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, 2013

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 7.75% Notes Due 2029 Irrevocably and Unconditionally Guaranteed by Apache Corporation	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, 2013	$	32,641,836,810
Number of shares of registrant’s common stock outstanding as of January 31, 2014		394,724,983

Documents Incorporated By Reference

Portions of registrant’s proxy statement relating to registrant’s 2014 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		20
	1B.	UNRESOLVED STAFF COMMENTS		30
	2.	PROPERTIES		1
	3.	LEGAL PROCEEDINGS		30
	4.	MINE SAFETY DISCLOSURES		30
		PART II
	5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES		31
	6.	SELECTED FINANCIAL DATA		33
	7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		34
	7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		60
	8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA		62
	9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE		62
	9A.	CONTROLS AND PROCEDURES		62
	9B.	OTHER INFORMATION		63
		PART III
	10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE		64
	11.	EXECUTIVE COMPENSATION		64
	12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS		64
	13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE		64
	14.	PRINCIPAL ACCOUNTING FEES AND SERVICES		64
		PART IV
	15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES		65

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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 of natural gas.

“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 of natural gas.

“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 the risk factors set forth in Item 1A of this Form 10-K and 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 5, 2013, 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:

• diverse 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 28 years and production 32 out of the past 35 years, a testament to our consistency over the long-term.

Apache pursues growth opportunities through exploration and development drilling, supplemented by occasional strategic acquisitions and portfolio highgrading through asset divestitures. At the end of 2012 and the beginning of 2013, Apache undertook a strategic review of our portfolio with the ultimate goal of keeping the right mix of assets that generate strong returns and excess cash flow and drive more predictable production growth to create shareholder value. In May 2013, Apache announced that it would divest approximately $4 billion in assets and use the proceeds to pay down debt and repurchase Apache common shares. Apache surpassed these goals, divesting approximately $7 billion of assets, paying down $2.6 billion in debt, and repurchasing $1 billion in Apache common shares during 2013. Significant transactions since announcing our strategic repositioning initiatives include:

• Argentina Divestiture On February 12, 2014, Apache subsidiaries announced an agreement to sell all of its operations in Argentina to YPF Sociedad Anónima (YPF) for cash consideration of $800 million plus the assumption of $52 million of bank debt. The transaction is expected to close in the first quarter of 2014.

• Egypt Sinopec Partnership On November 14, 2013, Apache announced the completion of the sale of a one-third minority participation in its Egypt oil and gas business to a subsidiary of Sinopec International Petroleum Exploration and Production Corporation (Sinopec). Apache received cash consideration of $2.95 billion. This noncontrolling interest is recorded separately in the Company’s financial statements.

• Gulf of Mexico Shelf Divestiture On September 30, 2013, Apache completed the sale of its Gulf of Mexico Shelf operations and properties to Fieldwood Energy LLC (Fieldwood), an affiliate of Riverstone Holdings. Under the terms of the agreement, Apache received cash consideration of $3.7 billion, and Fieldwood assumed $1.5 billion of discounted asset abandonment liabilities. Additionally, Apache retained 50 percent of its ownership interest in both exploration blocks and in horizons below production in developed blocks, and access to existing infrastructure.

• Canadian Divestitures In the third and fourth quarters of 2013, Apache completed three separate divestitures of oil and gas producing properties in Canada for total cash consideration of $326 million before customary post-closing adjustments.

Our growth portfolio going forward will be centered on (i) increasing onshore North American liquids production that provides for more predictable and attractive rates of return, (ii) generating excess cash flow from our international operations, and (iii) continuing longer-term growth initiatives, which include our Wheatstone and Kitimat LNG projects. In 2013, we demonstrated the effectiveness of our transition towards North American Onshore liquids growth, with all four of our onshore North American regions increasing liquids production and by replacing more than our worldwide production through our exploration and development activities.

For a more in-depth discussion of our growth strategy, 2013 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.

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Geographic Area Overviews

During 2013, we had 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 2013 data for each of our operating areas. Additional data and discussion is provided in Part II, Item 7 of this Form 10-K.

	Production		Percentage of Total Production			Production Revenue		Year-End Estimated Proved Reserves		Percentage of Total Estimated Proved Reserves			Gross Wells Drilled		Gross Productive Wells Drilled
	(In MMboe)					(In millions)		(In MMboe)
United States		121.1		44	%	$	6,902		1,347		51	%		1,179		1,148
Canada		39.2		14			1,224		462		17			143		135
Total North America		160.3		58			8,126		1,809		68			1,322		1,283
Egypt(1)		54.4		19			3,917		271		10			210		181
Australia		20.6		7			1,140		326		12			12		11
North Sea		26.8		10			2,728		150		6			19		17
Argentina		15.6		6			491		90		4			28		28
Total International		117.4		42			8,276		837		32			269		237
Total		277.7		100	%	$	16,402		2,646		100	%		1,591		1,520

⁽¹⁾  Includes production volumes, revenues, and reserves attributable to a noncontrolling interest in Egypt.

North America

Apache’s North American asset base primarily comprises operations in the Permian Basin, the Anadarko basin in western Oklahoma and the Texas Panhandle, Gulf Coast onshore and offshore areas of the U.S., and in Western Canada. We also have leasehold acreage holdings in the Cook Inlet of Alaska and other areas where we are pursuing exploration opportunities. Over the past several years, the Company has acquired significant acreage positions in many attractive basins and plays across North America. This extensive portfolio expansion phase shifted during 2013 when we completed strategic divestitures to rebalance our portfolio to an asset mix that we believe will continue to generate strong returns, drive more predictable growth and deliver increased value to our shareholders. As part of this effort, Apache’s drilling activity has focused on our North America onshore assets, which had liquids growth of 34 percent during 2013, primarily in the Permian Basin and Anadarko basin.

North America contributed approximately 58 percent of our worldwide production and 50 percent of our oil and gas production revenues for the year. At year-end 2013, North America held 68 percent of our estimated worldwide proved reserves including noncontrolling interests in Egypt.

United States

Overview We have access to significant liquid hydrocarbons across our 11.5 million gross acres in the U.S., approximately 75 percent of which is undeveloped. In 2013, 61 percent of our U.S. production and 67 percent of our U.S. year-end reserves were oil and natural gas liquids. Approximately 44 percent of Apache’s worldwide equivalent 2013 production and 51 percent of our estimated proved reserves were in the U.S. To better control our development efforts across broad acreage positions within the U.S., during 2013 our assets were divided into five regions: Permian, Central, Gulf Coast Onshore, Gulf of Mexico Deepwater, and the Gulf of Mexico Shelf. In 2014, the Gulf of Mexico Shelf region and Gulf of Mexico Deepwater region have been combined into the Gulf of Mexico region.

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Permian Region Our Permian region controls over 3.3 million gross acres with exposure to numerous plays across the Permian Basin. Apache is one of the largest operators in the Permian Basin, with more than 13,500 producing wells in 155 fields, including 47 waterfloods and seven CO² floods. Total region production for 2013 was up over 17 percent sequentially as a result of an active drilling program where we ran an average of 42 rigs during the year. Production in the region has increased for 12 consecutive quarters. During the year, we drilled or participated in drilling 785 wells, of which 186 were horizontal. The Permian region’s year-end 2013 estimated proved reserves were 910 MMboe, representing 14 percent growth over year-end 2012.

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 nearly 10 rigs and drilled 189 wells. Our activity in the Deadwood area is primarily drilling vertical wells targeting the Wolfwood and the Fusselman zones.

Over the past several years, the region has been testing numerous formations and building a large inventory of horizontal opportunities in several plays across our acreage position. Our success has led the region to increase the number of horizontal drilling rigs being utilized throughout 2013, and now approximately half of our rigs are drilling horizontal wells. In 2013, we ramped up multi-rig development programs in several horizontal plays in the Midland basin, targeting the Wolfcamp and Cline Shales. We have also increased development activity in our Yeso area of New Mexico and across the Permian’s Central Basin Platform. These extensive programs will carry into 2014 and drive the region’s growth.

We continue to balance large development programs with exploration activity in several new areas. Given its acreage holdings, recent seismic data acquisitions and continued exploration efforts, the region has built a deep portfolio of drilling inventory and opportunities to sustain our activity for many years. For 2014, the Permian region plans to invest approximately $2.55 billion. The region’s capital program covers planned expenditures for drilling, completions, recompletion projects, equipment upgrades, expansion of existing facilities and equipment, plugging and abandonment, seismic studies, and leasing additional acreage.

Central Region The Central region controls 1.8 million gross acres that are mostly held-by-production and includes more than 3,800 producing wells primarily in western Oklahoma and the Texas Panhandle. The region was Apache’s first core area and has historically grown through low-risk, highly predictable exploitation. Over the last several years, the region has aggressively targeted oil and liquids-rich gas plays through horizontal drilling across its acreage holdings. Oil and liquids production expanded during 2013, with oil production growth of 61 percent and NGL production more than doubling compared to the prior year. Total region production in 2013 was 91 Mboe/d, of which 50 percent was oil and natural gas liquids. As of year-end, the Central region’s estimated proved reserves totaled 304 MMboe, an increase of nearly 14 percent from year-end 2012.

The primary factor driving the region’s growth in 2013 was an active drilling program where we ran an average of 24 rigs during the year, over a 30 percent increase from the prior year. We drilled or participated in drilling 322 wells during 2013, with 98 percent being completed as producers.

The vast majority of our drilling activity has been in the Anadarko basin, which consists of a series of thick, stacked formations of liquids-rich, low-permeability sandstones. The Company’s significant acreage position in the basin provides a robust drilling inventory for the next several years across numerous horizontal liquids plays, notably the Granite Wash, Tonkawa, Marmaton, Cottage Grove, and Cleveland. In addition, in 2013 the region continued to invest in infrastructure facilities and contractually secure takeaway capacity.

In addition, in 2011 Apache acquired 92,000 contiguous net acres in the Whittenburg basin, located approximately 70 miles west of our Anadarko basin properties. The region has operated two drilling rigs targeting vertical objectives in 2012 and 2013, completing 26 vertical wells into the Canyon Wash sand and achieving a peak production rate of 10 Mb/d and 16 MMcf/d. Apache has now turned its attention to the prolific Canyon lime and is currently drilling its first horizontal test.

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The Central region plans to run an average of 34 rigs during 2014 and invest approximately $1.75 billion for drilling, recompletions, equipment upgrades, and production enhancement projects.

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. During 2013 the area was divided into three regions, which include the Gulf Coast Onshore, Gulf of Mexico Deepwater, and Gulf of Mexico Shelf. In 2014, the Gulf of Mexico Shelf region and Gulf of Mexico Deepwater region have been combined into the Gulf of Mexico region.

Apache’s Gulf Coast Onshore region is known for its proven onshore and near-shore basins of Texas, Louisiana and Mississippi where it has a significant acreage position of approximately 1.3 million gross acres, including approximately 275,000 mineral fee acres. During the year, the region primarily drilled shallow and moderate-depth development wells and completed the construction of gathering and processing facilities in our Atchafalaya Bay development project. The region also continued evaluating deeper exploitation opportunities and several unconventional resource plays, which included drilling three Eagle Ford shale wells on our Southeast Texas acreage with plans to substantially increase activity in 2014. For the year, the region drilled or participated in drilling 43 wells and projects drilling approximately 90 wells in 2014.

In offshore waters greater than 500 feet deep, the Gulf of Mexico Deepwater region is a relatively underexplored and oil-prone area that provides exposure to significant reserve and production potential. The Company owns over 900,000 gross acres across nearly 170 blocks as of the end of 2013. The Deepwater region contributed approximately two percent of Apache’s worldwide production with multiple projects and developments underway. The non-operated Lucius project, where Apache holds an 11.7 percent working interest, is currently under development with first production projected by year-end 2014. In addition, the large scale non-operated Heidelberg project was sanctioned in late 2012. Apache has a 12.5 percent working interest in this development with first production projected for 2016.

Apache’s former Gulf of Mexico Shelf region, constituting Gulf assets in waters less than 500 feet deep, experienced a significant shift during 2013 as the region’s producing base and associated infrastructure was sold to Fieldwood in September. As part of the transaction, Apache retained 50 percent of its ownership interest in all exploration blocks and in horizons below production in developed blocks, and access to existing infrastructure. These retained interests cover approximately 2.5 million gross acres across 515 offshore blocks. Several wells are expected to be drilled during 2014, and we expect future activities to provide a platform for continued exploration growth in this basin. Total region production in 2013 was 71 Mboe/d, reflecting nine months of Shelf production prior to the divestiture.

In 2014, Apache plans to invest approximately $550 million and $450 million in its Gulf Coast (formerly Gulf Coast Onshore) and Gulf of Mexico regions, respectively. The capital will be spent on drilling, recompletion, and development projects, equipment upgrades, production enhancement projects, seismic acquisitions, additional leasing activity, and plugging and abandonment of wells and platforms.

U.S. Marketing In general, most of our U.S. gas is sold at either monthly or daily market prices. Also, from time to time, the Company will enter into fixed physical sales contracts for durations of up to one-year. These physical sales volumes are typically sold at fixed prices over the term of the contract. Our natural gas is sold primarily to local distribution companies (LDCs), utilities, end-users, marketers, and integrated major oil companies. We strive to maintain a diverse client portfolio, which is intended to reduce the concentration of credit risk.

Apache primarily markets its U.S. crude oil to integrated major oil companies, marketing and transportation companies, and refiners based on a West Texas Intermediate (WTI) price, adjusted for quality, transportation and a market-reflective differential. The objective is to maximize the value of crude oil sold by identifying the best markets and most economical transportation routes available to move the product. Sales contracts are generally 30-day evergreen contracts that renew automatically until canceled by either party. These contracts provide for sales that are priced daily at prevailing market prices. Also, from time to time, the Company will enter into physical term sales contracts for durations up to five years. These term contracts typically have a firm transport commitment and often provide for the higher of prevailing market prices from multiple market hubs.

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

Canada

Overview Apache entered the Canadian market in 1995 and currently holds nearly 5.4 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 opportunities. Our Canadian region provided approximately 14 percent of Apache’s 2013 worldwide production.

In 2013, Apache drilled or participated in drilling 143 wells in Canada, with a continued focus on increasing oil and liquids-rich gas production. Reservoir modeling and horizontal drilling technology advanced several oil and liquids-rich gas plays in the Montney, Swan Hills, Viking, Bluesky, and Glauconite formations. Success with multi-stage fracture completions continues to increase the scope of oil and liquids-rich gas drilling opportunities.

We also furthered our region’s shift toward an oil and liquids-rich gas asset portfolio through several strategic divestitures of primarily dry gas assets during 2013. In September we completed the sale of certain Alberta producing assets for approximately $214 million. The assets comprised 621,000 gross acres (530,000 net acres) and more than 2,700 wells in the Nevis, North Grant Lands, and South Grant Lands areas. In October 2013, we completed two additional sales of producing properties in Saskatchewan and Alberta for $112 million. The divested assets comprised approximately 4,000 operated and 1,300 non-operated wells, including our Hatton, St. Lina, Marten Hills, Snipe Lake, and Valhalla developments, as well as a portion of our Hawkeye producing properties. Combined, our 2013 divestitures totaled 13 percent of the region’s production.

The Kitimat LNG project will allow us to monetize large unconventional natural gas resources in the Liard and Horn River basins in northern British Columbia. In February 2013, Apache completed a transaction with Chevron Canada Limited (Chevron Canada) under which each company became a 50 percent owner of the Kitimat LNG plant, the Pacific Trail Pipelines Limited Partnership (PTP), and 644,000 gross undeveloped acres in the Horn River and Liard basins. Chevron Canada will operate the LNG plant and pipeline while Apache Canada will continue to operate the upstream assets. 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. In 2014, we plan to invest approximately $1.0 billion of capital in the Kitimat project, which includes the LNG plant as well as our upstream assets in the Horn River and Liard basins. With a 50 percent project participation, Apache is actively evaluating ways to right-size its level of participation in the Kitimat LNG project.

Additionally, the region plans to invest approximately $600 million in drilling and development projects, equipment upgrades, and production enhancement projects for our other upstream assets.

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 under firm transportation contracts to delivery points into the United States. We sell the majority of our Canadian gas on a monthly basis at either first-of-the-month or daily AECO index prices. Also, from time to time, the Company will enter into fixed physical sales contracts for durations of up to one-year. These physical sales volumes are typically sold at fixed prices over the term of the contract.

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 differential. The crude is transported by pipeline or truck within Western Canada to market hubs in Alberta and Manitoba where it is sold, allowing for a more diversified group of purchasers and a higher netback price. A portion of our trucked barrels

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are delivered and sold at rail terminals. We evaluate our transport options monthly to maximize our netback prices.

The region’s NGL production is sold under contracts with prices based on local supply and demand conditions, 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 2013, international assets contributed 42 percent of our production and 50 percent of our oil and gas revenues. At year-end 2013, 32 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, and today we are one of the largest acreage holders in Egypt’s Western Desert. At year-end, we held 9.8 million gross acres, with gross oil production of 198 Mb/d and gross natural gas production of 912 MMcf/d in 2013, or 90 Mb/d and 356 MMcf/d net to Apache’s consolidated holdings. Although 3.0 million gross undeveloped acres expired in January 2014, we continue to pursue longer term extensions on areas we believe provide attractive growth opportunities. Of our remaining acreage, 72 percent is undeveloped, providing us with considerable exploration and development opportunities for the future.

Our operations in Egypt are conducted pursuant to production-sharing agreements in 24 separate concessions, under which the contractor partners pay all operating and capital expenditure costs for exploration and development. Development leases within concessions currently have expiration dates ranging from 2 to 25 years, with extensions possible for additional commercial discoveries or on a negotiated basis. 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 the Egyptian General Petroleum Corporation (EGPC) on a contractually defined basis. In 2013 Apache was granted 20 new development leases, representing one of our most successful years since our entry into Egypt.

Our growth in Egypt has been driven by an ongoing drilling program, and we have historically been one of the most active drillers in the Western Desert. During 2013, we drilled 181 development and injection wells and 54 exploration wells. Approximately 60 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 the ability to acquire and evaluate 3-D seismic surveys that enable our technical teams to consistently high-grade existing prospects and identify new targets across multiple pay horizons in the Cretaceous, Jurassic, and deeper Paleozoic formations.

Apache has also made a strategic decision to advance the application of horizontal drilling technology to unlock new plays in Egypt. During the year, we drilled our first well of a multi-well horizontal drilling program in the Abu Gharadig field. During December, this well produced an average of 1,681 b/d and 3 MMcf/d from a 1,970 foot lateral. This well was one of eight horizontal wells initiated during 2013 to test the technology’s ability to increase recoveries in a variety of conventional and unconventional reservoirs. Additional horizontal drilling is planned in the Abu Gharadig and surrounding fields in 2014.

In November 2013, Apache announced the completion of the sale of a one-third minority interest in its Egypt oil and gas business to Sinopec. After customary closing adjustments, Apache received cash consideration of $2.95 billion. At year-end 2013, our Egypt region’s estimated proved reserves were 271 MMboe, of which 90

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MMboe is attributable to Sinopec’s noncontrolling interest. Our estimated proved reserves in Egypt are reported under the economic interest method and exclude the host country’s share of reserves.

Heading into 2014, the region will continue an active drilling program and plans to invest approximately $1.4 billion, including approximately $460 million attributable to Sinopec’s noncontrolling interest, for drilling, recompletion projects, development projects, and seismic acquisition.

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. The region averaged $2.99 per Mcf in 2013.

Oil from the Khalda Concession, the Qarun Concession, and other nearby Western Desert blocks is sold to third parties in the export 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 presidential and parliamentary elections could be held. In June 2012, President Mohamed Morsi of the Muslim Brotherhood’s Freedom and Justice Party was elected as Egypt’s new president.

In July 2013, the Egyptian military removed President Morsi from power and installed Egypt’s Chief Justice, Adly Mansour, as acting president of a temporary government, which announced that it would seek to schedule parliamentary and presidential elections in early to mid-2014. In January 2014, Egyptians voted on and overwhelmingly approved a new constitution, and Mr. Mansour announced that the presidential election will be held prior to the parliamentary elections. While the date of the presidential election has not been announced, it is expected to be held by mid-April 2014.

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 further 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 $856 million of coverage to Apache for losses arising from confiscation, nationalization, and expropriation risks, with a $149 million sub-limit for currency inconvertibility.

In addition, Apache 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, with production operations in the Carnarvon and Exmouth basins. We have

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operated in the Carnarvon basin since acquiring the gas processing facilities on Varanus Island and adjacent producing properties in 1993. In total, we control approximately 7.9 million gross acres offshore Western Australia through 30 exploration permits, 18 production licenses, and 9 retention leases. Approximately 89 percent of our acreage is undeveloped, and the region continues to actively pursue additional acreage opportunities.

During 2013, the region had net production of 19 Mb/d and 223 MMcf/d, contributing 7 percent of Apache’s worldwide consolidated production revenue, 7 percent of worldwide consolidated production and 12 percent of year-end consolidated proved reserves. Production compared to the prior year was 12 percent lower primarily as a result of natural decline in the Pyrenees and Van Gogh oil fields.

Partially offsetting production declines from Pyrenees and Van Gogh was production through the BHP Billiton-operated Macedon gas plant, which commenced operations in the third quarter of 2013. The $1.5 billion natural gas facility, Western Australia’s fourth domestic gas hub, has a production capacity of approximately 200 MMcf/d. Gas is delivered to the facility via a 60-mile pipeline from four completed subsea gas wells in the Macedon field. Apache has successfully marketed production in the Macedon field under long-term contracts at prices higher than historical realizations. We have a 28.57 percent non-operating working interest in the field and gas plant. Apache has a participating interest in three of the four domestic gas hubs in Australia.

The region participated in drilling 12 offshore wells during 2013, of which 4 were exploration or appraisal wells, compared to 15 wells drilled in 2012. 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 online in the coming years.

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 Ningaloo Vision Floating Production Storage and Offloading Vessel (FPSO) at Van Gogh. Required modifications to the FPSO and the final phase of subsea installation work is planned for the first half of 2014. Apache has a 52.5 percent working interest in the field.

The region also continued development of the Balnaves field, an oil discovery located near the Brunello gas field. Development well drilling commenced in the third quarter of 2013, and the project is expected to begin production by the third quarter of 2014 utilizing a leased FPSO vessel. Apache has a 65 percent working interest in the project.

In 2013, further advances were made on the region’s largest development effort, which is the Chevron-operated Wheatstone LNG project (Wheatstone). 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 in the 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 2014, the region plans to invest approximately $800 million for drilling, recompletion projects, development projects, equipment upgrades, production enhancement projects, and seismic acquisition. Approximately $1.4 billion of additional 2014 capital will be invested in the Wheatstone development project.

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

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periodic price revision clauses based on either the Australian consumer price index or a commodity linkage. As of December 31, 2013, Apache had 21 active gas contracts in Australia with expiration dates ranging from August 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 WTI-based prices.

During 2013 Apache finalized binding Sales and Purchase Agreements with two Asian customers for the delivery of approximately 25 percent of Apache’s net LNG offtake from Wheatstone.

North Sea

Overview Apache entered the North Sea in 2003 after acquiring an approximate 97 percent working interest in the Forties field (Forties). Apache has actively invested in the region and has established a large inventory of drilling prospects through successful exploration programs and the interpretation of acquired 3-D and 4-D seismic data. Building upon its success in Forties, Apache in 2012 acquired Mobil North Sea Limited (Mobil North Sea), providing 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. In total, Apache has interests in approximately 1.2 million gross acres in the U.K. North Sea.

In 2013, the North Sea region produced 65 Mb/d and 51 MMcf/d, contributing 17 percent of Apache’s worldwide consolidated production revenue, 10 percent of worldwide consolidated production, and 6 percent of year-end consolidated proved reserves. During the year we drilled 19 wells in the North Sea, of which 17 were productive. Apache’s drilling success was highlighted with discoveries in the Tonto oil field. The Tonto-1 well, completed in April, had initial production of 10.3 Mb/d, and the Tonto-2 well, completed in September, had initial production of 8.3 Mb/d. Apache has a 100 percent working interest in the wells. The Tonto discovery follows Maule and Bacchus as the third new field brought online by Apache in the Forties area over the last three years. All three fields qualify for the U.K.’s small field allowance, which provides economic incentives for operators to bring discoveries from small fields into production. During the fourth quarter the region continued to commission the Forties Alpha Satellite Platform, adjacent to the main Forties Alpha platform. This platform has been constructed to exploit new opportunities at Forties and provides an additional 18 drilling slots as well as power generation, fluid separation, and gas lift compression.

In 2014, the region plans to invest approximately $900 million on drilling, recompletion projects, development projects, equipment upgrades, production enhancement projects, and seismic acquisition, focusing on both the Beryl field and Forties area.

Marketing We have traditionally sold our North Sea crude oil under both term contracts and spot cargoes. The Forties 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 Beryl spot cargoes are market driven and can trade at a premium 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.

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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 has active operations in the provinces of Neuquén, Rio Negro, and Tierra del Fuego. As of year-end 2013, Apache held interests in 31 concessions, exploration permits, and other interests totaling 3.3 million gross acres in three of the main Argentine hydrocarbon basins: Neuquén, Austral, and Cuyo. These concessions have varying expiration dates ranging from one year to over 15 years remaining, subject to potential extensions. In 2013, Argentina produced 6 percent of our worldwide consolidated production and held 4 percent of our year-end consolidated proved reserves.

On February 12, 2014, Apache announced an agreement to sell all of its operations in Argentina to YPF for cash consideration of $800 million plus the assumption of $52 million of bank debt as of June 30, 2013. The transaction is expected to close in the first quarter of 2014.

Marketing

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

• Gas Plus Program: This program was instituted by the Argentine government in 2008 to encourage investments for 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 2013, the average Gas Plus volume sold by Apache was 79.9 MMcf/d at an average price of $4.90 per Mcf.

• 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 category. During 2013, we realized an average price of $0.78 per Mcf on government-regulated sales.

• Unregulated market: In 2013, realizations on sales in the unregulated market averaged $3.69 per Mcf.

In 2013, we realized an average price of $2.96 per Mcf in the region.

Crude Oil The crude oil in Argentina is subject to an export tax which effectively limits the prices buyers are willing to pay for domestic sales. In 2013 there was an increase on the price of the crude paid by refiners, a combination of an increase of the sales price of fuels to end-users and the decrease of domestic production. Apache´s average sales price in Argentina during 2013 was $79.05 per barrel.

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. During 2014, we plan to invest approximately $75 million to further several projects and continue pursuing additional exploration opportunities.

Major Customers

In 2013, 2012, and 2011 purchases by Royal Dutch Shell plc and its subsidiaries accounted for 24 percent, 20 percent, and 11 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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Drilling Statistics

Worldwide in 2013 we participated in drilling 1,591 gross wells, with 1,520 (96 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 a number of wells had not yet reached completion: 160 in the U.S. (115.4 net); 17 in Egypt (17.0 net); and 2 in Argentina (0.3 net).

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

	Net Exploratory						Net Development						Total Net Wells
	Productive		Dry		Total		Productive		Dry		Total		Productive		Dry		Total
2013
United States		15.6		11.2		26.8		834.9		12.6		847.5		850.5		23.8		874.3
Canada		0.0		0.0		0.0		108.5		6.9		115.4		108.5		6.9		115.4
Egypt		30.5		18.7		49.2		141.9		7.3		149.2		172.4		26.0		198.4
Australia		2.2		0.4		2.6		3.4		0.0		3.4		5.6		0.4		6.0
North Sea		0.0		0.5		0.5		13.4		0.1		13.5		13.4		0.6		14.0
Argentina		2.4		0.0		2.4		22.0		0.0		22.0		24.4		0.0		24.4
Total		50.7		30.8		81.5		1,124.1		26.9		1,151.0		1,174.8		57.7		1,232.5
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

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, 2013, is set forth below:

	Oil				Gas				Total
	Gross		Net		Gross		Net		Gross		Net
United States		14,164		9,346		5,001		2,831		19,165		12,177
Canada		2,000		939		3,030		2,277		5,030		3,216
Egypt		1,040		992		85		80		1,125		1,072
Australia		49		23		16		9		65		32
North Sea		161		104		24		14		185		118
Argentina		475		396		425		389		900		785
Total		17,889		11,800		8,581		5,600		26,470		17,400

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Gross natural gas and crude oil wells include 650 wells with multiple completions.

Production, Pricing, and Lease Operating Cost Data

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

Year Ended December 31,	Production						Average Lease Operating Cost per Boe		Average Sales Price
	Oil (MMbbls)		NGLs (MMbbls)		Gas (Bcf)				Oil (Per bbl)		NGLs (Per bbl)		Gas (Per Mcf)
2013
United States		53.6		19.9		285.2	$	11.60	$	98.14	$	27.29	$	3.84
Canada		6.5		2.4		181.6		15.68		87.00		30.50		3.23
Egypt(1)		32.7		—		130.1		9.42		107.94		—		2.99
Australia		7.0		—		81.5		10.35		110.42		—		4.43
North Sea		23.3		0.5		18.6		15.16		107.48		73.06		10.43
Argentina		3.4		0.8		68.4		12.89		79.05		23.64		2.96
Total		126.5		23.6		765.4		12.06		101.99		28.40		3.70
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

⁽¹⁾  Includes production volumes attributable to a one-third noncontrolling interest in Egypt

Gross and Net Undeveloped and Developed Acreage

The following table sets out our gross and net acreage position as of December 31, 2013, in each country where we have operations:

	Undeveloped Acreage				Developed Acreage
	Gross Acres		Net Acres		Gross Acres		Net Acres
	(in thousands)
United States		8,730		4,772		2,797		1,445
Canada		2,329		1,712		3,078		2,151
Egypt		7,852		5,060		1,971		1,806
Australia		7,003		3,849		900		545
North Sea		1,092		487		160		98
Argentina		3,037		2,247		231		198
Total		30,043		18,127		9,137		6,243

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As of December 31, 2013, Apache had 3.2 million net undeveloped acres scheduled to expire by year-end 2014 if production is not established or we take no other action to extend the terms. Additionally, Apache has 2.7 million and 1.9 million net undeveloped acres set to expire in 2015 and 2016, respectively. We strive to extend 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.

Exploration concessions in our Egypt region comprise a significant portion of our net undeveloped acreage expiring over the next three years. We have 1.5 million net acres in Egypt scheduled to expire in 2014, and 1.0 million and 0.9 million net undeveloped acres set to expire in 2015 and 2016, respectively. Nearly all of the acreage expiring in 2014 was relinquished in January. There were no reserves recorded on this undeveloped acreage. Apache will continue to pursue acreage extensions in areas in which it believes exploration opportunities exist and over the past year has been successful in being awarded six-month extensions on targeted concessions. Longer term extensions are also being finalized with EGPC.

As of December 31, 2013, 23 percent of U.S. net undeveloped acreage and 54 percent of Canadian undeveloped acreage was held by production.

Estimated Proved Reserves and Future Net Cash Flows

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

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

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.

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The following table shows proved oil, NGL, and gas reserves as of December 31, 2013, based on average commodity prices in effect on the first day of each month in 2013, 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		458		184		2,006		977
Canada		81		26		1,294		323
Egypt(1)		119		—		622		223
Australia		23		—		627		127
North Sea		100		3		88		117
Argentina		14		4		289		66
Total Proved Developed		795		217		4,926		1,833
Proved Undeveloped:
United States		196		64		667		371
Canada		56		10		439		139
Egypt(1)		16		—		190		48
Australia		37		—		975		199
North Sea		29		—		19		32
Argentina		2		1		122		24
Total Proved Undeveloped		336		75		2,412		813
TOTAL PROVED		1,131		292		7,338		2,646

⁽¹⁾  Includes total proved reserves of 90 MMboe attributable to a one-third noncontrolling interest in Egypt

As of December 31, 2013, Apache had total estimated proved reserves of 1,131 MMbbls of crude oil, 292 MMbbls of NGLs, and 7.3 Tcf of natural gas. Combined, these total estimated proved reserves are the energy equivalent of 2.65 billion barrels of oil or 15.9 Tcf of natural gas, of which oil represents 43 percent. As of December 31, 2013, the Company’s proved developed reserves totaled 1,833 MMboe and estimated PUD reserves totaled 813 MMboe, or approximately 31 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, 2013, 2012, and 2011, 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 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 813 MMboe as of December 31, 2013, decreased by 57 MMboe from 870 MMboe of PUD reserves estimated at the end of 2012. During the year, Apache converted 154 MMboe of PUD reserves to proved developed reserves through development drilling activity. In North America, we converted 124 MMboe, with the remaining 30 MMboe in our international areas. We sold 109 MMboe and acquired 1 MMboe of PUD reserves during the year. We added 205 MMboe of new PUD reserves through extensions and discoveries.

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During the year, a total of approximately $3.7 billion was spent on projects associated with reserves that were carried as PUD reserves at the end of 2012. 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 $2.1 billion on PUD reserve development activity in North America and $1.6 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, 2013.

Preparation of Oil and Gas Reserve Information

Apache’s 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.

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 2013, the properties selected for each country ranged from 83 to 100 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 86 percent of total proved reserves, including 89 percent of proved developed reserves and 79 percent of PUD reserves.

During 2013, 2012, and 2011, Ryder Scott’s review covered 92, 88, and 81 percent, respectively, of the Company’s worldwide estimated proved reserves value and 86, 83, and 70 percent, respectively, of the Company’s total proved reserves volume. Ryder Scott’s review of 2013 covered 84 percent of U.S., 82 percent of Canada, 63 percent of Argentina, 99 percent of Australia, 88 percent of Egypt, and 88 percent of the U.K.’s total proved reserves. 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. We have filed Ryder Scott’s independent report as an exhibit to this Form 10-K.

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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, 2013, we had 5,342 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 2013, we maintained regional exploration and/or production offices in Midland, Texas; Tulsa, Oklahoma; Houston, Texas; Calgary, Alberta; Cairo, Egypt; Perth, Western Australia; Aberdeen, Scotland; and Buenos Aires, Argentina. Apache leases all of its primary office space. The current lease on our principal executive offices runs through December 31, 2018. For information regarding the Company’s obligations under its office leases, please see Part II, Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity—Contractual Obligations and Note 8—Commitments and Contingencies in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.

Title to Interests

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

Additional Information about Apache

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

Remediation Plans and Procedures

Apache and its wholly owned subsidiary, Apache Deepwater LLC (ADW), 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 Clean Gulf Associates (CGA), and representatives of governmental agencies. In the event of a spill, 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.

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Both Apache and ADW are members of CGA, a not-for-profit association of producing and pipeline companies operating in the Gulf of Mexico. CGA was created to provide a means of effectively staging response equipment and providing immediate spill response for its member companies’ operations in the Gulf of Mexico. In the event of a spill, CGA’s 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 2013, Apache incurred charges for CGA of approximately $700,000 based on a per-member fee and annual production.

In the event that CGA resources are already being utilized, other resources 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 seven major oil industry funded spill response organizations worldwide. 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 Marine Spill Response Corporation (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 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 hundreds of offshore vessels and supply boats worldwide. The equipment and resources available to MSRC and NRC changes from time to time, and current information is generally available on each company’s website. In 2013, Apache’s Gulf of Mexico Deepwater region incurred charges for NRC of $12,248 based on annual production and charges for MSRC of approximately $1.4 million based on annual production and total wells spud during the year.

An Apache subsidiary is also a member of the Marine Well Containment Company (MWCC) to help the Company fulfill the government’s permit requirements for containment and oil spill response plans in deepwater Gulf of Mexico operations. MWCC is a not-for-profit, stand-alone organization whose goal is to improve capabilities for containing an underwater well control incident in the U.S. Gulf of Mexico. Members and their affiliates have access to MWCC’s extensive containment network and systems. As of December 31, 2013, Apache’s investment in MWCC totals approximately $136 million.

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.

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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 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 certain international markets may materially adversely impact our operating results.

The U.S. and other world economies continue to recover from the 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 and certain emerging markets, 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 2013 ranged from a high of $110.53 per barrel to a low of $86.68 per barrel. The NYMEX daily settlement price for the prompt month natural gas contract in 2013 ranged from a high of $4.46 per MMBtu to a low of $3.11 per MMBtu. The market prices for crude oil and natural gas depend on factors beyond our control. These factors include demand for crude oil and natural gas, which fluctuates with changes in market and economic conditions, and other factors, including:

• worldwide and domestic supplies of crude oil and natural gas;

• actions taken by foreign oil and gas producing nations;

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

• the level of global crude oil and natural gas inventories;

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

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

• the availability of pipeline capacity and infrastructure;

• the availability of crude oil transportation and refining capacity;

• weather conditions;

• electricity generation;

• domestic and foreign governmental regulations and taxes; and

• the overall economic environment.

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

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

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• 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, limited, 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 freezing temperatures, hurricanes in the Gulf of Mexico, storms in the North Sea, 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 or other facility ruptures and spills;

• fires;

• formations with abnormal pressures;

• equipment malfunctions;

• hurricanes, storms, and/or cyclones, which could affect our operations in areas such as on- and offshore the Gulf Coast, North Sea, and Australia, and other natural disasters and weather conditions; and

• surface spillage and surface or ground water contamination from petroleum constituents, saltwater, 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

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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.

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 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;

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

• an 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 us 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.

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

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

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

Any indentures and other financing agreements that we enter into in the future may limit our ability to pay cash dividends on our capital stock, including common stock. In 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

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the sum of our total liabilities, including contingent liabilities, and the amount of our capital; if there is no surplus, cash dividends on capital stock may only be paid from our net profits for the then current and/or the preceding fiscal year. Further, even if we are permitted under our contractual obligations and Delaware law to pay cash dividends on common stock, we may not have sufficient cash to pay dividends in cash on our common stock.

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

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

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

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

• unexpected drilling conditions;

• pressure or irregularities in formations;

• equipment failures or accidents;

• fires, explosions, blowouts, and surface cratering;

• marine risks such as capsizing, collisions, and hurricanes;

• other adverse weather conditions; and

• increases 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 or costs may affect the completion and commencement of production from development projects.

We are involved in several large development projects and the completion of these projects 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. In addition, our estimates of future development costs are based on current expectation of prices and other costs of equipment and personell we will need to

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implement such projects. Our actual future development costs may be significantly higher than we currently estimate. If costs become too high, our development projects may become uneconomic to us and we may be forced to abandon such development projects.

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 has been 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 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

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and geological interpretation. Our reserves estimates are based on 12-month average prices, except where contractual arrangements exist; therefore, reserves quantities will change when actual prices increase or decrease. In addition, results of drilling, testing, and production may substantially change the reserve estimates for a given reservoir over time. The estimates of our proved reserves and estimated future net revenues also depend on a number of factors and assumptions that may vary considerably from actual results, including:

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

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

• future operating costs and capital expenditures; and

• workover and remediation costs.

For these reasons, estimates of the economically recoverable quantities of crude oil and natural gas attributable to any particular group of properties, classifications of those reserves and estimates of the future net cash flows expected from them prepared by different engineers or by the same engineers but at different times may vary substantially. Accordingly, reserves estimates may be subject to upward or downward adjustment, and actual production, revenue and expenditures with respect to our reserves likely will vary, possibly materially, from estimates.

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

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

A sizeable portion of our acreage is currently undeveloped. Unless production in paying quantities is established on units containing certain of these leases during their terms, the leases will expire. If our leases expire, we will lose our right to develop the related properties. Our drilling plans for these areas are subject to change based upon various factors, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling, and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints, and regulatory approvals.

We may incur significant costs related to environmental matters.

As an owner or lessee and operator of oil and gas properties, we are subject to various federal, provincial, state, local, and foreign country laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution clean-up and other remediation activities resulting from operations, subject the lessee to liability for pollution and other damages, limit or constrain operations in affected areas, 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 effects to 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,

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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 of operations.

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

Several countries where we operate, including Australia, Canada, and the United Kingdom either tax or assess some form of greenhouse gas (GHG) related fees on our 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 our 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. It is anticipated that the proposed budget may recommend the repeal of many tax incentives and deductions that are currently used by U.S. oil and gas companies. These provisions could include the 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 been 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 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

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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. Hydraulic fracturing of wells and subsurface water disposal are also under public and governmental scrutiny due to potential environmental and physical impacts, including possible contamination of groundwater and drinking water and possible links to earthquakes. 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 July 2013, the Egyptian military removed President Morsi from power and installed Egypt’s Chief Justice, Adly Mansour, as acting president of a temporary government, which is seeking to set a schedule for new parliamentary and presidential elections in 2014. In January 2014, Egyptians voted on and overwhelmingly approved a new constitution, and Mr. Mansour announced that the presidential election will be held prior to the parliamentary elections. While the date of the presidential election has not been announced, it is expected to be held by mid-April 2014. 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 19 percent of our 2013 production and accounted for 10 percent of our year-end estimated proved reserves. At year-end 2013, 18 percent of our estimated discounted future net cash flows and 8 percent of our net capitalized oil and gas property was attributable to Egypt. These totals reflect our consolidated interests in Egypt including Sinopec’s one-third noncontrolling interest.

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 42 percent of our 2013 production was outside North America, and approximately 32 percent of our estimated proved oil and gas reserves on December 31, 2013 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;

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• 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. Certain 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.

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

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

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

Exploration for and production of crude oil and natural gas can be hazardous, involving natural disasters and other events such as blowouts, cratering, fire and explosion and loss of well control, which can result in damage to or destruction of wells or production facilities, injury to persons, loss of life, or damage to property and the environment. Our international operations are also subject to political risk. The insurance coverage that we maintain against certain losses or liabilities arising from our operations may be inadequate to cover any such resulting liability; moreover, insurance is not available to us against all operational risks.

ITEM 1B. UNRESOLVED STAFF COMMENTS

As of December 31, 2013, 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 THE REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

During 2013, 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 2013 and 2012. 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.

	2013								2012
	Price Range				Dividends Per Share				Price Range				Dividends Per Share
	High		Low		Declared		Paid		High		Low		Declared		Paid
First Quarter	$	86.35	$	72.20	$	0.20	$	0.17	$	112.09	$	91.48	$	0.17	$	0.15
Second Quarter		87.57		67.91		0.20		0.20		102.13		77.93		0.17		0.17
Third Quarter		89.17		75.07		0.20		0.20		94.87		81.55		0.17		0.17
Fourth Quarter		94.84		84.15		0.20		0.20		89.08		74.50		0.17		0.17

The closing price of our common stock, as reported on the New York Stock Exchange Composite Transactions Reporting System for January 31, 2014 (last trading day of the month), was $80.26 per share. As of January 31, 2014, there were 394,724,983 shares of our common stock outstanding held by approximately 5,000 stockholders of record and 313,000 beneficial owners.

