (Parenthetical) (Detail)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk free interest rate	0.78%	1.95%	2.31%
Expected volatility	34.94%	34.47%	35.02%
Expected dividend yields	0.82%	0.47%	0.60%
Share Appreciation Program 2008 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares issuable upon vesting, maximum amount	0	1,372,000	1,485,000	2,592,000
Shares Issuable Upon Vesting, Minimum Amount	0	0	0
Risk free interest rate	2.98%
Expected volatility	28.31%
Expected dividend yields	0.54%

XML

ACQUISITIONS AND DIVESTITURES

12 Months Ended

Dec. 31, 2012

ACQUISITIONS AND DIVESTITURES

2.    ACQUISITIONS AND DIVESTITURES

2012 Activity

Cordillera Energy Partners III, LLC Acquisition

On April 30, 2012, Apache completed the acquisition of Cordillera Energy Partners III, LLC (Cordillera), a privately-held exploration and production company, in a stock and cash transaction. Cordillera’s properties include approximately 312,000 net acres in the Granite Wash, Tonkawa, Cleveland, and Marmaton plays in western Oklahoma and the Texas Panhandle. The effective date of the transaction was September 1, 2011.

Apache issued 6,272,667 shares of common stock and paid approximately $2.7 billion of cash to the sellers as consideration for the transaction. The cash paid at closing was funded with a portion of the proceeds from the Company’s April 2012 public note offering. For further discussion of this equity issuance, please see Note 10 — Capital Stock of this Form 10-K. For further discussion of the note offering, please see Note 6 — Debt and Financing Costs of this Form 10-K.

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 final estimates of the assets acquired and liabilities assumed in the acquisition.

	(In millions)
Current assets	$	39
Proved properties		1,040
Unproved properties		2,299
Gathering, transmission, and processing facilities		1
Goodwill(1)		173
Deferred tax asset		64
Total assets acquired	$	3,616
Current liabilities		88
Deferred income tax liabilities		237
Other long-term obligations		5
Total liabilities assumed	$	330
Net assets acquired	$	3,286

(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.

Yara Pilbara Holdings Pty Limited Acquisition

On January 31, 2012, a subsidiary of Apache Energy Limited completed the acquisition of a 49-percent interest in Yara Pilbara Holdings Pty Limited (YPHPL, formerly Burrup Holdings Limited) for $439 million, including working capital adjustments. The transaction was funded with debt. YPHPL is the owner of an ammonia plant on the Burrup Peninsula of Western Australia. Apache has supplied gas to the plant since operations commenced in 2006. Yara Australia Pty Ltd (Yara) owns the remaining 51 percent of YPHPL and operates the plant. In addition, Apache also acquired an interest in a planned technical ammonia nitrate plant to be developed with Yara and Orica Limited. The investment in YPHPL is accounted for under the equity method of accounting, with the balance recorded as a component of “Deferred charges and other” in Apache’s consolidated balance sheet and results of operations recorded as a component of “Other” under “Revenues and Other” in the Company’s statement of consolidated operations.

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. The following table summarizes the final estimates of the assets acquired and liabilities assumed in the acquisition.

	(In millions)
Current assets	$	219
Proved properties		2,341
Unproved properties		476
Gathering, transmission, and processing facilities		338
Goodwill(1)		84
Total assets acquired	$	3,458
Current liabilities		148
Asset retirement obligation		517
Deferred income tax liabilities		1,546
Other long-term obligations		1
Total liabilities assumed	$	2,212
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 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, 2010:

	For the Year  Ended December 31, 2010
	(In millions, except per share amounts)
Revenues and Other	$	13,780
Net Income (Loss)	$	3,364
Preferred Stock Dividends		76
Income (Loss) Attributable to Common Stock	$	3,288
Net Income (Loss) per Common Share — Basic	$	8.62
Net Income (Loss) per Common Share — Diluted	$	8.52

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 have been had the acquisitions and merger been completed on January 1, 2010. 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 2012, Apache recorded $31 million of expenses reflecting additional costs related to our 2011 acquisition of Mobil North Sea Limited and expenses associated with our 2012 acquisition of Cordillera. 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. 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.