We have paid cash dividends on our common stock for 49 consecutive years through December 31, 2013. In the first quarter of 2014 the Board of Directors approved a 25 percent increase to $0.25 per share for the regular quarterly cash dividend on the Company’s common shares. This increase will apply to the dividend on common shares payable on May 22, 2014, to stockholders of record on April 22, 2014, and subsequent dividends paid. 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.

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. Upon conversion of the outstanding Preferred Shares on August 1, 2013, 14.4 million Apache common shares were issued.

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.

On February 5, 2014, the Company’s Board of Directors voted to terminate the Company’s stockholder rights plan. As a result of this decision, the Board approved an amendment to the Rights Agreement that will have the effect of terminating the Rights. The amendment will change the expiration date to March 7, 2014, and, thereby, accelerate the expiration of the Rights. The Company expects that the amendment will be fully executed on March 7, 2014.

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 2014 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, 2008, through December 31, 2013. 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.

	2008		2009		2010		2011		2012		2013
Apache Corporation	$	100.00	$	139.51	$	162.19	$	123.87	$	108.13	$	119.51
S & P’s Composite 500 Stock Index		100.00		126.46		145.51		148.59		172.37		228.19
DJ US Expl & Prod Index		100.00		140.56		164.09		157.22		166.37		219.35

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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, 2013, 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, 2013 numbers in the following table reflect a total of $1.2 billion ($613 million net of tax) in non-cash write-downs of the carrying value of the Company’s U.S., North Sea, and Argentine proved oil and gas properties as a result of ceiling test limitations and a non-cash write-down related to the Company’s exit of operations in Kenya. The 2012 numbers 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. 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.

	As of or for the Year Ended December 31,
	2013		2012		2011		2010		2009
	(In millions, except per share amounts)
Income Statement Data
Total revenues	$	16,054	$	17,078	$	16,888	$	12,092	$	8,615
Net income (loss) attributable to common stock		2,188		1,925		4,508		3,000		(292	)
Net income (loss) per common share:
Basic		5.53		4.95		11.75		8.53		(0.87	)
Diluted		5.50		4.92		11.47		8.46		(0.87	)
Cash dividends declared per common share		0.80		0.68		0.60		0.60		0.60
Balance Sheet Data
Total assets	$	61,637	$	60,737	$	52,051	$	43,425	$	28,186
Long-term debt		9,672		11,355		6,785		8,095		4,950
Total equity		35,393		31,331		28,993		24,377		15,779
Common shares outstanding		396		392		384		382		336

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, and the risk factors and related information set forth in Part I, Item 1A, and Part II, Item 7A 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 exploration and development drilling, supplemented by occasional strategic acquisitions and portfolio high-grading through asset divestitures.

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.

Although 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 sale of assets for all other liquidity needs. In May 2013, the Company announced plans to divest approximately $4 billion of assets by year-end 2013 to enhance financial flexibility and rebalance our portfolio to an asset mix we believe will continue to generate strong returns, drive more predictable growth, and deliver value to our shareholders. By year-end, Apache completed more than $7 billion in asset sales, as discussed in “Operational Developments” below. The Company used the proceeds to pay down nearly $2.6 billion of debt and to repurchase $1 billion of Apache common shares under a 30-million share repurchase program authorized by the Company’s Board of Directors, and we exited the year with nearly $2 billion in cash.

We remain steadfast to the business principles that have guided Apache’s progress since our inception. Throughout the cycles of our industry, our strategic focus on growing a diverse portfolio 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

Continued volatility in the commodity price environment reinforces the importance of our asset portfolio. Our 2013 results reflected the benefit of our product balance, as combined crude oil and liquids represented 54 percent of our production but provided 83 percent of our $16.4 billion of oil and gas production revenues. In

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addition, approximately 65 percent of our 2013 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 WTI-based prices. After the sale of our Gulf of Mexico Shelf assets, less of our U.S. crude oil production is receiving these premium prices, which reduces our overall price realizations.

Results for the year ended December 31, 2013 include:

• Apache reported annual daily production of oil, natural gas, and natural gas liquids averaging 761 Mboe/d. Excluding the impact of the divested Gulf of Mexico Shelf and Canadian assets, production for the year would have increased 2 percent from 2012.

• Liquids production for the year averaged a record 411 Mboe/d, an increase of 4 percent from 396 Mboe/d in 2012. Crude oil accounted for 84 percent of liquids production. North American onshore liquids production increased 34 percent, averaging 179 Mboe/d in 2013 compared to 133 Mboe/d in 2012.

• Oil and gas production revenues totaled $16.4 billion, down $545 million from a record $16.9 billion in 2012, reflecting asset sales and lower realized prices compared to the prior year.

• Net cash provided by operating activities totaled $9.8 billion, an increase of 16 percent compared to 2012.

• Apache reported $2.2 billion in income attributable to common stock, or $5.50 per diluted common share, up from $1.9 billion, or $4.92 per share, in 2012. Earnings for 2013 and 2012 reflect the after-tax impact of oil and gas property write-downs totaling $659 million and $1.4 billion, respectively. For additional discussion regarding these write-downs, please refer to Note 1—Summary of Significant Accounting Policies—“Property and Equipment” 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 $3.2 billion, or $7.92 per diluted common share, down from $3.8 billion, or $9.48 per share, in 2012. 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.

2014 Outlook

As we head into 2014, we remain committed to the Company’s mission. At the end of 2012 and the beginning of 2013, Apache undertook a strategic review of our portfolio with the ultimate goal of focusing our company around the right mix of assets that can consistently generate strong returns, drive more predictable production growth, and create shareholder value. After completing more than $7 billion of divestitures in 2013 and announcing the agreed sale of our Argentine operations in 2014, our growth portfolio is centered on (i) increasing onshore North American liquids production that provides for predictable and attractive rates of return (ii) generating excess free cash flow from our international operations, and (iii) continuing longer-term growth initiatives which include our Wheatstone and Kitimat LNG projects.

We believe our core inventory of exploration and development projects offers numerous growth opportunities. Recent drilling successes and acquisitions of acreage positions across North America have built a robust drilling inventory for our Permian and Central regions that we intend to aggressively target because they are oil-prone and produce liquids-rich gas. Our plan for 2014 also includes further 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.

Our initial 2014 capital budget is approximately $11.6 billion, or $11.1 billion excluding expenditures attributable to a one-third noncontrolling interest in Egypt. Approximately $7.1 billion is expected to be spent on

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projects in North America, with the remaining amount allocated across our international regions. While funds have been committed for certain 2014 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. Approximately $2.4 billion of our 2014 capital will be invested in our Kitimat and Wheatstone LNG projects, reflecting our current project interests. Apache is actively evaluating ways to right-size its level of participation in the Kitimat LNG project.

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 2014 production between 5 percent and 8 percent from full-year 2013 production levels when excluding the divested assets.

Operational Developments

Apache has a significant producing asset base as well as large undeveloped acreage positions that provide a platform for organic growth through sustainable lower-risk drilling opportunities, balanced by higher-risk, higher reward exploration. We are also continuing to advance several longer-term, individually significant development projects.

Exploration, Exploitation, and Development Activities

Our internally generated exploration and drilling opportunities and multi-year development projects provide the foundation for our growth. Highlights of our 2013 drilling successes, exploration discoveries, LNG project milestones, and other opportunities for continued growth include:

North American Activities

Record Drilling Activity in U.S. Onshore Regions During 2013 Apache increased production in the Permian Basin 17 percent relative to 2012 through an active drilling program utilizing an average of 42 rigs. Over half of the region’s production is crude oil and 18 percent is natural gas liquids (NGL). Combined, this represents almost a quarter of Apache’s total liquids production for 2013.

The Central region increased production almost 50 percent relative to 2012 as a result of our active oil and liquids-rich drilling program across our nearly two million gross acres in the Anadarko basin. During the year we operated an average of 27 drilling rigs, and we drilled or participated in drilling 322 gross wells with 98 percent success.

In 2013, U.S. production represented 44 percent of Apache’s total worldwide production, an increase from 40 percent in 2012. Focused drilling programs in the Permian Basin and Anadarko basin continue to provide momentum for Apache’s U.S. production growth.

International Activities

North Sea Development Apache’s North Sea drilling success was highlighted with discoveries in the Tonto field. The Tonto-1 well, completed in April, had initial production of 10.3 Mb/d, and the Tonto-2 well, completed in September, had initial production of 8.3 Mb/d. Apache has a 100 percent working interest in the wells. The Tonto discovery follows Maule and Bacchus as the third new field brought online by Apache in the Forties area over the last three years. All three fields qualify for the U.K.’s small field allowance, which provides economic incentives for operators to bring discoveries from small fields on production.

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Egypt Discoveries In August, Apache announced seven oil and gas discoveries in four different geologic basins in Egypt’s Western Desert. In particular, the Riviera SW-1X discovery in the Abu Gharadig basin test-flowed 5,800 b/d and 2.8 Mcf/d from a Lower Bahariya sand with 24 feet of net pay. All seven discoveries have been tested and six are already producing.

Egypt Horizontal Drilling In 2013, the Company drilled its first well of a multi-well horizontal drilling program in the Abu Gharadig field. During December, this well produced an average of 1,681 b/d and 3 MMcf/d from a 1,970 foot lateral. The well was one of eight wells initiated during 2013 to test horizontal technology to increase recoveries in a variety of conventional and unconventional reservoirs. Additional horizontal drilling is planned in the Abu Gharadig and surrounding fields in 2014.

Australia Discoveries In July, Apache announced its Bianchi-1 natural gas discovery located 4 miles northeast of the 2011 Zola gas discovery offshore Western Australia in the Carnarvon Basin. The well logged 367 feet of net pay in eight reservoir zones between 15,577 and 17,530 feet subsea. Apache is in the early stages of evaluating the discovery and assessing potential commercial opportunities. Apache operates and owns a 30.25 percent working interest in the well.

Australia Macedon During the third quarter of 2013, Apache, along with operator and co-venturer BHP Billiton, officially commenced operations of the $1.5 billion Macedon natural gas facility, of which Apache owns a 28.57 percent interest. Macedon, Western Australia’s fourth domestic gas hub, has a production capacity of approximately 200 MMcf of natural gas per day.

Australia Wheatstone LNG Project On October 1, 2013, Apache and its Australian partners finalized agreements to sell LNG to Tohoku Electric Power Company, Inc. from the Chevron-operated Wheatstone Project in Western Australia. The Wheatstone partners have agreed to supply 0.9 million metric tons per annum of LNG for up to 20 years, which brings the total LNG supplies contracted to approximately 85 percent. Apache owns a 13 percent share in the Wheatstone project.

Acquisition and Divestiture Activity

2014 Activity

Argentina Divestiture On February 12, 2014, Apache subsidiaries announced an agreement to sell all of its operations in Argentina to Sociedad Anónima (YPF) for cash consideration of $800 million plus the assumption of $52 million of bank debt as of June 30, 2013. The transaction is expected to close in the first quarter of 2014.

2013 Activity

Egypt Sinopec Partnership On November 14, 2013, Apache announced the completion of the sale of a one-third minority participation in its Egypt oil and gas business to Sinopec for cash consideration of $2.95 billion after customary closing adjustments. Apache will continue to operate the Egypt upstream oil and gas business. This noncontrolling interest is recorded separately in the Company’s financial statements.

Gulf of Mexico Shelf Divestiture On September 30, 2013, Apache completed the sale of its Gulf of Mexico Shelf operations and properties to Fieldwood, an affiliate of Riverstone Holdings. Under the terms of the agreement, Apache received cash consideration of $3.7 billion, and Fieldwood assumed $1.5 billion of discounted asset abandonment liabilities. Additionally, Apache retained 50 percent of its ownership interest in all exploration blocks and in horizons below production in developed blocks. Total region production in 2013 was 71 Mboe/d, reflecting nine months of Shelf production prior to the divestiture.

Canadian Divestitures In September, Apache completed the sale of primarily dry gas assets in Alberta for $214 million. The sale includes 621,000 gross acres (530,000 net acres) and more than 2,700 wells. Additionally in October of 2013, Apache completed two additional sales of Canadian oil and gas production properties for $112 million. The assets comprise approximately 4,000 operated and 1,300 non-operated wells. Combined, our 2013 divestitures totaled 13 percent of the region’s production.

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Kitimat LNG Project In February 2013, Apache completed a transaction with Chevron Canada Limited (Chevron Canada) under which each company became a 50 percent owner of the Kitimat LNG plant, the Pacific Trail Pipelines Limited Partnership (PTP), and 644,000 gross undeveloped acres in the Horn River and Liard basins. Chevron Canada will operate the LNG plant and pipeline while Apache Canada will continue to operate the upstream assets. Apache’s net proceeds from the transaction were $396 million after post-closing adjustments.

For detailed information regarding our recent divestitures, please refer to Note 2—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.

2012 Activity

Cordillera Energy Partners III, LLC Acquisition 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. 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.

Yara Pilbara Holdings Pty 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. Yara Australia Pty Ltd (Yara) owns the remaining 51 percent of YPHPL and operates the plant.

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Results of Operations

Oil and Gas Revenues

Apache’s oil and gas revenues by regions are as follows:

	For the Year Ended December 31,
	2013					2012					2011
	$ Value		% Contribution			$ Value		% Contribution			$ Value		% Contribution
	($ in millions)
Total Oil Revenues:
United States	$	5,262		41	%	$	4,662		35	%	$	4,163		33	%
Canada		563		4	%		492		4	%		485		4	%
North America		5,825		45	%		5,154		39	%		4,648		37	%
Egypt(3)		3,528		27	%		4,050		31	%		4,169		33	%
Australia		779		6	%		1,218		9	%		1,552		12	%
North Sea		2,500		20	%		2,517		19	%		2,072		16	%
Argentina		271		2	%		271		2	%		238		2	%
International(3)		7,078		55	%		8,056		61	%		8,031		63	%
Total(1)(3)	$	12,903		100	%	$	13,210		100	%	$	12,679		100	%
Total Gas Revenues:
United States	$	1,096		38	%	$	1,169		37	%	$	1,550		43	%
Canada		587		21	%		751		23	%		1,033		29	%
North America		1,683		59	%		1,920		60	%		2,583		72	%
Egypt(3)		389		14	%		504		16	%		621		17	%
Australia		361		13	%		357		11	%		182		5	%
North Sea		194		7	%		188		6	%		19		0	%
Argentina		202		7	%		224		7	%		204		6	%
International(3)		1,146		41	%		1,273		40	%		1,026		28	%
Total(2)(3)	$	2,829		100	%	$	3,193		100	%	$	3,609		100	%
NGL Revenues:
United States	$	544		81	%	$	395		73	%	$	391		75	%
Canada		74		11	%		79		14	%		99		19	%
North America		618		92	%		474		87	%		490		94	%
Egypt(3)		—		—			—		0	%		1		0	%
North Sea		34		5	%		46		8	%		—		—
Argentina		18		3	%		24		5	%		31		6	%
International(3)		52		8	%		70		13	%		32		6	%
Total(3)	$	670		100	%	$	544		100	%	$	522		100	%
Total Oil and Gas Revenues:
United States	$	6,902		42	%	$	6,226		37	%	$	6,104		36	%
Canada		1,224		8	%		1,322		8	%		1,617		10	%
North America		8,126		50	%		7,548		45	%		7,721		46	%
Egypt(3)		3,917		24	%		4,554		27	%		4,791		29	%
Australia		1,140		7	%		1,575		9	%		1,734		10	%
North Sea		2,728		16	%		2,751		16	%		2,091		12	%
Argentina		491		3	%		519		3	%		473		3	%
International(3)		8,276		50	%		9,399		55	%		9,089		54	%
Total(3)	$	16,402		100	%	$	16,947		100	%	$	16,810		100	%

⁽¹⁾  Financial derivative hedging activities decreased 2013, 2012, and 2011 oil revenues $47 million, $146 million, and $379 million, respectively.

⁽²⁾  Financial derivative hedging activities increased 2013, 2012, and 2011 natural gas revenues $31 million, $414 million, and $272 million, respectively.

⁽³⁾  2013 includes revenues attributable to a noncontrolling interest in Egypt.

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Production

The following table presents production volumes by region:

	For the Year Ended December 31,
	2013		Increase (Decrease)			2012		Increase (Decrease)			2011
Oil Volume—b/d:
United States		146,907		10	%		134,123		12	%		119,415
Canada		17,724		12	%		15,830		11	%		14,252
North America		164,631		10	%		149,953		12	%		133,667
Egypt(1)(2)		89,561		(10	%)		99,756		(4	%)		103,912
Australia		19,329		(33	%)		28,884		(24	%)		38,228
North Sea		63,721		0	%		63,692		17	%		54,541
Argentina		9,375		(4	%)		9,741		2	%		9,597
International		181,986		(10	%)		202,073		(2	%)		206,278
Total		346,617		(2	%)		352,026		4	%		339,945
Natural Gas Volume—Mcf/d:
United States		781,335		(9	%)		854,099		(1	%)		864,742
Canada		497,515		(17	%)		600,680		(5	%)		632,550
North America		1,278,850		(12	%)		1,454,779		(3	%)		1,497,292
Egypt(1)(2)		356,454		1	%		353,738		(3	%)		365,418
Australia		223,433		4	%		214,013		16	%		185,079
North Sea		50,961		(11	%)		57,457		NM			2,284
Argentina		187,390		(12	%)		213,464		1	%		212,311
International		818,238		(2	%)		838,672		10	%		765,092
Total		2,097,088		(9	%)		2,293,451		1	%		2,262,384
NGL Volume—b/d:
United States		54,580		63	%		33,527		52	%		22,111
Canada		6,689		7	%		6,258		5	%		5,958
North America		61,269		54	%		39,785		42	%		28,069
Egypt		—		0	%		—		NM			49
North Sea		1,272		(21	%)		1,618		NM			4
Argentina		2,102		(30	%)		3,008		0	%		3,018
International		3,374		(27	%)		4,626		51	%		3,071
Total		64,643		46	%		44,411		43	%		31,140
BOE per day(3)
United States		331,709		7	%		310,000		9	%		285,650
Canada		107,332		(12	%)		122,201		(3	%)		125,636
North America		439,041		2	%		432,201		5	%		411,286
Egypt(2)		148,970		(6	%)		158,713		(4	%)		164,864
Australia		56,568		(12	%)		64,552		(7	%)		69,074
North Sea		73,487		(2	%)		74,887		36	%		54,925
Argentina		42,709		(12	%)		48,326		1	%		48,000
International		321,734		(7	%)		346,478		3	%		336,863
Total		760,775		(2	%)		778,679		4	%		748,149

(1)      Gross oil production and gross natural gas production in Egypt for 2013, 2012, and 2011 was as follows:
	2013		2012		2011
Oil (b/d)		197,622		213,112		217,207
Gas (Mcf/d)		912,478		899,972		865,485
(2)      Includes 2013 production volumes per day attributable to a noncontrolling interest in Egypt of:
Oil (b/d)		3,912
Gas (Mcf/d)		16,494

⁽³⁾      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

The following table presents pricing information by region:

	For the Year Ended December 31,
	2013		Increase (Decrease)			2012		Increase (Decrease)			2011
Average Oil Price—Per barrel
United States	$	98.14		3	%	$	94.98		(1	%)	$	95.51
Canada		87.00		2	%		84.89		(9	%)		93.19
North America		96.94		3	%		93.91		(1	%)		95.27
Egypt		107.94		(3	%)		110.92		1	%		109.92
Australia		110.42		(4	%)		115.22		4	%		111.22
North Sea		107.48		0	%		107.97		4	%		104.09
Argentina		79.05		4	%		75.89		12	%		68.02
International		106.55		(2	%)		108.92		2	%		106.67
Total(1)		101.99		(1	%)		102.53		0	%		102.19
Average Natural Gas Price—Per Mcf:
United States	$	3.84		3	%	$	3.74		(24	%)	$	4.91
Canada		3.23		(6	%)		3.42		(23	%)		4.47
North America		3.61		0	%		3.61		(24	%)		4.72
Egypt		2.99		(23	%)		3.90		(16	%)		4.66
Australia		4.43		(3	%)		4.55		69	%		2.69
North Sea		10.43		17	%		8.95		(60	%)		22.25
Argentina		2.96		3	%		2.87		9	%		2.64
International		3.84		(7	%)		4.15		13	%		3.67
Total(2)		3.70		(3	%)		3.80		(13	%)		4.37
Average NGL Price—Per barrel
United States	$	27.29		(15	%)	$	32.19		(34	%)	$	48.42
Canada		30.50		(12	%)		34.63		(24	%)		45.72
North America		27.64		(15	%)		32.57		(32	%)		47.85
Egypt		—		—			—		NM			66.36
North Sea		73.06		(5	%)		77.11		18	%		65.45
Argentina		23.64		10	%		21.55		(23	%)		27.90
International		42.27		3	%		40.98		43	%		28.56
Total		28.40		(15	%)		33.45		(27	%)		45.95

⁽¹⁾  Reflects a per-barrel decrease of $0.37, $1.13, and $3.05 in 2013, 2012, and 2011, respectively, from financial derivative hedging activities.

⁽²⁾  Reflects a per-Mcf increase of $0.04, $0.49, and $0.33 in 2013, 2012, and 2011, 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. Average realized crude oil prices for 2013 were essentially flat compared to 2012, although prices fluctuated throughout the year.

Continued volatility in the commodity price environment reinforces the importance of our diverse portfolio. 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

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generally move in the same direction. Crude oil prices realized in 2013 averaged $101.99 per barrel; however, International Dated Brent crudes and sweet crude from the U.S. Gulf Coast continue to be priced at a premium to WTI-based prices. In 2013 we realized these premium prices on approximately 65 percent of our crude oil production. Our Egypt, Australia, and North Sea regions, which collectively comprised 50 percent of our 2013 worldwide oil production, received International Dated Brent pricing with 2013 oil realizations averaging $108.04 per barrel compared with 2012 oil realizations averaging $110.59 per barrel.

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. Our primary markets include North America, Egypt, Australia, the U.K., 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. Our North American regions averaged $3.61 per Mcf in 2013, unchanged from 2012 levels.

• 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 $2.99 per Mcf in 2013, down 23 percent from the prior year.

• 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. During 2013, the region averaged $4.43 per Mcf, a 3 percent decrease from 2012 levels.

• 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 $10.43 per Mcf in 2013, a 17 percent increase from an average of $8.95 per Mcf in 2012.

• During 2013, we realized an average price of $2.96 per Mcf in Argentina, an increase of 3 percent over the 2012 average price of $2.87 per Mcf.

NGL Prices

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

Crude Oil Revenues

2013 vs. 2012 During 2013 crude oil revenues totaled $12.9 billion, $307 million lower than the 2012 total of $13.2 billion, driven by a 2 percent decrease in worldwide production. Average daily production in 2013 was 346.6 Mb/d, with prices averaging $101.99 per barrel. Crude oil represented 79 percent of our 2013 oil and gas production revenues and 46 percent of our equivalent production, compared to 78 and 45 percent, respectively, in the prior year. Lower production volumes reduced revenues $237 million, while slightly lower realized prices reduced revenues an additional $70 million.

Worldwide oil production decreased 5.4 Mb/d, however, when excluding the Gulf of Mexico Shelf and Canadian assets that we sold during the year, oil production increased 3.6 Mb/d, driven by growth of 23.7 Mb/d from our North American regions. Our Permian and Central regions increased production by 11.9 Mb/d and 8.6

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Mb/d, respectively, as a result of drilling and recompletion activity. Production from our remaining property base in Canada increased 1.9 Mb/d, or 12 percent, as a result of our continued focus on liquids-rich drilling targets. These increases were partially offset by a 20.1 Mb/d decrease in production from our international regions. Oil production from Egypt decreased 10.2 Mb/d, of which 7.8 Mb/d was related production used to pay taxes and, under the terms of our production sharing contracts, has no economic impact to Apache. Australia’s production decreased 9.6 Mb/d as a result of natural decline from our Pyrenees and Van Gogh fields.

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 4 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 and recompletion activity. The Central region increased 7.4 Mb/d on properties added from the Cordillera acquisition and drilling and recompletion activity. 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.

Natural Gas Revenues

2013 vs. 2012 Natural gas revenues of $2.8 billion for 2013 were $364 million lower than 2012, the result of a 9 percent decrease in production volumes and a 3 percent decrease in realized prices. Worldwide production decreased 196.4 MMcf/d, lowering revenues by $273 million. Realized prices in 2013 averaged $3.70 per Mcf, a decrease of $0.10 per Mcf, which reduced revenues by an additional $91 million.

Worldwide gas production decreased 9 percent; however, excluding production from the Gulf of Mexico Shelf and Canadian assets sold during the year, gas production declined only 3 percent, or 60 MMcf/d. Production declined 66 MMcf/d from our remaining properties in Canada, a result of a shift in our drilling and recompletion activity from dry gas to liquids-rich gas properties. Argentina production decreased 26 MMcf/d on lower capital investments pending negotiations of extensions of several of our concessions, and production from our U.S. Deepwater region decreased 26 MMcf/d on natural decline. These decreases were partially offset by production increases of 52.6 MMcf/d in our U.S. onshore regions resulting from drilling activity focusing on liquids-rich targets, 9.4 MMcf/d in Australia on volumes from our Macedon field discovery, which commenced operations in the third quarter, and 2.7 MMcf/d in Egypt.

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 1 percent increase in production volumes. Realized prices in 2012 averaged $3.80 per Mcf, a decrease of $0.57 per Mcf, which reduced revenues by $467 million. Worldwide production rose 31.1 MMcf/d, adding $51 million to revenues.

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 Gulf of Mexico 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.

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NGL Revenues

2013 vs. 2012 NGL revenues totaled $670 million in 2013, an increase of $126 million from 2012, the result of a 46 percent increase in production volumes partially offset by a 15 percent decrease in realized prices. Worldwide production rose 20.2 Mb/d, adding $208 million to revenues. This increase was primarily driven by drilling and recompletion activity in the U.S. Central and Permian regions. Realized prices in 2013 averaged $28.40 per Mcf barrel, a decrease of $5.05 per barrel, which reduced revenues by $82 million.

2012 vs. 2011 NGL revenues totaled $544 million in 2012, an increase of $22 million from 2011, the result of a 43 percent increase in production volumes partially offset by a 27 percent decrease in realized prices. Worldwide production rose 13.3 Mb/d, adding $164 million to revenues. This increase was driven by drilling and recompletion activity in the U.S. Central and Permian regions and production from the Cordillera acquisition in the Central region. Realized prices in 2012 averaged $33.45 per Mcf barrel, a decrease of $12.50 per barrel, which reduced revenues by $142 million.

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. All 2013 operating expenses include costs attributable to a noncontrolling interest in Egypt.

	For the Year Ended December 31,
	2013		2012		2011		2013		2012		2011
			(In millions)						(Per boe)
Depreciation, depletion and amortization:
Oil and gas property and equipment
Recurring	$	5,114	$	4,812	$	3,814	$	18.42	$	16.88	$	13.97
Additional		1,176		1,926		109		4.24		6.76		0.40
Other assets		410		371		281		1.47		1.30		1.03
Asset retirement obligation accretion		243		232		154		0.88		0.81		0.56
Lease operating costs		3,056		2,968		2,605		11.00		10.41		9.54
Gathering and transportation costs		297		303		296		1.06		1.08		1.08
Taxes other than income		832		862		899		3.00		3.02		3.29
General and administrative expense		503		531		459		1.81		1.86		1.68
Acquisitions, divestitures & transition		33		31		20		0.12		0.11		0.07
Financing costs, net		174		165		158		0.63		0.58		0.58
Total	$	11,838	$	12,201	$	8,795	$	42.63	$	42.81	$	32.20

Recurring Depreciation, Depletion and Amortization (DD&A)

The following table details the changes in recurring DD&A of oil and gas properties between December 31, 2011, and December 31, 2013:

	Recurring DD&A
	(In millions)
2011 DD&A	$	3,814
Volume change		231
DD&A Rate change		767
2012 DD&A	$	4,812
Volume change		(83	)
DD&A Rate change		385
2013 DD&A	$	5,114

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2013 vs. 2012 Recurring full-cost depletion expense increased $302 million on an absolute dollar basis: $385 million on rate partially offset by a decrease of $83 million from lower volumes. Our full-cost depletion rate increased $1.54 to $18.42 per boe reflecting acquisition and drilling costs that exceed our historical levels.

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.

Additional DD&A

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.

In 2013 we recorded non-cash write-downs of the carrying value of the Company’s proved oil and gas properties totaling $1.1 billion. The after-tax impact of these write-downs was $356 million in the U.S., $139 million in the North Sea, and $118 million in Argentina. During the year, the Company also exited operations in Kenya and recorded $46 million net of tax to additional DD&A related to the impairment of the carrying value of the Kenyan oil and gas property leases.

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). The Company also recorded $28 million of additional DD&A 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 but has not yet established a presence.

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 rig rates, labor, boats, helicopters, materials, and supplies. Oil, which contributed nearly half of our 2013 production, is inherently more expensive to produce than natural gas. Repair and maintenance costs are typically higher on offshore properties in Australia, the North Sea and the U.S. Gulf of Mexico regions.

45

The following table identifies changes in Apache’s LOE rate from 2011 to 2013:

For the Year Ended December 31, 2013				For the Year Ended December 31, 2012
	Per boe				Per boe
2012 LOE	$	10.41		2011 LOE	$	9.54
Divestitures(1)		(0.12	)	Repairs and maintenance		0.39
Power and fuel costs		0.19		Labor and pumper costs		0.31
Labor and overhead costs		0.17		Non-operated property costs		0.12
Non-operated property costs		0.13		Workover costs		0.06
Transportation		0.12		Other		0.10
Workover costs		0.07		Other decreased production		0.01
Repairs and maintenance		0.07		Acquisitions(1)		(0.12	)
Other		0.11
Other increased production		(0.15	)
2013 LOE	$	11.00		2012 LOE	$	10.41

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

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,
	2013		2012		2011
	(In millions)
Canada	$	155	$	163	$	166
U.S.		84		69		64
Egypt		42		39		34
North Sea		7		24		25
Argentina		9		8		7
Total Gathering and transportation	$	297	$	303	$	296

2013 vs. 2012 Gathering and transportation costs decreased $6 million from 2012. The U.S. costs for 2013 increased $15 million as compared to 2012 primarily as a result of increased production in the Permian and Central region from increased drilling activity. Egypt costs were up $3 million from increases in the world scale freight rates. North Sea costs decreased $17 million. Canada’s costs decreased $8 million from a decline in activity.

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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.

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 qualifying 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 and Saskatchewan Resources surtax. The table below presents a comparison of these expenses:

	For the Year Ended December 31,
	2013		2012		2011
	(In millions)
U.K. PRT	$	382	$	451	$	538
Severance taxes		254		220		212
Ad valorem taxes		113		104		94
Other		83		87		55
Total Taxes other than income	$	832	$	862	$	899

2013 vs. 2012 Taxes other than income were $30 million lower than 2012. U.K. PRT decreased $69 million over the comparable 2012 period based on a decrease in production revenues from qualifying fields during the year. Prior-year property acquisitions and higher drilling activity resulted in increases of $34 million and $9 million to severance and ad valorem tax expense, respectively.

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.

General and Administrative Expenses

2013 vs. 2012 General and administrative (G&A) expenses decreased $28 million, or 5 percent, from 2012. On a per-unit basis, G&A expenses were down $0.05 to $1.86 per boe, with the benefit of lower costs partially offset by the impact of lower production.

2012 vs. 2011 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 relates to growth-related increases, less $0.08 on increased production.

Acquisitions, Divestitures, and Transition Costs

In 2013, the Company recognized $33 million in acquisitions, divestitures, and transition costs related to the sale of our Gulf of Mexico Shelf assets to Fieldwood and our partnership with Sinopec in Egypt.

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

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In 2011, the Company recognized $20 million in acquisitions, divestitures, and 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.

Financing Costs, Net

Financing costs incurred during the period comprised the following:

	For the Year Ended December 31,
	2013			2012			2011
	(In millions)
Interest expense	$	571		$	509		$	433
Amortization of deferred loan costs		8			7			5
Capitalized interest		(374	)		(334	)		(263	)
Gain on extinguishment of debt		(16	)		—			—
Interest income		(15	)		(17	)		(17	)
Total Financing costs, net	$	174		$	165		$	158

2013 vs. 2012 Net financing costs increased $9 million from 2012. The increase is primarily related to a $62 million increase in interest expense from debt issuances during 2012, partially offset by a $40 million increase in capitalized interest resulting from additional unproved property balances in the Central and Permian regions. Additionally, Apache realized a gain of $16 million related to debt extinguished during 2013.

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.

Provision for Income Taxes

The 2013 provision for income taxes totaled $1.9 billion, representing an effective tax rate of 45.7 percent. The 2013 effective rate reflects the tax benefit from the $1.2 billion non-cash write-downs in the U.S., North Sea, Argentina, and Kenya, impacts from foreign currency fluctuations and a $225 million charge related to distributed foreign earnings and other adjustments. Excluding these items, the 2013 effective tax rate would have been 42 percent.

The 2012 provision for income taxes totaled $2.9 billion, representing an effective tax rate of 59.0 percent. The 2012 effective rate reflects the tax impact from the $1.9 billion Canadian non-cash write-down, a $118 million charge for a North Sea decommissioning tax rate change and other tax adjustments primarily associated with valuation allowances in Canada and Argentina. Excluding these items, the 2012 effective tax rate would have been 44 percent, approximately comparable with the current year rate and the 2011 effective rate of 43 percent.

For additional information regarding income taxes, please refer to Note 7—Income Taxes 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.

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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. Cash investments are required to fund activity necessary to offset the inherent declines in production and proved 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.

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.

In May 2013, Apache announced that it would divest approximately $4 billion in assets to enhance financial flexibility and rebalance our portfolio to an asset mix we believe will continue to generate strong returns, drive predictable growth, and deliver value to our shareholders. As of year-end 2013, Apache completed more than $7 billion in asset sales and used the proceeds to pay down nearly $2.6 billion in debt and to repurchase $1 billion in Apache common shares under a 30-million share repurchase program authorized by the Company’s Board of Directors. The Company ended the year with nearly $2 billion of cash on hand.

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.

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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,
	2013		2012			2011
	(In millions)
Sources of Cash and Cash Equivalents:
Net cash provided by operating activities	$	9,835	$	8,504		$	9,953
Commercial paper and bank loan borrowings, net		—		549			—
Sale of Gulf of Mexico Shelf properties		3,702		—			—
Proceeds from sale of Egypt noncontrolling interest		2,948		—			—
Proceeds from Kitimat LNG transaction, net		396		—			—
Proceeds from sale of oil and gas properties, other		307		27			422
Fixed-rate debt borrowings		—		4,978			—
Other		21		—			84
		17,209		14,058			10,459
Uses of Cash and Cash Equivalents:
Capital expenditures(1)	$	11,220	$	9,531		$	7,078
Acquisitions		215		2,918			1,813
Equity investment in Yara Pilbara Holdings Pty Limited (YPHPL)		—		439			—
Commercial paper, credit facility and bank loan repayments, net		513		—			925
Dividends paid		360		332			306
Shares repurchased		997		—			—
Payments on fixed-rate debt		2,072		400			—
Other		86		573			176
		15,463		14,193			10,298
Increase (decrease) in cash and cash equivalents	$	1,746	$	(135	)	$	161

⁽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 that determine operating cash flows are largely the same as those that affect net earnings, with the exception of non-cash expenses such as DD&A, asset retirement obligation (ARO) accretion, and deferred income tax expense, which affect earnings but do not affect cash flows.

Net cash provided by operating activities for 2013 totaled $9.8 billion, up $1.3 billion from 2012. The increase reflects comparative changes in working capital during the periods.

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.

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Proceeds from Sale of Oil and Gas Properties and Noncontrolling Interest in Egypt

During 2013 Apache completed the sale of certain properties in Canada and the U.S. for $4.4 billion. Apache also completed the sale of a one-third minority participation in its Egypt oil and gas business to Sinopec for $2.95 billion. For information regarding our acquisitions and divestitures, 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 Investments

We fund exploration and development (E&D) 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 and find high-margin reserves at competitive prices. As a majority of our exploration and development activity is discretionary, we routinely adjust our capital budget on a quarterly basis in response to changing market conditions and operating cash flow forecasts.

We have used a combination of operating cash flows, borrowings under lines of credit and our commercial paper program, and occasionally, issues of public debt or common stock to fund other significant capital investments.

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

	For the Year Ended December 31,
	2013		2012		2011
	(In millions)
Exploration and Development:
United States	$	5,473	$	5,151	$	2,768
Canada		720		590		817
North America		6,193		5,741		3,585
Egypt(1)		1,166		1,074		896
Australia		1,179		873		576
North Sea		874		886		823
Argentina		182		289		346
Other International		22		98		61
International(1)		3,423		3,220		2,702
Worldwide E&D Costs(1)		9,616		8,961		6,287
Gathering, Transmission, and Processing Facilities (GTP):
United States		169		75		27
Canada		135		172		148
Egypt(1)		82		33		111
Australia		745		441		345
Argentina		11		16		12
North Sea		1		1		—
Total GTP Costs(1)		1,143		738		643
Asset Retirement Costs		484		948		819
Capitalized Interest		374		334		263
Capital Expenditures	$	11,617	$	10,981	$	8,012
Acquisitions, including GTP	$	377	$	3,543	$	3,189
Asset Retirement Costs—Acquired		53		84		592
Total Acquisitions	$	430	$	3,627	$	3,781

⁽¹⁾ Includes 2013 capital costs attributable to a noncontrolling interest in Egypt.

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Exploration and Development Worldwide E&D expenditures for 2013 totaled $9.6 billion, or 7 percent above 2012. E&D spending in North America was up 8 percent from the prior year and totaled 64 percent of worldwide E&D spending. Expenditures in the U.S. reflect increased drilling activity in the Anadarko basin and Permian Basin, where we continue to shift to more horizontal drilling. In the Permian Basin, we averaged operating 42 rigs during the year. Our recent drilling successes in the Permian has led the region to increase the number of horizontal drilling rigs being utilized throughout 2013, and now approximately half of our rigs are drilling horizontal wells that, given their nature, are more costly than vertical wells. In our Central region we have increased our activity in the Whittenburg and Anadarko basins where our active drilling programs continued to expand. E&D spending in Canada increased 22 percent from the prior-year period as the region has continued to target oil and liquids-rich gas plays across its acreage and drilling more horizontal wells.

E&D expenditures outside of North America increased 6 percent over 2012. Australian expenditures were up $306 million as both exploration and development drilling continued with high activity levels. Egypt was $92 million higher than the prior year on continued drilling activity across all major basins. E&D spending in the North Sea was up $12 million on Beryl field development activity, following the field’s acquisition at the end of 2011. Argentina expenditures were down $107 million on decreased drilling activity.

Gathering, Transmission and Processing Facilities We invested $1.1 billion in GTP in 2013 compared to $738 million in 2012, primarily related to activities associated with the Wheatstone LNG project in Australia.

Acquisitions We acquired $377 million of oil and gas properties and GTP in 2013 compared to $3.5 billion in 2012. Acquisition capital expenditures occur as attractive opportunities arise and, therefore, vary from year to year. For information regarding our acquisitions and divestitures, 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.

Payments on Fixed-Rate Debt

During 2013, Apache repaid the $500 million aggregate principal amount of its 5.25 percent notes that matured on April 15, 2013 and the $400 million aggregate principal amount of its 6.00 percent notes that matured on September 15, 2013 by borrowing under our commercial paper program.

In November 2013 the Company announced a cash tender offer to purchase up to $850 million aggregate principal amount of five series of its outstanding notes. On December 20, 2013, the Company accepted for purchase $669 million principal amount of its 2.625 percent notes due 2023 and $181 million principal amount of its 3.25 percent notes due 2022. Apache paid the holders an aggregate of approximately $811 million in cash reflecting principal, the discount to par, and accrued and unpaid interest.

In December 2013, Apache Finance Canada Corporation (Apache Finance Canada) fully redeemed $350 million principal amount of its 4.375 percent notes due in 2015. The notes were redeemed pursuant to the provisions of the notes’ indenture. Apache paid the holders an aggregate of approximately $371 million in cash reflecting principal, the premium to par, and accrued and unpaid interest.

Dividends

The Company has paid cash dividends on its common stock for 49 consecutive years through 2013. Future dividend payments will depend on the Company’s level of earnings, financial requirements, and other relevant factors. Common stock dividends paid during 2013 totaled $303 million, compared with $256 million in 2012 and $230 million in 2011. The Company paid dividends on its Series D Preferred Stock totaling $57 million in 2013, compared with $76 million in each 2012 and 2011. The preferred stock was converted to common stock in August 2013.

In the first quarter of 2013 the Board of Directors approved an 18 percent increase to $0.20 per share for the regular quarterly cash dividend on the Company’s common shares. This increase first applied to the dividend on common shares payable on May 22, 2013, to stockholders of record on April 22, 2013, and subsequent dividends paid.

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In the first quarter of 2014 the Board of Directors approved a 25 percent increase to $0.25 per share for the regular quarterly cash dividend on the Company’s common shares. This increase will apply to the dividend on common shares payable on May 22, 2014, to stockholders of record on April 22, 2014, and subsequent dividends paid.

Shares Repurchased

In May 2013, Apache’s Board of Directors authorized the purchase of up to 30 million shares of the Company’s common stock, valued at approximately $2 billion when first announced. Shares may be purchased either in the open market or through privately held negotiated transactions. The Company initiated the buyback program on June 10, 2013, with the repurchase of 2,924,271 shares at an average price of $85.47 during the month of June. During the fourth quarter of 2013, 8,297,648 shares were repurchased at an average price of $90.08. An additional 2,393,917 shares were purchased subsequent to December 31, 2013 at an average cost of $84.67. The Company anticipates that further purchases will primarily be made with proceeds from asset dispositions, but the Company is not obligated to acquire any specific number of shares.

Liquidity

	At December 31,
	2013			2012
	(In millions, except percentages)
Cash and cash equivalents	$	1,906		$	160
Total debt		9,725			12,345
Equity		35,393			31,331
Available committed borrowing capacity		3,300			2,811
Floating-rate debt/total debt		1	%		5	%
Percent of total debt-to-capitalization		22	%		28	%

Cash and Cash Equivalents

At December 31, 2013, we had $1.9 billion in cash and cash equivalents, of which $1.7 billion of cash was held by foreign subsidiaries, and approximately $158 million was held by Apache Corporation and U.S. subsidiaries. The cash held by foreign subsidiaries is subject to additional U.S. income taxes if repatriated. Almost all of the cash is denominated in U.S. dollars and, at times, is invested in highly liquid, investment-grade securities with maturities of three months or less at the time of purchase. We intend to use cash from our international subsidiaries to fund international projects.

Debt

At December 31, 2013, outstanding debt, which consisted of notes, debentures, and uncommitted bank lines, totaled $9.7 billion. Current debt consists of $53 million borrowed under uncommitted money market and overdraft lines of credit in Argentina and Canada. We have $900 million of debt maturing in 2017, $550 million maturing in 2018 and the remaining $8.3 billion maturing intermittently in years 2019 through 2096.

Available Credit Facilities

As of December 31, 2013, 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 in the U.S., a $300 million facility in Australia, and a $300 million facility in Canada. In July 2013, we amended our $1.0 billion U.S. credit facility to conform certain representations, covenants, and events of default to those in our $1.7 billion U.S. credit

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facility. The amendments did not affect the amount or repayment terms of the $1.0 billion U.S. facility. As of December 31, 2013, aggregate available borrowing capacity under the Company’s credit facilities was $3.3 billion. The Company’s committed credit facilities are used to support Apache’s commercial paper program.

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, 2013, 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, 2013, the Company’s debt-to-capitalization ratio was 22 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 $3.1 billion as of December 31, 2013. 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, 2013.

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 25 banks in our bank group. Having a large bank group allows the Company to mitigate the potential impact of any bank’s failure to honor its lending commitment.

Commercial Paper Program

The Company has available a $3.0 billion commercial paper program, which generally enables Apache to borrow funds for up to 270 days at competitive interest rates. The commercial paper program is fully supported by available borrowing capacity under committed credit facilities. Our 2013 weighted-average interest rate for commercial paper was 0.38 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, 2013, the Company had no outstanding commercial paper. At December 31, 2012, the Company had $489 million in commercial paper outstanding.

Letter of Credit Collateral

In the event Apache’s credit rating is downgraded by Moody’s and S&P, Apache will need to provide a letter of credit as collateral to secure certain abandonment obligations. In conjunction with the Forties field and Mobil North Sea Limited acquisitions in 2003 and 2012, respectively, Apache assumed the abandonment

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obligation of each seller for those properties. Although not currently required, to ensure Apache’s payment of these costs, Apache agreed to deliver a letter of credit to the applicable seller if the rating of Apache’s senior unsecured debt is lowered by both Moody’s and Standard and Poor’s to ratings specified in the agreement with such seller.

Total Debt-to-Capitalization

The Company’s debt-to-capitalization ratio as of December 31, 2013, was 22 percent as compared to 28 percent at December 31, 2012. The decrease in our debt-to-capitalization ratio is directly related to the 2013 payment of fixed and floating debt and repurchase of shares. 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.

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.

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.

Contractual Obligations

The following table summarizes the Company’s contractual obligations as of December 31, 2013. 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		2014		2015-2016		2017-2018		2019 & Beyond
	(In millions)
Debt, at face value		Note 6	$	9,784	$	53	$	1	$	1,450	$	8,280
Interest payments		Note 6		10,234		482		965		907		7,880
Drilling rig commitments(2)		Note 8		974		376		429		157		12
Purchase obligations(3)		Note 8		1,759		1,002		533		204		20
Firm transportation agreements		Note 8		683		158		223		129		173
Office and related equipment		Note 8		391		46		101		95		149
Other operating lease obligations(4)		Note 8		686		190		295		193		8
Total Contractual Obligations			$	24,511	$	2,307	$	2,547	$	3,135	$	16,522

⁽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,

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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.

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 $93 million for environmental remediation and approximately $10 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 $79 million accrued as of December 31, 2013, 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 an annual aggregate of $300 million.

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, 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 $856 million of coverage to Apache for losses arising from confiscation, nationalization, and expropriation risks, with a $149 million sub-limit for currency inconvertibility.

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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.

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,
	2013			2012		2011
	(In millions, except per share data)
Income (Loss) Attributable to Common Stock (GAAP)	$	2,188		$	1,925	$	4,508
Adjustments:
Oil & gas property write-downs, net of tax(1)		659			1,427		60
Deferred tax on distributed foreign earnings		225			—		—
Deferred tax adjustments		58			226		(75	)
U.K. income tax adjustments		—			118		218
Commodity derivative mark-to-market, net of tax(2)		142			51		—
Acquisitions, divestitures, and transition, net of tax(3)		21			19		13
Unrealized foreign currency fluctuation impact on deferred tax expense		(123	)		1		(73	)
Adjusted Earnings (Non-GAAP)	$	3,170		$	3,767	$	4,651
Net Income per Common Share—Diluted (GAAP)	$	5.50		$	4.92	$	11.47
Adjustments:
Oil & gas property write-downs, net of tax(1)		1.63			3.53		0.15
Deferred tax on distributed foreign earnings		0.55			—		—
Deferred tax adjustments		0.14			0.56		(0.19	)
U.K. income tax adjustments		—			0.30		0.55
Commodity derivative mark-to-market, net of tax(2)		0.35			0.13		—
Acquisitions, divestitures, and transition, net of tax(3)		0.05			0.04		0.03
Unrealized foreign currency fluctuation impact on deferred tax expense		(0.30	)		—		(0.18	)
Adjusted Earnings Per Share—Diluted (Non-GAAP)	$	7.92		$	9.48	$	11.83

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⁽¹⁾  Write-downs of our U.S., North Sea, and Argentina proved oil and gas property balances of $552 million, $368 million, and $181 million, respectively, were recorded in 2013, for which tax benefits of $196 million, $229 million, and $63 million, respectively, were recognized. Separately, a $75 million non-cash write-down was recorded related to the Company’s exit of operations in Kenya, for which a tax benefit of $29 million was recognized. 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⁾  Commodity derivative mark-to-market losses recorded in 2013 totaled $221 million, for which a tax benefit of $79 million was recognized.

⁽³⁾  Acquisitions, divestitures, and transition costs recorded in 2013, 2012, and 2011, totaled $33 million, $31 million, and $20 million, respectively, for which tax benefits of $12 million, $12 million, and $7 million, respectively, were recognized. The tax effect was calculated utilizing the statutory rates in effect in each country where costs were incurred.

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 are 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.

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Asset Retirement Obligation (ARO)

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

ARO associated with retiring tangible long-lived assets is recognized as a liability in the period in which the legal obligation is incurred and becomes determinable. The liability is offset by a corresponding increase in the underlying asset. The ARO liability reflects the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with Apache’s oil and gas properties. The Company utilizes current retirement costs to estimate the expected cash outflows for retirement obligations. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit-adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental, and political environments. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property balance. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value.

Income Taxes

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

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

Purchase Price Allocation

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

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

In estimating the fair values of assets acquired and liabilities assumed, we made various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved and unproved crude oil and

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natural gas properties. To estimate the fair values of these properties, we prepared estimates of crude oil and natural gas reserves as described above in “Reserve Estimates” of this Item 7. Estimated fair values assigned to assets acquired can have a significant effect on results of operations in the future.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Commodity Risk

The Company’s revenues, earnings, cash flow, capital investments and, ultimately, future rate of growth are highly dependent on the prices we receive for our crude oil, natural gas and NGLs, which have historically been very volatile because of unpredictable events such as economic growth or retraction, weather and political climate. In 2013, our average crude oil realizations have remained flat at $101.99 per barrel compared to $102.53 per barrel in 2012. Our average natural gas price realizations decreased 3 percent in 2013 to $3.70 per Mcf from $3.80 per Mcf in 2012.

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 2013 approximately 8 percent of our natural gas production and approximately 42 percent of our crude oil production was subject to financial derivative hedges, compared with 13 percent and 13 percent, respectively, in 2012.

On December 31, 2013, the Company had open natural gas derivatives in an asset position with a fair value of $3 million. A 10 percent movement in natural gas prices would move the fair value by approximately $463,000. The Company also had open oil derivatives in a liability position with a fair value of $301 million. A 10 percent increase in oil prices would increase the liability by approximately $476 million, while a 10 percent decrease in prices would move the derivatives to an asset position of $175 million. These fair value changes assume volatility based on prevailing market parameters at December 31, 2013. 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 99.5 percent of the Company’s debt. At December 31, 2013, total debt included $53 million of floating-rate debt. As a result, Apache’s annual interest costs in 2013 will fluctuate based on short-term interest rates on approximately 0.5 percent of our total debt outstanding at December 31, 2013. A 10 percent change in floating interest rates on year-end floating debt balances would change annual interest expense by approximately $1.6 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 mixture of fixed-price U.S. dollar and Australian dollar contracts. Approximately 40 percent of the costs incurred for Australian operations are paid in U.S. dollars. In Canada, oil

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and gas prices and costs, such as equipment rentals and services, are generally denominated in Canadian dollars but are heavily influenced by U.S. markets. Our North Sea production is sold under U.S. dollar contracts, and the majority of costs incurred are paid in British pounds. In Egypt, all oil and gas production is sold under U.S. dollar contracts, and the majority of the costs incurred are denominated in U.S. dollars. Argentine revenues and expenditures are largely denominated in U.S. dollars, but are converted into Argentine pesos at the time of payment. Revenue and disbursement transactions denominated in Australian dollars, Canadian dollars, British pounds, and Argentine pesos are converted to U.S. dollar equivalents based on the average exchange rates during the period.

Foreign currency gains and losses also arise when monetary assets and monetary liabilities denominated in foreign currencies are translated at the end of each month. Currency gains and losses are included as either a component of “Other” under “Revenues and Other” or, as is the case when we re-measure our foreign tax liabilities, as a component of the Company’s provision for income tax expense on the statement of consolidated operations. A 10 percent strengthening or weakening of the Australian dollar, Canadian dollar, British pound, and Argentine peso against the U.S. dollar as of December 31, 2013, would result in a foreign currency net loss or gain, respectively, of approximately $186 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, 2013, 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 supply and demand for oil, natural gas, NGLs and other products or services;

• production and reserve levels;

• drilling risks;

• economic and competitive conditions;

• the availability of capital resources;

• capital expenditure and other contractual obligations;

• currency exchange rates;

• weather conditions;

• inflation rates;

• the availability of goods and services;

• legislative or regulatory changes;

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

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• the integration of acquisitions;

• terrorism or cyber attacks;

• occurrence of property acquisitions or divestitures;

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

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

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

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The financial statements and supplementary financial information required to be filed under this Item 8 are presented on pages F-1 through F-73 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, 2013, 2012, and 2011, 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 Senior Vice President, Finance, in his capacity as principal financial officer, evaluated the effectiveness of our disclosure controls and procedures as of December 31, 2013, 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, 2013, 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.

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Management’s Annual Report on Internal Control over Financial Reporting; Attestation Report of the Registered Public Accounting Firm

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, 2013, that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

ITEM 9B. OTHER INFORMATION

On February 11, 2014, the Company appointed Alfonso Leon as executive vice president and chief financial officer effective as of February 13, 2014, and Thomas P. Chambers ceased service as the chief financial officer as of the close of business on that date, assuming the new position of the Company’s senior vice president, Finance. Continuing through March 1, 2014, Mr. Chambers will continue to perform the functions of Company’s principal financial officer; Mr. Leon will assume the role of principal financial officer effective as of that date.

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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 2014 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 2013. 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, 2013	F-4
Statement of consolidated comprehensive income for each of the three years in the period ended December  31, 2013	F-5
Statement of consolidated cash flows for each of the three years in the period ended December 31, 2013	F-6
Consolidated balance sheet as of December 31, 2013 and 2012	F-7
Statement of consolidated changes in equity for each of the three years in the period ended December  31, 2013	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).
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).

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EXHIBIT NO.		DESCRIPTION
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 September 19, 2013, as filed with the Secretary of State of Delaware on September 19, 2013 (incorporated by reference to Exhibit 3.2 to Registrant’s Current Report on Form 8-K filed September 20, 2013, 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	–	Certificate of Elimination of Series D Preferred Stock of Registrant, dated September 18, 2013, as filed with the Secretary of State of Delaware on September 19, 2013 (incorporated by reference to Exhibit 3.1 to Registrant’s Current Report on Form 8-K filed September 19, 2013, SEC File No. 001-4300).
3.4	–	Bylaws of Registrant, as amended May 16, 2013 (incorporated by reference to Exhibit 3.1 to Registrant’s Current Report on Form 8-K filed May 17, 2013, 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).

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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).
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).

67

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	–	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).
10.2	–	First Amendment to Credit Agreement, dated as of July 17, 2013, among Apache Corporation, the lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, and the other agents party thereto, amending Credit Agreement, dated as of August 12, 2011, among the same parties (incorporated by reference to Exhibit 10.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2013, SEC File No. 001-4300).
10.3	–	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).
10.4	–	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)

68

EXHIBIT NO.		DESCRIPTION
10.5	–	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).
†10.6	–	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).
†10.7	–	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).
†10.8	–	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).
†10.9	–	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).
*†10.10	–	Apache Corporation 401(k) Savings Plan, as amended and restated, dated May 14, 2013, effective May 1, 2013.
†10.11	–	Amendment to Apache Corporation 401(k) Savings Plan, dated October 25, 2013 (incorporated by reference to Exhibit 10.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2013, SEC File No. 001-4300).
†10.12	–	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).
†10.13	–	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).
†10.14	–	Amendment to Non-Qualified Retirement/Savings Plan of Apache Corporation, dated November 8, 2012, effective January 1, 2013 (incorporated by reference to Exhibit 10.25 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2012, SEC File No. 001-4300).
†10.15	–	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).
†10.16	–	Amendment to Non-Qualified Restorative Retirement Savings Plan of Apache Corporation, dated November 8, 2012, effective January 1, 2013 (incorporated by reference to Exhibit 10.27 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2012, SEC File No. 001-4300).

69

EXHIBIT NO.		DESCRIPTION
*†10.17	–	Apache Corporation 2011 Omnibus Equity Compensation Plan, as amended and restated February 3, 2014.
†10.18	–	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).
†10.19	–	Apache Corporation 2000 Stock Option Plan, as amended and restated May 5, 2011 (incorporated by reference to Exhibit 10.3 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2011, SEC File No. 001-4300).
†10.20	–	Apache Corporation 2003 Stock Appreciation Rights Plan, as amended and restated September 16, 2013 (incorporated by reference to Exhibit 10.2 to Registrant’s Quarterly Report on Form 10-Q for quarter ended September 30, 2013, SEC File No. 001-4300).
†10.21	–	Apache Corporation 2005 Stock Option Plan, as amended and restated September 16, 2013 (incorporated by reference to Exhibit 10.3 to Registrant’s Quarterly Report on Form 10-Q for quarter ended September 30, 2013, Commission File No. 001-4300).
†10.22	–	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).
*†10.23	–	Apache Corporation Deferred Delivery Plan, as amended and restated November 11, 2013.
†10.24	–	Apache Corporation Non-Employee Directors’ Compensation Plan, as amended and restated February 6, 2013 (incorporated by reference to Exhibit 10.39 to Registrant’s Annual Report on Form 10-K for the year ended December 31, 2012, SEC File No. 001-4300).
†10.25	–	Apache Corporation Outside Directors’ Retirement Plan, as amended and restated February 6, 2013 (incorporated by reference to Exhibit 10.40 to Registrant’s Annual Report on Form 10-K for the year ended December 31, 2012, SEC File No. 001-4300).
†10.26	–	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).
†10.27	–	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).
*†10.28	–	Apache Corporation Non-Employee Directors’ Restricted Stock Units Program Specifications, as amended and restated May 15, 2013, pursuant to Apache Corporation 2011 Omnibus Equity Compensation Plan.
†10.29	–	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).
†10.30	–	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).
†10.31	–	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).

70

EXHIBIT NO.		DESCRIPTION
†10.32	–	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).
†10.33	–	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).
†10.34	–	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).
†10.35	–	Resignation Agreement, dated March 7, 2011 between Registrant and John A. Crum (incorporated by reference to Exhibit 10.2 to Registrant’s Current Report on Form 8-K/A filed March 8, 2011, SEC File No. 001-4300).
†10.36	–	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).
†10.37	–	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).
†10.38	–	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).
†10.39	–	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).
†10.40	–	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).
†10.41	–	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).
†10.42	–	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).
†10.43	–	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).
†10.44	–	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).

71

EXHIBIT NO.		DESCRIPTION
†10.45	–	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 11, 2013, SEC File No. 001-4300).
*10.46	–	Form of 2014 Performance Agreement (Total Shareholder Return), dated January 9, 2014, between Registrant and each of G. Steven Farris, Rodney J. Eichler, Roger B. Plank, P. Anthony Lannie, and Thomas P. Chambers.
*10.47	–	Form of 2014 Performance Agreement (Business Performance), dated February 3, 2014, between Registrant and each of G. Steven Farris, Roger B. Plank, Rodney J. Eichler, P. Anthony Lannie, and Thomas P. Chambers.
*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 13, 2013.
*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.

72

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, Chief Executive Officer, and President

Dated: February 28, 2014

POWER OF ATTORNEY

The officers and directors of Apache Corporation, whose signatures appear below, hereby constitute and appoint G. Steven Farris, P. Anthony Lannie, Alfonso Leon, Thomas P. Chambers, 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, Chief Executive Officer, and President (principal executive officer)	February 28, 2014
/s/ THOMAS P. CHAMBERS Thomas P. Chambers	Senior Vice President, Finance (principal financial officer)	February 28, 2014
/s/ REBECCA A. HOYT Rebecca A. Hoyt	Vice President, Chief Accounting Officer and Controller (principal accounting officer)	February 28, 2014

73

Name	Title	Date
/s/ RANDOLPH M. FERLIC Randolph M. Ferlic	Director	February 28, 2014
/s/ EUGENE C. FIEDOREK Eugene C. Fiedorek	Director	February 28, 2014
/s/ A.D. FRAZIER, JR. A. D. Frazier, Jr.	Director	February 28, 2014
/s/ CHANSOO JOUNG Chansoo Joung	Director	February 28, 2014
/s/ GEORGE D. LAWRENCE George D. Lawrence	Director	February 28, 2014
/s/ JOHN E. LOWE John E. Lowe	Director	February 28, 2014
/s/ WILLIAM C. MONTGOMERY William C. Montgomery	Director	February 28, 2014
/s/ AMY H. NELSON Amy H. Nelson	Director	February 28, 2014
/s/ RODMAN D. PATTON Rodman D. Patton	Director	February 28, 2014
/s/ CHARLES J. PITMAN Charles J. Pitman	Director	February 28, 2014

74

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, 2013. 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 (1992). Based on our assessment, management believes that the Company maintained effective internal control over financial reporting as of December 31, 2013.

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, Chief Executive Officer, and President

(principal executive officer)

/s/ Thomas P. Chambers

Senior Vice President, Finance

(principal financial officer)

/s/ Rebecca A. Hoyt

Vice President, Chief Accounting Officer and Controller

(principal accounting officer)

Houston, Texas

February 28, 2014

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, 2013 and 2012, and the related consolidated statements of operations, comprehensive income, changes in equity, and cash flows for each of the three years in the period ended December 31, 2013. 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, 2013 and 2012, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2013, 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, 2013, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 framework) and our report dated February 28, 2014, expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Houston, Texas

February 28, 2014

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, 2013, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 framework) (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, 2013, 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, 2013 and 2012, and the related consolidated statements of operations, comprehensive income, changes in equity, and cash flows for each of the three years in the period ended December 31, 2013 of Apache Corporation and subsidiaries, and our report dated February 28, 2014, expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Houston, Texas

February 28, 2014

F-3

APACHE CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED OPERATIONS

	For the Year Ended December 31,
	2013			2012			2011
	(In millions, except per common share data)
REVENUES AND OTHER:
Oil and gas production revenues:
Oil revenues	$	12,903		$	13,210		$	12,679
Gas revenues		2,829			3,193			3,609
Natural gas liquids revenues		670			544			522
		16,402			16,947			16,810
Derivative instrument gains (losses), net		(399	)		(79	)		—
Other		51			210			78
		16,054			17,078			16,888
OPERATING EXPENSES:
Depreciation, depletion, and amortization:
Oil and gas property and equipment
Recurring		5,114			4,812			3,814
Additional		1,176			1,926			109
Other assets		410			371			281
Asset retirement obligation accretion		243			232			154
Lease operating expenses		3,056			2,968			2,605
Gathering and transportation		297			303			296
Taxes other than income		832			862			899
General and administrative		503			531			459
Acquisitions, divestitures and transition		33			31			20
Financing costs, net		174			165			158
		11,838			12,201			8,795
INCOME BEFORE INCOME TAXES		4,216			4,877			8,093
Current income tax provision		1,665			2,199			2,263
Deferred income tax provision		263			677			1,246
NET INCOME INCLUDING NONCONTROLLING INTEREST		2,288			2,001			4,584
Net income attributable to noncontrolling interest		56			—			—
Preferred stock dividends		44			76			76
NET INCOME ATTRIBUTABLE TO COMMON STOCK	$	2,188		$	1,925		$	4,508
NET INCOME PER COMMON SHARE:
Basic	$	5.53		$	4.95		$	11.75
Diluted	$	5.50		$	4.92		$	11.47
WEIGHTED-AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
Basic		395			389			384
Diluted		406			391			400
DIVIDENDS DECLARED PER COMMON SHARE	$	0.80		$	0.68		$	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,
	2013			2012			2011
	(In millions)
NET INCOME INCLUDING NONCONTROLLING INTEREST	$	2,288		$	2,001		$	4,584
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and postretirement benefit plan, net of tax		9			(2	)		(1	)
Commodity cash flow hedge activity, net of tax:
Reclassification of (gain) loss on settled derivative instruments		11			(199	)		19
Change in fair value of derivative instruments		(5	)		79			115
Derivative hedge ineffectiveness reclassified into earnings		1			—			(1	)
		16			(122	)		132
COMPREHENSIVE INCOME INCLUDING NONCONTROLLING INTEREST		2,304			1,879			4,716
Comprehensive income attributable to noncontrolling interest		56			—			—
Preferred stock dividends		44			76			76
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON STOCK	$	2,204		$	1,803		$	4,640

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,
	2013			2012			2011
	(In millions)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income including noncontrolling interest	$	2,288		$	2,001		$	4,584
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, and amortization		6,700			7,109			4,204
Asset retirement obligation accretion		243			232			154
Provision for deferred income taxes		263			677			1,246
Other		260			226			46
Changes in operating assets and liabilities:
Receivables		124			12			(759	)
Inventories		(70	)		(59	)		(37	)
Drilling advances		230			(343	)		26
Deferred charges and other		(124	)		61			27
Accounts payable		479			(100	)		241
Accrued expenses		(553	)		(1,142	)		90
Deferred credits and noncurrent liabilities		(5	)		(170	)		131
NET CASH PROVIDED BY OPERATING ACTIVITIES		9,835			8,504			9,953
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property		(10,019	)		(8,781	)		(6,414	)
Additions to gas gathering, transmission, and processing facilities		(1,201	)		(750	)		(664	)
Proceeds from divestiture of Gulf of Mexico Shelf properties		3,702			—			—
Proceeds from Kitimat LNG transaction, net		396			—			—
Proceeds from sale of oil and gas properties, other		307			27			422
Acquisition of Cordillera Energy Partners III, LLC		—			(2,666	)		—
Acquisition of Yara Pilbara Holdings Pty Limited		—			(439	)		—
Acquisition of Mobil North Sea Limited		—			—			(1,246	)
Acquisitions, other		(215	)		(252	)		(567	)
Other, net		(86	)		(563	)		(176	)
NET CASH USED IN INVESTING ACTIVITIES		(7,116	)		(13,424	)		(8,645	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Commercial paper, credit facilities and bank notes, net		(513	)		549			(925	)
Fixed rate debt borrowings		—			4,978			—
Payments on fixed rate debt		(2,072	)		(400	)		—
Proceeds from sale of noncontrolling interest		2,948			—			—
Dividends paid		(360	)		(332	)		(306	)
Shares repurchased		(997	)		—			—
Other		21			(10	)		84
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		(973	)		4,785			(1,147	)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		1,746			(135	)		161
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR		160			295			134
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	1,906		$	160		$	295
SUPPLEMENTARY CASH FLOW DATA:
Interest paid, net of capitalized interest	$	192		$	146		$	156
Income taxes paid, net of refunds		1,766			2,590			1,686

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

F-6

APACHE CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET

	December 31,
	2013			2012
	(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	1,906		$	160
Receivables, net of allowance		2,952			3,086
Inventories		891			908
Drilling advances		371			584
Derivative instruments		1			31
Prepaid assets and other		245			193
		6,366			4,962
PROPERTY AND EQUIPMENT:
Oil and gas, on the basis of full-cost accounting:
Proved properties		83,390			78,383
Unproved properties and properties under development, not being amortized		8,363			8,754
Gathering, transmission, and processing facilities		6,995			5,955
Other		1,071			1,055
		99,819			94,147
Less: Accumulated depreciation, depletion, and amortization		(47,398	)		(40,867	)
		52,421			53,280
OTHER ASSETS:
Goodwill		1,369			1,289
Deferred charges and other		1,481			1,206
	$	61,637		$	60,737
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable	$	1,616		$	1,092
Current debt		53			990
Current asset retirement obligation		121			478
Derivative instruments		299			116
Other current liabilities		2,611			2,860
		4,700			5,536
LONG-TERM DEBT		9,672			11,355
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes		8,364			8,024
Asset retirement obligation		3,101			4,100
Other		407			391
		11,872			12,515
COMMITMENTS AND CONTINGENCIES (Note 8)
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 converted in 2013, 1,265,000 shares issued and outstanding in 2012		—			1,227
Common stock, $0.625 par, 860,000,000 shares authorized, 408,041,088 and 392,712,245 shares issued, respectively		255			245
Paid-in capital		12,251			9,859
Retained earnings		22,032			20,161
Treasury stock, at cost, 12,268,180 and 1,071,475 shares, respectively		(1,027	)		(30	)
Accumulated other comprehensive loss		(115	)		(131	)
APACHE SHAREHOLDERS’ EQUITY		33,396			31,331
Noncontrolling interest		1,997			—
TOTAL EQUITY		35,393			31,331
	$	61,637		$	60,737

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

F-7

APACHE CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED CHANGES IN EQUITY

	Series D Preferred Stock			Common Stock		Paid-In Capital			Retained Earnings			Treasury Stock			Accumulated Other Comprehensive (Loss)			APACHE SHAREHOLDERS’ EQUITY			Non Controlling Interest		TOTAL EQUITY
	(In millions)
BALANCE AT DECEMBER 31, 2010	$	1,227		$	240	$	8,864		$	14,223		$	(36	)	$	(141	)	$	24,377		$	—	$	24,377
Net income		—			—		—			4,584			—			—			4,584			—		4,584
Postretirement, net of tax of $7		—			—		—			—			—			(1	)		(1	)		—		(1	)
Commodity hedges, net of tax of $66		—			—		—			—			—			133			133			—		133
Dividends:
Preferred		—			—		—			(76	)		—			—			(76	)		—		(76	)
Common ($0.60 per share)		—			—		—			(231	)		—			—			(231	)		—		(231	)
Common stock activity, net		—			1		35			—			—			—			36			—		36
Treasury stock activity, net		—			—		2			—			4			—			6			—		6
Compensation expense		—			—		167			—			—			—			167			—		167
Other		—			—		(2	)		—			—			—			(2	)		—		(2	)
BALANCE AT DECEMBER 31, 2011	$	1,227		$	241	$	9,066		$	18,500		$	(32	)	$	(9	)	$	28,993		$	—	$	28,993
Net income		—			—		—			2,001			—			—			2,001			—		2,001
Postretirement, net of tax of $5		—			—		—			—			—			(2	)		(2	)		—		(2	)
Commodity hedges, net of tax of $35		—			—		—			—			—			(120	)		(120	)		—		(120	)
Dividends:
Preferred		—			—		—			(76	)		—			—			(76	)		—		(76	)
Common ($0.68 per share)		—			—		—			(264	)		—			—			(264	)		—		(264	)
Common shares issued		—			3		598			—			—			—			601			—		601
Common stock activity, net		—			1		(44	)		—			—			—			(43	)		—		(43	)
Treasury stock activity, net		—			—		1			—			2			—			3			—		3
Compensation expense		—			—		238			—			—			—			238			—		238
BALANCE AT DECEMBER 31, 2012	$	1,227		$	245	$	9,859		$	20,161		$	(30	)	$	(131	)	$	31,331		$	—	$	31,331
Net income		—			—		—			2,232			—			—			2,232			56		2,288
Postretirement, net of tax of $9		—			—		—			—			—			9			9			—		9
Commodity hedges, net of tax of $4		—			—		—			—			—			7			7			—		7
Dividends:
Preferred		—			—		—			(44	)		—			—			(44	)		—		(44	)
Common ($0.80 per share)		—			—		—			(317	)		—			—			(317	)		—		(317	)
Common stock activity, net		—			1		(22	)		—			—			—			(21	)		—		(21	)
Treasury stock activity, net		—			—		—			—			(997	)		—			(997	)		—		(997	)
Sale of noncontrolling interest		—			—		1,007			—			—			—			1,007			1,941		2,948
Conversion of Series D preferred stock		(1,227	)		9		1,218			—			—			—			—			—		—
Compensation expense		—			—		189			—			—			—			189			—		189
BALANCE AT DECEMBER 31, 2013	$	—		$	255	$	12,251		$	22,032		$	(1,027	)	$	(115	)	$	33,396		$	1,997	$	35,393

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 independent energy company that explores for, develops, and produces natural gas, crude oil, and natural gas liquids. The Company has exploration and production interests in six countries: the United States (U.S.), Canada, Egypt, Australia, the United Kingdom (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.

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). The Company’s financial statements for prior periods may include reclassifications that were made to conform to the 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 undivided interests in oil and gas exploration and production ventures and partnerships are proportionately consolidated. The Company consolidates all other investments in which, either through direct or indirect ownership, Apache has more than a 50 percent voting interest or controls the financial and operating decisions. Noncontrolling interests represent third-party ownership in the net assets of a consolidated Apache subsidiary and are reflected separately in the Company’s financial statements. For further information, please refer to Note 2 — Acquisitions and Divestitures. Investments in which Apache holds less than 50 percent of the voting interest are typically 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.

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 with regard to 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 estimate 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,

F-9

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

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 and 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, 2013 and 2012, Apache had $1.9 billion and $160 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 an 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, 2013 and 2012, the Company had an allowance for doubtful accounts of $96 million and $82 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

F-10

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

property acquisitions are capitalized. All costs related to production, general corporate overhead, and similar activities are expensed as incurred. Apache capitalized $401 million, $402 million, and $335 million of internal costs in 2013, 2012, and 2011, respectively.

Proved properties are amortized on a country-by-country basis using the units of production method (UOP). The UOP calculation 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 prospects 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 2013, Apache’s statement of consolidated operations includes additional DD&A of $75 million related to exiting operations in Kenya. In 2012, Apache recorded 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 designated 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 2013, Apache recorded non-cash write-downs of the carrying value of the Company’s proved oil and gas properties totaling $1.1 billion. The after-tax impact of these write-downs was $356 million in the U.S., $139 million in the North Sea, and $118 million in Argentina. Cash flow hedges did not materially affect the 2013 calculations. 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).

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. No gain or loss was recorded on the Company’s divestitures in 2013, 2012, or 2011.

F-11

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

Gathering, Transmission, and Processing Facilities

Gathering, transmission, and processing facilities totaled $7.0 billion and $6.0 billion at December 31, 2013 and 2012, 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 2013, 2012, or 2011.

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 $2.1 billion and $1.9 billion at December 31, 2013 and 2012, 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 $1.4 billion and $1.3 billion at December 31, 2013 and 2012, respectively. As of December 31, 2013 and 2012, goodwill of $163 million and $84 million, respectively, was recorded in the North Sea. As of December 31, 2013 and 2012, goodwill of $1.0 billion, $103 million, and $86 million was recorded in the U.S., Canada, and Egypt, respectively. Each country was assessed as a reporting unit, and no impairment of goodwill was recognized during 2013, 2012, or 2011.

Accounts Payable

Included in accounts payable at December 31, 2013 and 2012, are liabilities of approximately $271 million and $255 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 $34 million, $27 million, and $28 million, for 2013, 2012, and 2011, 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 periods. 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 records all derivative instruments, other than those that meet the normal purchases and sales exception, 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. 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 “Derivative instrument gains (losses), net” under “Revenues and Other” in the statement of consolidated operations. 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. 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.

Apache does not recognize U.S. deferred income taxes on the unremitted earnings of its foreign subsidiaries that are deemed to be indefinitely reinvested. When such earnings are no longer deemed permanently reinvested, Apache recognizes the appropriate deferred or current income tax liabilities.

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.

Foreign currency transaction gains and losses related to current taxes payable and deferred tax assets and liabilities are recorded as components of the provision for income taxes. In 2013, Apache recorded a tax benefit of $154 million, including current and deferred taxes. In 2012 and 2011, the Company recorded tax expense of $16 million and a tax benefit of $66 million, respectively. For further discussion, please refer to 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 loss in 2013 of $30 million and gains in 2012 and 2011 of $24 million and $4 million, respectively.

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

F-14

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

fully vested. The diluted EPS calculations for the years ended December 31, 2011 and 2013, includes weighted-average shares of common stock from the assumed conversion of Apache’s convertible preferred stock. For the year ended December 31, 2012, the diluted EPS calculation excludes shares related to the assumed conversion of the convertible preferred stock as such conversion would have been anti-dilutive.

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 $1 million, $4 million, and $32 million as financing cash inflows in 2013, 2012, and 2011, 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 July 2013, the FASB issued ASU No. 2013-11, which requires entities to present unrecognized tax benefits as a decrease in a net operating loss, similar tax loss, or tax credit carryforward if certain criteria are met. The guidance will eliminate the diversity in practice in the presentation of unrecognized tax benefits but will not alter the way in which entities assess deferred tax assets for realizability. ASU No. 2013-11 is effective for annual and interim reporting periods beginning after December 15, 2013. The Company will apply all changes prospectively and does not expect the adoption of this amendment to have a material impact on its consolidated financial statements.

In February 2013, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2013-04, which increases disclosures for certain liability arrangements. The guidance requires an entity that is joint and severally liable to measure the obligation as the sum of the amount the entity has agreed with co-obligors to pay and any additional amount it expects to pay on behalf of one or more co-obligors. Required disclosures include a description of the nature of the arrangement, how the liability arose, the relationship with co-obligors and the terms and conditions of the arrangement. ASU No. 2013-04 is effective for annual and interim reporting periods beginning after December 15, 2013. The Company does not expect the adoption of this amendment to have a material impact on its consolidated financial statements.

2.     ACQUISITIONS AND DIVESTITURES

2014 Activity

Argentina Divestiture

On February 12, 2014, Apache Corporation and its subsidiaries announced an agreement to sell all of its operations in Argentina to YPF Sociedad Anónima for cash consideration of $800 million plus the assumption of $52 million of bank debt as of June 30, 2013. As of December 31, 2013, Apache’s net assets in Argentina totaled approximately $1.3 billion, and the Company expects to recognize a loss associated with this transaction upon closing. The transaction is expected to close in the first quarter of 2014.

F-15

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

2013 Activity

Egypt Partnership

On November 14, 2013, Apache completed the sale of a one-third minority participation in its Egypt oil and gas business to a subsidiary of Sinopec International Petroleum Exploration and Production Corporation (Sinopec). Apache received cash consideration of $2.95 billion after customary closing adjustments. Apache continues to operate its Egypt upstream oil and gas business. The effective date of the agreement is January 1, 2013.

Apache recorded $1.9 billion of the proceeds as a non-controlling interest, which is reflected as a separate component of equity in the Company’s consolidated balance sheet. This represents one-third of Apache’s net book value of its Egypt holdings at the time of the transaction. The remaining proceeds were recorded as additional paid-in capital. Included in “Net income including noncontrolling interest” for the year ended December 31, 2013, is net income attributable to Sinopec’s interest totaling $56 million.

Gulf of Mexico Shelf Divestiture

On September 30, 2013, Apache completed the sale of its Gulf of Mexico Shelf operations and properties to Fieldwood Energy LLC (Fieldwood), an affiliate of Riverstone Holdings. Under the terms of the agreement, Apache received cash consideration of $3.7 billion, and Fieldwood assumed $1.5 billion of discounted asset abandonment liabilities. Additionally, Apache retained 50 percent of its ownership interest in all exploration blocks and in horizons below production in developed blocks. The effective date of the agreement is July 1, 2013. Apache’s net book value of oil and gas properties was reduced by approximately $4.6 billion of proved property costs and $473 million of unproved property costs as a result of the transaction.

Canada LNG Project

In February 2013, Apache completed a transaction with Chevron Canada Limited (Chevron Canada) under which each company became a 50 percent owner of the Kitimat LNG plant, the Pacific Trail Pipelines Limited Partnership (PTP), and 644,000 gross undeveloped acres in the Horn River and Liard basins. Chevron Canada will operate the LNG plant and pipeline while Apache Canada will continue to operate the upstream assets. Apache’s net proceeds from the transaction were $396 million after post-closing adjustments, and no gain or loss was recorded.

Other Activity

During 2013 Apache completed $307 million of other oil and gas property sales and $215 million of oil and gas property acquisitions.

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 included approximately 312,000 net acres in the Granite Wash, Tonkawa, Cleveland, and Marmaton plays in western Oklahoma and the Texas Panhandle.

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 transaction was accounted for using the acquisition method of

F-16

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

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. Yara Australia Pty Ltd (Yara) owns the remaining 51 percent of YPHPL and operates the plant. 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.

F-17

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

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.

Acquisitions, Divestitures, and Transition Expenses

In 2013, Apache recorded $33 million of investment banking fees and other costs associated with divestitures during the year. In 2012, the Company recorded $31 million of expenses reflecting costs related to our 2011 acquisition of Mobil North Sea and our 2012 acquisition of Cordillera. In 2011, Apache recorded $20 million of expenses primarily for separation and other costs related to the merger with Mariner Energy, Inc. (Mariner) and the acquisition of Mobil North Sea.

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, 2013, Apache had derivative positions with 14 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.

F-18

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

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. The Company’s net derivative liability position at December 31, 2013, represents the aggregate fair value of all derivative instruments with credit-risk-related contingent features that are in a net liability position. The Company has not provided any collateral to any of its counterparties as of December 31, 2013.

Derivative Instruments

As of December 31, 2013, Apache had the following open crude oil derivative positions which have not been designated as cash flow hedges:

		Fixed-Price Swaps
Production Period	Settlement Index	Mbbls		Weighted Average Fixed Price
2014	NYMEX WTI		22,889	$	90.77
2014	Dated Brent		22,812		100.05

As of December 31, 2013, Apache had the following open natural gas derivative positions which have been designated as cash flow hedges:

		Fixed-Price Swaps
Production Period	Settlement Index	MMBtu (in 000’s)		Weighted Average Fixed Price
2014	NYMEX Henry Hub		1,295	$	6.72

Subsequent to December 31, 2013, Apache entered into additional natural gas derivatives not designated as cash flow hedges totaling 55.9 million MMBtu for 2014. These contracts are settled against NYMEX Henry Hub and various Inside FERC indices, with a weighted average fixed price of $4.35.

Fair Value Measurements

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.

F-19

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, 2013
Assets:
Derivatives designated as cash flow hedges	$	—	$	3	$	—	$	3	$	(2	)	$	1
Liabilities:
Derivatives designated as cash flow hedges	$	—	$	1	$	—	$	1
Derivatives not designated as cash flow hedges		—		300		—		300
Total Derivative liabilities	$	—	$	301	$	—	$	301	$	(2	)	$	299
December 31, 2012
Assets:
Derivatives designated as cash flow hedges	$	—	$	48	$	—	$	48	$	(15	)	$	33
Liabilities:
Derivatives designated as cash flow hedges	$	—	$	51	$	—	$	51
Derivatives not designated as cash flow hedges		—		80		—		80
Total Derivative liabilities	$	—	$	131	$	—	$	131	$	(15	)	$	116

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

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, 2013		December 31, 2012
	(In millions)
Current Assets: Derivative instruments	$	1	$	31
Other Assets: Deferred charges and other		—		2
Total Assets	$	1	$	33
Current Liabilities: Derivative instruments	$	299	$	116
Total Liabilities	$	299	$	116

F-20

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

Derivative Activity Recorded in Statement of Consolidated Operations

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

	Gain (Loss) on Derivatives	For the Year Ended December 31,
	Recognized in Income	2013			2012			2011
		(In millions)
Gain (loss) on cash flow hedges reclassified from accumulated other comprehensive loss	Oil and Gas Production Revenues	$	(16	)	$	268		$	(13	)
Gain (loss) for ineffectiveness on cash flow hedges	Revenues and Other: Other	$	(1	)	$	—		$	2
Loss on derivatives not designated as cash flow hedges	Derivative instrument gains (losses), net	$	(399	)	$	(79	)	$	—

Unrealized gains and losses for derivative activity recorded in the statement of consolidated operations is reflected in the statement of consolidated cash flows as a component of “Other” in “Adjustments to reconcile net income to net cash provided by operating activities.”

Derivative Activity in Accumulated Other Comprehensive Income (Loss)

As of December 31, 2013, a portion of the Company’s derivative instruments were designated as cash flow hedges. A reconciliation of the components of accumulated other comprehensive income (loss) in the statement of consolidated changes in equity related to Apache’s cash flow hedges is presented in the table below:

	For the Year Ended December 31,
	2013						2012						2011
	Before			After			Before			After			Before			After
	tax			tax			tax			tax			tax			tax
	(In millions)
Unrealized gain (loss) on derivatives at beginning of year	$	(10	)	$	(6	)	$	145		$	114		$	(54	)	$	(19	)
Realized amounts reclassified into earnings		16			11			(268	)		(199	)		13			19
Net change in derivative fair value		(6	)		(5	)		113			79			188			115
Ineffectiveness reclassified into earnings		1			1			—			—			(2	)		(1	)
Unrealized gain (loss) on derivatives at end of period	$	1		$	1		$	(10	)	$	(6	)	$	145		$	114

Unrealized net gains on existing cash flow hedges as of December 31, 2013 will be realized in earnings through mid-2014, in the same period as the related sales of natural gas and crude oil production occur; however, estimated and actual amounts may vary materially as a result of changes in market conditions.