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Debt - Non-Recurring Fair Value Measurement (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Debt Instrument [Line Items]
Money market lines of credit, Carrying Amount	$ 91	$ 31
Commercial paper, Carrying Amount	489	0
Notes and debentures, Carrying Amount	11,765	7,185
Total Debt, Carrying Amount	12,345	7,216
Total Debt, Fair Value	13,920	8,704
Money Market Lines of Credit [Member]
Debt Instrument [Line Items]
Total Debt, Fair Value	91	31
Commercial Paper [Member]
Debt Instrument [Line Items]
Total Debt, Fair Value	489
Notes and Debentures [Member]
Debt Instrument [Line Items]
Total Debt, Fair Value	$ 13,340	$ 8,673

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Capital Stock - Summary of Stock Options Issued Under Stock Option Plans (Detail) (USD $) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Outstanding, beginning of year, Shares	6,092
Granted, Shares	2,072
Exercised, Shares	(311)
Forfeited or expired, Shares	(280)
Outstanding, end of year, Shares	7,573	6,092
Expected to vest, Shares	2,900
Exercisable, end of year, Shares	3,922
Available for grant, end of year	15,498
Weighted average fair value of options granted during the year	$ 26.41	$ 42.20	$ 34.12
Outstanding, beginning of year, Weighted Average exercise Price	$ 91.96
Granted, Weighted Average Exercise Price	$ 82.65
Exercised, Weighted Average Exercise Price	$ 56.15
Forfeited or expired, Weighted Average Exercise Price	$ 102.90
Outstanding, end of year, Weighted Average Exercise Price	$ 90.47	$ 91.96
Expected to vest, Weighted Average Exercise Price	$ 96.23
Exercisable, end of year, Weighted Average Exercise Price	$ 85.55

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Supplemental Guarantor Information - Supplemental Condensed Consolidating Statement of Operations (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
REVENUES AND OTHER:
Oil and gas production revenues									$ 16,947	$ 16,810	$ 12,183
Other									131	78	(91)
Total revenues and other	4,391	4,179	3,972	4,536	4,297	4,328	4,338	3,925	17,078	16,888	12,092
OPERATING EXPENSES:
Depreciation, depletion, and amortization									7,109	4,204	3,083
Asset retirement obligation accretion									232	154	111
Lease operating expenses									2,968	2,605	2,032
Gathering and transportation									303	296	178
Taxes other than income									862	899	690
General and administrative									531	459	380
Merger, acquisitions & transition									31	20	183
Financing costs, net									165	158	229
Total operating expenses									12,201	8,795	6,886
INCOME BEFORE INCOME TAXES									4,877	8,093	5,206
Provision (benefit) for income taxes									2,876	3,509	2,174
NET INCOME	668	180	356	797	1,189	1,002	1,259	1,134	2,001	4,584	3,032
Preferred stock dividends									76	76	32
INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	649	161	337	778	1,170	983	1,240	1,115	1,925	4,508	3,000
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK									1,803	4,640	3,149
Apache Corporation [Member]
REVENUES AND OTHER:
Oil and gas production revenues									4,237	4,380	3,665
Equity in net income (loss) of affiliates									1,523	3,590	2,265
Other									(80)	9	27
Total revenues and other									5,680	7,979	5,957
OPERATING EXPENSES:
Depreciation, depletion, and amortization									1,391	1,257	1,041
Asset retirement obligation accretion									76	70	57
Lease operating expenses									957	794	797
Gathering and transportation									51	51	42
Taxes other than income									185	170	140
General and administrative									425	365	273
Merger, acquisitions & transition									25	14	183
Financing costs, net									94	149	158
Total operating expenses									3,204	2,870	2,691
INCOME BEFORE INCOME TAXES									2,476	5,109	3,266
Provision (benefit) for income taxes									475	525	234
NET INCOME									2,001	4,584	3,032
Preferred stock dividends									76	76	32
INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK									1,925	4,508	3,000
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK									1,803	4,640	3,149
Apache Finance Canada [Member]
REVENUES AND OTHER:
Equity in net income (loss) of affiliates									(737)	234	81
Other									69	125	(1)
Total revenues and other									(668)	359	80
OPERATING EXPENSES:
Financing costs, net									(20)	(18)	(19)
Total operating expenses									(20)	(18)	(19)
INCOME BEFORE INCOME TAXES									(648)	377	99
Provision (benefit) for income taxes									(159)	97	25
NET INCOME									(489)	280	74
INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK									(489)	280
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK									(489)	280
All Other Subsidiaries of Apache Corporation [Member]
REVENUES AND OTHER:
Oil and gas production revenues									12,710	12,430	8,518
Equity in net income (loss) of affiliates									248	46	(7)
Other									146	(52)	(113)
Total revenues and other									13,104	12,424	8,398
OPERATING EXPENSES:
Depreciation, depletion, and amortization									5,718	2,947	2,042
Asset retirement obligation accretion									156	84	54
Lease operating expenses									2,011	1,811	1,235
Gathering and transportation									252	245	136
Taxes other than income									677	729	550
General and administrative									110	98	111
Merger, acquisitions & transition									6	6
Financing costs, net									91	27	90
Total operating expenses									9,021	5,947	4,218
INCOME BEFORE INCOME TAXES									4,083	6,477	4,180
Provision (benefit) for income taxes									2,560	2,887	1,915
NET INCOME									1,523	3,590	2,265
INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK									1,523	3,590	2,265
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK									1,523	3,590	2,265
Reclassifications & Eliminations [Member]
REVENUES AND OTHER:
Equity in net income (loss) of affiliates									(1,034)	(3,870)	(2,339)
Other									(4)	(4)	(4)
Total revenues and other									(1,038)	(3,874)	(2,343)
OPERATING EXPENSES:
General and administrative									(4)	(4)	(4)
Total operating expenses									(4)	(4)	(4)
INCOME BEFORE INCOME TAXES									(1,034)	(3,870)	(2,339)
NET INCOME									(1,034)	(3,870)	(2,339)
INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK									(1,034)	(3,870)	(2,339)
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK									$ (1,034)	$ (3,870)	$ (2,339)

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Commitments and Contingencies - Contractual Obligations (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012
Oil and Gas Delivery Commitments and Contracts [Line Items]
Total	$ 5,403
2013	2,208
2014-2015	2,142
2016-2017	622
2018 & Beyond	431
Drilling Rig Commitments [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Total	896
2013	602
2014-2015	289
2016-2017	3
2018 & Beyond	2
Purchase Obligations [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Total	2,588
2013	1,200
2014-2015	1,182
2016-2017	184
2018 & Beyond	22
Firm Transportation Agreements [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Total	763
2013	148
2014-2015	264
2016-2017	134
2018 & Beyond	217
Office Equipment [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Total	402
2013	49
2014-2015	91
2016-2017	96
2018 & Beyond	166
Other Contractual Obligation [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Total	754
2013	209
2014-2015	316
2016-2017	205
2018 & Beyond	$ 24

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DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES (Tables)

12 Months Ended

Dec. 31, 2012

Open Crude Oil and Natural Gas Derivative Instruments

As of December 31, 2012, Apache had the following open crude oil derivative positions:

	Fixed-Price Swaps				Collars
Production Period	Mbbls(2)		Weighted Average Fixed Price(1)		Mbbls(2)		Weighted Average Floor Price(1)		Weighted Average Ceiling Price(1)
2013		40,292	$	97.31		5,701	$	82.84	$	111.63
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 NYMEX WTI Cushing Index and Platts Dated Brent. Approximately 50 percent of 2013 contracts are settled against Dated Brent.

(2) For 2013, fixed-price swaps of 38,320 Mbbls have not been designated as cash flow hedges, and changes in fair value are reflected directly in earnings. All other derivative positions have been designated as cash flow hedges.

As of December 31, 2012, Apache had the following open natural gas derivative positions which have all been designated as cash flow hedges:

	Fixed-Price Swaps				Collars
Production Period	MMBtu (in 000’s)		Weighted Average Fixed Price(1)		MMBtu (in 000’s)		Weighted Average Floor Price(1)		Weighted Average Ceiling Price(1)
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 against NYMEX Henry Hub.