F-21

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, 2013 and 2012:

	December 31,		December 31,
	2013		2012
	(In millions)
Accrued operating expenses	$	190	$	211
Accrued exploration and development		1,582		1,792
Accrued compensation and benefits		242		198
Accrued interest		161		160
Accrued income taxes		248		297
Accrued U.K. Petroleum Revenue Tax		9		53
Other		179		149
Total Other current liabilities	$	2,611	$	2,860

5.     ASSET RETIREMENT OBLIGATION

The following table describes changes to the Company’s asset retirement obligation (ARO) liability for the years ended December 31, 2013 and 2012:

	2013			2012
	(In millions)
Asset retirement obligation at beginning of year	$	4,578		$	3,887
Liabilities incurred		481			592
Liabilities acquired		53			72
Liabilities divested		(1,692	)		—
Liabilities settled		(497	)		(550	)
Accretion expense		243			232
Revisions in estimated liabilities		56			345
Asset retirement obligation at end of year		3,222			4,578
Less current portion		(121	)		(478	)
Asset retirement obligation, long-term	$	3,101		$	4,100

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 2013 and 2012, the Company recorded $481 million and $592 million, respectively, in abandonment liabilities resulting from Apache’s active exploration and development capital program. Liabilities settled primarily relate to individual properties, platforms, and facilities plugged and abandoned during the period.

F-22

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

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.

During 2013, Apache repaid the $500 million aggregate principal amount of 5.25 percent notes that matured on April 15, 2013 and the $400 million aggregate principal amount of 6.00 percent notes that matured on September 15, 2013 by borrowing under our commercial paper program.

In November 2013 the Company announced a cash tender offer to purchase up to $850 million aggregate principal amount of five series of its outstanding notes. On December 20, 2013, the Company accepted for purchase $669 million principal amount of its 2.625 percent notes due 2023 and $181 million principal amount of its 3.25 percent notes due 2022. Apache paid the holders an aggregate of approximately $811 million in cash reflecting principal, the discount to par, and accrued and unpaid interest.

In December 2013, Apache Finance Canada Corporation (Apache Finance Canada) fully redeemed $350 million principal amount of its 4.375 percent notes due in 2015. The notes were redeemed pursuant to the provisions of the note’s indenture. Apache paid the holders an aggregate of approximately $371 million in cash reflecting principal, the premium to par, and accrued and unpaid interest.

The Company recorded a net gain on extinguishment of debt totaling $16 million in connection with the cash tender offer and redemption of Apache Finance Canada notes.

F-23

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, 2013 and 2012:

	December 31,
	2013			2012
	(In millions)
U.S.:
Money market lines of credit	$	—		$	13
Commercial paper		—			489
5.25% notes due 2013(1)		—			500
6.0% notes due 2013(1)		—			400
5.625% notes due 2017(1)		500			500
1.75% notes due 2017(1)		400			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)		919			1,100
2.625% notes due 2023(1)		531			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			1,500
4.25% notes due 2044(1)		800			800
7.375% debentures due 2047		150			150
7.625% debentures due 2096		150			150
		9,430			11,682
Subsidiary and other obligations:
Argentina overdraft lines of credit		51			69
Canada lines of credit		2			9
Apache Finance Canada 4.375% notes due 2015(1)		—			350
Notes due in 2016 and 2017		1			1
Apache Finance Canada 7.75% notes due 2029		300			300
		354			729
Debt before unamortized discount		9,784			12,411
Unamortized discount		(59	)		(66	)
Total debt	$	9,725		$	12,345
Current maturities	$	(53	)	$	(990	)
Long-term debt	$	9,672		$	11,355

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

F-24

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

Debt maturities as of December 31, 2013, excluding discounts, are as follows:

	(In millions)
2014	$	53
2015		—
2016		1
2017		900
2018		550
Thereafter		8,280
Total Debt, excluding discounts	$	9,784

Fair Value

The Company’s debt is recorded at the carrying amount, net of unamortized discount, on its consolidated balance sheet. The carrying amount of the Company’s commercial paper and uncommitted credit facilities and overdraft lines 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 (a Level 2 fair value measurement).

	December 31, 2013				December 31, 2012
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)
Money market lines of credit	$	53	$	53	$	91	$	91
Commercial paper		—		—		489		489
Notes and debentures		9,672		10,247		11,765		13,340
Total Debt	$	9,725	$	10,300	$	12,345	$	13,920

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, 2013, a total of $53 million was drawn on facilities in Argentina and Canada. As of December 31, 2012, a total of $91 million was drawn on facilities in the U.S., Argentina, and Canada.

Unsecured Committed Bank Credit Facilities

As of December 31, 2013, 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. In July 2013, we amended our $1.0 billion U.S. credit facility to conform certain representations, covenants, and events of default to those in our $1.7 billion U.S. credit facility. The amendments did not affect the amount or repayment terms of the $1.0 billion U.S. facility. As of December 31, 2013, aggregate available borrowing capacity under the Company’s credit facilities was $3.3 billion. The committed credit facilities are used to support Apache’s commercial paper program.

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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

At December 31, 2013, 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, 2013, the Company’s debt-to-capitalization ratio was 22 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 $3.1 billion as of December 31, 2013. 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.

The facilities do not permit the lenders to accelerate payments or refuse to lend based on unspecified material adverse changes. The credit facility agreements do not have drawdown restrictions or prepayment obligations in the event of a decline in credit ratings. However, the agreements allow the lenders to accelerate payments and terminate lending commitments if Apache, or any of its U.S. or Canadian subsidiaries, defaults on any direct payment obligation in excess of 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, 2013.

Commercial Paper Program

The Company has available a $3.0 billion commercial paper program, which generally enables Apache to borrow funds for up to 270 days at competitive interest rates. The commercial paper program is fully supported by available borrowing capacity under committed credit facilities. Our 2013 weighted-average interest rate for commercial paper was 0.38 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. The Company used proceeds from divestitures to repay commercial paper and at year end had no outstanding balance. At December 31, 2012, the Company had $489 million in commercial paper outstanding.

Subsidiary Notes – Apache Finance Canada

Apache Finance Canada has approximately $300 million of publicly-traded notes due in 2029 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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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

Financing Costs, Net

The following table presents the components of Apache’s financing costs, net:

	For the Year Ended December 31,
	2013			2012			2011
	(In millions)
Interest expense	$	571		$	509		$	433
Amortization of deferred loan costs		8			7			5
Capitalized interest		(374	)		(334	)		(263	)
Gain on extinguishment of debt		(16	)		—			—
Interest income		(15	)		(17	)		(17	)
Financing costs, net	$	174		$	165		$	158

The Company has $59 million of debt discounts as of December 31, 2013, which will be charged to interest expense over the life of the related debt issuances. Discount amortization of $3 million, $3 million, and $2 million were recorded as interest expense in 2013, 2012, and 2011, respectively.

As of December 31, 2013 and 2012, the Company had approximately $73 million and $70 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,
	2013		2012		2011
	(In millions)
U.S.	$	1,191	$	1,605	$	2,373
Foreign		3,025		3,272		5,720
Total	$	4,216	$	4,877	$	8,093

The total provision for income taxes consists of the following:

	For the Year Ended December 31,
	2013			2012			2011
	(In millions)
Current taxes:
Federal	$	(29	)	$	(150	)	$	64
State		—			—			2
Foreign		1,694			2,349			2,197
		1,665			2,199			2,263
Deferred taxes:
Federal		509			596			656
State		44			10			17
Foreign		(290	)		71			573
		263			677			1,246
Total	$	1,928		$	2,876		$	3,509

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

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,
	2013			2012			2011
	(In millions)
Income tax expense at U.S. statutory rate	$	1,476		$	1,707		$	2,833
State income tax, less federal benefit		29			6			12
Taxes related to foreign operations		200			773			568
Tax credits		6			(4	)		(15	)
Deferred tax on distributed foreign earnings		225			—			—
Current and deferred taxes related to currency fluctuations		(154	)		16			(66	)
Change in U.K. tax rate		—			118			218
Net change in tax contingencies		(10	)		(115	)		(6	)
Valuation allowances		199			355			8
All other, net		(43	)		20			(43	)
	$	1,928		$	2,876		$	3,509

The net deferred tax liability consists of the following:

	December 31,
	2013			2012
	(In millions)
Deferred tax assets:
Deferred income	$	153		$	33
Federal and state net operating loss carryforwards		900			932
Foreign net operating loss carryforwards		156			61
Tax credits		66			78
Accrued expenses and liabilities		162			2
Asset retirement obligation		1,231			1,677
Total deferred tax assets		2,668			2,783
Valuation allowance		(651	)		(419	)
Net deferred tax assets		2,017			2,364
Deferred tax liabilities:
Other		29			23
Depreciation, depletion and amortization		10,224			10,213
Total deferred tax liabilities		10,253			10,236
Net deferred income tax liability	$	8,236		$	7,872

The Company has recorded a valuation allowance against the net deferred tax asset in Argentina and Canada and against certain state net operating losses. The Company has assessed the future potential realization of these deferred tax assets and has concluded that it is more likely than not that these deferred tax assets will not be realized based on current economic conditions. In 2013, 2012, and 2011, the Company increased its valuation allowance by $232 million, $359 million, and $7 million, respectively.

On November 14, 2013, the Company completed the formation of its strategic partnership with Sinopec, whereby the Company received $2.95 billion in exchange for a one-third minority participation interest in

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

Apache’s Egypt oil and gas business. As a result of the transaction, the Company reassessed its position with respect to certain current year untaxed foreign earnings to treat the reinvestment of these earnings as not permanent in duration. As such, the Company recorded a $225 million deferred tax charge on current year foreign earnings deemed not permanently reinvested. The Company repatriated approximately $643 million of cash from foreign subsidiaries and utilized net operating losses to offset any U.S. current income tax expense.

The Company considers the undistributed earnings of its foreign subsidiaries to be permanently reinvested, as it has no current intention to repatriate these earnings. As such, deferred income taxes are not provided for temporary differences of approximately $17 billion at December 31, 2013, representing unremitted earnings of subsidiaries outside the United States intended to be permanently reinvested. Upon an actual or deemed 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 practicable, 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, 2013, the Company had net operating losses as follows:

	December 31, 2013
	Amount		Expiration
	(In millions)
Net operating losses:
U.S. — Federal	$	1,558		2032 - 2034
U.S. — Federal (Mariner IRC §382 limited)		520		2018 - 2030
U.S. — Federal (Cordillera IRC §382 limited)		183		2026 - 2032
U.S. — State		2,242		Various
Canada		5		2014
Australia		59		Indefinite
Argentina		299		2014

The Company has a federal net operating loss carryforward of $2.3 billion. Included in the federal net operating loss carryforward is $520 million of federal net operating losses related to the 2010 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 has $186 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 discussed above, the Company does not believe the utilization of the Argentine net operating losses, Canadian capital losses, and certain state net operating losses to be “more likely than not.” As such, a valuation allowance was provided against these deferred tax assets.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

The Company 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:

	2013		2012			2011
	(In millions)
Balance at beginning of year	$	3	$	97		$	110
Additions based on tax positions related to the current year		—		4			13
Reductions for tax positions of prior years		—		(33	)		(4	)
Settlements		—		(65	)		(22	)
Balance at end of year	$	3	$	3		$	97

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, 2013, 2012, and 2011 the Company recorded tax expense of $1 million, $5 million, and $6 million, respectively, for interest and penalties. As of December 31, 2013 and 2012, the Company had approximately $1 million and $5 million, respectively, accrued for payment of interest and penalties.

The Company is under IRS audit for 2011 and 2012 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 2013, the Company reached an agreement with the IRS regarding an audit of the 2009 and 2010 tax years. There was no change in the Company’s unrecognized tax benefit as a result of the 2009 and 2010 IRS settlement. In 2012, the Company reached an agreement with the IRS Administrative Appeals office regarding the audits of tax years 2004 through 2008. As a result of this agreement, the Company reduced its 2012 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.	2010
Canada	2009
Egypt	1998
Australia	2009
U.K.	2011
Argentina	2006

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 $10 million for all

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

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 in 2012 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.

Argentine Tariff 

Enargas, an autonomous entity that functions under the Argentine Ministry of Economy, issued administrative orders pursuant to national executive Decree No. 2067/2008 creating a tariff charge on all fuel gas used by oil and gas producers in field operations effective December 1, 2011. The tariff charge, which is applicable to the operations of Company affiliates in Argentina, totaled approximately $39.5 million since inception, of which $11 million has been paid. The Company’s affiliates have initiated legal proceedings in the Provinces of Neuquén and Tierra del Fuego challenging the Enargas tariff charge and have obtained temporary injunctive relief that prohibits the collection of the charges pending final rulings on the merits of the legal challenges.

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

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 also denied, and petitioned the United States Court of Appeals for the Tenth Circuit to accept an appeal of the District Court’s ruling denying class certification. The plaintiff withdrew the petition to appeal following decisions on July 8, 2013, by the United States Court of Appeals for the Tenth Circuit to vacate District Court class certification orders in two unrelated lawsuits — Wallace B. Roderick Revocable Living Trust v. XTO Energy, Inc., No. 12-3176, and Chieftain Royalty Company v. XTO Energy, Inc., No. 12-7047. The plaintiff and Apache recently filed a joint stipulation to dismiss the Foster lawsuit with prejudice, which concludes the matter.

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.

On July 24, 2013, a lawsuit captioned Board of Commissioners of the Southeast Louisiana Flood Protection Authority — East v. Tennessee Gas Pipeline Company et al., Case No. 2013-6911 was filed in the Civil District Court for the Parish of Orleans, State of Louisiana, in which plaintiff on behalf of itself and as the board governing the levee districts of Orleans, Lake Borgne Basin, and East Jefferson alleges that Louisiana coastal lands have been damaged as a result of oil and gas industry activity, including a network of canals for access and pipelines. The plaintiff seeks damages and injunctive relief in the form of abatement and restoration based on claims of negligence, strict liability, natural servitude of drain, public nuisance, private nuisance, and breach of contract — third party beneficiary. Apache has been indiscriminately named as one of approximately 100 defendants in the lawsuit. Defendant Chevron U.S.A., Inc. filed a notice to remove the case to the United States District Court for the Eastern District of Louisiana, civil action No. 13-5410. The overall exposure related to this lawsuit is not currently determinable. While an adverse judgment against Apache might be possible, Apache intends to vigorously defend the case.

On November 8, 2013, the Parish of Plaquemines in Louisiana filed three lawsuits against the Company and other oil and gas producers alleging that certain of defendants’ oil and gas exploration, production, and transportation operations in specified fields were conducted in violation of the State and Local Coastal Resources Management Act of 1978, as amended, and applicable regulations, rules, orders, and ordinances promulgated or adopted thereunder by the State of Louisiana or the Parish of Plaquemines. The plaintiff alleges that defendants

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

caused substantial damage to land and water bodies located in the coastal zone of Louisiana. The plaintiff seeks, among other things, unspecified damages for alleged violations of applicable state law within the coastal zone, the payment of costs necessary to clear, re-vegetate, detoxify, and otherwise restore the subject coastal zone as near as practicable to its original condition, and actual restoration of the coastal zone to its original condition. The lawsuits were all filed in Division A of the 25^th Judicial District Court for the Parish of Plaquemines, State of Louisiana, and are captioned as follows: Parish of Plaquemines v. Rozel Operating Company et al., Docket No. 60-996; Parish of Plaquemines v. Apache Oil Corporation et al., Docket No. 61-000; and Parish of Plaquemines v. HHE Energy Company et al., Docket No. 60-983. Defendants have filed notices to remove the cases to the United States District Court for the Eastern District of Louisiana, civil action Nos. 13-6722, 13-6711, and 13-6735. The plaintiff has moved to remand each of the lawsuits to state court, and plaintiff’s motions are pending. Many similar lawsuits have been filed against other oil and gas producers in the Parish of Plaquemines and in other Parishes across south Louisiana. The overall exposure related to these lawsuits is not currently determinable. While an adverse judgment against Apache might be possible, Apache intends to vigorously defend the cases.

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, alleged 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 sought 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 was one of numerous defendants. The District Court granted defendants’ motion to dismiss plaintiffs’ claims. Plaintiffs appealed the decision to the United States Court of Appeals for the Fifth Circuit, which affirmed dismissal of the suit. Plaintiffs did not appeal further, thus concluding the matter. 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 natural gas customer, Burrup Fertilisers Pty Ltd (Burrup Fertilisers), 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, in a case captioned Burrup Fertilisers Pty Ltd v. Apache Corporation, Apache Energy Limited, and Apache Northwest Pty Ltd, Cause No. 2009-79834, in the District Court of Harris County, Texas. The lawsuit concerned the interruption of deliveries of natural gas to Burrup Fertilisers following the pipeline explosion. Burrup Fertilisers and its underwriters asserted claims for negligence, breach of contract, alter ego, single business enterprise, res ipsa loquitur, and gross negligence/exemplary damages, and sought 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. On March 22, 2013, Burrup Fertilisers agreed to dismiss its

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

Texas lawsuit based on Apache Corporation’s motion to dismiss on the ground of forum non conveniens. Accordingly, the District Court entered an agreed order dismissing Burrup Fertilisers’ Texas lawsuit on the ground of forum non conveniens. By its terms, the order of dismissal does not prevent Burrup Fertilisers from re-filing its lawsuit in the civil courts of Western Australia.

On March 24, 2011, another natural gas 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. On September 17, 2013, the Western Australia Court of Appeal dismissed the Company subsidiaries’ appeal concerning Alcoa’s remaining tort claim for economic loss. On October 15, 2013, the Company subsidiaries applied to the High Court of Australia for leave to appeal. The applications for leave to appeal are pending. If the High Court does not grant leave to appeal at this time, all of the Company subsidiaries’ defenses remain intact for further proceedings at the trial court level.

On October 31, 2013, a third natural gas customer, Barrick (Plutonic) Limited (“Barrick”), filed a lawsuit captioned Barrick (Plutonic) Limited v. Apache Energy Limited, Apache Northwest Pty Ltd, Harriet (Onyx) Pty Ltd, and Kufpec Australia Pty Ltd , Civ. 2656 of 2013, in the Supreme Court of Western Australia. The lawsuit concerns the interruption of gas deliveries to Barrick under certain gas supply contracts. Barrick asserts tort claims against the Company’s subsidiaries and seeks approximately $19 million USD in general damages, including for alleged lost gold production at the Plutonic mine in Western Australia.

The Company and its subsidiaries do not believe that the Burrup Fertilisers, Alcoa, and Barrick 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. At least one third party that is not a customer has also threatened to file suit. Contract prices under customer contracts are significantly below current 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 $50 million AUD exclusive of interest. This is a reduction from the previous estimate of $200 million AUD. No assurance can be given that customers would not assert claims in excess of contractual liquidated damages, and exposure related to such claims (or any claims by non-customers) is not currently determinable. While an adverse judgment against Company subsidiaries (and the Company, in the case of Burrup Fertilisers) 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

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

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 was $50,000 AUD. The Company subsidiary did not believe that the charge had 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 stated 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 was 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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

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 would 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 were 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. On May 28, 2013, the United States District Court for the Southern District of Texas dismissed the plaintiffs’ claims and entered judgment in favor of the defendants. On June 3, 2013, the plaintiffs filed a notice of appeal in the United States Court of Appeals for the Fifth Circuit. The appeal is pending. The exposure related to the re-filed lawsuit is not currently determinable. While an adverse judgment against Apache is possible, Apache intends to vigorously 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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

being conducted by Kelmar Associates on behalf of the State of Delaware. 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 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 Pankaj Oswal et al. v. Apache Corporation, Cause No. 2011-30302, in the District Court of Harris County, Texas, was filed in which plaintiffs asserted claims against the Company under the Australian Trade Practices Act. Following a hearing on March 22, 2013, the District Court on April 5, 2013, granted Apache Corporation’s motion to dismiss on the ground of forum non conveniens and entered an order dismissing the Texas lawsuit. On or about October 11, 2013, a statement of claim captioned Pankaj Oswal v. Apache Corporation, No. WAD 389/2013, in the Federal Court of Australia, District of Western Australia, General Division, was filed in which plaintiff Oswal once again asserts claims against the Company under the Australian Trade Practices Act. The Western Australia lawsuit is one of a number of legal actions involving the 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 Western Australia 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 and Western Australia lawsuits relate 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 operates the ammonia plant and is proceeding 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. 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). YPHPL share ownership, and the modified gas supply agreement, continues to be the subject of ongoing litigation in Australia with third parties, including Pankaj and Radhika Oswal. Two such cases directly involve the Company or certain of its subsidiaries. In a case captioned Radhika Oswal v. Australia and New Zealand Banking Group Limited (ANZ) et al., No. SCI 2011 4653, in the Supreme Court of Victoria, the defendants include a Company affiliate. The Court has denied plaintiff’s application seeking to amend her statement of claim in order to add parties as defendants to the proceedings, including the Company and certain of its other subsidiaries. Similarly, in a companion case captioned Pankaj Oswal v. Australia and New Zealand Banking Group Limited (ANZ) et al., No. SCI 2012 01995, in the Supreme Court of Victoria, the Court has also denied plaintiff’s application seeking to amend his statement of claim in order to add parties as defendants to the proceedings, including the Company and certain of its subsidiaries. The plaintiffs, either in their original claims or in their proposed amended claims, seek to set aside the YPHPL share sale, void the modified gas sale agreement, and recover unspecified damages. The plaintiffs’ in both cases have sought leave to appeal the Court’s denial of their applications. The new gas supply

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

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, 2013, the Company had an undiscounted reserve for environmental remediation of approximately $93 million. Apache is not aware of any environmental claims existing as of December 31, 2013 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.

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

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.

On June 1, 2013, Apache Canada Ltd. discovered a leak of produced water from a below ground pipeline in the Zama Operations area in northern Alberta. The pipeline was associated with a produced water disposal well. The spill resulted in approximately 97 thousand barrels of produced water being released to the marsh land environment. The applicable government agencies were immediately notified of the event and the line was shut down. Apache Canada Ltd. investigated the leak while conducting clean up and monitoring activities in the affected area and communicating with appropriate parties, including regulatory and First Nation representatives. The investigation revealed a pinhole feature in the outer polyethylene liner of the composite flex line. While the exposure related to this incident is not currently determinable, the Company does not expect the economic impact of this incident to have a material effect on the Company’s financial position, results of operations, or liquidity.

Contractual Obligations

At December 31, 2013, contractual obligations for drilling rigs, purchase obligations, firm transportation agreements, and long-term operating leases are as follows:

									2019 &
Net Minimum Commitments	Total		2014		2015-2016		2017-2018		Beyond
	(In millions)
Drilling rig commitments(1)	$	974	$	376	$	429	$	157	$	12
Purchase obligations(2)		1,759		1,002		533		204		20
Firm transportation agreements(3)		683		158		223		129		173
Office and related equipment(4)		391		46		101		95		149
Other operating lease obligations(5)		686		190		295		193		8
Total Net Minimum Commitments	$	4,493	$	1,772	$	1,581	$	778	$	362

(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 $81 million, $76 million, and $64 million for 2013, 2012, and 2011, respectively.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

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 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 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. These plans allow 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 $123 million, $117 million, and $93 million for 2013, 2012, and 2011, 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, 2013, 2012, and 2011, 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.

	2013						2012						2011
	Pension			Postretirement			Pension			Postretirement			Pension			Postretirement
	Benefits			Benefits			Benefits			Benefits			Benefits			Benefits
	(In millions)
Change in Projected Benefit Obligation
Projected benefit obligation beginning of year	$	177		$	35		$	150		$	30		$	136		$	29
Service cost		5			4			5			4			5			3
Interest cost		7			1			7			1			7			1
Foreign currency exchange rate changes		4			—			7			—			(1	)		—
Actuarial losses (gains)		—			(8	)		14			1			6			(2	)
Effect of curtailment and settlements		—			(3	)		—			—			—			—
Benefits paid		(4	)		(2	)		(6	)		(1	)		(3	)		(1	)
Retiree contributions		—			1			—			—			—			—
Projected benefit obligation at end of year		189			28			177			35			150			30
Change in Plan Assets
Fair value of plan assets at beginning of year		170			—			145			—			135			—
Actual return on plan assets		15			—			14			—			4			—
Foreign currency exchange rates		4			—			6			—			(1	)		—
Employer contributions		6			1			11			1			10			1
Benefits paid		(4	)		(2	)		(6	)		(1	)		(3	)		(1	)
Retiree contributions		—			1			—			—			—			—
Fair value of plan assets at end of year		191			—			170			—			145			—
Funded status at end of year	$	2		$	(28	)	$	(7	)	$	(35	)	$	(5	)	$	(30	)
Amounts recognized in Consolidated Balance Sheet
Current liability		—			(1	)		—			(1	)		—			(1	)
Non-current asset (liability)		2			(27	)		(7	)		(34	)		(5	)		(29	)
	$	2		$	(28	)	$	(7	)	$	(35	)	$	(5	)	$	(30	)
Pre-tax Amounts Recognized in Accumulated Other Comprehensive Income (Loss)
Accumulated gain (loss)		(22	)		1			(32	)		(7	)		(25	)		(6	)
	$	(22	)	$	1		$	(32	)	$	(7	)	$	(25	)	$	(6	)
Weighted Average Assumptions used as of December 31
Discount rate		4.60	%		4.33	%		4.30	%		3.43	%		4.70	%		4.04	%
Salary increases		4.90	%		N/A			4.60	%		N/A			4.60	%		N/A
Expected return on assets		5.60	%		N/A			4.70	%		N/A			4.85	%		N/A
Healthcare cost trend
Initial		N/A			7.00	%		N/A			7.25	%		N/A			7.50	%
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, 2013, 2012, and 2011, the accumulated benefit obligation for the U.K. Pension Plan was $160 million, $139 million, and $119 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
	2013			2013			2012
Asset Category
Equity securities:
U.K. quoted equities		17	%		18	%		16	%
Overseas quoted equities		33	%		33	%		33	%
Total equity securities		50	%		51	%		49	%
Debt securities:
U.K. Government bonds		30	%		29	%		30	%
U.K. corporate bonds		20	%		20	%		20	%
Debt securities		50	%		49	%		50	%
Cash		0	%		0	%		1	%
Total		100	%		100	%		100	%

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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. The following tables present 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, 2013 and 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)
December 31, 2013
Equity securities:
U.K. quoted equities(1)	$	35	$	—	$	—	$	35
Overseas quoted equities(2)		63		—		—		63
Total equity securities		98		—		—		98
Debt securities:
U.K. Government bonds(3)		54		—		—		54
U.K. corporate bonds(4)		38		—		—		38
Total debt securities		92		—		—		92
Cash		1		—		—		1
Fair value of plan assets	$	191	$	—	$	—	$	191
December 31, 2012
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 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 the 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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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—  (Continued)

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, out performance 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, 2013, 2012, and 2011:

	2013						2012						2011
	Pension			Postretirement			Pension			Postretirement			Pension			Postretirement
	Benefits			Benefits			Benefits			Benefits			Benefits			Benefits
	(In millions)
Component of Net Periodic Benefit Costs
Service cost	$	5		$	4		$	5		$	4		$	5		$	3
Interest cost		7			1			7			1			7			1
Expected return on assets		(8	)		—			(7	)		—			(8	)		—
Amortization of actuarial (gain) loss		2			—			1			—			—			—
Curtailment (gain) loss		—			(3	)		—			—			—			—
Net periodic benefit cost	$	6		$	2		$	6		$	5		$	4		$	4
Weighted Average Assumptions used to determine Net Period Benefit Cost for the Years ended 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	%

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		6		(4	)

F-44

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

Apache expects to contribute approximately $6 million to its pension plan and $1 million to its postretirement benefit plan in 2014. The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:

	Pension		Postretirement
	Benefits		Benefits
	(In millions)
2014	$	5	$	1
2015		5		1
2016		5		2
2017		5		2
2018		5		2
Years 2019-2023		30		16

10.     CAPITAL STOCK

Common Stock Outstanding

	2013			2012		2011
Balance, beginning of year		391,640,770			384,117,643		382,391,742
Shares issued for stock-based compensation plans:
Treasury shares issued		25,214			60,767		144,313
Common shares issued		929,596			1,189,693		1,581,588
Common shares issued for conversion of preferred shares		14,399,247			—		—
Treasury shares acquired		(11,221,919	)		—		—
Cordillera consideration (Note 2)		—			6,272,667		—
Balance, end of year		395,772,908			391,640,770		384,117,643

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, 2013, 2012, and 2011 is presented in the table below.

	2013						2012						2011
	Income		Shares		Per Share		Income		Shares		Per Share		Income		Shares		Per Share
	(In millions, except per share amounts)
Basic:
Net income attributable to common stock	$	2,188		395	$	5.53	$	1,925		389	$	4.95	$	4,508		384	$	11.75
Effect of Dilutive Securities:
Mandatory Convertible Preferred Stock	$	44		9			$	—		—			$	76		14
Stock options and other		—		2				—		2				—		2
Diluted:
Net income attributable to common stock, including assumed conversions	$	2,232		406	$	5.50	$	1,925		391	$	4.92	$	4,584		400	$	11.47

F-45

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

The diluted EPS calculation excludes options and restricted shares that were anti-dilutive totaling 4.9 million, 4.4 million, and 2.5 million for the years ended December 31, 2013, 2012, and 2011, 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.

Stock Repurchase Program

In May 2013, Apache’s Board of Directors authorized the purchase of up to 30 million shares of the Company’s common stock, valued at approximately $2 billion when first announced. Shares may be purchased either in the open market or through privately held negotiated transactions. The Company initiated the buyback program on June 10, 2013, with the repurchase of 2,924,271 shares at an average price of $85.47 during the month of June. During the fourth quarter of 2013, 8,297,648 shares were repurchased at an average price of $90.08. An additional 2,393,917 shares were purchased subsequent to December 31, 2013 at an average cost of $84.67. The Company anticipates that further purchases will primarily be made with proceeds from asset dispositions, but the Company is not obligated to acquire any specific number of shares.

Common Stock Dividend

The Company paid common stock dividends of $0.77 per share in 2013, $0.66 per share in 2012, and $0.60 per share in 2011.

Stock Compensation Plans

The Company has several stock-based compensation plans, which include stock options, stock appreciation rights, restricted stock, and conditional restricted stock unit 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. A total of 27.3 million shares were authorized and available for grant under the 2011 Plan as of December 31, 2013. 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 2013, 2012, and 2011, stock-based compensation expensed was $136 million, $167 million, and $113 million ($94 million, $119 million, and $73 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:

	2013		2012		2011
	(In millions)
Stock-based compensation expensed:
General and administrative	$	89	$	104	$	69
Lease operating expenses		47		63		44
Stock-based compensation capitalized		55		67		42
	$	191	$	234	$	155

Stock Options

As of December 31, 2013, 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 2000 and 2005 (collectively, the Stock Option Plans), as well as the 2007 Omnibus Equity Compensation Plan (the 2007 Plan), and the 2011 Plan

F-46

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

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:

	2013
	Shares Under Option			Weighted Average Exercise Price
	(In thousands)
Outstanding, beginning of year		7,573		$	90.47
Granted		819			80.89
Exercised		(327	)		72.55
Forfeited or expired		(502	)		97.88
Outstanding, end of year(1)		7,563			89.71
Expected to vest(1)		2,370			92.50
Exercisable, end of year(1)		4,678			88.53
Weighted average fair value of options granted during the year	$	23.18

(1) As of December 31, 2013, the weighted average remaining contractual life for options outstanding, expected to vest, and exercisable is 6.1 years, 8.2 years, and 4.7 years, respectively. The aggregate intrinsic value of options outstanding, expected to vest, and exercisable at year-end was $43 million, $7 million, and $34 million, respectively. The weighted-average grant-date fair value of options granted during the years 2013, 2012, and 2011 was $23.18, $26.41, and $42.20, 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.

	2013			2012			2011
Expected volatility		33.60	%		34.94	%		34.47	%
Expected dividend yields		0.99	%		0.82	%		0.47	%
Expected term (in years)		5.5			5.5			5.5
Risk-free rate		0.79	%		0.78	%		1.95	%

The intrinsic value of options exercised during 2013, 2012, and 2011 was approximately $4 million, $12 million and $50 million, respectively. The cash received from exercise of options during 2013 was approximately

F-47

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

$24 million. The Company realized an additional tax benefit of approximately $1.5 million for the amount of intrinsic value in excess of compensation cost recognized in 2013. As of December 31, 2013, the total compensation cost related to non-vested options not yet recognized was $60 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. As of December 31, 2013, a total of 316,127 SARs were outstanding, of which 201,552 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 $33.41 based on the Black-Scholes valuation methodology using assumptions comparable to those discussed above. During 2013, 237,288 SARs were exercised. The aggregate of cash payments made to settle SARs was $11 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 2013, the Company awarded 3,098,029 restricted stock units at a weighted-average per-share market price of $82.95. In 2012 and 2011, the Company awarded 1,219,886 and 887,851 restricted stock units at a weighted-average per-share market price of $85.67 and $124.16, 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 2013, 2012, and 2011, $82 million ($53 million after tax), $74 million ($48 million after tax), and $76 million ($49 million after tax), respectively, was charged to expense. In 2013, 2012, and 2011, $30 million, $25 million, and $28 million was capitalized, respectively. As of December 31, 2013, there was $242 million of total unrecognized compensation cost related to 3,952,539 unvested restricted stock units. The weighted-average remaining life of unvested restricted stock units is approximately 1.3 years.

The fair value of the awards vested during 2013, 2012 and 2011 was approximately $88 million, $114 million, and $85 million, respectively. A summary of restricted stock activity for the year ended December 31, 2013, is presented below.

	Shares			Weighted- Average Grant- Date Fair Value
	(In thousands)
Non-vested at January 1, 2013		2,164		$	97.34
Granted		3,098			82.95
Vested		(907	)		96.79
Forfeited		(402	)		88.61
Non-vested at December 31, 2013		3,953			86.70

Conditional Restricted Stock Units

To provide long-term incentives for Apache employees to deliver competitive returns to the Company’s stockholders, the Company has 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

F-48

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

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. Grants from two conditional restricted stock unit programs were outstanding at December 31, 2013, as described below:

• 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. Based on measurement of total shareholder return relative to the designated peer group at December 31, 2013, zero shares were awarded and all unvested conditional restricted stock units were cancelled. Upon cancellation, all remaining unamortized expense related to these awards was immediately amortized.

• 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 710,686 units were outstanding at December 31, 2013, from which a minimum of zero and a maximum of 1,776,715 units could be awarded.

• In January 2013 the Company’s Board of Directors approved the 2013 Performance Program, pursuant to the 2011 Plan. In January 2013 eligible employees received initial conditional restricted stock unit awards totaling 1,232,176 units. In May 2013, the Company’s Board of Directors cancelled 918,016 awards under the 2013 Performance Program for nonexecutive employees. A total of 310,091 awards were outstanding at December 31, 2013, from which a minimum of zero and a maximum of 775,228 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 2013, 2012, and 2011, $27 million ($17 million after tax), $47 million ($31 million after tax), and $12 million ($8 million after tax), respectively, was charged to expense. During 2013, 2012, and 2011, $13 million, $21 million, and $5 million was capitalized, respectively. As of December 31, 2013, there was $47 million of total unrecognized compensation cost related to 1,020,777 unvested conditional restricted stock units. The weighted-average remaining life of the unvested conditional restricted stock units is approximately 2.1 years.

	Shares			Weighted- Average Grant- Date Fair Value(1)
	(In thousands)
Non-vested at January 1, 2013		1,306		$	78.40
Granted		1,232			79.60
Vested		0			79.49
Cancelled		(1,369	)		83.34
Forfeited		(149	)		78.09
Non-vested at December 31, 2013		1,020			73.73

(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.

F-49

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

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). The Company’s 6.00 percent Mandatory Convertible Preferred Stock, Series D (the Series D Preferred Stock) were converted to Apache common shares in August 2013.

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.

On February 5, 2014, the Company’s Board of Directors voted to terminate the Company’s stockholder rights plan. As a result of this decision, the Board approved an amendment to the Rights Agreement that will have the effect of terminating the Rights. The amendment will change the expiration date to March 7, 2014 and, thereby, accelerate the expiration of the Rights. The Company expects that the amendment will be fully executed on March 7, 2014.

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. Upon conversion of the outstanding Preferred Shares on August 1, 2013, 14.4 million Apache common shares were issued.

F-50

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

11.     ACCUMULATED OTHER COMPREHENSIVE LOSS

Components of accumulated other comprehensive loss include the following:

	For the Year Ended December 31,
	2013			2012			2011
	(In millions)
Currency translation adjustment(1)	$	(109	)	$	(109	)	$	(109	)
Unrealized gain (loss) on derivatives (Note 3)		1			(6	)		114
Unfunded pension and postretirement benefit plan (Note 9)		(7	)		(16	)		(14	)
Accumulated other comprehensive loss	$	(115	)	$	(131	)	$	(9	)

(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 2013, 2012, and 2011, purchases by Royal Dutch Shell plc and its subsidiaries accounted for 24 percent, 20 percent, and 11 percent, respectively, of the Company’s worldwide oil and gas production revenues. In 2011, purchases by the Vitol Group accounted for 13 percent of the Company’s worldwide oil and gas production revenues.

F-51

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

13.     BUSINESS SEGMENT INFORMATION

Apache is engaged in a single line of business. Both domestically and internationally, the Company explores for, develops, and produces natural gas, crude oil and natural gas liquids. At December 31, 2013, the Company had production in six countries: the United States, 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. Financial information for each country is presented below:

	United States		Canada			Egypt(1)		Australia		North Sea		Argentina			Other International			Total(1)
	(In millions)
2013
Oil and gas production revenues	$	6,902	$	1,224		$	3,917	$	1,140	$	2,728	$	491		$	—		$	16,402
Operating Expenses:
Depreciation, depletion, and amortization
Recurring		2,338		505			1,005		423		1,022		230			1			5,524
Additional		552		—			—		—		367		181			76			1,176
Asset retirement obligation accretion		94		49			—		27		68		5			—			243
Lease operating expenses		1,320		459			471		214		400		192			—			3,056
Gathering and transportation		84		155			42		—		7		9			—			297
Taxes other than income		335		45			8		13		384		47			—			832
Operating Income (Loss)	$	2,179	$	11		$	2,391	$	463	$	480	$	(173	)	$	(77	)		5,274
Other Income (Expense):
Derivative instrument gains (losses), net																			(399	)
Other																			51
General and administrative																			(503	)
Acquisitions, divestitures, and transition																			(33	)
Financing costs, net																			(174	)
Income Before Income Taxes																		$	4,216
Net Property and Equipment	$	27,010	$	6,058		$	5,454	$	6,838	$	5,622	$	1,416		$	23		$	52,421
Total Assets	$	29,940	$	6,952		$	8,121	$	8,094	$	6,902	$	1,577		$	51		$	61,637
Additions to Net Property and Equipment	$	6,404	$	1,082		$	1,309	$	1,954	$	1,084	$	205		$	24		$	12,062
(1) Includes a noncontrolling interest in Egypt.
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)	$	2,311	$	(1,867	)	$	3,166	$	866	$	989	$	51		$	(43	)		5,473
Other Income (Expense):
Derivative instrument gains (losses), net																			(79	)
Other																			210
General and administrative																			(531	)
Acquisitions, divestitures, and 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

F-52

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

	United States		Canada		Egypt		Australia		North Sea		Argentina		Other International			Total
	(In millions)
2011
Oil and gas production revenues	$	6,103	$	1,617	$	4,791	$	1,734	$	2,091	$	474	$	—		$	16,810
Operating Expenses:
Depreciation, depletion, and amortization
Recurring		1,684		546		818		440		409		198		—			4,095
Additional		—		—		—		—		—		—		109			109
Asset retirement obligation accretion		97		26		—		10		17		4		—			154
Lease operating expenses		1,167		470		398		197		208		165		—			2,605
Gathering and transportation		64		165		35		—		25		7		—			296
Taxes other than income		259		51		13		9		539		28		—			899
Operating Income (Loss)	$	2,832	$	359	$	3,527	$	1,078	$	893	$	72	$	(109	)		8,652
Other Expense:
Other																	78
General and administrative																	(459	)
Acquisitions, divestitures, and 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

F-53

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

14.     SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited)

Oil and Gas Operations

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

	United States		Canada			Egypt(3)		Australia		North Sea		Argentina			Other International			Total(3)
	(In millions, except per boe)
2013
Oil and gas production revenues	$	6,902	$	1,224		$	3,917	$	1,140	$	2,728	$	491		$	—		$	16,402
Operating cost:
Depreciation, depletion, and amortization
Recurring(1)		2,227		426			881		361		999		220			—			5,114
Additional		552		—			—		—		367		181			76			1,176
Asset retirement obligation accretion		94		49			—		27		68		5			—			243
Lease operating expenses		1,320		459			471		214		400		192			—			3,056
Gathering and transportation		84		155			42		—		7		9			—			297
Production taxes(2)		324		40			—		14		382		36			—			796
Income tax		817		24			1,161		157		313		(53	)		—			2,419
		5,418		1,153			2,555		773		2,536		590			76			13,101
Results of operation	$	1,484	$	71		$	1,362	$	367	$	192	$	(99	)	$	(76	)	$	3,301
Amortization rate per boe	$	18.39	$	10.89		$	16.21	$	17.47	$	37.25	$	14.13		$	—		$	18.42
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			—		—		—		—			109			1,992
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			109			14,207
Results of operation	$	1,545	$	(1,379	)	$	1,654	$	610	$	377	$	42		$	(109	)	$	2,740
Amortization rate per boe	$	17.24	$	11.66		$	13.81	$	17.67	$	32.65	$	12.39		$	—		$	16.88

F-54

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

	United States		Canada		Egypt(3)		Australia		North Sea		Argentina		Other International			Total(3)
	(In millions, except per boe)
2011
Oil and gas production revenues	$	6,103	$	1,617	$	4,791	$	1,734	$	2,091	$	474	$	—		$	16,810
Operating cost:
Depreciation, depletion, and amortization
Recurring(1)		1,634		537		818		435		405		195		—			4,024
Additional		—		—		—		—		—		—		109			109
Asset retirement obligation accretion		97		26		—		10		17		4		—			154
Lease operating expenses		1,167		470		398		197		208		165		—			2,605
Gathering and transportation		64		165		35		—		25		7		—			296
Production taxes(2)		255		44		—		9		538		19		—			865
Income tax		1,025		95		1,699		325		557		29		—			3,730
		4,242		1,337		2,950		976		1,750		419		109			11,783
Results of 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

(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) 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.