Assets and Liabilities Measured at Fair Value on Recurring Basis

The following table presents the Company’s derivative assets and liabilities measured at fair value on a recurring basis:

	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, 2012
Assets:
Commodity Derivative Instruments		$—	$	48		$—	$	48	$	(15	)	$	33
Liabilities:
Commodity Derivative Instruments		—		131		—		131		(15	)		116
December 31, 2011
Assets:
Commodity Derivative Instruments		$—	$	428		$—	$	428	$	(96	)	$	332
Liabilities:
Commodity Derivative Instruments		—		250		—		250		(96	)		154

(1) The derivative fair values are based on analysis of each contract on a gross basis, even where the legal right of offset exists.

Fair Values of Derivative Instruments Recorded in Consolidated Balance Sheet

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, 2012		December 31, 2011
	(In millions)
Current Assets: Derivative instruments	$	31	$	304
Other Assets: Deferred charges and other		2		28
Total Assets	$	33	$	332
Current Liabilities: Derivative instruments	$	116	$	113
Noncurrent Liabilities: Other		—		41
Total Liabilities	$	116	$	154

Commodity 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 Income	For the Year Ended December 31,
		2012			2011			2010
		(In millions)
Gain (loss) on cash flow hedges reclassified from accumulated other comprehensive loss	Oil and Gas Production Revenues	$	268		$	(13	)	$	165
Gain (loss) for ineffectiveness on cash flow hedges	Revenues and Other: Other	$	—		$	2		$	(2	)
Loss on derivatives not designated as cash flow hedges	Revenues and Other: Other	$	(79	)	$	—		$	—

Commodity Derivative Activity in Accumulated Other Comprehensive Income (Loss)

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:

	For the Year Ended December 31,
	2012						2011						2010
	Before tax			After tax			Before tax			After tax			Before tax			After tax
	(In millions)
Unrealized gain (loss) on derivatives at beginning of year	$	145		$	114		$	(54	)	$	(19	)	$	(267	)	$	(170	)
Realized amounts reclassified into earnings		(268	)		(199	)		13			19			(165	)		(106	)
Net change in derivative fair value		113			79			188			115			376			256
Ineffectiveness reclassified into earnings		—			—			(2	)		(1	)		2			1
Unrealized gain (loss) on derivatives at end of period	$	(10	)	$	(6	)	$	145		$	114		$	(54	)	$	(19	)

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Retirement and Deferred Compensation Plans - Fair Values of Plan Assets for Each Major Asset Category Based on Nature and Significant Concentration of Risks in Plan Assets (Parenthetical) (Detail)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Defined Benefit Plan Disclosure [Line Items]
MSCI Emerging Markets Index	100.00%	100.00%
Global Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
MSCI Emerging Markets Index	85.00%	85.00%
Emerging Markets [Member]
Defined Benefit Plan Disclosure [Line Items]
MSCI Emerging Markets Index	15.00%	15.00%
Overseas Quoted Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Performance target over the benchmark	2.00%	2.00%
U.K. Government Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Performance target per annum over benchmark against iBoxx Sterling Overall Index	0.75%	0.75%
Portion of debt securities government bonds and corporate bonds benchmarked against iBoxx Sterling Overall Index	33.00%	72.00%
MSCI World Index [Member]
Defined Benefit Plan Disclosure [Line Items]
Period for the portion of UK Equities, overseas equities, government bonds and corporate bonds, benchmarked against FTSE	3 years
FTSE Actuaries Government Securities Index [Member]
Defined Benefit Plan Disclosure [Line Items]
Period for the portion of UK Equities, overseas equities, government bonds and corporate bonds, benchmarked against FTSE	5 years	5 years
iBoxx Sterling Overall Index [Member]
Defined Benefit Plan Disclosure [Line Items]
Period for the portion of UK Equities, overseas equities, government bonds and corporate bonds, benchmarked against FTSE	3 years	3 years
Index - Linked Index [Member]
Defined Benefit Plan Disclosure [Line Items]
Portion of debt securities government bonds and corporate bonds benchmarked against FTSE	67.00%	28.00%
U.K. Corporate Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Performance target per annum over benchmark against iBoxx Sterling Overall Index	0.75%
Benchmarked against iBoxx Sterling	50

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SUPPLEMENTAL QUARTERLY FINANCIAL DATA (Tables)