(3) 2013 includes a noncontrolling interest in Egypt.

F-55

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(2)			Australia			North Sea		Argentina		Other International		Total(2)
	(In millions)
2013
Acquisitions:
Proved	$	17	$	—	$	35		$	—		$	125	$	—	$	—	$	177
Unproved		—		137		11			—			17		—		—		165
Exploration		757		50		563			169			278		53		22		1,892
Development		5,435		722		618			996			635		142		—		8,548
Costs incurred(1)	$	6,209	$	909	$	1,227		$	1,165		$	1,055	$	195	$	22	$	10,782
(1) Includes capitalized interest and asset retirement costs as follows:
Capitalized interest	$	239	$	35	$	15		$	16		$	25	$	10	$	—	$	340
Asset retirement costs		480		17		—			(30	)		67		3		—		537
(2) Includes a noncontrolling interest in Egypt.
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

F-56

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(1)			Australia			North Sea			Argentina			Other International			Total(1)
	(In millions)
2013
Proved properties	$	41,904		$	13,231		$	8,418		$	7,298		$	9,378		$	2,933		$	228		$	83,390
Unproved properties		5,042			1,116			660			471			702			349			23			8,363
		46,946			14,347			9,078			7,769			10,080			3,282			251			91,753
Accumulated DD&A		(20,745	)		(9,310	)		(5,356	)		(2,839	)		(4,811	)		(1,964	)		(228	)		(45,253	)
	$	26,201		$	5,037		$	3,722		$	4,930		$	5,269		$	1,318		$	23		$	46,500
(1) Includes a noncontrolling interest in Egypt.
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

Costs Not Being Amortized

The following table sets forth a summary of oil and gas property costs not being amortized at December 31, 2013, 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		2013		2012		2011		2010 and Prior
	(In millions)
Property acquisition costs	$	6,437	$	466	$	3,391	$	899	$	1,681
Exploration and development		1,666		1,138		388		88		52
Capitalized interest		260		48		48		30		134
Total	$	8,363	$	1,652	$	3,827	$	1,017	$	1,867

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-57

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-58

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 reserve data in the following tables only represent estimates and should not be construed as being exact.

	Crude Oil and Condensate
	(Thousands of barrels)
	United States			Canada			Egypt(1)			Australia			North Sea			Argentina			Total(1)
Proved developed reserves:
December 31, 2010		422,737			90,292			109,657			48,072			115,705			16,583			803,046
December 31, 2011		428,251			81,846			105,840			35,725			136,990			16,001			804,653
December 31, 2012		474,837			79,695			106,746			29,053			119,635			15,845			825,811
December 31, 2013		457,981			80,526			119,242			22,524			100,327			14,195			794,795
Proved undeveloped reserves:
December 31, 2010		214,117			56,855			17,470			18,064			38,663			4,062			349,231
December 31, 2011		205,763			59,746			22,195			32,220			32,415			4,585			356,924
December 31, 2012		203,068			70,650			17,288			34,808			28,019			2,981			356,814
December 31, 2013		195,835			56,366			16,302			36,703			29,253			2,231			336,690
Total proved reserves:
Balance December 31, 2010		636,855			147,146			127,127			66,136			154,368			20,645			1,152,277
Extensions, discoveries and other additions		45,676			16,712			45,021			15,762			332			3,230			126,733
Purchase of minerals in-place		5,097			705			—			—			34,612			—			40,414
Revisions of previous estimates		(8,904	)		(17,117	)		(6,185	)		—			—			215			(31,991	)
Production		(43,587	)		(5,202	)		(37,928	)		(13,953	)		(19,907	)		(3,503	)		(124,080	)
Sale of properties		(1,123	)		(653	)		—			—			—			—			(1,776	)
Balance December 31, 2011		634,014			141,591			128,035			67,945			169,405			20,587			1,161,577
Extensions, discoveries and other additions		84,656			18,935			36,188			6,277			346			1,133			147,535
Purchase of minerals in-place		15,942			188			—			276			2,143			—			18,549
Revisions of previous estimates		(7,474	)		(4,577	)		(3,678	)		(66	)		(928	)		671			(16,052	)
Production		(49,089	)		(5,792	)		(36,511	)		(10,571	)		(23,312	)		(3,565	)		(128,840	)
Sale of properties		(144	)		—			—			—			—			—			(144	)
Balance December 31, 2012		677,905			150,345			124,034			63,861			147,654			18,826			1,182,625
Extensions, discoveries and other additions		133,227			10,177			43,738			2,539			1,543			998			192,222
Purchase of minerals in-place		85			—			5			—			3,623			—			3,713
Revisions of previous estimates		1,683			(531	)		457			(118	)		18			24			1,533
Production		(53,621	)		(6,469	)		(32,690	)		(7,055	)		(23,258	)		(3,422	)		(126,515	)
Sale of properties		(105,463	)		(16,630	)		—			—			—			—			(122,093	)
Balance December 31, 2013		653,816			136,892			135,544			59,227			129,580			16,426			1,131,485

(1) 2013 includes proved reserves of 45 MMbbls as of December 31, 2013 attributable to a noncontrolling interest in Egypt.

F-59

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

	Natural Gas Liquids
	(Thousands of barrels)
	United States			Canada			Egypt			Australia		North Sea			Argentina			Total
Proved developed reserves:
December 31, 2010		91,800			23,701			—			—		—			5,875			121,376
December 31, 2011		107,490			23,256			—			—		8,753			5,939			145,438
December 31, 2012		154,508			21,996			—			—		2,438			5,007			183,949
December 31, 2013		184,485			26,099			—			—		2,435			4,110			217,129
Proved undeveloped reserves:
December 31, 2010		30,361			4,142			—			—		—			579			35,082
December 31, 2011		52,543			8,193			—			—		509			1,215			62,460
December 31, 2012		60,889			12,258			—			—		380			876			74,403
December 31, 2013		63,538			9,970			—			—		215			1,009			74,732
Total proved reserves:
Balance December 31, 2010		122,160			27,844			—			—		—			6,454			156,458
Extensions, discoveries and other additions		43,915			5,890			18			—		72			1,784			51,679
Purchase of minerals in-place		586			47			—			—		9,191			—			9,824
Revisions of previous estimates		1,713			774			—			—		—			17			2,504
Production		(8,071	)		(2,174	)		(18	)		—		(1	)		(1,102	)		(11,366	)
Sale of properties		(270	)		(931	)		—			—		—			—			(1,201	)
Balance December 31, 2011		160,033			31,450			—			—		9,262			7,153			207,898
Extensions, discoveries and other additions		71,965			7,655			—			—		246			—			79,866
Purchase of minerals in-place		230			9			—			—		231			—			470
Revisions of previous estimates		(4,559	)		(2,569	)		—			—		(6,329	)		(169	)		(13,626	)
Production		(12,272	)		(2,291	)		—			—		(592	)		(1,101	)		(16,256	)
Sale of properties		—			—			—			—		—			—			—
Balance December 31, 2012		215,397			34,254			—			—		2,818			5,883			258,352
Extensions, discoveries and other additions		69,231			4,014			—			—		—			—			73,245
Purchase of minerals in-place		45			—			—			—		295			—			340
Revisions of previous estimates		1,591			546			—			—		1			3			2,141
Production		(19,922	)		(2,442	)		—			—		(464	)		(767	)		(23,595	)
Sale of properties		(18,319	)		(303	)		—			—		—			—			(18,622	)
Balance December 31, 2013		248,023			36,069			—			—		2,650			5,119			291,861

F-60

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

	Natural Gas
	(Millions of cubic feet)
	United States			Canada			Egypt(1)			Australia			North Sea			Argentina			Total(1)
Proved developed reserves:
December 31, 2010		2,284,116			2,181,615			748,573			682,763			4,144			462,206			6,363,417
December 31, 2011		2,215,973			2,108,801			700,866			675,618			105,028			447,132			6,253,418
December 31, 2012		2,353,587			1,734,657			690,436			596,052			93,319			365,054			5,833,105
December 31, 2013		2,005,966			1,294,420			621,825			626,543			88,177			289,133			4,926,064
Proved undeveloped reserves:
December 31, 2010		988,869			1,310,352			328,344			805,735			—			70,465			3,503,765
December 31, 2011		760,238			1,438,710			282,100			893,966			3,414			90,427			3,468,855
December 31, 2012		832,320			403,227			205,055			1,074,018			18,985			97,496			2,631,101
December 31, 2013		667,160			439,037			190,355			975,224			18,988			121,584			2,412,348
Total proved reserves:
Balance December 31, 2010		3,272,985			3,491,967			1,076,917			1,488,498			4,144			532,671			9,867,182
Extensions, discoveries and other additions		169,506			505,049			77,049			148,640			475			81,274			981,993
Purchase of minerals in-place		67,595			8,838			—			—			104,658			—			181,091
Revisions of previous estimates		(7,716	)		(133,359	)		(37,623	)		—			—			1,107			(177,591	)
Production		(315,631	)		(230,880	)		(133,377	)		(67,554	)		(835	)		(77,493	)		(825,770	)
Sale of properties		(210,528	)		(94,104	)		—			—			—			—			(304,632	)
Balance December 31, 2011		2,976,211			3,547,511			982,966			1,569,584			108,442			537,559			9,722,273
Extensions, discoveries and other additions		365,863			252,130			55,967			176,969			16,397			2,623			869,949
Purchase of minerals in-place		313,885			2,503			—			1,745			8,494			—			326,627
Revisions of previous estimates		(156,840	)		(1,443,989	)		(13,974	)		101			—			496			(1,614,206	)
Production		(312,600	)		(219,849	)		(129,468	)		(78,329	)		(21,029	)		(78,128	)		(839,403	)
Sale of properties		(612	)		(422	)		—			—			—			—			(1,034	)
Balance December 31, 2012		3,185,907			2,137,884			895,491			1,670,070			112,304			462,550			8,464,206
Extensions, discoveries and other additions		306,721			359,493			44,382			13,351			2,750			16,515			743,212
Purchase of minerals in-place		855			—			—			—			10,680			—			11,535
Revisions of previous estimates		61,247			109,551			2,413			(101	)		32			49			173,191
Production		(285,187	)		(181,593	)		(130,106	)		(81,553	)		(18,601	)		(68,397	)		(765,437	)
Sale of properties		(596,417	)		(691,878	)		—			—			—			—			(1,288,295	)
Balance December 31, 2013		2,673,126			1,733,457			812,180			1,601,767			107,165			410,717			7,338,412

(1) 2013 includes proved reserves of 271 Bcf as of December 31, 2013 attributable to a noncontrolling interest in Egypt.

F-61

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

	Total Equivalent Reserves
	(Thousands barrels of oil equivalent)
	United States			Canada			Egypt(1)			Australia			North Sea			Argentina			Total(1)
Proved developed reserves:
December 31, 2010		895,223			477,594			234,419			161,866			116,396			99,493			1,984,991
December 31, 2011		905,069			456,569			222,651			148,328			163,248			96,462			1,992,327
December 31, 2012		1,021,610			390,800			221,819			128,395			137,626			81,695			1,981,945
December 31, 2013		976,795			322,362			222,880			126,948			117,457			66,494			1,832,936
Proved undeveloped reserves:
December 31, 2010		409,290			279,389			72,194			152,353			38,663			16,385			968,274
December 31, 2011		385,013			307,724			69,212			181,214			33,493			20,871			997,527
December 31, 2012		402,677			150,113			51,464			213,811			31,563			20,106			869,734
December 31, 2013		370,566			139,509			48,028			199,240			32,633			23,504			813,480
Total proved reserves:
Balance December 31, 2010		1,304,512			756,984			306,613			314,219			155,059			115,878			2,953,265
Extensions, discoveries and other additions		117,842			106,778			57,882			40,534			483			18,559			342,078
Purchase of minerals in-place		16,949			2,225			—			—			61,246			—			80,420
Revisions of previous estimates		(8,477	)		(38,570	)		(12,456	)		—			—			417			(59,086	)
Production		(104,263	)		(45,856	)		(60,176	)		(25,211	)		(20,047	)		(17,521	)		(273,074	)
Sale of properties		(36,481	)		(17,268	)		—			—			—			—			(53,749	)
Balance December 31, 2011		1,290,082			764,293			291,863			329,542			196,741			117,333			2,989,854
Extensions, discoveries and other additions		217,598			68,612			45,516			35,772			3,325			1,570			372,393
Purchase of minerals in-place		68,486			614			—			567			3,790			—			73,457
Revisions of previous estimates		(38,172	)		(247,811	)		(6,007	)		(49	)		(7,258	)		585			(298,712	)
Production		(113,461	)		(44,725	)		(58,089	)		(23,626	)		(27,409	)		(17,687	)		(284,997	)
Sale of properties		(246	)		(70	)		—			—			—			—			(316	)
Balance December 31, 2012		1,424,287			540,913			273,283			342,206			169,189			101,801			2,851,679
Extensions, discoveries and other additions		253,578			74,107			51,135			4,764			2,001			3,751			389,336
Purchase of minerals in-place		273			—			5			—			5,698			—			5,976
Revisions of previous estimates		13,482			18,274			859			(135	)		24			35			32,539
Production		(121,074	)		(39,177	)		(54,374	)		(20,647	)		(26,822	)		(15,589	)		(277,683	)
Sale of properties		(223,185	)		(132,246	)		—			—			—			—			(355,431	)
Balance December 31, 2013		1,347,361			461,871			270,908			326,188			150,090			89,998			2,646,416

(1) 2013 includes total proved reserves of 90 MMboe attributable to a noncontrolling interest in Egypt.

F-62

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

During 2013, Apache added 6 MMboe of estimated proved reserves through purchases of minerals in-place. We sold 355 MMboe through several divestiture transactions which included the majority of our Gulf of Mexico Shelf properties and certain fields in Canada. During 2013, Apache also added 389 MMboe from extensions, discoveries and other additions. In the U.S., the Company recorded 254 MMboe primarily associated with drilling successes in the Permian and Anadarko basins, which added 150 MMboe and 65 MMboe, respectively; 20 MMboe from appraisal drilling in the deepwater Gulf of Mexico; and 19 MMboe from various drilling programs in other U.S. regions. In Canada, additions of 74 MMboe were primarily a result of drilling activity for liquids-rich gas targets in the Kaybob field area, horizontal drilling in our House Mountain waterflood units, extensions of the Glauconitic trend in our West 5 area and shallow oil drilling in Brownfield and Consort field areas. Egypt contributed 51 MMboe from exploration and appraisal activity in the West Kalabsha, Shushan, Khalda and Ras Kanayes concessions along with continued development of the Razzak, Abu Gharadig and Meghar fields. Australia, Argentina and North Sea regions contributed 11 MMboe from their combined drilling programs.

Approximately 10 percent of Apache’s year-end 2013 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.”

Future Net Cash Flows

Future cash inflows as of December 31, 2013 and 2012 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-63

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(2)			Australia			North Sea			Argentina			Total(2)
	(In millions)
2013
Cash inflows	$	79,654		$	19,260		$	16,864		$	20,637		$	15,359		$	2,824		$	154,598
Production costs		(26,032	)		(8,105	)		(2,590	)		(4,494	)		(8,147	)		(1,176	)		(50,554	)
Development costs		(4,834	)		(2,458	)		(1,899	)		(2,283	)		(3,284	)		(397	)		(15,155	)
Income tax expense		(12,832	)		(678	)		(4,328	)		(3,072	)		(2,376	)		(142	)		(23,428	)
Net cash flows		35,956			8,019			8,047			10,788			1,552			1,109			65,471
10 percent discount rate		(20,117	)		(3,987	)		(2,193	)		(6,423	)		85			(242	)		(32,877	)
Discounted future net cash flows(1)	$	15,839		$	4,032		$	5,854		$	4,365		$	1,637		$	867		$	32,594
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

(1) Estimated future net cash flows before income tax expense, discounted at 10 percent per annum, totaled approximately $45.4 billion and $48.2 billion as of December 31, 2013 and 2012, respectively.

(2) Includes discounted future net cash flows of approximately $1.95 billion in 2013 attributable to a noncontrolling interest in Egypt.

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

	For the Year Ended December 31,
	2013			2012			2011
	(In millions)
Sales, net of production costs	$	(12,271	)	$	(12,589	)	$	(13,152	)
Net change in prices and production costs		1,438			(1,941	)		12,167
Discoveries and improved recovery, net of related costs		6,892			6,742			6,751
Change in future development costs		(2,017	)		(935	)		(2,250	)
Previously estimated development costs incurred during the period		4,654			4,359			2,479
Revision of quantities		500			(4,065	)		(1,475	)
Purchases of minerals in-place		227			1,181			2,139
Accretion of discount		4,823			5,234			4,161
Change in income taxes		855			2,711			(4,303	)
Sales of properties		(6,232	)		(3	)		(1,285	)
Change in production rates and other		(828	)		(2,088	)		273
	$	(1,959	)	$	(1,394	)	$	5,505

F-64

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)
2013
Revenues and other	$	4,076	$	4,383	$	4,019	$	3,576	$	16,054
Expenses(2)		3,359		3,348		3,713		3,346		13,766
Net income including noncontrolling interest	$	717	$	1,035	$	306	$	230	$	2,288
Net income attributable to common stock	$	698	$	1,016	$	300	$	174	$	2,188
Net income per common share(1):
Basic	$	1.78	$	2.59	$	0.75	$	0.44	$	5.53
Diluted	$	1.76	$	2.54	$	0.75	$	0.43	$	5.50
2012
Revenues and other	$	4,536	$	3,972	$	4,179	$	4,391	$	17,078
Expenses(2)		3,739		3,616		3,999		3,723		15,077
Net income including noncontrolling interest	$	797	$	356	$	180	$	668	$	2,001
Net 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

(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.

(2) In 2013, operating expenses include non-cash write-downs of the Company’s oil and gas properties totaling $659 million, net of tax, in the U.S., North Sea, and Argentina regions and also the Company’s exit of operations in Kenya. In 2012, the Company recorded a $1.4 billion, net of tax, non-cash write-down of the carrying value of the Company’s Canadian proved oil and gas properties.

16.     SUPPLEMENTAL GUARANTOR INFORMATION

In December 1999, Apache Finance Canada issued approximately $300 million of publicly-traded notes due in 2029, which 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-65

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME

For the Year Ended December 31, 2013

	Apache Corporation			Apache Finance Canada		All Other Subsidiaries of Apache Corporation			Reclassifications & Eliminations			Consolidated
	(In millions)
REVENUES AND OTHER:
Oil and gas production revenues	$	4,585		$	—	$	11,817		$	—		$	16,402
Equity in net income (loss) of affiliates		2,313			17		36			(2,366	)		—
Derivative instrument gains (losses), net		(399	)		—		—			—			(399	)
Other		—			61		(6	)		(4	)		51
		6,499			78		11,847			(2,370	)		16,054
OPERATING EXPENSES:
Depreciation, depletion, and amortization		2,250			—		4,450			—			6,700
Asset retirement obligation accretion		67			—		176			—			243
Lease operating expenses		939			—		2,117			—			3,056
Gathering and transportation		61			—		236			—			297
Taxes other than income		190			—		642			—			832
General and administrative		408			—		99			(4	)		503
Acquisitions, divestitures, and transition		33			—		—			—			33
Financing costs, net		97			5		72			—			174
		4,045			5		7,792			(4	)		11,838
INCOME (LOSS) BEFORE INCOME TAXES		2,454			73		4,055			(2,366	)		4,216
Provision (benefit) for income taxes		222			20		1,686			—			1,928
NET INCOME (LOSS) INCLUDING
NONCONTROLLING INTEREST		2,232			53		2,369			(2,366	)		2,288
Net income attributable to noncontrolling interest		—			—		56			—			56
Preferred stock dividends		44			—		—			—			44
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	2,188		$	53	$	2,313		$	(2,366	)	$	2,188
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	2,204		$	53	$	2,313		$	(2,366	)	$	2,204

F-66

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME

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
Acquisitions, divestitures, and 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
NET 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-67

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME

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
Acquisitions, divestitures, and 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
NET 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-68

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

For the Year Ended December 31, 2013

	Apache Corporation			Apache Finance Canada			All Other Subsidiaries of Apache Corporation			Reclassifications & Eliminations		Consolidated
	(In millions)
CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	$	1,421		$	315		$	8,099		$	—	$	9,835
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property		(4,291	)		—			(5,728	)		—		(10,019	)
Additions to gas gathering, transmission, and processing facilities		(124	)		—			(1,077	)		—		(1,201	)
Proceeds from divestiture of Gulf of Mexico Shelf properties		3,702			—			—			—		3,702
Acquisitions, other		—			—			(215	)		—		(215	)
Proceeds from Kitimat LNG transaction, net		—			—			396			—		396
Proceeds from sale of oil and gas properties		—			—			307			—		307
Other		(58	)		—			(28	)		—		(86	)
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES		(771	)		—			(6,345	)		—		(7,116	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Commercial paper, credit facility, and bank notes, net		(501	)		—			(12	)		—		(513	)
Intercompany borrowings		3,056			1			(3,057	)		—		—
Payments on fixed rate debt		(1,722	)		(350	)		—			—		(2,072	)
Dividends paid		(360	)		—			—			—		(360	)
Proceeds from sale of noncontrolling interest		—			—			2,948			—		2,948
Shares repurchased		(997	)		—			—			—		(997	)
Other		29			37			(45	)		—		21
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		(495	)		(312	)		(166	)		—		(973	)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		155			3			1,588			—		1,746
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR		—			—			160			—		160
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	155		$	3		$	1,748		$	—	$	1,906

F-69

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 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-70

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

For the Year Ended December 31, 2011

	Apache Corporation			Apache Finance Canada			All Other Subsidiaries of Apache Corporation			Reclassifications & Eliminations			Consolidated
	(In millions)
CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	$	2,191		$	13		$	7,749		$	—		$	9,953
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property		(1,478	)		—			(4,936	)		—			(6,414	)
Additions to gas gathering, transmission, and processing facilities		—			—			(664	)		—			(664	)
Acquisitions 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-71

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

CONDENSED CONSOLIDATING BALANCE SHEET

December 31, 2013

	Apache Corporation		Apache Finance Canada		All Other Subsidiaries of Apache Corporation		Reclassifications & Eliminations			Consolidated
	(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	155	$	3	$	1,748	$	—		$	1,906
Receivables, net of allowance		1,043		—		1,909		—			2,952
Inventories		48		—		843		—			891
Drilling advances		49		—		322		—			371
Derivative instruments		1		—		—		—			1
Prepaid assets and other		99		—		146		—			245
Intercompany receivable		5,357		—		—		(5,357	)		—
		6,752		3		4,968		(5,357	)		6,366
PROPERTY AND EQUIPMENT, NET		16,092		—		36,329		—			52,421
OTHER ASSETS:
Intercompany receivable		1,572		—		—		(1,572	)		—
Equity in affiliates		24,743		1,155		449		(26,347	)		—
Goodwill, net		173		—		1,196		—			1,369
Deferred charges and other		166		1,006		1,309		(1,000	)		1,481
	$	49,498	$	2,164	$	44,251	$	(34,276	)	$	61,637
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable	$	956	$	2	$	658	$	—		$	1,616
Current debt		—		—		53		—			53
Asset retirement obligation		115		—		6		—			121
Derivative instruments		299		—		—		—			299
Other current liabilities		896		10		1,705		—			2,611
Intercompany payable		—		—		5,357		(5,357	)		—
		2,266		12		7,779		(5,357	)		4,700
LONG-TERM DEBT		9,374		298		—		—			9,672
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Intercompany payable		—		—		1,572		(1,572	)		—
Income taxes		3,586		—		4,778		—			8,364
Asset retirement obligation		430		—		2,671		—			3,101
Other		446		250		711		(1,000	)		407
		4,462		250		9,732		(2,572	)		11,872
COMMITMENTS AND CONTINGENCIES APACHE SHAREHOLDERS’ EQUITY		33,396		1,604		24,743		(26,347	)		33,396
Noncontrolling interest		—		—		1,997		—			1,997
TOTAL EQUITY		33,396		1,604		26,740		(26,347	)		35,393
	$	49,498	$	2,164	$	44,251	$	(34,276	)	$	61,637

F-72

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		102		—		91		—			193
Intercompany receivable		3,766		—		—		(3,766	)		—
		4,891		1		3,836		(3,766	)		4,962
PROPERTY AND EQUIPMENT, NET		18,517		—		34,763		—			53,280
OTHER ASSETS:
Intercompany receivable		4,628		—		—		(4,628	)		—
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	$	40,864	$	(31,472	)	$	60,737
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable	$	639	$	1	$	452	$	—		$	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
Intercompany payable		—		—		3,766		(3,766	)		—
		3,011		4		6,287		(3,766	)		5,536
LONG-TERM DEBT		10,706		647		2		—			11,355
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Intercompany payable		—		—		4,628		(4,628	)		—
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		13,528		(5,628	)		12,515
COMMITMENTS AND CONTINGENCIES TOTAL EQUITY		31,331		1,031		21,047		(22,078	)		31,331
	$	49,408	$	1,937	$	40,864	$	(31,472	)	$	60,737

F-73

Board of Directors

Officers

G. Steven Farris Chairman of the Board, Chief Executive Officer, and President Apache Corporation Randolph M. Ferlic, M.D.(1) Founder and Former President, Surgical Services of the Great Plains, P.C. Eugene C. Fiedorek(1) Private Investor, Co-Founder and Former President and Managing Director, EnCap Investments L.C. A.D. Frazier, Jr.(2)(4) President, Georgia Oak Partners Chansoo Joung(1)(3) Senior Advisor and Former Partner, Warburg Pincus LLC George D. Lawrence(2) Private Investor; Former Chief Executive Officer, The Phoenix Resource Companies, Inc. John E. Lowe(2)(4) Former Executive Vice President, ConocoPhillips William C. Montgomery(2)(3) Managing Director, Quantum Energy Partners Amy H. Nelson President and Founder, Greenridge Advisors, LLC Rodman D. Patton(1) Former Managing Director, Merrill Lynch Energy Group Charles J. Pitman(3)(4) Former Regional President — Middle East/ Caspian/Egypt/India, BP Amoco plc

G. Steven Farris Chairman of the Board, Chief Executive Officer, and President John J. Christmann Executive Vice President and Chief Operating Officer — North America Thomas E. Voytovich Executive Vice President and Chief Operating Officer — International Michael S. Bahorich Executive Vice President and Chief Technology Officer Rodney J. Eichler Executive Advisor to the Chairman; Chief Executive Officer — Kitimat Margery M. Harris Executive Vice President — Human Resources P. Anthony Lannie Executive Vice President and General Counsel Alfonso Leon Executive Vice President and Chief Financial Officer W. Kregg Olson Executive Vice President — Corporate Reservoir Engineering Thomas P. Chambers Senior Vice President, Finance Matthew W. Dundrea Senior Vice President — Treasury and Administration Robert J. Dye Senior Vice President — Global Communication and Corporate Affairs Janine J. McArdle Senior Vice President — Gas Monetization Sarah B. Teslik Senior Vice President — Policy and Governance 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 — Investor Relations Jon W. Sauer Vice President — Tax Cheri L. Peper Corporate Secretary

(1) Audit Committee

(2) Management Development and Compensation Committee

(3) Corporate Governance and Nominating Committee

(4) Stock Plan Committee

Shareholder Information

Stock Data

	Price Range				Dividends per Share
	High		Low		Declared		Paid
2013
First Quarter	$	86.35	$	72.20	$	0.20	$	0.17
Second Quarter		87.57		67.91		0.20		0.20
Third Quarter		89.17		75.07		0.20		0.20
Fourth Quarter		94.84		84.15		0.20		0.20
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

The Company has paid cash dividends on its common stock for 49 consecutive years through December 31, 2013. 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, 2013, the Company’s shares of common stock outstanding were held by approximately 5,000 shareholders of record and 327,000 beneficial owners. Also listed on the New York Stock Exchange are 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 15, 2014, 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 September 19, 2013, as filed with the Secretary of State of Delaware on September 19, 2013 (incorporated by reference to Exhibit 3.2 to Registrant’s Current Report on Form 8-K filed September 20, 2013, 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	–	Certificate of Elimination of Series D Preferred Stock of Registrant, dated September 18, 2013, as filed with the Secretary of State of Delaware on September 19, 2013 (incorporated by reference to Exhibit 3.1 to Registrant’s Current Report on Form 8-K filed September 19, 2013, SEC File No. 001-4300).
3.4	–	Bylaws of Registrant, as amended May 16, 2013 (incorporated by reference to Exhibit 3.1 to Registrant’s Current Report on Form 8-K filed May 17, 2013, SEC File No. 001-4300).
4.1	–	Form of Certificate for Registrant’s Common Stock (incorporated by reference to Exhibit 4.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2004, SEC File No. 001-4300).
4.2	–	Form of Certificate for the 6.00% Mandatory Convertible Preferred Stock, Series D (incorporated by reference to Exhibit A of Exhibit 3.3 to Registrant’s Registration Statement on Form 8-A, dated July 29, 2010, SEC File No. 001-4300).
4.3	–	Form of 3.625% Notes due 2021 (incorporated by reference to Exhibit 4.1 to Registrant’s Current Report on Form 8-K, dated November 30, 2010, filed on December 3, 2010, SEC File No. 001-4300).

EXHIBIT NO.		DESCRIPTION
4.4	–	Form of 5.250% Notes due 2042 (incorporated by reference to Exhibit 4.2 to Registrant’s Current Report on Form 8-K, dated November 30, 2010, filed on December 3, 2010, SEC File No. 001-4300).
4.5	–	Form of 5.100% Notes due 2040 (incorporated by reference to Exhibit 4.1 to Registrant’s Current Report on Form 8-K, dated August 17, 2010, filed on August 20, 2010, SEC File No. 001-4300).
4.6	–	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).
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).

EXHIBIT NO.		DESCRIPTION
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).
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	–	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).

EXHIBIT NO.		DESCRIPTION
10.2	–	First Amendment to Credit Agreement, dated as of July 17, 2013, among Apache Corporation, the lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, and the other agents party thereto, amending Credit Agreement, dated as of August 12, 2011, among the same parties (incorporated by reference to Exhibit 10.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2013, SEC File No. 001-4300).
10.3	–	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).
10.4	–	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)
10.5	–	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).
†10.6	–	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).
†10.7	–	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).
†10.8	–	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).
†10.9	–	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).
*†10.10	–	Apache Corporation 401(k) Savings Plan, as amended and restated, dated May 14, 2013, effective May 1, 2013.
†10.11	–	Amendment to Apache Corporation 401(k) Savings Plan, dated October 25, 2013 (incorporated by reference to Exhibit 10.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2013, SEC File No. 001-4300).
†10.12	–	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).

EXHIBIT NO.		DESCRIPTION
†10.13	–	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).
†10.14	–	Amendment to Non-Qualified Retirement/Savings Plan of Apache Corporation, dated November 8, 2012, effective January 1, 2013 (incorporated by reference to Exhibit 10.25 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2012, SEC File No. 001-4300).
†10.15	–	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).
†10.16	–	Amendment to Non-Qualified Restorative Retirement Savings Plan of Apache Corporation, dated November 8, 2012, effective January 1, 2013 (incorporated by reference to Exhibit 10.27 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2012, SEC File No. 001-4300).
*†10.17	–	Apache Corporation 2011 Omnibus Equity Compensation Plan, as amended and restated February 3, 2014.
†10.18	–	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).
†10.19	–	Apache Corporation 2000 Stock Option Plan, as amended and restated May 5, 2011 (incorporated by reference to Exhibit 10.3 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2011, SEC File No. 001-4300).
†10.20	–	Apache Corporation 2003 Stock Appreciation Rights Plan, as amended and restated September 16, 2013 (incorporated by reference to Exhibit 10.2 to Registrant’s Quarterly Report on Form 10-Q for quarter ended September 30, 2013, SEC File No. 001-4300).
†10.21	–	Apache Corporation 2005 Stock Option Plan, as amended and restated September 16, 2013 (incorporated by reference to Exhibit 10.3 to Registrant’s Quarterly Report on Form 10-Q for quarter ended September 30, 2013, Commission File No. 001-4300).
†10.22	–	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).
*†10.23	–	Apache Corporation Deferred Delivery Plan, as amended and restated November 11, 2013.
†10.24	–	Apache Corporation Non-Employee Directors’ Compensation Plan, as amended and restated February 6, 2013 (incorporated by reference to Exhibit 10.39 to Registrant’s Annual Report on Form 10-K for the year ended December 31, 2012, SEC File No. 001-4300).
†10.25	–	Apache Corporation Outside Directors’ Retirement Plan, as amended and restated February 6, 2013 (incorporated by reference to Exhibit 10.40 to Registrant’s Annual Report on Form 10-K for the year ended December 31, 2012, SEC File No. 001-4300).
†10.26	–	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).
†10.27	–	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
*†10.28	–	Apache Corporation Non-Employee Directors’ Restricted Stock Units Program Specifications, as amended and restated May 15, 2013, pursuant to Apache Corporation 2011 Omnibus Equity Compensation Plan.
†10.29	–	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).
†10.30	–	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).
†10.31	–	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).
†10.32	–	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).
†10.33	–	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).
†10.34	–	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).
†10.35	–	Resignation Agreement, dated March 7, 2011 between Registrant and John A. Crum (incorporated by reference to Exhibit 10.2 to Registrant’s Current Report on Form 8-K/A filed March 8, 2011, SEC File No. 001-4300).
†10.36	–	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).
†10.37	–	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).
†10.38	–	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).
†10.39	–	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).
†10.40	–	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).

EXHIBIT NO.		DESCRIPTION
†10.41	–	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).
†10.42	–	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).
†10.43	–	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).
†10.44	–	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).
†10.45	–	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 11, 2013, SEC File No. 001-4300).
*10.46	–	Form of 2014 Performance Agreement (Total Shareholder Return), dated January 9, 2014, between Registrant and each of G. Steven Farris, Rodney J. Eichler, Roger B. Plan, P. Anthony Lannie, and Thomas P. Chambers.
*10.47	–	Form of 2014 Performance Agreement (Business Performance), dated February 3, 2014, between Registrant and each of G. Steven Farris, Roger B. Plank, Rodney J. Eichler, P. Anthony Lannie, and Thomas P. Chambers.
*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 13, 2013.
*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-10.10

Exhibit 10.10

APACHE CORPORATION

401(k) SAVINGS PLAN

Effective May 1, 2013 Prepared May 13, 2013

Table of Contents

ARTICLE I DEFINITIONS			1
	1.1	Account Owner	1
	1.2	Accounts	1
	1.3	Affiliated Entity	1
	1.4	Alternate Payee	1
	1.5	Annual Addition	1
	1.6	Catch-Up Contributions	2
	1.7	Code	2
	1.8	Committee	2
	1.9	Company	2
	1.10	Company Contributions	2
	1.11	Company Discretionary Contributions	2
	1.12	Company Matching Contributions	2
	1.13	Company Stock	2
	1.14	Compensation	2
	1.15	Covered Employee	4
	1.16	Disability	5
	1.17	Domestic Relations Order	5
	1.18	Employee	5
	1.19	ERISA	5
	1.20	Five-Percent Owner	5
	1.21	401(k) Contributions	6
	1.22	Highly Compensated Employee	6
	1.23	Key Employee	6
	1.24	Lapse in Apache Employment	6
	1.25	Limitation Year	6
	1.26	Non-Highly Compensated Employee	6
	1.27	Non-Key Employee	6
	1.28	Normal Retirement Age	6
	1.29	NQ Plan	6
	1.30	Participant	6
	1.31	Participant Contributions	7
	1.32	Period of Service	7
	1.33	Plan Year	7
	1.34	QDRO	7
	1.35	QMAC	7
	1.36	QNECs	7
	1.37	Required Beginning Date	7
	1.38	Restorative Plan	7
	1.39	Roth Catch-Up Contributions	8
	1.40	Roth Contributions	8
	1.41	Roth Rollover Contribution	8
	1.42	Rollover Contribution	8
	1.43	Spouse	8
	1.44	Termination of Employment	8
	1.45	Termination From Service Date	8
	1.46	Valuation Date	8
ARTICLE II PARTICIPATION			8
	2.1	Participation-Required Service.	8
	2.2	Enrollment Procedure.	8

ARTICLE III CONTRIBUTIONS			9
	3.1	Company Contributions.	9
	3.2	Participant Contributions.	10
	3.3	Return of Contributions.	14
	3.4	Limitation on Annual Additions.	14
	3.5	Contribution Limits for Highly Compensated Employees (ADP Test).	14
	3.6	Contribution Limits for Highly Compensated Employees (ACP Test).	15
	3.7	QNECs.	17
	3.8	QMACs.	17
ARTICLE IV INTERESTS IN THE TRUST FUND			18
	4.1	Participants’ Accounts.	18
	4.2	Valuation of Trust Fund.	18
	4.3	Allocation of Increase or Decrease in Net Worth.	19
ARTICLE V AMOUNT OF BENEFITS			19
	5.1	Vesting Schedule.	19
	5.2	Vesting After a Lapse in Apache Employment.	20
	5.3	Calculating Service.	20
	5.4	Forfeitures.	21
	5.5	Transfers - Portability.	22
ARTICLE VI DISTRIBUTION OF BENEFITS			22
	6.1	Beneficiaries.	22
	6.2	Consent.	23
	6.3	Distributable Amount.	23
	6.4	Manner of Distribution.	24
	6.5	In-Service Withdrawals.	24
	6.6	Time of Distribution.	25
	6.7	Direct Rollover Election.	27
ARTICLE VII LOANS			29
	7.1	Availability	29
	7.2	Number of Loans	29
	7.3	Loan Amount	29
	7.4	Interest	29
	7.5	Repayment.	30
	7.6	Default	30
	7.7	Administration	30
ARTICLE VIII ALLOCATION OF RESPONSIBILITIES-NAMED FIDUCIARIES			30
	8.1	No Joint Fiduciary Responsibilities.	30

i

	8.2	The Company.	30
	8.3	The Trustee.	31
	8.4	The Committee-Plan Administrator.	31
	8.5	Committee to Construe Plan.	31
	8.6	Organization of Committee.	31
	8.7	Agent for Process.	31
	8.8	Indemnification of Committee Members.	31
	8.9	Conclusiveness of Action.	32
	8.10	Payment of Expenses.	32
ARTICLE IX TRUST AGREEMENT – INVESTMENTS			32
	9.1	Trust Agreement.	32
	9.2	Plan Expenses.	32
	9.3	Investments.	32
ARTICLE X TERMINATION AND AMENDMENT			33
	10.1	Termination of Plan or Discontinuance of Contributions.	33
	10.2	Allocations upon Termination or Discontinuance of Company Contributions.	33
	10.3	Procedure upon Termination of Plan or Discontinuance of Contributions.	33
	10.4	Amendment by Apache.	34
ARTICLE XI PLAN ADOPTION BY AFFILIATED ENTITIES			34
	11.1	Adoption of Plan.	34
	11.2	Agent of Affiliated Entity.	34
	11.3	Disaffiliation and Withdrawal from Plan.	34
	11.4	Effect of Disaffiliation or Withdrawal.	35
	11.5	Actions upon Disaffiliation or Withdrawal.	35
ARTICLE XII TOP-HEAVY PROVISIONS			35
	12.1	Application of Top-Heavy Provisions.	35
	12.2	Determination of Top-Heavy Status.	35
	12.3	Special Vesting Rule.	36
	12.4	Special Minimum Contribution.	36
	12.5	Change in Top-Heavy Status.	36

ARTICLE XIII MISCELLANEOUS			36
	13.1	Right to Dismiss Employees-No Employment Contract.	36
	13.2	Claims Procedure.	37
	13.3	Source of Benefits.	38
	13.4	Exclusive Benefit of Employees.	38
	13.5	Forms of Notices.	38
	13.6	Failure of Any Other Entity to Qualify.	38
	13.7	Notice of Adoption of the Plan.	38
	13.8	Plan Merger.	38
	13.9	Inalienability of Benefits-Domestic Relations Orders.	39
	13.10	Payments due Minors or Incapacitated Individuals.	42
	13.11	Uniformity of Application.	42
	13.12	Disposition of Unclaimed Payments.	42
	13.13	Applicable Law.	42
ARTICLE XIV MATTERS AFFECTING COMPANY STOCK			42
	14.1	Voting, Etc.	42
	14.2	Notices.	42
	14.3	Retention/Sale of Company Stock and Other Securities.	43
	14.4	Tender Offers.	43
	14.5	Stock Rights.	43
	14.6	Other Rights Appurtenant to the Company Stock.	44
	14.7	Information to Trustee.	44
	14.8	Information to Account Owners.	44
	14.9	Expenses.	45
	14.10	Former Account Owners.	45
	14.11	No Recommendations.	45
	14.12	Trustee to Follow Instructions.	45
	14.13	Confidentiality.	46
	14.14	Investment of Proceeds.	46
	14.15	Independent Fiduciary.	46
	14.16	Method of Communications.	46
ARTICLE XV UNIFORMED SERVICES EMPLOYMENT AND REEMPLOYMENT RIGHTS ACT OF 1994			47
	15.1	General.	47
	15.2	While a Serviceman.	47
	15.3	Expiration of USERRA Reemployment Rights.	48
	15.4	Return From Uniformed Service.	49

Appendix A — Participating Companies

Appendix B — Hadson Energy Resources Company

Appendix C — Corporate Transactions

Appendix D —DEKALB Energy Company / Apache Canada Ltd.

Appendix E — Mariner Energy, Inc.

ii

APACHE CORPORATION

401(k) SAVINGS PLAN

PREAMBLE

Apache Corporation, a Delaware corporation (“Apache”), maintains this profit sharing plan (the “Plan”), which is intended to be qualified under Code §401(a), and which contains a cash or deferred arrangement that is intended to be qualified under Code §401(k).

The Plan was restated to reflect the plan document for which the IRS issued a favorable determination letter on October 28, 2010. The Plan was subsequently restated to incorporate the four Plan amendments that were not covered by the favorable determination letter and to eliminate several special effective dates for certain provisions. This restatement adds Roth contributions and makes other minor changes. This restatement is effective as of May 1, 2013.

Each Appendix to this Plan is a part of the Plan document. It is intended that an Appendix will be used, among other things, to (1) describe which business entities are actively participating in the Plan, (2) describe any special participation, eligibility, vesting, or other provisions that apply to the employees of a business entity, (3) describe any special provisions that apply to Participants affected by a designated corporation transaction, and (4) describe any special distribution rules that apply to directly transferred benefits from other plans.

ARTICLE I

Definitions

The following words and phrases shall have the meaning set forth below:

1.1 Account Owner

“Account Owner” means a Participant who has an Account balance, an Alternate Payee who has an Account balance, or a beneficiary who has obtained an interest in the Account(s) of the previous Account Owner because of the previous Account Owner’s death.

1.2 Accounts

“Accounts” means the various Participant accounts established pursuant to section 4.1.

1.3 Affiliated Entity

“Affiliated Entity” means:

(a) For all purposes of the Plan except those listed in subsection (b), the term “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).

(b) For purposes of determining Annual Additions under section 1.5, limiting Annual Additions to a Participant’s Account(s) under section 3.4, and construing the defined terms as they are used in sections 1.5 and 3.4 (such as “ Compensation” and “Employee”), the term “Affiliated Entity” means any legal entity that is treated as a single employer with Apache pursuant to Code §414(m) or §414(o), and any legal entity that would be an Affiliated Entity pursuant to Code §414(b) or §414(c) if the phrase “more than 50%” were substituted for the phrase “at least 80%” each place it occurs in Code §1563(a)(1).

1.4 Alternate Payee

“Alternate Payee” means a Participant’s Spouse, former spouse, child, or other dependent who is recognized by a QDRO as having a right to receive all, or a portion of, the benefits payable under this Plan with respect to such Participant.

1.5 Annual Addition

“Annual Addition” means the allocations to a Participant’s Account(s) for any Limitation Year, as described in detail below.

Page 1 of 51 Prepared May 13, 2013

(a) Annual Additions shall include: (i) Company Contributions (except as provided in paragraphs (b)(iii) and (b)(v)) to this Plan and Company contributions to any other defined contribution plan maintained by the Company or any Affiliated Entity, including Company Matching Contributions forfeited to satisfy the ACP test of section 3.6, (ii) after-tax contributions to any other defined contribution plan maintained by the Company or an Affiliated Entity; (iii) 401(k) Contributions to this Plan and similar contributions to any other defined contribution plan maintained by the Company or an Affiliated Entity, including any such contributions distributed to satisfy the ADP test of section 3.5; (iv) forfeitures allocated to a Participant’s Account(s) in this Plan and any other defined contribution plan maintained by the Company or any Affiliated Entity (except as provided in paragraphs (b)(iii) and (b)(v) below); (v) all amounts paid or accrued to a welfare benefit fund as defined in Code §419(e) and allocated to the separate account (under the welfare benefit fund) of a Key Employee to provide post-retirement medical benefits; and (vi) contributions allocated on the Participant’s behalf to any individual medical account as defined in Code §415(l)(2).

(b) Annual Additions shall not include: (i) Rollover Contributions to this Plan or rollovers to any other defined contribution plan maintained by the Company or an Affiliated Entity; (ii) repayments of loans made to a Participant from a qualified plan maintained by the Company or any Affiliated Entity; (iii) repayments of forfeitures for rehired Participants, as described in Code §411(a)(7)(B) and §411(a)(3)(D); (iv) direct transfers of employee contributions from one qualified plan to any qualified defined contribution plan maintained by the Company or any Affiliated Entity; (v) repayments of forfeitures of missing individuals pursuant to section 13.12; (vi) salary deferrals by a returning Serviceman within the meaning of Code §414(u)(2)(C) that are attributable to a different Plan Year, (vii) Catch-Up Contributions, or (viii) Roth Catch-Up Contributions.

1.6 Catch-Up Contributions

“Catch-Up Contributions” means those contributions made to the Plan by the Company, at the election of the Participant pursuant to subsection 3.2(b) that meet the requirements of Code §414(v).

1.7 Code

“Code” means the Internal Revenue Code of 1986, as amended from time to time, and the regulations and rulings in effect thereunder from time to time.

1.8 Committee

“Committee” means the administrative committee provided for in section 8.4.

1.9 Company

“Company” means Apache, any successor thereto, and any Affiliated Entity that adopts the Plan pursuant to Article XI. Each Company is listed in Appendix A.

1.10 Company Contributions

“Company Contributions” means all contributions to the Plan made by the Company pursuant to section 3.1 for the Plan Year.

1.11 Company Discretionary Contributions

“Company Discretionary Contributions” means all contributions to the Plan made by the Company pursuant to subsection 3.1(a) for the Plan Year.

1.12 Company Matching Contributions

“Company Matching Contributions” means all contributions to the Plan made by the Company pursuant to subsection 3.1(b) for the Plan Year.

1.13 Company Stock

“Company Stock” means shares of the $0.625 par value common stock of Apache.

1.14 Compensation

“Compensation” means:

Page 2 of 51 Prepared May 13, 2013

(a) Compensation for Annual Additions.

(i) Items Included. For purposes of determining the limitation on Annual Additions under section 3.4, Compensation means those amounts reported as “wages, tips, other compensation” on Form W-2 by Apache or an Affiliated Entity elective contributions that would have been reported as “wages, tips, other compensation” on Form W-2 by Apache or an Affiliated Entity but for an election under Code §125(a), §132(f)(4), §402(e)(3), §402(h)(1)(B), §402(k), or §457(b). The Plan shall ignore any rules that limit the remuneration included in “wages, tips, other compensation” based on the nature or location of the employment or the services performed.

(ii) Timing Restrictions. Compensation includes amounts that are paid or made available to the Participant during the Limitation Year. Compensation does not include amounts paid after a Participant’s termination of employment except that Compensation does include (A) amounts included in the final payment of his regular compensation for services provided before his termination (including regular pay, overtime, shift differential, commissions, bonuses, and similar payments), but only if the amounts are paid during the Limitation Year in which the termination occurred or, if later, within 2 ¹⁄₂ months of his termination, (B) the cash-out of any paid time off that the former employee would have been able to use had his employment continued, but only if such amount is paid during the Limitation Year in which the termination occurs or, if later, within 2 ¹⁄₂ months of his termination, and (C) payments from an unfunded nonqualified deferred compensation plan (1) that are includible in the Participant’s gross income (2) that are paid during the Limitation Year in which the termination occurred or, if later, within 2 ¹⁄₂ months of the termination, and (3) that would have been paid on such date(s) if the Participant had continued in employment.

(b) Compensation for Top-Heavy Minimum Contributions and Identifying Highly Compensated Employees and Key Employees. For purposes of determining the minimum contribution under section 11.4 when the Plan is top-heavy, and for identifying Highly Compensated Employees and Key Employees, Compensation means the amounts that would be included as Compensation under subsection (a) if every occurrence of the phrase “Limitation Year” were replaced by the phrase “Plan Year.”

(c) Code §414(s) Compensation. For purposes of the ADP and ACP tests under sections 3.5 and 3.6, and for purposes of allocating QNECs under subsection 3.7(c) and QMACs under subsection 3.8(c), Compensation means any definition of compensation for a Plan Year, as selected by the Committee, that satisfies the requirements of Code §414(s) and the regulations promulgated thereunder. The definition of Compensation used in one Plan Year may differ from the definition used in another Plan Year.

(d) Benefit Compensation. For purposes of determining and allocating Company Discretionary Contributions under subsection 3.1(a), Compensation generally means regular compensation paid by the Company.

(i) Inclusions. Specifically, Compensation includes:

(A) Regular salary or wages,

(B) Overtime pay,

(C) The regular annual bonus (unless all or a portion is excluded by the Committee before the regular annual bonus is paid) and any other bonus designated by the Committee,

(D) Salary reductions pursuant to this Plan,

(E) Salary reductions that are excludable from an Employee’s gross income pursuant to Code §125 or §132(f)(4), and

(F) Amounts contributed as salary deferrals to the NQ Plan or the Restorative Plan.

(ii) Exclusions. Compensation excludes:

(A) Commissions,

Page 3 of 51 Prepared May 13, 2013

(B) Severance pay,

(C) Moving expenses,

(D) Any gross-up of moving expenses to account for increased income or employment taxes,

(E) Foreign service premiums paid as an inducement to work outside of the United States,

(F) Credits or benefits under this Plan (except as provided in subparagraph (i)(D)) and credits or benefits under the Apache Corporation Money Purchase Retirement Plan,

(G) Other contingent compensation,

(H) Any amount relating to the granting of a stock option by the Company or an Affiliated Entity, the exercise of such a stock option, or the sale or deemed sale of any shares thereby acquired,

(I) Contributions to any other fringe benefit plan (including, but not limited to, overriding royalty payments or any other exploration-related payments),

(J) Any bonus other than a bonus described in subparagraph (i)(C), and

(K) Except as provided under subparagraph (i)(F), any benefit accrued under, or any payment from, any nonqualified plan of deferred compensation.

(iii) Timing Issues. Compensation includes amounts that are paid to the Employee during that portion of a Plan Year while the Employee is a Covered Employee. Compensation does not include amounts paid after an Employee’s termination of employment, except that Compensation does include (A) amounts included in the final payment of his regular compensation for services provided before his termination (including regular pay, overtime, shift differential, commissions, bonuses, and similar payments), but only if the amounts are paid during the Plan Year in which the termination occurred or, if later, within 2 ¹⁄₂ months of his termination and (B) any cash-out of accrued vacation time that the former employee would have been able to use had he continued in employment that is paid to him during the Plan Year in which the termination occurred or, if later, within 2 ¹⁄₂ months of his termination.

(e) Deferral Compensation. For purposes of determining Participant Contributions under section 3.2 and for purposes of determining and allocating Company Matching Contributions under subsection 3.1(b), Compensation means Compensation as defined in subsection (d), but only including amounts paid after the Employee has satisfied the eligibility requirements of subsection 2.1(a).

(f) Limit on Compensation. For all purposes of subsection (a), for purposes of calculating the minimum contribution required in top-heavy years under subsection (b), for all purposes of subsections (c) and (d), and for purposes of determining the allocation of Company Matching Contributions under subsection (e), the Compensation taken into account for the Limitation Year or Plan Year shall not exceed the dollar limit specified in Code §401(a)(17) in effect for the Limitation Year or Plan Year.

1.15 Covered Employee

“Covered Employee” means any Employee of the Company, with the following exceptions.

(a) Any individual directly employed by an entity other than the Company shall not be a Covered Employee, even if such individual is considered a common-law employee of the Company or is treated as an employee of the Company pursuant to Code §414(n).

(b) An Employee shall not be a Covered Employee unless he is either based in the U.S. or on the U.S. payroll. An individual is not an Eligible Employee even if he is on the U.S. payroll if (i) he is neither a U.S. citizen nor U.S. resident, and (ii) he performs no services for Apache or any Affiliated Entity in the U.S. (in other words, third country nationals are not Eligible Employees).

(c) An Employee included in a unit of Employees covered by a collective bargaining agreement shall not be a Covered Employee unless the collective bargaining agreement specifically provides for such Employee’s participation in the Plan.

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(d) An Employee whose job is classified as “temporary” shall be a Covered Employee only after he has worked for the Company and Affiliated Entities for six consecutive months.

(e) An Employee shall not be a Covered Employee while he is classified as an “intern,” a “consultant,” or an “independent contractor.” An Employee may be classified as an “intern” only if he is currently enrolled (or the Company expects him to be enrolled within the next 12 months) in a high school, college, or university. An Employee may be classified as an intern even if he does not receive academic course credit from his school for this employment with the Company.

(f) An individual who is employed pursuant to a written agreement with an agency or other third party for a specific job assignment or project shall not be a Covered Employee.

1.16 Disability

“Disability” means a physical or mental condition that qualifies the Employee for long-term disability payments under Apache’s Long-Term Disability Plan.

1.17 Domestic Relations Order

“Domestic Relations Order” means any judgment, decree, or order (including approval of a property settlement agreement) issued by a court of competent jurisdiction that relates to the provisions of child support, alimony or maintenance payments, or marital property rights to a Participant’s Spouse, former spouse, child, or other dependent and is made pursuant to a state domestic relations law (including a community property law).

1.18 Employee

“Employee” means each individual who performs services for the Company or an Affiliated Entity and whose wages are subject to withholding by the Company or an Affiliated Entity. The term “Employee” includes only individuals currently performing services for the Company or an Affiliated Entity, and excludes former Employees who are still being paid by the Company or an Affiliated Entity (whether through the payroll system, through overriding royalty payments, through exploration-related payments, severance, or otherwise). The term “Employee” also includes any individual who provides services to the Company or an Affiliated Entity pursuant to an agreement between the Company or an Affiliated Entity and a third party that employs the individual, but only if the individual has performed such services for the Company or an Affiliated Entity on a substantially full-time basis for at least one year and only if the services are performed under the primary direction or control by the Company or an Affiliated Entity; provided, however, that if the individuals included as Employees pursuant to the first part of this sentence constitute 20% or less of the Non-Highly Compensated Employees of the Company and Affiliated Entities, then any such individuals who are covered by a qualified plan that is a money purchase pension plan that provides a nonintegrated employer contribution rate for each participant of at least 10% of compensation, that provides for full and immediate vesting, and that provides immediate participation for each employee of the third party (other than those who perform substantially all of their services for the third party and other than those whose compensation from the third party during each of the four preceding plan years was less than $1000) shall not be considered an Employee.

1.19 ERISA

“ERISA” means the Employee Retirement Income Security Act of 1974, as amended, and the regulations and rulings in effect thereunder from time to time.

1.20 Five-Percent Owner

“Five-Percent Owner” means:

(a) With respect to a corporation, any individual who owns (either directly or indirectly according to the rules of Code §318) more than 5% of the value of the outstanding stock of the corporation or stock processing more than 5% of the total combined voting power of all stock of the corporation.

(b) With respect to a non-corporate entity, any individual who owns (either directly or indirectly according to rules similar to those of Code §318) more than 5% of the capital or profits interest in the entity.

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(c) An individual shall be a Five-Percent Owner for a particular year if such individual is a Five-Percent Owner at any time during such year.

1.21 401(k) Contributions

“401(k) Contributions” means those contributions made to the Plan by the Company, at the election of the Participant pursuant to subsection 3.2(a), that are excludable from the Participant’s gross income under Code §401(k) and §402(e)(3).

1.22 Highly Compensated Employee

“Highly Compensated Employee” means, for each Plan Year, an Employee who (a) was in the “top-paid group” during the immediately preceding Plan Year and had Compensation of $80,000 (as adjusted by the Secretary of the Treasury) or more during the immediately preceding Plan Year, or (b) is a Five-Percent Owner during the current Plan Year, or (c) was a Five-Percent Owner during the immediately preceding Plan Year. The term “top-paid group” means the top 20% of Employees when ranked on the basis of Compensation paid during the year. In determining the number of Employees in the top-paid group, the Committee may elect to exclude Employees with less than six (or some smaller number of) months of service at the end of the year, Employees who normally work less than 17 ¹⁄₂ (or some fewer number of) hours per week, Employees who normally work less than six (or some fewer number of) months during any year, Employees younger than 21 (or some younger age) on the last day of the year, and Employees who are nonresident aliens who receive no earned income (within the meaning of Code §911(d)(2)) from Apache or an Affiliated Entity that constitutes income from sources within the United States (within the meaning of Code §861(a)(3)). Furthermore, an Employee who is a nonresident alien who receives no earned income (within the meaning of Code §911(d)(2)) from Apache or an Affiliated Entity that constitutes income from sources within the United States (within the meaning of Code §861(a)(3)) during the year shall not be in the top-paid group for that year.

1.23 Key Employee

“Key Employee” means an individual described in Code §416(i)(1) and the regulations promulgated thereunder.

1.24 Lapse in Apache Employment

“Lapse in Apache Employment” means a Lapse in Apache Employment as defined in subsection 5.3(c).

1.25 Limitation Year

“Limitation Year” means the calendar year.

1.26 Non-Highly Compensated Employee

“Non-Highly Compensated Employee” means an Employee who is not a Highly Compensated Employee.

1.27 Non-Key Employee

“Non-Key Employee” means an Employee who is not a Key Employee.

1.28 Normal Retirement Age

“Normal Retirement Age” means age 65.

1.29 NQ Plan

“NQ Plan” means the Non-Qualified Retirement/Savings Plan of Apache Corporation.

1.30 Participant

“Participant” means any individual with an account balance under the Plan except beneficiaries and Alternate Payees. The term “Participant” shall also include any Covered Employee who has satisfied the eligibility requirements of section 2.1, but who does not yet have an account balance.

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1.31 Participant Contributions

“Participant Contributions” means 401(k) Contributions, Catch-Up Contributions, Roth Contributions, and Roth Catch-Up Contributions.

1.32 Period of Service

“Period of Service” means a Period of Service as defined in subsection 5.3(a).

1.33 Plan Year

“Plan Year” means the 12-month period on which the records of the Plan are kept, which shall be the calendar year.

1.34 QDRO

“QDRO,” which is an acronym for qualified domestic relations order, means a Domestic Relations Order that creates or recognizes the existence of an Alternate Payee’s right to, or assigns to an Alternate Payee the right to, receive all or a portion of the benefits payable with respect to a Participant under the Plan and with respect to which the requirements of Code §414(p) and ERISA §206(d)(3) are met.

1.35 QMAC

“QMAC,” which is an acronym for qualified matching contribution, means any contribution to the Plan made by the Company that the Company designates as a QMAC, or any portion of the forfeitures designated as a QMAC under subsection 5.4(d). A QMAC must satisfy the requirements of section 3.8.

1.36 QNECs

“QNEC,” which is an acronym for qualified non-elective contribution, means any contribution to the Plan made by the Company that the Company designates as a QNEC, or any portion of the forfeitures designated as a QNEC under subsection 5.4(d). A QNEC must satisfy the requirements of section 3.7.

1.37 Required Beginning Date

“Required Beginning Date” means:

(a) Excepted as provided in subsections (b), (c), and (d), Required Beginning Date means April 1 of the calendar year following the later of (i) the calendar year in which the Participant attains age 70 ¹⁄₂, or (ii) the calendar year in which the Participant terminates employment with Apache and all Affiliated Entities.

(b) For a Participant who is both an Employee and a Five-Percent Owner of Apache or an Affiliated Entity, the term “Required Beginning Date” means April 1 of the calendar year following the calendar year in which the Five-Percent Owner attains age 70 ¹⁄₂. If an Employee older than 70 ¹⁄₂ becomes a Five-Percent Owner, his Required Beginning Date shall be April 1 of the calendar year following the calendar year in which he becomes a Five-Percent Owner.

(c) Before January 1, 1997, an Employee who was not a Five-Percent Owner may have had a Required Beginning Date. Beginning January 1, 1997, such an Employee shall be treated as if he has not yet had a Required Beginning Date, with the result that his minimum required distributions under subsection 6.6(c) will be zero until his new Required Beginning Date. His new Required Beginning Date shall be determined pursuant to subsections (a) and (b).

(d) If a Participant is rehired after his Required Beginning Date, and he is not a Five-Percent Owner, he shall be treated upon rehire as if he has not yet had a Required Beginning Date, with the result that his minimum required distributions under subsection 6.6(c) will be zero until his new Required Beginning Date. His new Required Beginning Date shall be determined pursuant to subsection (a).

1.38 Restorative Plan

“Restorative Plan” means the Apache Corporation Non-Qualified Restorative Retirement Savings Plan.

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1.39 Roth Catch-Up Contributions

“Roth Catch-Up Contributions” means Participant Contributions made pursuant to subsection 3.2(b) that would be Catch-Up Contributions but for the fact that the Participant elected to characterize them as designated Roth contributions within the meaning of Code §402A(c)(1).

1.40 Roth Contributions

“Roth Contributions” means Participant Contributions made pursuant to subsection 3.2(a) that would be 401(k) Contributions but for the fact that the Participant elected to characterize them as designated Roth contributions within the meaning of Code §402A(c)(1). The term “Roth Contributions” does not include any Roth Catch-up Contributions.

1.41 Roth Rollover Contribution

“Roth Rollover Contribution” means any contribution that is rolled over to this Plan pursuant to subsection 3.2(d) that is comprised of designated Roth contributions within the meaning of Code §402A(c)(1) and the earnings thereon.

1.42 Rollover Contribution

“Rollover Contribution” means any contribution that is rolled over to this Plan pursuant to subsection 3.2(d) other than Roth Rollover Contributions.

1.43 Spouse

“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.

1.44 Termination of Employment

“Termination of Employment” means a severance from employment within the meaning of Code §401(k)(2)(b)(i)(I), and which therefore generally means the date a Participant ceases to be an Employee.

1.45 Termination From Service Date

“Termination From Service Date” means the Termination From Service Date defined in subsection 5.3(b).

1.46 Valuation Date

“Valuation Date” means the last day of each Plan Year and any other dates as specified in section 4.2 as of which the assets of the Trust Fund are valued at fair market value and as of which the increase or decrease in the net worth of the Trust Fund is allocated among the Participants’ Accounts.

ARTICLE II

Participation

2.1 Participation - Required Service.

(a) Participant Contributions. A Covered Employee shall be eligible to begin making Participant Contributions and receiving an allocation of Company Matching Contributions as of the first day of the first pay period of the month that begins after the day the Employee becomes a Covered Employee.

(b) Company Discretionary Contributions. Each Covered Employee shall be eligible to participate in the Plan with respect to the Company Discretionary Contribution provided by subsection 3.1(a) on the day the Employee first becomes a Covered Employee.

2.2 Enrollment Procedure.

Notwithstanding section 2.1, a Covered Employee shall not be eligible to participate in the Plan until after completing the enrollment procedures specified by the Committee. Such enrollment procedures may, for example, require the Covered Employee to complete and sign an enrollment form or to complete a voice-response telephone enrollment or an online enrollment. The Covered Employee shall provide all information requested by the Committee, such as the initial investment direction, the address and date of birth of the Employee, and the initial rate of the Participant Contributions. An election to make Participant Contributions

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shall not be effective until after the Covered Employee has properly completed the enrollment procedures. The Committee may require that the enrollment procedure be completed a certain number of days prior to the date that a Covered Employee actually begins to participate.

ARTICLE III

Contributions

The only contributions that can be made to the Plan are Company Contributions pursuant to section 3.1, Plan expenses that are paid by the Company or Account Owner, Participant Contributions and Rollover Contributions and Roth Rollover Contributions pursuant to section 3.2, and loan repayments pursuant to Article VII.

3.1 Company Contributions.

(a) Company Discretionary Contributions. For each Plan Year, the Company shall contribute to the Trust Fund such amount of Company Discretionary Contributions that the Company, in its sole discretion, determines to contribute. The Company may elect to treat any available forfeitures as Company Discretionary Contributions, pursuant to subsection 5.4(d). Company Discretionary Contributions shall be allocated to each “eligible Participant” in proportion to the eligible Participant’s Compensation. For purposes of this subsection, an “eligible Participant” is a Participant who was a Covered Employee on one or more days during the Plan Year and who was employed by the Company or an Affiliated Entity on the last business day of the Plan Year. Company Discretionary Contributions shall be allocated to Company Contributions Accounts, except for those Company Discretionary Contributions that are designated as QNECs pursuant to subsection 3.7(b), which shall be allocated to Participant Contributions Accounts.

(b) Company Matching Contributions.

(i) Standard Match. As of the last day of the Plan Year, the Committee shall make the final allocation of Company Matching Contributions (including such forfeitures occurring during the Plan Year that are treated as Company Matching Contributions pursuant to subsection 5.4(d)) to each Participant who made Participant Contributions during the Plan Year as follows. Each Participant’s allocation shall be equal to his Participant Contributions for the Plan Year, up to a maximum allocation of 8% of his Compensation. The Committee may make interim allocations of Company Matching Contributions during the Plan Year, reflecting the allocation earned thus far in the Plan Year.

(ii) Additional Match.

(A) The Company may elect to contribute an amount, in addition to the amount specified in paragraph (i), that is allocated in proportion to the amount described in paragraph (i). For example, each Participant’s allocation may be equal to 110% of his Participant Contributions for the Plan Year, up to a maximum allocation of 8.8% of his Compensation.

(B) If either nondiscrimination tests described in sections 3.5 and 3.6 is not satisfied for a Plan Year, the Company may elect to contribute an additional amount, or it may elect to use any forfeitures occurring during the Plan Year, as an extra Company Matching Contribution for the Plan Year. The extra Company Matching Contribution under this subparagraph shall be designated as a QMAC and allocated pursuant to section 3.8

(iii) Coordination With Code §401(a)(17). Company Matching Contributions in a Plan Year shall accrue only on Participant Contributions up to 8% of the Code §401(a)(17) limit for that Plan Year. Any Company Matching Contributions allocated during the Plan Year in which they were accrued shall be allocated on a temporary basis only; the allocation shall become final after the Committee verifies that the allocation complies with the terms of the Plan, including the limits of Code §401(a)(17). Any reduction in the allocation to comply with Code §401(a)(17), adjusted to reflect investment experience, shall be used as specified in subsection 5.4(d).

(iv) Accounts. Company Matching Contributions shall be allocated to Company Contributions Accounts, except for those Company Matching Contributions that are designated as QMACs under section 3.8, which shall be allocated to Participant Contributions Accounts.

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(c) Miscellaneous Contributions.

(i) Forfeiture Restoration. The Company may make additional contributions to the Plan to restore amounts forfeited from the Company Contributions Accounts of certain rehired Participants, pursuant to section 5.4. This additional contribution shall be required only when the available forfeitures are insufficient to restore such forfeited amounts, as described in subsection 5.4(d). This contribution shall be allocated to the Participant’s Company Contributions Account.

(ii) Top Heavy Contribution. The Company may make additional contributions to the Plan to satisfy the minimum contribution required by section 12.4. The Company may elect to use any available forfeitures for this purpose, pursuant to subsection 5.4(d).

(iii) Missing Individuals. The Company may make additional contributions to the Plan to restore the forfeited benefit of any missing individual, pursuant to section 13.12. This additional contribution shall be required only when the available forfeitures are insufficient to restore such forfeited amounts, as described in subsection 5.4(d).

(iv) Non-Discrimination Testing. The Company may make QNECs to the Plan to enable the Plan to satisfy the ADP and ACP tests of sections 3.5 and 3.6. The Company may elect to treat any available forfeitures as QNECs, pursuant to subsection 5.4(d). QNECs shall be allocated to Participant Contributions Accounts.

(v) Returning Servicemen. The Company may make additional contributions to the Plan to provide make-up contributions for returning servicemen, pursuant to section 15.4.

(d) Contributions Contingent on Deductibility. The Company Contributions for a Plan Year (excluding forfeitures and contributions pursuant to paragraph 3.1(c)(v) shall not exceed the amount allowable as a deduction for Apache’s taxable year ending with or within the Plan Year pursuant to Code §404. The amount allowable as a deduction under Code §404 shall include carry forwards of unused deductions for prior years. If the Code §404 deduction limit would be exceeded for any Plan Year, the Plan contributions shall be reduced, in the following order, until the Plan contributions equal the Code §404 deduction limit: first, the Company Matching Contributions for those Highly Compensated Employees who are eligible to participate in either the NQ Plan or the Restorative Plan; second, all but $1 of the Company Discretionary Contributions for those Highly Compensated Employees who are eligible to participate in either the NQ Plan or the Restorative Plan; third, any remaining Company Matching Contribution; fourth, any remaining Company Discretionary Contributions. Company Contributions other than QNECs, QMACs, and contributions pursuant to paragraph 3.1(c)(v) shall be paid to the Trustee no later than the due date (including any extensions) for filing the Company’s federal income tax return for such year; QNECs and QMACs shall be paid to the Trustee no later than 12 months after the close of the Plan Year; and contributions subject to paragraph 3.1(c)(v) shall be paid to the Trustee as specified in section 15.4. Company Contributions may be made without regard to current or accumulated earnings and profits; nevertheless, this Plan is intended to qualify as a “profit sharing plan” as defined in Code §401(a). The Company may pay any contribution in the form of Company Stock or cash, as the Company determines.

3.2 Participant Contributions.

(a) 401(k) Contributions and Roth Contributions.

(i) General Rules. A Participant may elect to defer the receipt of a portion of his Compensation during the Plan Year and contribute such amounts to the Plan as 401(k) Contributions or Roth Contributions. The Committee shall determine the maximum 401(k) Contributions and Roth Contributions that a Participant may make and shall establish other administrative rules governing such contributions; for example, the Committee may require 401(k) Contributions and Roth Contributions to each be made in whole percentages of Compensation, or collectively made in whole percentage of Compensation, the Committee may allow different contribution percentages from bonuses than are allowed from regular pay, and the Committee may limit 401(k) Contributions and Roth Contributions (for the year or for the pay period or for a bonus) to a percentage of Compensation (for the year or for the pay period or for the bonus). The Company shall pay the amount deducted from the Participant’s Compensation to the Trustee

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promptly after the deduction is made. 401(k) Contributions shall be allocated to Participant Contributions Accounts, while Roth Contributions shall be allocated to Roth Contributions Accounts.

(ii) Limitations on 401(k) Contributions and Roth Contributions.

(A) Limit for Apache Plans. The sum of (1) 401(k) Contributions and Roth Contributions to this Plan and (2) elective deferrals (as defined in Code §402(g)(3)) and designated Roth contributions (as defined in Code §402A(c)(1)) to any other plan maintained by the Company or an Affiliated Entity shall not exceed the dollar limit in effect under Code §402(g)(1)(B) in any calendar year. The Company shall inform the Committee if such limit has been exceeded, and the excess amount allocated to this Plan. The excess amount allocated to this Plan shall be reduced by any 401(k) Contributions and Roth Contributions returned pursuant to any other provision of this Article. Any remaining excess 401(k) Contribution shall be recharacterized as a Catch-Up Contribution to the extent possible, any remaining excess Roth Contribution shall be recharacterized as a Roth Catch-Up Contribution, and any then-remaining excess amount shall be returned to the Participant as soon as administratively possible, and in no event later than April 15 of the calendar year after the calendar year in which the excess occurred. Company Matching Contributions attributable to amounts returned under this subparagraph shall be forfeited. Unmatched 401(k) Contributions will be returned first, unmatched Roth Contributions will be returned second, matched 401(k) Contributions will be returned third, and matched Roth Contributions will be returned last. The amount of Participant Contributions returned or recharacterized, and the amount of Company Matching Contributions forfeited, shall be adjusted to reflect the net increase or decrease in the net value of the Participant’s Account attributable thereto. The Committee may use any reasonable method to allocate this adjustment.

(B) Participant Limit. If the sum of (1) the 401(k) Contributions and Roth Contributions to this Plan and (2) elective deferrals (as defined in Code §402(g)(3)) and designated Roth contributions (as defined in Code §402A(c)(1)) to any other plan exceed the dollar limit in effect under Code §402(g)(1)(B) in a calendar year, and the Participant is an Employee on the last day of the Plan Year and informs the Committee of the amount of the excess allocated to this Plan, then that amount will be reduced by any 401(k) Contributions and Roth Contributions for that calendar year that were returned pursuant to any other provision in this Article. Any remaining excess 401(k) Contribution shall be recharacterized as a Catch-Up Contribution to the extent possible, any remaining excess Roth Contributions shall be recharacterized as a Roth Catch-Up Contribution to the extent possible, and any then-remaining excess amount shall be returned to the Participant as soon as administratively possible, and in no event later than April 15 of the calendar year after the calendar year in which the excess occurred. Company Matching Contributions attributable to amounts returned under this subparagraph shall be forfeited. Unmatched 401(k) Contributions shall be returned first, unmatched Roth Contributions shall be returned second, matched 401(k) Contributions will be returned third, and matched Roth Contributions will be returned last. The amount of Participant Contributions returned or recharacterized, and the amount of Company Matching Contributions forfeited, shall be adjusted to reflect the net increase or decrease in the net value of the Participant’s Account attributable thereto. The Committee may use any reasonable method to allocate this adjustment.

(b) Catch-Up Contributions and Roth Catch-Up Contributions.

(i) General Rules. A Participant whose 49th birthday occurred before the first day of the Plan Year may elect to defer the receipt of a portion of his Compensation during the Plan Year and contribute such amounts to the Plan as Catch-Up Contributions or Roth Catch-Up Contributions. The Company shall pay the amount deducted from the Participant’s Compensation to the Trustee promptly after the deduction is made. The Committee shall determine after the end of each calendar year which Participant Contributions were Catch-Up Contributions or Roth

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Catch-Up Contributions and which were 401(k) Contributions or Roth Contributions. See sections 3.5 and 3.6 for instances in which Participant Contributions that would normally be characterized as 401(k) Contributions or Roth Contributions are in fact characterized as Catch-Up Contributions or Roth Catch-Up Contributions. Catch-Up Contributions shall be allocated to Participant Contributions Accounts, while Roth Catch-Up Contributions shall be allocated to Roth Contributions Accounts.

(ii) Limitations on Catch-Up Contributions and Roth Catch-Up Contributions.

(A) Limit for Apache Plans. The sum of (1) Catch-Up Contributions and Roth Catch-Up Contributions to this Plan and (ii) similar deferrals under Code §414(v) whether or not characterized as designated Roth contributions (as defined in Code §402A(c)(1)) to any other plan maintained by the Company or an Affiliated Entity shall not exceed the dollar limit in effect under Code §414(v)(2)(B)(i) in any calendar year. The Company shall inform the Committee if such limit has been exceeded, and the excess amount allocated to this Plan. The excess amount allocated to this Plan shall be reduced by any Catch-Up Contributions or Roth Catch-Up Contributions returned pursuant to any other provision of this Article. Any remaining excess amount shall be returned to the Participant as soon as administratively possible, and in no event later than April 15 of the calendar year after the calendar year in which the excess occurred. Company Matching Contributions attributable to amounts returned under this subparagraph shall be forfeited. Unmatched Catch-Up Contributions shall be returned first, unmatched Roth Catch-Up Contributions will be returned second, matched Catch-Up Contributions will be returned third, and matched Roth Catch-Up Contributions will be returned last. The amount of Participant Contributions returned, and the amount of Company Matching Contributions forfeited shall be adjusted to reflect the net increase or decrease in the net value of the Participant’s Account attributable thereto. The Committee may use any reasonable method to allocate this adjustment.

(B) Participant Limit. If the sum of (1) Catch-Up Contributions and Roth Catch-Up Contributions to this Plan and similar deferrals under Code §414(v) whether or not characterized as designated Roth contributions (as defined in Code §402A(c)(1)) to any other plan exceed the dollar limit in effect under Code §414(v)(2)(B)(i) in a calendar year, and the Participant is an Employee on the last day of the Plan Year and informs the Committee of the amount of the excess allocated to this Plan, then that amount will be reduced by any Catch-Up Contributions and Roth Catch-Up Contributions for that calendar year that were returned pursuant to any other provision in this Article and any then-remaining excess amount shall be returned to the Participant as soon as administratively possible, and in no event later than April 15 of the calendar year after the calendar year in which the excess occurred. Company Matching Contributions attributable to amounts returned under this subparagraph shall be forfeited. Unmatched Catch-Up Contributions shall be returned first, unmatched Roth Catch-Up Contributions will be returned second, matched Catch-Up Contributions will be returned third, and matched Roth Catch-Up Contributions will be returned last. The amount of Participant Contributions returned, and the amount of Company Matching Contributions forfeited shall be adjusted to reflect the net increase or decrease in the net value of the Participant’s Account attributable thereto. The Committee may use any reasonable method to allocate this adjustment.

(c) Procedures. Participant Contributions shall be made according to rules prescribed by the Committee that are consistent with the rules in this subsection.

(i) Authorization. An individual who has become, or who is expected to shortly become, a Covered Employee may make an affirmative election to make have amounts withheld from his Compensation and to have such Participant Contributions contributed to this Plan; such Participant Contributions shall begin as soon as administratively practicable after the Participant has satisfied the waiting period described in subsection 2.1(a). In addition, an individual who becomes a Covered Employee shall be automatically enrolled in the Plan, and will make

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Participant Contributions at 8% of his Compensation, unless he affirmatively elects otherwise; the Participant Contributions will not be designated Roth contributions within the meaning of Code §402A(c)(1)), unless he affirmatively elects otherwise; the Participant shall be provided with a reasonable opportunity of at least 30 days to select a different rate of Participant Contribution and the extent to which the Participant Contributions are designated Roth contributions within the meaning of Code §402A(c)(1)); the Participant shall be notified in a sufficiently accurate and comprehensive manner that apprises the Participant of his rights and obligations, written in a manner calculated to be understood by the Participant, that explains his right to elect a contribution percentage rate that is not 8% of Compensation (and that may be 0%), that explains when such automatic contributions will begin (unless he makes an affirmative election otherwise), and that explains how such automatic Participant Contributions and the associated match will be invested. Any authorization or deemed authorization may apply only to Compensation that is not then currently available to the Participant. Such authorization or deemed authorization shall remain in effect until revoked or changed by the Participant. If an Employee makes a hardship withdrawal from his Participant Contributions Account or Roth Contributions Account under section 6.5, his contribution rate shall be immediately reduced to 0%, and shall remain at 0% for at least 6 months. To be effective, any authorization, change of authorization, change of designation of Participant Contributions as designated Roth Contributions within the meaning of Code §402A(c)(1), or notice of revocation must be filed with the Committee according to such restrictions and requirements as the Committee prescribes. The Committee shall establish procedures from time to time for Participants to change their contribution elections, which procedures shall be communicated to Participants. The Committee may establish different procedures for Participant Contributions from different types of Compensation, such as bonuses. The Committee may establish different procedures for each type of Participant Contributions. A Participant who also participates in the NQ Plan or the Restorative Plan may make a combined contribution election that applies to both this Plan and the NQ Plan or Restorative Plan; once made, such combined elections are irrevocable for the periods and the compensation described in the elections.

(ii) Catch-Up Contributions and Roth Catch-Up Contributions. The Committee’s procedures for Catch-Up Contributions and Roth Catch-Up Contributions shall allow all Participants who can make such contributions the effective opportunity to make the same dollar amount of such contributions for the calendar year.

(iii) Inadequate Paycheck. If the amounts withheld from a Participant’s paycheck (including, without limitation, loan repayments, Participant Contributions, taxes, contributions to the NQ Plan or the Restorative Plan, and premium payments for various benefits) are greater than the paycheck, the Committee shall establish the order in which the deductions shall be applied, with the result that Participant Contributions may be reduced below what the Participant had elected. The Committee’s procedures may also automatically increase a Participant’s Participant Contributions in subsequent pay periods to make up for any missed contributions.

(d) Rollovers. The Plan may accept any rollover from or on behalf of a Covered Employee, subject to the following rules. The Committee shall decide from time to time which types of rollovers the Plan will accept, and the conditions under which the Plan will accept them. A rollover may be comprised of a direct transfer of an eligible rollover distribution from a qualified plan described in Code §401(a), a qualified annuity plan described in Code §403(a), an annuity contract described in Code §403(b), or an eligible plan under Code §457(b) that is maintained by an eligible employer described in Code §457(e)(1)(A) (which generally includes state or local governments), except that the rollover may not include any after-tax contributions, though a direct rollover from such sources may include designated Roth contributions within the meaning of Code §402A(c)(1) and the earnings thereon. A rollover may also be comprised of the portion of a distribution from an individual retirement account or annuity described in Code §408(a) or §408(b) that is eligible to be rolled over and that would otherwise be included in the Covered Employee’s gross income, but a rollover may not be comprised of amounts from a Roth IRA within the meaning of Code §408A(b). If the Plan accepts a contribution and subsequently determines that the contribution did not satisfy the conditions for the Plan to accept it, the Plan shall distribute such contribution, as well as the net increase or decrease in the net value of the

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Trust Fund attributable to the contribution, to the Covered Employee as soon as administratively practicable. All rollovers accepted under this subsection shall be allocated to Rollover Accounts, except for direct rollovers of designated Roth contributions within the meaning of Code §402A(c)(1) and the earning thereon, which shall be allocated to Roth Rollover Accounts.

3.3 Return of Contributions.

(a) Mistake of Fact. Upon the request of the Company, the Trustee shall return to the Company, any Company Contribution made under a mistake of fact. The amount that shall be returned shall not exceed the excess of the amount contributed (reduced to reflect any decrease in the net worth of the appropriate Accounts attributable thereto) over the amount that would have been contributed without the mistake of fact. Appropriate reductions shall be made in the Accounts of Participants to reflect the return of any contributions previously credited to such Accounts. If the Company so requests, any contribution made under a mistake of fact shall be returned to the Company within one year after the date of payment.

(b) Non-Deductible Contributions. Upon the request of the Company, the Trustee shall return to the Company, any Company Contribution or Participant Contribution that is not deductible under Code §404. The Company shall pay any returned Participant Contribution to the appropriate Participant or the NQ Plan or Restorative Plan, as appropriate, as soon as administratively practicable, subject to any withholding. All contributions under the Plan are expressly conditioned upon their deductibility for federal income tax purposes. The amount that shall be returned shall be the excess of the amount contributed (reduced to reflect any decrease in the net worth of the appropriate Accounts attributable thereto) over the amount that would have been contributed if there had not been a mistake in determining the deduction. Appropriate reductions shall be made in the Accounts of Participants to reflect the return of any contributions previously credited to such Accounts. Any contribution conditioned on its deductibility shall be returned within one year after it is disallowed as a deduction.

(c) Effect of Correction. A contribution shall be returned under this section only to the extent that its return will not reduce the Account(s) of a Participant to an amount less than the balance that would have been credited to the Participant’s Account(s) had the contribution not been made.

3.4 Limitation on Annual Additions.

The Annual Additions to a Participant’s Account(s) in this Plan and to his accounts in any other defined contribution plans maintained by the Company or an Affiliated Entity for any Limitation Year shall not exceed in the aggregate the lesser of (a) $40,000 (as adjusted for inflation pursuant to Code §415(d)), or (b) 100% of the Participant’s Compensation. The limit in clause (b) shall not apply to any contribution for medical benefits (within the meaning of Code §419A(f)(2)) after separation from service that is treated as an Annual Addition.