12 Months Ended

Dec. 31, 2012

Supplemental Quarterly Financial Data

	First		Second		Third		Fourth		Total
	(In millions, except per share amounts)
2012
Revenues and other	$	4,536	$	3,972	$	4,179	$	4,391	$	17,078
Expenses		3,739		3,616		3,999		3,723		15,077
Net income	$	797	$	356	$	180	$	668	$	2,001
Income attributable to common stock	$	778	$	337	$	161	$	649	$	1,925
Net income per common share(1):
Basic	$	2.02	$	0.87	$	0.41	$	1.66	$	4.95
Diluted	$	2.00	$	0.86	$	0.41	$	1.64	$	4.92
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

(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.

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MAJOR CUSTOMERS

12 Months Ended

Dec. 31, 2012

MAJOR CUSTOMERS

12.    MAJOR CUSTOMERS

In 2012, 2011, and 2010, purchases by Royal Dutch Shell plc and its subsidiaries accounted for 20 percent, 11 percent, and 15 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.

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Supplemental Oil and Gas Disclosures - Unaudited Information of Future Net Cash Flows for Oil and Gas Reserves, Net of Income Tax Expense (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Schedule Of Changes In Standardized Measure Of Discounted Future Net Cash Flows [Line Items]
Cash inflows	$ 161,347	$ 172,533
Production costs	(52,408)	(54,576)
Development costs	(17,225)	(18,035)
Income tax expense	(24,216)	(28,980)
Net cash flows	67,498	70,942
10 percent discount rate	(32,945)	(34,995)
Discounted future net cash flows	34,553	35,947
United States [Member]
Schedule Of Changes In Standardized Measure Of Discounted Future Net Cash Flows [Line Items]
Cash inflows	84,060	85,041
Production costs	(27,230)	(25,379)
Development costs	(6,768)	(6,493)
Income tax expense	(12,740)	(15,351)
Net cash flows	37,322	37,818
10 percent discount rate	(19,464)	(20,311)
Discounted future net cash flows	17,858	17,507
Canada [Member]
Schedule Of Changes In Standardized Measure Of Discounted Future Net Cash Flows [Line Items]
Cash inflows	20,512	27,727
Production costs	(8,543)	(13,142)
Development costs	(2,916)	(3,274)
Income tax expense	(754)	(972)
Net cash flows	8,299	10,339
10 percent discount rate	(4,472)	(4,956)
Discounted future net cash flows	3,827	5,383
Egypt [Member]
Schedule Of Changes In Standardized Measure Of Discounted Future Net Cash Flows [Line Items]
Cash inflows	16,210	17,092
Production costs	(2,126)	(2,467)
Development costs	(1,756)	(1,909)
Income tax expense	(4,246)	(4,565)
Net cash flows	8,082	8,151
10 percent discount rate	(2,107)	(2,168)
Discounted future net cash flows	5,975	5,983
Australia [Member]
Schedule Of Changes In Standardized Measure Of Discounted Future Net Cash Flows [Line Items]
Cash inflows	20,823	20,579
Production costs	(4,896)	(3,588)
Development costs	(2,484)	(3,124)
Income tax expense	(3,172)	(3,455)
Net cash flows	10,271	10,412
10 percent discount rate	(6,361)	(6,624)
Discounted future net cash flows	3,910	3,788
North Sea [Member]
Schedule Of Changes In Standardized Measure Of Discounted Future Net Cash Flows [Line Items]
Cash inflows	16,732	19,012
Production costs	(8,451)	(8,810)
Development costs	(3,053)	(3,003)
Income tax expense	(3,163)	(4,453)
Net cash flows	2,065	2,746
10 percent discount rate	(98)	(493)
Discounted future net cash flows	1,967	2,253
Argentina [Member]
Schedule Of Changes In Standardized Measure Of Discounted Future Net Cash Flows [Line Items]
Cash inflows	3,010	3,082
Production costs	(1,162)	(1,190)
Development costs	(248)	(232)
Income tax expense	(141)	(184)
Net cash flows	1,459	1,476
10 percent discount rate	(443)	(443)
Discounted future net cash flows	$ 1,016	$ 1,033