3.5 Contribution Limits for Highly Compensated Employees (ADP Test).

(a) Limits on Contributions. Notwithstanding any provision in this Plan to the contrary, the actual deferral percentage (“ADP”) test of Code §401(k)(3) shall be satisfied. Code §401(k) and the regulations issued thereunder are hereby incorporated by reference to the extent permitted by such regulations. In performing the ADP test for a Plan Year, the Plan will use that Plan Year’s data for the Non-Highly Compensated Employees.

(b) Permissible Variations of the ADP Test. To the extent permitted by the regulations under Code §401(m) and §401(k), 401(k) Contributions, QMACs, and QNECs may be used to satisfy the ACP test of section 3.6 if they are not used to satisfy the ADP test. The Committee may elect to exclude from the ADP test those Non-Highly Compensated Employees who, at the end of the Plan Year, had not attained age 21 and/or whose Period of Service was less than one year.

(c) Advanced Limitation on Participant Contributions or Company Matching Contributions. The Committee may limit the Participant Contributions of any Highly Compensated Employee (or any Employee expected to be a Highly Compensated Employee) at any time during the Plan Year, with the result that his share of Company Matching Contributions may be limited. This limitation may be made, if practicable, whenever the Committee believes that the limits of this section or sections 3.4 or 3.6 will not be satisfied for the Plan Year.

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(d) Corrections to Satisfy Test. If the ADP test is not satisfied for the Plan Year, the Committee shall decide which one or more of the following methods shall be employed to satisfy the ADP test. All corrections shall be accomplished if possible before March 15 of the following Plan Year, and in no event later than 12 months after the close of the Plan Year.

(i) The Committee may recommend to the Company and the Company may make QNECs and/or QMACs to the Plan, pursuant to subsections 3.7(c) and 3.8(c).

(ii) The Committee may recommend to the Company and the Company may designate any Company Discretionary Contribution allocated to Non-Highly Compensated Employees as QNECs, pursuant to subsection 3.7(b).

(iii) The Committee may recommend to the Company and the Company may designate any Company Matching Contributions allocated to Non-Highly Compensated Employees as QMACs, pursuant to section 3.8(b).

(iv) 401(k) Contributions of Highly Compensated Employees may be recharacterized as Catch-Up Contributions or returned to the Highly Compensated Employee, without the consent of either the Highly Compensated Employee or his Spouse, subject to the rules of subsection (f).

(v) Roth Contributions of Highly Compensated Employees may be recharacterized as Roth Catch-Up Contributions or returned to the Highly Compensated Employee, without the consent of either the Highly Compensated Employee or his Spouse, subject to the rules of subsection (f).

(e) Order of Correction. The method described in subsection (c) shall be employed first, during the Plan Year. If that method is not used during the Plan Year, or if the net effect of such method was insufficient for the ADP test to be satisfied, the Company has the discretion to use any one or more of the methods described in paragraphs (d)(i), (d)(ii), and (d)(iii). If the Company does not choose to make the corrections described in paragraphs (d)(i), (d)(ii), and (d)(iii), or if such corrections are insufficient to satisfy the ADP test, then the correction method described in paragraphs (d)(iv) and (d)(v) shall be used in tandem, as described in subsection (f).

(f) Calculating the Amounts Returned or Recharacterized. If the ADP test is not satisfied, and 401(k) Contributions or Roth Contributions are returned or recharacterized pursuant to paragraph (d)(iv) or (d)(v) above, the Committee shall determine the amount to be returned or recharacterized and shall then allocate that amount among the Highly Compensated Employees pursuant to Treasury Regulations. The correction for each Highly Compensated Employee shall occur in the following order, to the extent necessary: 401(k) Contributions shall be recharacterized as Catch-Up Contributions to the extent possible, then Roth Contributions shall be recharacterized as Roth Catch-Up Contributions to the extent possible, then unmatched 401(k) Contributions shall be returned to the Participant, then unmatched Roth Contributions shall be returned to the Participant, then matched 401(k) Contributions shall be returned to the Participant and the corresponding Company Matching Contribution shall be forfeited (unless the ACP test was performed before the ADP test, and the vested Company Matching Contribution has already been returned to the Participant or the unvested Company Matching Contribution has already been forfeited, both pursuant to paragraph 3.6(c)(v)), then matched Roth Contributions shall be returned to the Participant and the corresponding Company Matching Contribution shall be forfeited (unless the ACP test was performed before the ADP test, and the vested Company Matching Contribution has already been returned to the Participant or the unvested Company Matching Contribution has already been forfeited, both pursuant to paragraph 3.6(c)(v)). The amount actually recharacterized or returned to each Highly Compensated Employee shall be adjusted to reflect as nearly as possible the actual increase or decrease in the net value of the Trust Fund attributable to the correction through the end of the Plan Year for which the correction is being made.

3.6 Contribution Limits for Highly Compensated Employees (ACP Test).

(a) Limits on Contributions. Notwithstanding any provision in this Plan to the contrary, the actual contribution percentage (“ACP”) test of Code §401(m)(2) shall be satisfied. Code §401(m) and the regulations issued thereunder are hereby incorporated by reference to the extent permitted by such regulations. In performing the ACP test for a Plan Year, the Plan will use that Plan Year’s data for the Non-Highly Compensated Employees.

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(b) Permissible Variations of the ACP Test. To the extent permitted by the regulations under Code §401(m) and §401(k), 401(k) Contributions, Roth Contributions, QMACs, and QNECs may be used to satisfy this test if not used to satisfy the ADP test of section 3.5. The Committee may elect to exclude from the ACP test those Non-Highly Compensated Employees who, at the end of the Plan Year, had not attained age 21 and/or whose Period of Service was for less than one year.

(c) Corrections to Satisfy Test. If the ACP test is not satisfied, the Committee shall decide which one or more of the following methods shall be employed to satisfy the ACP test. All corrections shall be accomplished if possible before March 15 of the following Plan Year, and in no event later than 12 months after the close of the Plan Year.

(i) The Committee may recommend to the Company and the Company may make QNECs or QMACs to the Plan, pursuant to subsections 3.7(c) and 3.8(c).

(ii) The Committee may recommend to the Company and the Company may designate any portion of its Company Discretionary Contributions as QNECs, pursuant to subsection 3.7(b).

(iii) The Committee may recommend to the Company and the Company may designate any portion of its Company Matching Contributions as QMACs, pursuant to subsection 3.8(b).

(iv) The Committee may recommend to the Company and the Company may make extra Company Matching Contributions to the Plan, pursuant to paragraph 3.1(b)(ii).

(v) The non-vested Company Matching Contributions allocated to Highly Compensated Employees as of any date during the Plan Year may be forfeited as of the last day of the Plan Year, and the vested Company Matching Contributions allocated to any Highly Compensated Employee for the Plan Year may be paid to such Highly Compensated Employee, without the consent of either the Highly Compensated Employee or his Spouse, subject to the rules of subsection (e).

(vi) Those 401(k) Contributions and Roth Contributions that are taken into account for this ACP test for any Highly Compensated Employee may be returned to such Highly Compensated Employee, without the consent of either the Highly Compensated Employee or his Spouse, subject to the rules of subsection (e).

(d) Order of Correction. The method described in subsection 3.5(c) shall be employed first, during the Plan Year. If that method is not used during the Plan Year, or if the net effect of such method was insufficient for the ACP test to be satisfied, the Company has the discretion to use any one or more of the methods described in paragraphs (c)(i), (c)(ii), (c)(iii) and (c)(iv). If the Company does not choose to make the corrections described in paragraphs (c)(i), (c)(ii), (c)(iii), and (c)(iv) or if such corrections are insufficient to satisfy the ACP test, then the correction methods described in paragraphs (c)(v) and (c)(vi) shall be used, as described in subsection (e).

(e) Calculating the Corrective Reduction. If the correction methods described in paragraphs (c)(v) and (c)(vi) are to be used, the Committee shall determine the amount of the correction and then allocate that amount among the Highly Compensated Employees pursuant to Treasury Regulations. The corrections under paragraphs (c)(v) and (c)(vi) are done in tandem; thus, the correction shall be accomplished in the following order, to the extent necessary: 401(k) Contributions shall be recharacterized as Catch-Up Contributions to the extent possible, then Roth Contributions shall be recharacterized as Roth Catch-Up Contributions to the extent possible, then unmatched 401(k) Contributions shall be returned to the Participant, then unmatched Roth Contributions shall be returned to the Participant, then the vested Company Matching Contribution shall be paid to the Participant, then matched 401(k) Contributions shall be returned to the Participant and any corresponding unvested Company Matching Contribution shall be forfeited, then matched Roth Contributions shall be returned to the Participant and any corresponding unvested Company Matching Contribution shall be forfeited. The amount of the correction shall be adjusted to reflect as nearly as possible the actual increase or decrease in the net value of the Trust Fund attributable to the correction through the end of the Plan Year for which the correction is being made.

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3.7 QNECs.

(a) Time of Payment. QNECs shall be paid to the Plan no later than 12 months after the close of the Plan Year to which they relate.

(b) Source. The Company may designate as a QNEC all or any portion of the Company Discretionary Contribution that is allocated to Non-Highly Compensated Employees. The designation of Company Contributions as QNECs shall be made before such contributions are made to the Trust Fund. If the Company inadvertently designates any Highly Compensated Employee’s allocation as a QNEC, the designation shall be ineffective.

(c) Allocation. The Company may make a contribution to the Plan, in addition to the Company Discretionary Contribution, that the Company designates as a QNEC. This subsection applies to such contributions. As of the last day of each Plan Year, the Committee shall allocate such QNECs for such Plan Year (including such forfeitures occurring during such Plan Year that are treated as QNECs pursuant to subsection 5.4(d)) to the Participant Contributions Accounts of those Non-Highly Compensated Employees who were Covered Employees on the last day of the Plan Year, as follows:

(i) QNECs shall be allocated to the Participant Contributions Account of the Non-Highly Compensated Employee with the least Compensation, until either the QNECs are exhausted or the Non-Highly Compensated Employee has received the maximum QNEC allocation that can be taken into account in the ADP test or the ACP test, whichever is applicable. Under Treasury Regulation §1.401(k)-2(a)(6)(iv) or §1.401(m)-2(a)(5)(ii), the maximum QNEC allocation, for this Plan, is generally 5% of the Non-Highly Compensated Employee’s Compensation.

(ii) Any remaining QNECs shall be allocated to the Participant Contributions Account of the Non-Highly Compensated Employee with the next lowest Compensation, until either the QNECs are exhausted or the Non-Highly Compensated Employee has received the maximum QNEC allocation that can be taken into account in the ADP test or the ACP test, whichever is applicable.

(iii) The procedure in paragraph (ii) shall be repeated until all QNECs have been allocated.

(d) Coordination with Top-Heavy Rules. All QNECs shall be treated in the same manner as a Company Discretionary Contribution for purposes of section 12.4.

3.8 QMACs.

(a) Time of Payment. QMACs shall be paid to the Plan no later than 12 months after the close of the Plan Year to which they relate.

(b) Source. The Company may designate as a QMAC all or any portion of the Company Matching Contributions that is allocated to Non-Highly Compensated Employees. The designation of Company Contributions as QMACs shall be made before such contributions are made to the Trust Fund. If the Company inadvertently designates any Highly Compensated Employee’s allocation as a QMAC, the designation shall be ineffective.

(c) Allocation. The Company may make a contribution to the Plan, in addition to the Company Matching Contribution, that the Company designates as a QMAC. This subsection applies to such contributions. As of the last day of each Plan Year, the Committee shall allocate such QMACs for such Plan Year (including such forfeitures occurring during such Plan Year that are treated as QMACs pursuant to subsection 5.4(d)) to the Participant Contributions Accounts of those Non-Highly Compensated Employees who were Covered Employees on the last day of the Plan Year and who made Participant Contributions for the Plan Year, as follows:

(i) QMACs shall be allocated to the Participant Contributions Account of the Non-Highly Compensated Employee with the least Compensation, until either the QMACs are exhausted or the Non-Highly Compensated Employee has received the maximum QMAC allocation that can be taken into account in the ADP test or the ACP test, whichever is applicable. Under Treasury Regulation §1.401(k)-2(a)(6)(iv) or §1.401(m)-2(a)(5)(ii), the maximum QMAC allocation, for this Plan, is generally 5% of the Non-Highly Compensated Employee’s Compensation.

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(ii) Any remaining QMACs shall be allocated to the Participant Contributions Account of the Non-Highly Compensated Employee with the next lowest Compensation, until either the QMACs are exhausted or the Non-Highly Compensated Employee has received the maximum QMAC allocation that can be taken into account in the ADP test or the ACP test, whichever is applicable.

(iii) The procedure in paragraph (ii) shall be repeated until all QMACs have been allocated.

(d) Coordination with Top-Heavy Rules. All QMACs shall be treated in the same manner as a Company Discretionary Contribution for purposes of section 12.4.

ARTICLE IV

Interests in the Trust Fund

4.1 Participants’ Accounts.

The Committee shall establish and maintain separate Accounts in the name of each Participant, but the maintenance of such Accounts shall not require any segregation of assets of the Trust Fund. Each Account shall contain the contributions specified below and the increase or decrease in the net worth of the Trust Fund attributable to such contributions.

(a) Participant Contributions Account. A Participant Contributions Account shall be established for each Participant who makes Participant Contributions other than Roth Contributions or Roth Catch-Up Contributions or who receives an allocation of QNECs or QMACs. The Committee may elect to establish subaccounts for the different types of contributions allocated to this Account.

(b) Company Contributions Account. A Company Contributions Account shall be established for each Participant who receives an allocation of Company Discretionary Contributions that are not designated as QNECs or an allocation of Company Matching Contributions that are not designated as QMACs. The Committee may elect to establish subaccounts for the different types of contributions allocated to this Account.

(c) Rollover Account. A Rollover Account shall be established for each Participant who makes a Rollover Contribution.

(d) Roth Contributions Account. A Participant Contributions Account shall be established for each Participant who makes Roth Contributions or Roth Catch-Up Contributions. The Committee may elect to establish subaccounts for the different types of contributions allocated to this Account.

(e) Roth Rollover Account. A Roth Rollover Account shall be established for each Participant who makes a Roth Rollover Contribution.

4.2 Valuation of Trust Fund.

(a) General. The Trustee shall value the assets of the Trust Fund at least annually as of the last day of the Plan Year, and as of any other dates determined by the Committee, at their current fair market value and determine the net worth of the Trust Fund. In addition, the Committee may direct the Trustee to have a special valuation of the assets of the Trust Fund when the Committee determines, in its sole discretion, that such valuation is necessary or appropriate or in the event of unusual market fluctuations of such assets. Such special valuation shall not include any contributions made by Participants since the preceding Valuation Date, any Company Contributions for the current Plan Year, or any unallocated forfeitures. The Trustee shall allocate the expenses of the Trust Fund occurring since the preceding Valuation Date, pursuant to section 9.2, and then determine the increase or decrease in the net worth of the Trust Fund that has occurred since the preceding Valuation Date. The Trustee shall determine the share of the increase of decrease that is attributable to the non-separately accounted for portion of the Trust Fund and to any amount separately accounted for, as described in subsections (b) and (c).

(b) Mandatory Separate Accounting. The Trustee shall separately account for (i) any individually directed investments permitted under section 9.3, and (ii) amounts subject to a Domestic Relations Order.

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(c) Permissible Separate Accounting. The Trustee may separately account for the following amounts to provide a more equitable allocation of any increase or decrease in the net worth of the Trust Fund:

(i) the distributable amount of a Participant, pursuant to section 6.7, including any amount distributable to an Alternate Payee or to a beneficiary of a deceased Participant; and

(ii) Company Matching Contributions made since the preceding Valuation Date;

(iii) Participant Contributions that were received by the Trustee since the preceding Valuation Date;

(iv) Company Matching Contributions, Roth Contributions, and 401(k) Contributions of Highly Compensated Employees that may need to be distributed or forfeited to satisfy the ADP and ACP tests of sections 3.5 or 3.6;

(v) Rollovers that were received by the Trustee since the preceding Valuation Date;

(vi) Any other amounts for which separate accounting will provide a more equitable allocation of the increase or decrease in the net worth of the Trust Fund.

4.3 Allocation of Increase or Decrease in Net Worth.

The Committee shall, as of each Valuation Date, allocate the increase or decrease in the net worth of the Trust Fund that has occurred since the preceding Valuation Date between the non-separately accounted for portion of the Trust Fund and the amounts separately accounted for that are identified in subsections 4.2(b) and 4.2(c). The increase or decrease attributable to the non-separately accounted for portion of the Trust Fund shall be allocated among the appropriate Accounts in the ratio that the dollar value of each such Account bore to the aggregate dollar value of all such Accounts on the preceding Valuation Date after all allocations and credits made as of such date had been completed. The Committee shall then allocate any amounts separately accounted for (including the increase or decrease in the net worth of the Trust Fund attributable to such amounts) to the appropriate Account(s) if such separate accounting is no longer necessary.

ARTICLE V

Amount of Benefits

5.1 Vesting Schedule.

A Participant shall have a fully vested and nonforfeitable interest in all his Account(s) upon his Normal Retirement Age if he is an Employee on such date, upon his death while an Employee or while on an approved leave of absence from the Company or an Affiliated Entity, or upon his termination of employment with the Company or an Affiliated Entity because of a Disability. In all other instances a Participant’s vested interest shall be calculated according to the following rules.

(a) Participant Contributions Account and Rollover Account. A Participant shall be fully vested at all times in his Participant Contributions Account and his Rollover Account.

(b) Company Contributions Account. A Participant shall become fully vested in his Company Contributions Account in accordance with the following schedule:

Period of Service	Vesting Percentage
Less than 1 year	0%
At least 1 year, but less than 2 years	20%
At least 2 years, but less than 3 years	40%
At least 3 years, but less than 4 years	60%
At least 4 years, but less than 5 years	80%
5 or more years	100%

(c) Change of Control. The Company Contributions Accounts of all Participants shall be fully vested as of the effective date of a “change in control.” For purposes of this subsection, a “change of control” shall mean the event occurring when a person, partnership, or corporation, together with all persons, partnerships, or corporations acting in concert with each person, partnership, or corporation, or any or all of them, acquires more than 20% of Apache’s outstanding voting securities; provided that a change of control shall not occur if such persons, partnerships, or corporations acquiring more than 20% of

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Apache’s voting securities is solicited to do so by Apache’s board of directors, upon its own initiative, and such persons, partnerships, or corporations have not previously proposed to acquire more than 20% of Apache’s voting securities in an unsolicited offer made either to Apache’s board of directors or directly to the stockholders of Apache.

(d) Plan Termination. A Company Contributions Account shall be fully vested as described in section 10.1, which discusses the full or partial termination of the Plan or the complete discontinuance of contributions.

5.2 Vesting After a Lapse in Apache Employment.

(a) Separate Accounts. If a Participant is rehired before incurring a one-year Lapse in Apache Employment, he shall have only one Company Contributions Account, and its vested percentage shall be determined under section 5.1. If a Participant is rehired after incurring a one-year Lapse in Apache Employment, he shall have two Company Contribution Accounts, an “old” Company Contributions Account for the contributions from his earlier episode of employment, and a “new” Company Contributions Account for his later episode of employment. If both the old and new Company Contributions Accounts are fully vested, they shall be combined into a single Company Contributions Account.

(b) Vesting of New Account. The vested percentage of the new Company Contributions Account shall be determined based on all the Participant’s Periods of Service.

(c) Vesting of Old Account. If the Participant’s Lapse in Apache Employment was for five years or longer, the vested percentage of the old Company Contributions Account shall be based solely on the Participant’s Period of Service from his first episode of employment. If the Participant’s Lapse in Apache Employment was for less than five years, the vested percentage of the old Company Contributions Account shall be determined by aggregating his Periods of Service from both episodes of employment.

5.3 Calculating Service.

(a) Period of Service.

(i) General. A Participant’s Period of Service shall be determined according to the provisions of the Plan in effect when the service was rendered. A Participant’s Period of Service begins on the date he first begins to perform duties as an Employee for which he is entitled to payment, and ends on his Termination From Service Date. In addition, a Participant’s Period of Service also includes the period between his Termination From Service Date and the day he again begins to perform duties for the Company or an Affiliated Entity for which he is entitled to payment, but only if such period is less than one year in duration.

(ii) Additional Rules. The service-crediting provisions in this paragraph are more generous than required by the Code.

(A) Leased Employees. For vesting purposes only, the Plan shall treat an individual as an Employee if he satisfies all the requirements specified in Code §414(n)(2) for being a leased employee of Apache’s or an Affiliated Entity’s, except for the requirement of having performed such services for at least one year.

(B) Approved Leave. If the Employee is absent from the Company or Affiliated Entity for more than one year because of an approved leave of absence (either with or without pay) for any reason (including, but not limited to, jury duty) and the Employee returns to work at or prior to the expiration of his leave of absence, no Termination From Service Date will occur during the leave of absence.

(C) Servicemen. See Article XV for special provisions that apply to Servicemen.

(D) Corporate Transactions. See Appendix C for instances in which a new Employee’s Period of Service includes his prior employment with another company.

(E) Contractors. If an “eligible contractor” becomes an Employee, his Period of Service shall include his previous continuous service as an eligible contractor, excluding any service

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provided before 2003. An “eligible contractor” is an individual who (A) performed services for Apache or an Affiliated Entity on a substantially full-time basis in the capacity of an independent contractor (for federal income tax purposes); (B) became an Employee within a month of ceasing to be an independent contractor working full-time for Apache or an Affiliated Entity; and (C) notified the Plan of his prior service as an independent contractor within two months of becoming an Employee (or, if later, by February 28, 2006 or other deadline established by the Committee).

(b) Termination From Service Date.

(i) Usual Rule. If the Employee quits, is discharged, retires, or dies, his Termination From Service Date occurs on the last day the Employee performs services for the Company or an Affiliated Entity, except for an Employee who incurs a Disability, in which case his Termination From Service Date does not occur, even if he quits, until the earlier of the one-year anniversary of the date his Disability or the date he recovers from his Disability.

(ii) Other Absences. If an Employee is absent from the Company and Affiliated Entities for any reason other than a quit, discharge, or retirement, his “Termination From Service Date” is the earlier of (A) the date he quits, is discharged, retires, or dies, or (B) one year from the date the Employee is absent from the Company or Affiliated Entity for any other reason (such as vacation, holiday, sickness, disability, leave of absence, or temporary lay-off), with the following exception. If the Employee is absent from the Company or Affiliated Entity because of parental leave (which includes only the pregnancy of the Employee, the birth of the Employee’s child, the placement of a child with the Employee in connection with adoption of such child by the Employee, or the caring for such child immediately following birth or placement) on the first anniversary of the day the Employee was first absent, his Termination From Service Date does not occur until the second anniversary of the day he was first absent (and the period between the first and second anniversaries of the day he was first absent shall not be counted in his Period of Service).

(c) Lapse in Apache Employment. A Lapse in Apache Employment means the period commencing on an individual’s Termination from Service Date and ending on the date he again begins to perform services as an Employee.

5.4 Forfeitures.

(a) Exceptions to the Vesting Rules. The following rules supersede the vesting rules of section 5.1.

(i) Excess Annual Additions. Annual Additions to a Participant’s Accounts and any increase or decrease in the net worth of the Participant’s Accounts attributable to such Annual Additions may be reduced to satisfy the limits described in section 3.4. Any reduction shall be used as specified in section 3.4.

(ii) Excess Participant Contribution. Company Matching Contributions and any increase or decrease in the net worth of the Account(s) attributable to such contributions may be forfeited as of the last day of the Plan Year if the Participant Contribution that they matched was returned under paragraph 3.2(a)(ii) or 3.2(b)(ii) or subsection 3.5(d) or 3.6(c). Any such forfeiture shall be used as specified in subsection (d).

(iii) Missing Individuals. A missing individual’s vested Accounts may be forfeited as of the last day of any Plan Year, as provided in section 13.12. Any such forfeiture shall be used as specified in subsection (d).

(iv) Excess Match. Company Matching Contributions that would violate Code §401(a)(17), and any increase or decrease in the net worth of the Account(s) attributable to such contributions, may be forfeited as specified in subsection 3.1(b). Any such reduction shall be used as specified in subsection 3.1(b).

(b) Regular Forfeitures. A Participant’s non-vested interest in his Company Contributions Account shall be forfeited at the earlier of the fifth anniversary of the date he terminated employment (or such later date as is administratively convenient) or the date he receives a full distribution of his vested Plan Account. Any such forfeiture shall be used as specified in subsection (d).

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(c) Restoration of Forfeitures.

(i) Missing Individuals. The forfeiture of a missing individual’s Account(s), as described in section 13.12, shall be restored to such individual if the individual makes a claim for such amount.

(ii) Regular Forfeitures.

(A) Rehire Within 5 Years. If a Participant is rehired before incurring a five-year Lapse in Apache Employment, and the Participant has received a distribution of his entire vested interest in his Company Contributions Account (with the result that the Participant forfeited his non-vested interest in such Account), then the exact amount of the forfeiture shall be restored to the Participant’s Account. All the rights, benefits, and features available to the Participant when the forfeiture occurred shall be available with respect to the restored forfeiture. If such a Participant again terminates employment prior to becoming fully vested in his Company Contributions Account, the vested portion of his Company Contributions Account shall be determined by applying the vested percentage determined under section 5.1 to the sum of (x) and (y), then subtracting (y) from such sum, where: (x) is the value of the Participant’s Company Contributions Account as of the Valuation Date immediately following his most recent termination of employment; and (y) is the amount previously distributed to the Participant on account of the prior termination of employment.

(B) Rehire After 5 Years. If a Participant is rehired after incurring a five-year Lapse in Apache Employment, then no amount forfeited from his Company Contributions Account shall be restored to that Account.

(iii) Method of Forfeiture Restoration. Forfeitures that are restored shall be accomplished by an allocation of the forfeitures under subsection (d) or by a special Company Contribution pursuant to paragraph 3.1(c)(i).

(d) Use of Forfeitures. The Committee shall decide how forfeitures are used. Forfeitures may be used (i) to restore Accounts as described in subsection (c), (ii) to pay those expenses of the Plan that are properly payable from the Trust Fund and that are not paid by the Company or Account Owners or charged to Accounts, or (iii) as any Company Contribution.

5.5 Transfers - Portability.

If any other employer adopts this or a similar profit sharing plan and enters into a reciprocal agreement with the Company that provides that (a) the transfer of a Participant from such employer to the Company (or vice versa) shall not be deemed a termination of employment for purposes of the plans, and (b) service with either or both employers shall be credited for purposes of vesting under both plans, then the transferred Participant’s Account shall be unaffected by the transfer, except, if deemed advisable by the Committee, it may be transferred to the trustee of the other plan.

ARTICLE VI

Distribution of Benefits

6.1 Beneficiaries.

(a) Designating Beneficiaries. Each Account Owner shall file with the Committee a designation of the beneficiaries and contingent beneficiaries to whom the distributable amount (determined pursuant to section 6.2) shall be paid in the event of the Account Owner’s death. In the absence of an effective beneficiary designation as to any portion of the distributable amount after a Participant dies, such amount shall be paid to the Participant’s surviving Spouse, or, if none, to his estate. In the absence of an effective beneficiary designation as to any portion of the distributable amount after any non-Participant Account Owner dies, such amount shall be paid to the Account Owner’s estate. The Account Owner may change a beneficiary designation at any time and without the consent of any previously designated beneficiary.

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(b) Special Rule for Married Participants. If the Account Owner is a married Participant, his Spouse shall be the sole beneficiary unless the 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. Any spousal consent shall be effective only as to the Spouse who signed the consent.

(c) Special Rule for Divorces. If an Account Owner has designated his spouse as a primary or contingent beneficiary, and the Account Owner and spouse later divorce (or their marriage is annulled), then the former spouse will be treated as having pre-deceased the Account Owner for purposes of interpreting a beneficiary designation form completed prior to the divorce or annulment. This subsection will apply only if the Committee is informed of the divorce or annulment 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 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.

(e) Multiple Beneficiaries. If an Account Owner has more than one beneficiary, each subaccount of the Account Owner shall be allocated proportionally to each beneficiary. Thus, for example, if the Account Owner has designated Adam to receive $10,000, with the remainder (which happens to be $90,000) split evenly between William and Charles, then Adam will receive 10% of each subaccount, and William and Charles will each receive 45% of each subaccount.

6.2 Consent.

(a) General. Except for distributions identified in subsection (b), distributions may be made only after the appropriate consent has been obtained under this subsection. Distributions to a Participant or to a beneficiary (other than a beneficiary of a deceased Alternate Payee) shall be made only with the Participant’s or beneficiary’s consent to the time of distribution. Distributions to an Alternate Payee or his beneficiary shall be made as specified in the QDRO and in accordance with section 13.9. To be effective, the consent must be filed with the Committee according to the procedures adopted by the Committee, within 180 days before the distribution is to commence. A consent once given shall be irrevocable after the distribution has been processed.

(b) Exceptions to General Rule. Consent is not required for the following distributions:

(i) Corrective distributions under Article III that are returned to the Participant because the contribution is not deductible by the Company or because the contribution would exceed the limits of Code §401(a)(17), §415(c)(1), §402(g), §401(k)(3), §401(m)(2), §401(m)(9), §414(v)(2)(B)(i), or any other limitation of the Code;

(ii) Distributions required to comply with Code §401(a)(9);

(iii) Cashouts of small Accounts, as described in subsection 6.6(d) or paragraphs 6.6(e)(i) or 13.9(f)(ii);

(iv) Distributions required to comply with Code §401(a)(14);

(v) Distributions of invalid rollovers pursuant to subsection 3.2(d);

(vi) Distributions upon Plan termination pursuant to section 10.3; and

(vii) Distributions that must occur by a deadline specified in the Plan.

6.3 Distributable Amount.

The distributable amount of an Account Owner’s Account(s) is the vested portion of the Account(s) (as determined by Article V) as of the Valuation Date coincident with or next preceding the date distribution is made, reduced by (a) any amount that is payable to an Alternate Payee pursuant to section 13.9, (b) any amount withdrawn since such Valuation Date, and (c) the outstanding balance of any loan under Article VII

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(except that the outstanding balance of such a loan is included in the distributable amount of any final distribution(s) under section 6.6). Furthermore, the Committee shall temporarily suspend or limit distributions (by reducing the distributable amount), as explained in subsection 13.9, when the Committee is informed that a Domestic Relations Order affecting the Participant’s Accounts is or may be in the process of becoming QDRO, while the Committee has suspended withdrawals because it believes that the Plan may have a cause of action against the Participant, or when the Plan has notice of a lien or other claim against the Participant.

6.4 Manner of Distribution.

(a) General. The distributable amount shall be paid in a single payment, except as otherwise provided in the remainder of this section. Distributions shall be in the form of cash except (i) to the extent that an Account is invested in Company Stock or a fund containing primarily Company Stock, the distributee may elect to receive a distribution of whole shares of Company Stock, while fractional shares of Company Stock shall be converted to and paid in cash, (ii) in-kind distributions may be elected, to the extent administratively practicable as determined by the processor of distributions, when a rollover is made to an IRA and the custodian or trustee of the IRA is willing to accept an in-kind contribution, and (iii) a loan may be treated, for purposes of a making a rollover, as distributed to an Account Owner who has an outstanding loan pursuant to Article VII as part of the Account Owner’s final distribution(s).

(b) Partial Withdrawals and Installments. In-service withdrawals are available to Employees as specified in section 6.5. Withdrawals of at least the minimum required amount are available to Participants whose Required Beginning Date has passed or whose Required Beginning Date will occur later in the Plan Year or in the following Plan Year, as described in subsection 6.6(b); similar withdrawals are available to the Participant’s Alternate Payee, as described in subsection 13.9(f). Annual installments are available to beneficiaries as described in subsection 6.6(d).

(c) Grandfather Rules. Installments were a distribution option under the Plan until June 30, 2001. Any Account Owner who could receive a distribution before July 1, 2001 and who elected before July 1, 2001 to receive the distribution in the form of installments shall receive the benefit so elected. An Account Owner who elected installments may elect to accelerate any or all remaining installment payments.

6.5 In-Service Withdrawals.

An Employee may withdraw amounts from his Accounts only as provided in this section. An Employee may make withdrawals as follows.

(a) Withdrawals for Employees Age 59 ¹⁄₂ or Older. An Employee who has attained age 59 ¹⁄₂ may at any time thereafter withdraw any portion of his Participant Contributions Account, his Roth Contributions Account, and any vested portion of his Company Contributions Account. If the Employee is not fully vested in his Company Contributions Account at the time of a withdrawal under this subsection, the rules of subparagraph 5.4(c)(ii)(A) shall be applied when determining the vested portion of the Company Contributions Account at any time thereafter.

(b) Rollover Accounts. An Employee may withdraw all or any portion of his Rollover Account and his Roth Rollover Account at any time.

(c) Participant Contributions Account. An Employee under age 59 ¹⁄₂ may withdraw all or any portion of his Participant Contributions, provided that the Employee has an immediate and heavy financial need, as defined in paragraph (i), the withdrawal is needed to satisfy the financial need, as explained in paragraph (ii), and the amount of the withdrawal does not exceed the limits in paragraph (iii).

(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

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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.

(ii) Satisfaction of Need. The withdrawal is deemed to be needed to satisfy the Employee’s financial need if (A) the Employee has obtained all withdrawals and all non-taxable loans available from the Company’s and any Affiliated Entities’ plans of deferred compensation, qualified plans, stock options, stock purchase plans, and similar plans, and (B) for a period of at least 6 months from the date the Employee receives the withdrawal, he ceases to make Participant Contributions and elective contributions to all plans of deferred compensation, qualified plans, stock options, stock purchase plans, and similar plans maintained by the Company or any Affiliated Entity.

(iii) Maximum Withdrawal. An Employee may not withdraw more than the sum of the amount needed to satisfy his financial need and any taxes and penalties reasonably anticipated to result from the withdrawal. An Employee may not withdraw any amount in excess of his Participant Contributions unless he has attained age 59 ¹⁄₂.

(iv) Pro Rata Withdrawal. Any hardship distribution under this subsection shall be taken pro rata from the Employee’s Participant Contributions Account and his Roth Contributions Account.

(d) Compliance with Code §401(a)(9). See paragraph 6.6(b)(ii) for the required distributions to a Five-Percent Owner who is age 70 ¹⁄₂ or older.

(e) Form of Payment of Withdrawal. Withdrawals under subsection (c) shall be in cash. Withdrawals under subsections (a) and (b) shall be in cash, except that any portion of a Participant’s Accounts that is invested in Company Stock may, at the election of the Participant made at the time that notice of withdrawal is made to the Committee, be withdrawn in the form of whole shares of Company Stock.

(f) Withdrawal Rules. An Employee may not withdraw any amount under this section that has been borrowed or that is subject to a QDRO. The Committee shall temporarily suspend or limit withdrawals under this section, as explained in section 13.9, when the Committee is informed that a QDRO affecting the Employee’s Accounts is in process or may be in process. The Committee shall issue such rules as to the frequency of withdrawals, and withdrawal procedures, as it deems appropriate. The Committee may postpone the withdrawal until after the next Valuation Date. The Committee may have a special valuation of the Trust Fund performed before a withdrawal is permitted. The Plan may charge a fee for the withdrawal as well as a fee for having a special valuation performed, as determined by the Committee in its sole discretion.

(g) Pro Rata Withdrawals. Except as required by subparagraph (c)(ii)(A), when withdrawals under this section are available from more than one subaccount, the withdrawal will be taken pro rata from each available subaccount.

6.6 Time of Distribution.

(a) Earliest Date of Distribution. Unless an earlier distribution is permitted by section 6.5 (relating to in-service withdrawals), the earliest date that a Participant may elect to receive a distribution is the date of his Termination of Employment or the date he incurs a Disability. This provision will always result in a distribution date that precedes the latest date of distribution specified in Code §401(a)(14). For purposes of Code §401(a)(14), if a Participant does not affirmatively elect a distribution, he shall be deemed to have elected to defer the distribution to a later date.

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(b) Latest Date of Distribution. A Participant shall receive annual distributions of at least the minimum amount required to be distributed pursuant to Code §401(a)(9), which shall be calculated by using only the Participant’s life expectancy, which shall be recalculated each year; the Participant may withdraw any larger amount. A Participant may request that his first minimum required distribution be distributed in the calendar year preceding his Required Beginning Date; the Committee shall comply with this request if administratively practicable to do so.

(c) Small Amounts.

(i) $1000 or Less. If the aggregate value of the nonforfeitable portion of a Participant’s Accounts is $1,000 or less on any date after his Termination of Employment, the Participant shall receive a single payment of the distributable amount as soon as practicable, provided that the aggregate value is $1,000 or less when the distribution is processed.

(ii) $1000 to $5000. If paragraph (i) does not apply and the aggregate value of the nonforfeitable portion of a Participant’s Accounts is $5,000 or less on any date after his Termination of Employment, then as soon as practicable the Plan shall pay the distributable amount to an individual retirement account or annuity within the meaning of Code §408(a) or §408(b) (collectively, an “IRA”) for the Participant, unless the Participant affirmatively elects to receive the distribution directly or to have it paid in a direct rollover under section 6.7. The Committee shall select the trustee or custodian of the IRA as well as how the IRA shall be invested initially. The Plan shall notify the Participant (A) that the distribution has been made to an IRA and can be transferred to another IRA, (B) of the identity and contact information of the trustee or custodian of the IRA into which the distribution is made, and (C) of such other information as required to comply with Code §401(a)(31)(B)(i).

(iii) Date Account Valued. The Committee may elect to check the value of the Participant’s Accounts on an occasional (rather than a daily) basis, to determine whether to apply the provisions of this subsection.

(d) Distribution Upon Participant’s Death.

(i) Small Accounts. If the aggregate cash value of the nonforfeitable portion of a Participant’s Accounts is $5,000 or less at any time after the Participant’s death and before any beneficiary elects to receive a distribution under this subsection, then each beneficiary shall each receive a single payment of his share of the distributable amount as soon as administratively practicable, provided that the aggregate value is $5,000 or less when the distribution is processed. The Committee may elect to check the value of the Participant’s Accounts on an occasional (rather than a daily) basis, to determine whether to apply the provisions of this paragraph.

(ii) Larger Accounts. If paragraph (i) does not apply, then each beneficiary may elect to have his distributable amount distributed in a single payment or in annual installments at any time after the Participant’s death, within the following guidelines. No distribution shall be processed until the beneficiary’s identity as a beneficiary is established. The entire distributable amount shall be distributed by the last day of the calendar year containing the fifth anniversary of the Participant’s death. A beneficiary who has elected installments may elect to accelerate any or all remaining payments. If the Participant was a Five-Percent Owner who began to receive the minimum required distributions under paragraph (b)(ii), the distribution to each beneficiary must be made at least as rapidly as required by the method used to calculate the minimum required distributions that was in effect when the Five-Percent Owner died.

(e) Alternate Payee. Distributions to an Alternate Payee shall be made in accordance with the provisions of the QDRO and pursuant to subsection 13.9.

(f) Pro Rata Withdrawals. Any distribution under this section of less than the Account Owner’s entire Account balance shall be taken pro rata from each of the Account Owner’s subaccounts.

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6.7 Direct Rollover Election.

(a) General Rule. A Participant, an Alternate Payee who is the Spouse or former Spouse of the Participant, any individual who is treated as a designated beneficiary of the Participant pursuant to Code §401(a)(9)(E), or any trust to the extent that any beneficiary of the trust is treated as a designated beneficiary of the Participant pursuant to Code §401(a)(9)(E), (collectively, the “distributee”) may direct the Trustee to pay all or any portion of his “eligible rollover distribution” to an “eligible retirement plan” in a “direct rollover.” This direct rollover option is not available to other Account Owners. Within a reasonable period of time before an eligible rollover distribution, the Committee shall inform the distributee of this direct rollover option, the appropriate withholding rules, other rollover options, the options regarding income taxation, and any other information required by Code §402(f). The distributee may waive the usual 30-day waiting period before receiving a distribution, and elect to receive his distribution as soon as administratively practicable after completing and filing his distribution election.

(b) Definition of Eligible Rollover Distribution. An eligible rollover distribution is any distribution or in-service withdrawal other than (i) distributions required under Code §401(a)(9), (ii) distributions of amounts that have already been subject to federal income tax (such as defaulted loans or after-tax voluntary contributions), other than a direct transfer to (A) another retirement plan that meets the requirements of Code §401(a) or §403(a), or (B) an individual retirement account or annuity described in Code §408(a) or §408(b), (iii) installment payments in a series of substantially equal payments made at least annually and (A) made over a specified period of ten or more years, (B) made for the life or life expectancy of the distributee, or (C) made for the joint life or joint life expectancy of the distributee and his designated beneficiary, (iv) a distribution to satisfy the limits of Code §415 or §402(g), (v) a deemed distribution of a defaulted loan from this Plan, to the extent provided in the regulations, (vi) a distribution to satisfy the ADP or ACP tests, (vii) any other actual or deemed distribution specified in IRS guidance of general applicability, or (viii) any hardship withdrawal.

(c) Definition of Eligible Retirement Plan.

(i) Participants, Spouses, and Alternate Payees.

(A) Non-Roth Accounts. This subparagraph applies to all subaccounts other than the Roth Contributions Account and the Roth Rollover Account. For a Participant, an Alternate Payee who is the Spouse or former Spouse of the Participant, or a surviving Spouse of a deceased Participant, an eligible retirement plan is an individual retirement account or annuity described in Code §408(a) or §408(b), a Roth IRA, an annuity plan described in Code §403(a), an annuity contract described in Code §403(b), an eligible plan under Code §457(b) that is maintained by an eligible employer described in Code §457(e)(1)(A) (which generally includes state and local governments), or the qualified trust of a defined contribution plan described in Code §401(a), that accepts eligible rollover distributions.

(B) Roth Accounts. This subparagraph applies to the Roth Contributions Account and the Roth Rollover Account. all subaccounts that contain or once contained a designated Roth contribution within the meaning of Code §402A(c)(1). For a Participant, an Alternate Payee who is the Spouse or former Spouse of the Participant, or a surviving Spouse of a deceased Participant, a Roth IRA, an annuity plan described in Code §403(a), an annuity contract described in Code §403(b), an eligible plan under Code §457(b) that is maintained by an eligible employer described in Code §457(e)(1)(A) (which generally includes state and local governments), or the qualified trust of a defined contribution plan described in Code §401(a), but only if such arrangements accept eligible rollover distributions of designated Roth contributions within the meaning of Code §402A(c)(1).

(ii) Other Distributees, Non-Roth Accounts. This paragraph applies to all subaccounts other than the Roth Contributions Account and the Roth Rollover Account. For an individual who is treated as a designated beneficiary of the Participant pursuant to Code §401(a)(9)(E), and for any trust to the extent that a beneficiary of the trust is treated as a designated beneficiary of the Participant pursuant to Code §401(a)(9)(E), an eligible retirement plan is an individual retirement account or annuity described in Code §408(a) or §408(b) that is in existence or is

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established for the purposes of receiving the distribution on behalf of the beneficiary, and that, with respect to the beneficiary, is treated as an inherited individual retirement account or annuity within the meaning of Code §408(d)(3)(C). The designated beneficiary has two choices for receiving distributions that are to be paid in a direct rollover to such inherited individual retirement account or annuity.

(A) The designated beneficiary may elect to receive a single payment or installments from the Plan, pursuant to paragraph 6.6(d)(ii), during the calendar year in which the Participant died or in the following calendar year (or by such later date allowed pursuant to IRS guidance of general applicability or a private letter ruling obtained by the designated beneficiary). Each annual installment from the Plan must satisfy the requirements of Code §401(a)(9)(B)(iii) (which essentially means that each annual installment must be equal to at least the account balance standing to the credit of the deceased Plan Participant at the end of the previous year, divided by the designated beneficiary’s life expectancy). In this case, distributions from the inherited individual retirement account or annuity may be made over the life expectancy of the designated beneficiary.

(B) If the requirements of subparagraph (A) are not satisfied, the designated beneficiary must receive, pursuant to paragraph 6.6(d)(ii), a full distribution from the Plan by the end of the calendar year containing the fifth anniversary of the Participant’s death. In this case, distributions from the inherited individual retirement account or annuity must generally be completed by the end of the calendar year containing the fifth anniversary of the Participant’s death.

(iii) Other Distributees, Roth Accounts. This paragraph applies only to the Roth Contributions Account and the Roth Rollover Account. For an individual who is treated as a designated beneficiary of the Participant pursuant to Code §401(a)(9)(E), and for any trust to the extent that a beneficiary of the trust is treated as a designated beneficiary of the Participant pursuant to Code §401(a)(9)(E), an eligible retirement plan is a Roth IRA that is in existence or is established for the purposes of receiving the distribution on behalf of the beneficiary, and that, with respect to the beneficiary, is treated as an inherited individual retirement account or annuity within the meaning of Code §408(d)(3)(C). The designated beneficiary has two choices for receiving distributions that are to be paid in a direct rollover to such inherited Roth IRA.

(A) The designated beneficiary may elect to receive a single payment or installments from the Plan, pursuant to paragraph 6.6(d)(ii), during the calendar year in which the Participant died or in the following calendar year (or by such later date allowed pursuant to IRS guidance of general applicability or a private letter ruling obtained by the designated beneficiary). Each annual installment from the Plan must satisfy the requirements of Code §401(a)(9)(B)(iii) (which essentially means that each annual installment must be equal to at least the account balance standing to the credit of the deceased Plan Participant at the end of the previous year, divided by the designated beneficiary’s life expectancy). In this case, distributions from the inherited individual retirement account or annuity may be made over the life expectancy of the designated beneficiary.

(B) If the requirements of subparagraph (A) are not satisfied, the designated beneficiary must receive, pursuant to paragraph 6.6(d)(ii), a full distribution from the Plan by the end of the calendar year containing the fifth anniversary of the Participant’s death. In this case, distributions from the inherited individual retirement account or annuity must generally be completed by the end of the calendar year containing the fifth anniversary of the Participant’s death.

(d) Definition of Direct Rollover. A direct rollover is a payment by the Trustee to the eligible retirement plan specified by the distributee.

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ARTICLE VII

Loans

The Committee is authorized, as one of the Plan fiduciaries responsible for investing Plan assets, to establish a loan program. The loan program shall become effective on the date determined by the Committee. The Committee shall administer the Plan’s loan program in accordance with the following rules.

7.1 Availability

Loans are available only to Employees, Participants who are parties-in-interest (within the meaning of ERISA §3(14)), and beneficiaries who are parties-in-interest (collectively referred to in this section as “Borrowers”). The Committee shall temporarily reduce the amount a Participant may borrow or temporarily prevent the Participant from borrowing when, as described in section 13.9, the Committee is informed that a QDRO affecting the Participant’s Accounts is in process or may be in process. Loans shall be temporarily unavailable to a prospective Borrower while the Committee has suspended loans because the Committee believes that the Plan may have a cause of action against the Participant, as explained in subsection 13.9(h).

7.2 Number of Loans

A Borrower may have no more than one loan outstanding. The Committee may change the maximum number of outstanding loans allowed at any time.

7.3 Loan Amount

The Committee may establish a minimum loan amount of no more than $500. The Committee may require loans to be made in increments of no more than $100. The amount that a Borrower may borrow is subject to the following limits.

(a) A Borrower may not borrow more than the sum of the balances in his Participant Contributions Account, Rollover Contributions Account, Rollover Account, and Roth Rollover Account.

(b) At the time the loan from this Plan is made, the aggregate outstanding balance of all the Borrower’s loans from all qualified plans maintained by the Company and Affiliated Entities, including the new loan from this Plan, shall not exceed 50% of the Borrower’s vested interest in all qualified plans maintained by the Company and Affiliated Entities.

(c) For purposes of this paragraph, the term “one-year maximum” means the largest aggregate outstanding balance, on any day in the one-year period ending on the day before the new loan from this Plan is obtained, of all loans to the Borrower from all qualified plans maintained by the Company and Affiliated Entities. For purposes of this paragraph, the term “existing loans” means the aggregate outstanding balance, on the day the new loan is made to the Borrower, of all loans to the Borrower from all qualified plans maintained by the Company and Affiliated Entities, excluding the new loan from this Plan. If the existing loans are greater than or equal to the one-year maximum, then the new loan from this Plan shall not exceed $50,000 minus the existing loans. If the existing loans are less than the one-year maximum, then the new loan from this Plan shall not exceed $50,000 minus the one-year maximum.

For purposes of applying the above limits, the vested portion of the Borrower’s accounts under this Plan and all other plans maintained by the Company and Affiliated Entities shall be determined without regard to any accumulated deductible employee contributions (as defined in Code §72(o)(5)(B)), and without regard to any amounts accrued while the Borrower was ineligible to obtain a loan (as described in subsection (a)). Notwithstanding the foregoing, the Committee may, in its sole discretion, establish lesser limits on the amounts that may be borrowed, which limits shall be applied in a non-discriminatory manner. The Committee shall temporarily reduce the amount a Participant may borrow or temporarily prevent the Participant from borrowing, as described in section 13.9, when the Committee is informed that a QDRO affecting the Participant’s Accounts is in process or may be in process. No loan shall be made of amounts that are required to be distributed prior to the end of the term of the loan.

7.4 Interest

Each loan shall bear a reasonable rate of interest, which shall remain fixed for the duration of the loan. The Committee or its agent shall determine the reasonable rate of interest on the date the loan documents are prepared. The Committee shall have the authority to establish procedures from time to time for determining the rate of interest.

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7.5 Repayment.

All loans shall be repaid, with interest, in substantially level amortized payments made not less frequently than quarterly. The maximum term for a loan is four years; the minimum term for a loan is one year. The Committee has the authority to decrease the minimum term for future loans and the authority to increase the maximum term for future loans to no more than five years. Loan repayments shall be accelerated, and all loans shall be payable in full on the date the Borrower separates from service (if the Borrower is an Employee), the date the Borrower becomes ineligible to borrow from the Plan under to section 7.1, and on any other date or any other contingency as determined by the Committee. If the Borrower is an Employee, loans shall be repaid through payroll withholding unless (a) the Employee is pre-paying his loan, in which case the pre-payment need not be through payroll withholding, or (b) the Employee is on an unpaid leave of absence, in which case he may pay any installment by personal check. Partial pre-payments are accepted.

7.6 Default

A loan shall be in default if any installment is not paid by the end of the calendar quarter following the calendar quarter in which the installment was due. Upon default, the Committee may, in addition to all other remedies, apply the Borrower’s Plan accounts toward payment of the loan; however, the Trustee may not exercise such right of set-off with respect to the Borrower’s Participant Contributions Account until such account has become payable, pursuant to section 6.5 or 6.6.

7.7 Administration

A Borrower shall apply for a loan by completing the application procedures specified by the Committee. Until changed by the Committee, a Borrower shall apply for a loan by calling the Trustee and completing a voice application. The loan shall be processed in accordance with reasonable procedures adopted from time to time by the Committee. The Committee may impose a loan application fee, a loan origination fee, a loan pre-payment fee, and loan maintenance fees. All loans shall be evidenced by a promissory note and shall be fully secured. No Borrower whose Plan accounts are so pledged may obtain distribution of any portion of the accounts that have been pledged. The rights of the Trustee under such pledge shall have priority over all claims of the Borrower, his beneficiaries, and creditors. Each loan shall be treated as a directed investment. Any increase or decrease in the net worth of the Trust Fund attributable to such loan shall be allocated solely to the Plan accounts of the Borrower.

ARTICLE VIII

Allocation of Responsibilities - Named Fiduciaries

8.1 No Joint Fiduciary Responsibilities.

The Trustee(s) and the Committee shall be the named fiduciaries under the Plan and Trust agreement and shall be the only named fiduciaries thereunder. The fiduciaries shall have only the responsibilities specifically allocated to them herein or in the Trust agreement. Such allocations are intended to be mutually exclusive and there shall be no sharing of fiduciary responsibilities. Whenever one named fiduciary is required by the Plan or Trust agreement to follow the directions of another named fiduciary, the two named fiduciaries shall not be deemed to have been assigned a shared responsibility, but the responsibility of the named fiduciary giving the directions shall be deemed his sole responsibility, and the responsibility of the named fiduciary receiving those directions shall be to follow them insofar as the instructions are on their face proper under applicable law.

8.2 The Company.

The Company shall be responsible for: (a) making Company Contributions; (b) certifying to the Trustee the names and specimen signatures of the members of the Committee acting from time to time; (c) keeping accurate books and records with respect to its Employees and the appropriate components of each Employee’s Compensation and furnishing such data to the Committee; (d) selecting agents and fiduciaries to operate and administer the Plan and Trust; (e) appointing an investment manager if it determines that one should be appointed; and (f) reviewing periodically the performance of such agents, managers, and fiduciaries.

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8.3 The Trustee.

The Trustee shall be responsible for: (a) the investment of the Trust Fund to the extent and in the manner provided in the Trust agreement; (b) the custody and preservation of Trust assets delivered to it; and (c) the payment of such amounts from the Trust Fund as the Committee shall direct.

8.4 The Committee - Plan Administrator.

The board of directors of Apache shall appoint an administrative Committee consisting of no fewer than three individuals who may be, but need not be, Participants, officers, directors, or Employees of the Company. If the board of directors does not appoint a Committee, Apache shall act as the Committee under the Plan. The members of the Committee shall hold office at the pleasure of the board of directors and shall service without compensation. The Committee shall be the Plan’s “administrator” as defined in section 3(16)(A) of ERISA. It shall be responsible for establishing and implementing a funding policy consistent with the objectives of the Plan and with the requirements of ERISA. This responsibility shall include establishing (and revising as necessary) short-term and long-term goals and requirements pertaining to the financial condition of the Plan, communicating such goals and requirements to the persons responsible for the various aspects of the Plan operations, and monitoring periodically the implementation of such goals and requirements. The Committee shall publish and file or cause to be published and filed or disclosed all reports and disclosures required by federal or state laws.

8.5 Committee to Construe Plan.

(a) The Committee shall administer the Plan and shall have all discretion, power, and authority necessary for that purpose, including, but not by way of limitation, the full and absolute discretion and power to interpret the Plan, to determine the eligibility, status, and rights of all individuals under the Plan, and in general to decide any dispute and all questions arising in connection with the Plan. The Committee shall direct the Trustee concerning all distributions from the Trust Fund, in accordance with the provisions of the Plan, and shall have such other powers in the administration of the Trust Fund as may be conferred upon it by the Trust agreement. The Committee shall maintain all Plan records except records of the Trust Fund.

(b) The Committee may adjust the Account(s) of any Participant, in order to correct errors and rectify omissions, in such manner as the Committee believes will best result in the equitable and nondiscriminatory administration of the Plan.

8.6 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. It may appoint agents (who need not be members of the Committee) to whom it may delegate such powers as it deems appropriate, except that any dispute shall be determined by the Committee. The Committee may make its determinations with or without meetings. It may authorize one or more of its members or agents to sign instructions, notices and determinations on its behalf. If a Committee decision or action affects a relatively small percentage of Plan Participants including a Committee member, such Committee member shall not participate in the Committee decision or action. The action of a majority of the disinterested Committee members shall constitute the action of the Committee.

8.7 Agent for Process.

Apache’s Vice President, General Counsel, and Secretary shall be the agents of the Plan for service of all process.

8.8 Indemnification of Committee Members.

The Company shall indemnify and hold the members of the Committee, and each of them, harmless from the effects and consequences of their acts, omissions, and conduct in their official capacities, except to the extent that the effects and consequences thereof shall result from their own willful misconduct, breach of good faith, or gross negligence in the performance of their duties. The foregoing right of indemnification shall not be exclusive of the rights to which each such member may be entitled as a matter of law.

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8.9 Conclusiveness of Action.

Any action taken by the Committee on matters within the discretion of the Committee shall be conclusive, final and binding upon all participants in the Plan and upon all persons claiming any rights hereunder, including alternate payees and beneficiaries.

8.10 Payment of Expenses.

The members of the Committee shall serve without compensation but their reasonable expenses shall be paid by the Company. The compensation or fees of accountants, counsel, and other specialists and any other costs of administering the Plan or Trust Fund may be paid by the Company or Account Owners or may be charged to the Trust Fund, to the extent permissible under ERISA.

ARTICLE IX

Trust Agreement – Investments

9.1 Trust Agreement.

Apache has entered into a Trust agreement to provide for the holding, investment, and administration of the funds of the Plan. The Trust agreement shall be part of the Plan, and the rights and duties of any individual under the Plan shall be subject to all terms and provisions of the Trust agreement.

9.2 Plan Expenses.

(a) General. Except as provided in subsection (b), (i) all taxes upon or in respect of the Plan and Trust shall be paid out of Plan assets, and all expenses of administering the Plan and Trust shall be paid out of Plan assets, to the extent permitted by law and to the extent such taxes and expenses are not paid by the Company or an Account Owner, and (ii) the Committee shall have full discretion to determine how each tax or expense that is not paid by the Company shall be paid and the Committee shall have full discretion to determine how each tax or expense that is paid out of Plan assets shall be allocated. No fiduciary shall receive any compensation for services rendered to the Plan if the fiduciary is being compensated on a full time basis by the Company or an Affiliated Entity.

(b) Individual Expenses. To the extent not paid by the Company or an Account Owner, all expenses of individually directed transactions, including without limitation the Trustee’s transaction fee, brokerage commissions, transfer taxes, interest on insurance policy loans, and any taxes and penalties that may be imposed as a result of an individual’s investment direction, shall be assessed against the Account(s) of the Account Owner directing such transactions.

9.3 Investments.

(a) §404(c) Plan. The Plan is intended to be a plan described in ERISA §404(c). To the extent that an Account Owner exercises control over the investment of his Accounts, no person who is a fiduciary shall be liable for any loss, or by reason of any breach, that is the direct and necessary result of the Account Owner’s exercise of control.

(b) Directed Investments. Accounts shall be invested, upon direction of each Account Owner made in a manner acceptable to the Committee, in any one or more of a series of investment funds designated by the Committee or to the extent permitted by the Committee in a brokerage arrangement. Either (i) one or more such funds shall consist primarily of shares of Company Stock or (ii) Company Stock shall be a permitted investment option, whether inside a brokerage arrangement or otherwise. If so directed by Account Owners, up to 100% of the Accounts under the Plan may be invested in Company Stock. To the extent that any Account is invested in Company Stock or in an investment funds consisting primarily of Company Stock, an Account Owner may sell such investment at any time, subject to reasonable administrative delays and any blackout periods imposed by the Committee (including blackout periods that apply to particular Participants to ensure compliance with the securities laws). The funds available for investment and the principal features thereof, including a general description of the investment objectives, the risk and return characteristics, and the type and diversification of the investment portfolio of each fund, shall be communicated to the Account Owners in the Plan from time to time. Any changes in such funds shall be immediately communicated to all Account Owners.

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(c) Absence of Directions. To the extent that an Account Owner fails to affirmatively direct the investment of his Accounts, the Committee shall direct the Trustee in writing concerning the investment of such Accounts. The Committee shall act by majority vote. Any dissenting member of the Committee shall, having registered his dissent in writing, thereafter cooperate to the extent necessary to implement the decision of the Committee.

(d) Change in Investment Directions. Account Owners may change their investment directions, with respect to the investment of new contributions and with respect to the investment of existing amounts allocated to Accounts, on any business day, subject to any restrictions and limitations imposed by the Trustee, investment funds, or brokerage arrangement. The Committee shall establish procedures for giving investment directions, which shall be in writing and communicated to Account Owners.

ARTICLE X

Termination and Amendment

10.1 Termination of Plan or Discontinuance of Contributions.

Apache expects to continue the Plan indefinitely, but the continuance of the Plan and the payment of contributions are not assumed as contractual obligations. Apache may terminate the Plan or discontinue contributions at any time. Upon the termination of the Plan or the complete discontinuance of contributions, each Participant’s Accounts shall become fully vested. Upon the partial termination of the Plan, the Accounts of all affected Participants shall become fully vested. The only Participants who are affected by a partial termination are those whose employment with the Company or Affiliated Entity is terminated as a result of the corporate event causing the partial termination; Employees terminated for cause and those who leave voluntarily are not affected by a partial termination.

10.2 Allocations upon Termination or Discontinuance of Company Contributions.

Upon the termination or partial termination of the Plan or upon the complete discontinuance of contributions, the Committee shall promptly notify the Trustee of such termination or discontinuance. The Trustee shall then determine, in the manner prescribed in section 4.2, the net worth of the Trust Fund as of the close of the business day specified by the Committee. The Trustee shall advise the Committee of any increase or decrease in such net worth that has occurred since the preceding Valuation Date. After crediting to the Participant Contributions Account of each Participant any amount contributed since the preceding Valuation Date, the Committee shall thereupon allocate, in the manner described in section 4.3, among the remaining Plan Accounts, in the manner described in Articles III, IV and V, any Company Contributions or forfeitures occurring since the preceding Valuation Date.

10.3 Procedure upon Termination of Plan or Discontinuance of Contributions.

If the Plan has been terminated or partially terminated, or if a complete discontinuance of contributions to the Plan has occurred, then after the allocations required under section 10.2 have been completed, the Trustee shall distribute or transfer the Account(s) of affected Account Owners as follows.

(a) No Other Plan. If the Company and Affiliated Entities are not treated, pursuant to the Treasury Regulations under Code §401(k), as maintaining another “alternative defined contribution plan,” the Trustee shall distribute each Account Owner’s entire Account in a single payment, after complying with the requirements of section 6.7. For purposes of this section only, an “alternative defined contribution plan” means a defined contribution plan that is not an employee stock ownership plan within the meaning of Code §4975(e)(7) or §409(a)), a simplified employee pension within the meaning of Code §408(k), a SIMPLE IRA within the meaning of Code §408(p), a plan or contract that satisfies the requirements of Code §403(b), or a plan described in Code §457(b) or §457(f).

(b) Other Plan Maintained. If the Company and Affiliated Entities are treated, pursuant to the Treasury Regulations under Code §401(k), as maintaining another “alternative defined contribution plan,” the Trustee shall (i) distribute the Accounts of each non-Participant Account Owner in a single payment, after complying with the requirements of section 6.7, and (ii) transfer the Accounts of each Participant to an alternative defined contribution plan. All the rights, benefits, features, and distribution restrictions with respect to the transferred amounts shall continue to apply to the transferred amounts unless a change is permitted pursuant to applicable IRS guidance of general applicability.

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(c) Form of Payment. A transfer made pursuant to this section may be in cash, in kind, or partly in cash and partly in kind. Any distribution made pursuant to this section may be in cash, in shares of Company Stock to the extent an Account is invested in Company Stock, or partly in cash and partly in shares of Company Stock. After all such distributions or transfers have been made, the Trustee shall be discharged from all obligation under the Trust; no Account Owner who has received any such distribution, or for whom any such transfer has been made, shall have any further right or claim under the Plan or Trust.

10.4 Amendment by Apache.

(a) Amendment. Apache may at any time amend the Plan in any respect, without prior notice, subject to the following limitations. No amendment shall be made that would have the effect of vesting in the Company any part of the Trust Fund or of diverting any part of the Trust Fund to purposes other than for the exclusive benefit of Account Owners. The rights of any Account Owner with respect to contributions previously made shall not be adversely affected by any amendment. No amendment shall reduce or restrict, either directly or indirectly, the accrued benefit (within the meaning of Code §411(d)(6)) provided to any Account Owner before the amendment, except as permitted by the Code or IRS guidance of general applicability.

(b) Amendment to Vesting Schedule. If the vesting schedule is amended, and it has the potential to provide slower vesting for one or more Participants, each such Participant with a three-year or longer Period of Service may elect to have his nonforfeitable percentage computed under the Plan without regard to such amendment. The period during which the election may be made shall commence with the date the amendment is adopted and shall end on the latest of: (i) 60 days after the amendment is adopted; (ii) 60 days after the amendment becomes effective; or (iii) 60 days after the Participant is issued written notice of the amendment by the Company or Committee. Furthermore, no amendment shall decrease the nonforfeitable percentage, measured as of the later of the date the amendment is adopted or effective, of any Account Owner’s Accounts.

(c) Procedure. Each amendment shall be in writing. Each amendment shall be approved by Apache’s board of directors or by an officer of Apache who has the authority to amend the Plan. Each amendment shall be executed by an officer of Apache who has the authority to execute the amendment.

ARTICLE XI

Plan Adoption by Affiliated Entities

11.1 Adoption of Plan.

Apache may permit any Affiliated Entity to adopt the Plan and Trust for its Employees. Thereafter, such Affiliated Entity shall deliver to the Trustee a certified copy of the resolutions or other documents evidencing its adoption of the Plan and Trust. The Employees of the Affiliated Entity adopting the Plan shall not be eligible to invest their Accounts in Company Stock until compliance with the applicable registration and reporting requirements of the securities laws.

11.2 Agent of Affiliated Entity.

By becoming a party to the Plan, each Affiliated Entity appoints Apache as its agent with authority to act for the Affiliated Entity in all transactions in which Apache believes such agency will facilitate the administration of the Plan. Apache shall have the sole authority to amend and terminate the Plan.

11.3 Disaffiliation and Withdrawal from Plan.

(a) Disaffiliation. Any Affiliated Entity that has adopted the Plan and thereafter ceases for any reason to be an Affiliated Entity shall forthwith cease to be a party to the Plan.

(b) Withdrawal. Any Affiliated Entity may, by appropriate action and written notice thereof to Apache, provide for the discontinuance of its participation in the Plan. Such withdrawal from the Plan shall not be effective until the end of the Plan Year.

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11.4 Effect of Disaffiliation or Withdrawal.

If at the time of disaffiliation or withdrawal, the disaffiliating or withdrawing entity, by appropriate action, adopts a substantially identical plan that provides for direct transfers from this Plan, then, as to Account Owners associated with such entity, no plan termination shall have occurred; the new plan shall be deemed a continuation of this Plan for such Account Owners. In such case, the Trustee shall transfer to the trustee of the new plan all of the assets held for the benefit of Account Owners associated with the disaffiliating or withdrawing entity, and no forfeitures or acceleration of vesting shall occur solely by reason of such action. Such payment shall operate as a complete discharge of the Trustee, and of all organizations except the disaffiliating or withdrawing entity, of all obligations under this Plan to Account Owners associated with the disaffiliating or withdrawing entity. A new plan shall not be deemed substantially identical to this Plan if it provides slower vesting than this Plan. Nothing in this section shall authorize the divesting of any vested portion of a Participant’s Account(s).

11.5 Actions upon Disaffiliation or Withdrawal.

(a) Distribution or Transfer. If an entity disaffiliates from Apache or withdraws from the Plan and the provisions of section 11.4 are not followed, then the following rules apply to the Account(s) of the Account Owners associated with the disaffiliating or withdrawing entity. The Account Owner’s Accounts shall remain in this Plan until a distribution is processed under the usual rules of Article VI, unless the disaffiliating or withdrawing entity maintains another qualified plan that accepts direct transfers from this Plan, in which case the Committee may transfer the Account Owner’s Accounts to the disaffiliating or withdrawing entity’s plan without the consent of the Account Owner.

(b) Form of Transfer. A transfer made pursuant to this section may be in cash, in kind, or partly in cash and partly in kind. Any distribution made pursuant to this section may be in cash, in shares of Company Stock to the extent an Account is invested in Company Stock, or partly in cash and partly in shares of Company Stock. After such distribution or transfer has been made, no Account Owner who has received any such distribution, or for whom any such transfer has been made, shall have any further right or claim under the Plan or Trust.

ARTICLE XII

Top-Heavy Provisions

12.1 Application of Top-Heavy Provisions.

The provisions of this Article XII shall be applicable only if the Plan becomes “top-heavy” as defined below for any Plan Year. If the Plan becomes “top-heavy” for a Plan Year, the provisions of this Article XII shall apply to the Plan effective as of the first day of such Plan Year and shall continue to apply to the Plan until the Plan ceases to be “top-heavy” or until the Plan is terminated or otherwise amended.

12.2 Determination of Top-Heavy Status.

The Plan shall be considered “top-heavy” for a Plan Year if, as of the last day of the prior Plan Year, the aggregate of the Account balances (as calculated according to the regulations under Code §416) of Key Employees under this Plan (and under all other plans required or permitted to be aggregated with this Plan) exceeds 60% of the aggregate of the Account balances (as calculated according to the regulations under Code §416) in this Plan (and under all other plans required or permitted to be aggregated with this Plan) of all current Employees and all former Employees who had performed services for Apache or an Affiliated Entity within the one-year period ending on the last day of the prior Plan Year. This ratio shall be referred to as the “top-heavy ratio”. For purposes of determining the account balance of any Participant, (a) the balance shall be determined as of the last day of the prior Plan Year, (b) the balance shall also include any distributions to the Participant during the one-year period ending on the last day of the prior Plan Year, and (c) the balance shall also include, for distributions made for a reason other than severance of employment or death or disability, any distributions to the Participant during the five-year period ending on the last day of the prior Plan Year. This shall also apply to distributions under a terminated plan that, if it had not been terminated, would have been required to be included in an aggregation group. The Account balances of a Participant who had once been a Key Employee, but who is not a Key Employee during the Plan Year, shall not be taken into account. The following plans must be aggregated with this Plan for the top-heavy test: (a) a qualified plan maintained by the Company or an Affiliated Entity in which a Key Employee participated during this Plan

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Year or during the previous four Plan Years and (b) any other qualified plan maintained by the Company or an Affiliated Entity that enables this Plan or any plan described in clause (a) to meet the requirements of Code §401(a)(4) or §410. The following plans may be aggregated with this Plan for the top-heavy test: any qualified plan maintained by the Company or an Affiliated Entity that, in combination with the Plan or any plan required to be aggregated with this Plan when testing this Plan for top-heaviness, would satisfy the requirements of Code §401(a)(4) and §410. If one or more of the plans required or permitted to be aggregated with this Plan is a defined benefit plan, a Participant’s “account balance” shall equal the present value of the Participant’s accrued benefit. If the aggregation group includes more than one defined benefit plan, the same actuarial assumptions shall be used with respect to each such defined benefit plan. The foregoing top-heavy ratio shall be computed in accordance with the provisions of Code §416(g), together with the regulations and rulings thereunder.

12.3 Special Vesting Rule.

Unless section 5.1 provides for faster vesting, the amount credited to the Participant’s Company Contributions Account shall vest in accordance with the following schedule during any top-heavy Plan Year:

Period of Service	Vesting Percentage
Less than 2 years	0%
At least 2 years, but less than 3 years	20%
At least 3 years, but less than 4 years	40%
At least 4 years, but less than 5 years	60%
At least 5 years, but less than 6 years	80%
6 or more years	100%

12.4 Special Minimum Contribution.

Notwithstanding the provisions of section 3.1, in every top-heavy Plan Year, a minimum allocation is required for each Non-Key Employee who both (a) performed one or more hours of service as an Employee during the Plan Year as a Covered Employee after satisfying the eligibility requirements of section 2.1, and (b) was an Employee on the last day of the Plan Year. The minimum allocation shall be a percentage of each Non-Key Employee’s Compensation. The percentage shall be the lesser of 3% or the largest percentage obtained for any Key Employee by dividing his Annual Additions (to this Plan and any other plan aggregated with this Plan) for the Plan Year by his Compensation for the Plan Year. If the Participant participates in both this Plan and the Apache Corporation Money Purchase Retirement Plan, then the Participant’s minimum allocation shall be provided in the Apache Corporation Money Purchase Retirement Plan. If this minimum allocation is not otherwise satisfied for any Non-Key Employee, the Company shall contribute the additional amount needed to satisfy this requirement to such Non-Key Employee’s Company Contributions Account.

12.5 Change in Top-Heavy Status.

If the Plan ceases to be a “top-heavy” plan as defined in this Article XII, and if any change in the benefit structure, vesting schedule, or other component of a Participant’s accrued benefit occurs as a result of such change in top-heavy status, the nonforfeitable portion of each Participant’s benefit attributable to Company Contributions shall not be decreased as a result of such change. In addition, each Participant with at least a three-year Period of Service on the date of such change, may elect to have the nonforfeitable percentage computed under the Plan without regard to such change in status. The period during which the election may be made shall commence on the date the Plan ceases to be a top-heavy plan and shall end on the later of (a) 60 days after the change in status occurs, (b) 60 days after the change in status becomes effective, or (c) 60 days after the Participant is issued written notice of the change by the Company or the Committee.

ARTICLE XIII

Miscellaneous

13.1 Right to Dismiss Employees - No Employment Contract.

The Company and Affiliated Entities may terminate the employment of any employee as freely and with the same effect as if this Plan were not in existence. Participation in this Plan by an employee shall not constitute an express or implied contract of employment between the Company or an Affiliated Entity and the employee.

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13.2 Claims Procedure.

(a) General. Each claim for benefits shall be processed in accordance with the procedures that are 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 not be copied on any 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 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.

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(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 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 the appellate decision, or (ii) the date on which the statute of limitations for such claim expires.

(l) Discretionary Authority. The Committee shall have total discretionary authority to determine eligibility, status, and the rights of all individuals under the Plan and to construe any and all terms of the Plan.

13.3 Source of Benefits.

All benefits payable under the Plan shall be paid solely from the Trust Fund, and the Company and Affiliated Entities assume no liability or responsibility therefor.

13.4 Exclusive Benefit of Employees.

It is the intention of the Company that no part of the Trust, other than as provided in sections 3.3, 9.2, and 13.9 and Article VII hereof and the Trust Agreement, ever to be used for or diverted for purposes other than for the exclusive benefit of Participants, Alternate Payees, and their beneficiaries, and that this Plan shall be construed to follow the spirit and intent of the Code and ERISA.

13.5 Forms of Notices.

Wherever provision is made in the Plan for the filing of any notice, election, or designation by a Participant, Spouse, Alternate Payee, or beneficiary, the action of such individual may be evidenced by the execution of such form as the Committee may prescribe for the purpose. The Committee may also prescribe alternate methods for filing any notice, election, or designation (such as telephone voice-response or e-mail).

13.6 Failure of Any Other Entity to Qualify.

If any entity adopts this Plan but fails to obtain or retain the qualification of the Plan under the applicable provisions of the Code, such entity shall withdraw from this Plan upon a determination by the Internal Revenue Service that it has failed to obtain or retain such qualification. Within 30 days after the date of such determination, the assets of the Trust Fund held for the benefit of the Employees of such entity shall be separately accounted for and disposed of in accordance with the Plan and Trust.

13.7 Notice of Adoption of the Plan.

The Company shall provide each of its Employees with notice of the adoption of this Plan, notice of any amendments to the Plan, and notice of the salient provisions of the Plan prior to the end of the first Plan Year. A complete copy of the Plan shall also be made available for inspection by Employees or any other individual with an Account balance under the Plan.

13.8 Plan Merger.

If this Plan is merged or consolidated with, or its assets or liabilities are transferred to, any other qualified plan of deferred compensation, each Participant shall be entitled to receive a benefit immediately after the merger, consolidation, or transfer that is equal to or greater than the benefit the Participant would have been entitled to receive immediately before the merger, consolidation, or transfer if this Plan had then been terminated.

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13.9 Inalienability of Benefits - Domestic Relations Orders.

(a) General. Except as provided in section 7.2, relating to Plan loans, subsection 6.1(d) relating to disclaimers, and subsections (b), (g), and (h) below, no Account Owner shall have any right to assign, alienate, transfer, or encumber his interest in any benefits under this Plan, nor shall such benefits be subject to any legal process to levy upon or attach the same for payment of any claim against any such Account Owner.

(b) QDRO Exception. Subsection (a) shall apply to the creation, assignment, or recognition of a right to any benefit payable with respect to a Participant pursuant to a Domestic Relations Order unless such Domestic Relations Order is a QDRO, in which case the Plan shall make payment of benefits in accordance with the applicable requirements of any such QDRO.

(c) QDRO Requirements. In order to be a QDRO, the Domestic Relations Order must satisfy the requirements of Code §414(p) and ERISA §206(d)(3). In particular, the Domestic Relations Order: (i) must specify the name and the last known mailing address of the Participant; (ii) must specify the name and mailing address of each Alternate Payee covered by the order; (iii) must specify either the amount or percentage of the Participant’s benefits to be paid by the Plan to each such Alternate Payee, or the manner in which such amount or percentage is to be determined; (iv) must specify the number of payments or period to which such order applies; (v) must specify each plan to which such order applies; (vi) may not require the Plan to provide any type or form of benefit, or any option, not otherwise provided under the Plan, subject to the provisions of subsection (f); (vii) may not require the Plan to provide increased benefits (determined on the basis of actuarial value); and (viii) may not require the payment of benefits to an Alternate Payee if such benefits have already been designated to be paid to another Alternate Payee under another order previously determined to be a QDRO.

(d) QDRO Payment Rules. In the case of any payment before an Employee has separated from service, a Domestic Relations Order shall not be treated as failing to meet the requirements of subsection (c) solely because such order requires that payment of benefits be made to an Alternate Payee (i) on or after the dates specified in subsection (f), (ii) as if the Employee had retired on the date on which such payment is to begin under such order (but taking into account only the Account balance on such date), and (iii) in any form in which such benefits may be paid under the Plan to the Employee. For purposes of this subsection, the Account balance as of the date specified in the QDRO shall be the vested portion of the Employee’s Account(s) on such date.

(e) QDRO Review Procedures and Suspension of Benefits. The Committee shall establish reasonable procedures to determine the qualified status of Domestic Relations Orders and to administer distributions under QDROs. Such procedures shall be in writing and shall permit an Alternate Payee to designate a representative to receive copies of notices. The Committee may temporarily prevent the Participant from borrowing from his Accounts and shall temporarily suspend distributions and withdrawals from the Participant’s Accounts, except to the extent necessary to make the required minimum distributions under Code §401(a)(9), when the Committee receives a Domestic Relations Order or a draft of such an order that affects the Participant’s Accounts or when one or the following individuals informs the Committee, orally or in writing, that a QDRO is in process or may be in process: the Participant, a prospective Alternate Payee, or counsel for the Participant or a prospective Alternate Payee. The Committee shall promulgate reasonable and non-discriminatory rules regarding such suspensions, including but not limited to how long such suspensions remain in effect. The procedures may allow the Participant to borrow such amounts from the Plan, subject to the limits of Article VII, and the Participant to receive such distributions and withdrawals from the Plan, subject to the rules of Articles VI and VII, as are consented to in writing by all prospective Alternate Payees identified in the Domestic Relations Order or, in the absence of a Domestic Relations Order, as are consented to in writing by the prospective Alternate Payee(s) who informed the Committee that a QDRO was in process or may be in process. When the Committee receives a Domestic Relations Order it shall promptly notify the Participant and each Alternate Payee of such receipt and provide them with copies of the Plan’s procedures for determining the qualified status of the order. Within a reasonable period after receipt of a Domestic Relations Order, the Committee shall determine whether such order is a QDRO and notify the Participant and each Alternate Payee of such determination. During any period in which the issue of whether a Domestic Relations Order is a QDRO is being

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determined (by the Committee, by a court of competent jurisdiction, or otherwise), the Committee shall separately account for the amounts payable to the Alternate Payee if the order is determined to be a QDRO. If the order (or modification thereof) is determined to be a QDRO within 18 months after the date the first payment would have been required by such order, the Committee shall pay the amounts separately accounted for (plus any interest thereon) to the individual(s) entitled thereto. However, if the Committee determines that the order is not a QDRO, or if the issue as to whether such order is a QDRO has not been resolved within 18 months after the date of the first payment would have been required by such order, then the Committee shall pay the amounts separately accounted for (plus any interest thereon) to the individual(s) who would have been entitled to such amounts if there had been no order. Any determination that an order is a QDRO that is made after the close of the 18-month period shall be applied prospectively only. If the Plan’s fiduciaries act in accordance with fiduciary provision of ERISA in treating a Domestic Relations Order as being (or not being) a QDRO or in taking action in accordance with this subsection, then the Plan’s obligation to the Participant and each Alternate Payee shall be discharged to the extent of any payment made pursuant to the acts of such fiduciaries.

(f) Rights of Alternate Payee. The Alternate Payee shall have the following rights under the Plan:

(i) Single Payment. The only form of payment available to an Alternate Payee is a single payment of the distributable amount (measured at the time the payment is processed), except for the minimum required distributions under paragraph (ii) and except that partial withdrawals are available to the Alternate Payee between the date the Participant attains age 59 ¹⁄₂ and the Participant’s Required Beginning Date. If the Alternate Payee is awarded more than the distributable amount, the Alternate Payee shall initially be eligible to receive a distribution of the distributable amount, with additional amounts becoming eligible for distribution when more of the amount awarded to the Alternate Payee becomes distributable.

(ii) Timing of Distribution. Subject to the limits imposed by this paragraph, the Alternate Payee may choose (or the QDRO may specify) the date of the distribution. If the value of the nonforfeitable portion of an Alternate Payee’s Account is $5,000 or less, the Alternate Payee shall receive a single payment of the distributable amount as soon as practicable (without the Alternate Payee’s consent), provided that the value is $5,000 or less when the distribution is processed. Otherwise, the distribution to the Alternate Payee may occur at any time after the Committee determines that the Domestic Relations Order is a QDRO and before the Participant’s Required Beginning Date (unless the order is determined to be a QDRO after the Participant’s Required Beginning Date, in which case the first minimum required distribution to the Alternate Payee shall be made by the deadline for making such distributions under Code §401(a)(9), which will usually be the end of the year in which the order was determined to be a QDRO). An Alternate Payee shall receive annual distributions of at least the minimum amount required to be distributed pursuant to Code §401(a)(9), which shall be calculated by using only the Participant’s life expectancy, which shall be recalculated each year; the Alternate Payee may withdraw any larger amount. The Alternate Payee may request that his first minimum required distribution be distributed in the calendar year preceding the Participant’s Required Beginning Date; the Plan shall comply with this request if administratively practicable to do so.

(iii) Death of Alternate Payee. The Alternate Payee may designate one or more beneficiaries, as specified in section 6.1. When the Alternate Payee dies, the Alternate Payee’s beneficiary shall receive a complete distribution of the distributable amount in a single payment as soon as administratively convenient.

(iv) Investing. An Alternate Payee may direct the investment of his Account pursuant to section 9.3.

(v) Claims. The Alternate Payee may bring claims against the Plan pursuant to section 13.2.

(vi) Roth Contributions and Rollovers. The amount awarded to the Alternate Payee shall contain a pro rate share (determined as of the date specified in the QDRO or, if the QDRO is silent, determined as of the date of the divorce or annulment) of the Participant’s designated Roth contributions within the meaning of Code §402A(c)(1).

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(g) Exception for Misconduct towards the Plan. Subsection (a) shall not apply to any offset of a Participant’s benefits against an amount that the Participant is ordered or required to pay to the Plan if the following conditions are met.

(i) The order or requirement to pay must arise (A) under a judgment of conviction for a crime involving the Plan, (B) under a civil judgment (including a consent order or decree) entered by a court in an action brought in connection with a violation (or alleged violation) of part 4 of subtitle B of title I of ERISA, or (iii) pursuant to a settlement agreement between the Secretary of Labor and the Participant, or a settlement agreement between the Pension Benefit Guaranty Corporation and the Participant, in connection with a violation (or alleged violation) of part 4 of subtitle B of title I of ERISA by a fiduciary or any other person.

(ii) The judgment, order, decree, or settlement agreement must expressly provide for the offset of all or part of the amount ordered or required to be paid to the Plan against the Participant’s benefits provided under the Plan.

(iii) To the extent that the survivor annuity requirements of Code §401(a)(11) apply with respect to distributions from the Plan to the Participant, if the Participant is married at the time at which the offset is to be made, (A) either the Participant’s Spouse must have already waived his right to a qualified preretirement survivor annuity and a qualified joint and survivor annuity or the Participant’s Spouse must consent in writing to such offset with such consent witnessed by a notary public or representative of the Plan (or it is established to the satisfaction of a Plan representative that such consent may not be obtained by reason of circumstances described in Code §417(a)(2)(B)), or (B) the Participant’s Spouse is ordered or required in such judgment, order, decree, or settlement to pay an amount to the Plan in connection with a violation of part 4 of subtitle B of title I of ERISA, or (C) in such judgment, order, decree, or settlement, the Participant’s Spouse retains the right to receive a survivor annuity under a qualified joint and survivor annuity pursuant to Code §401(a)(11)(A)(i) and under a qualified preretirement survivor annuity provided pursuant to Code §401(a)(11)(A)(ii). The value of the Spouse’s survivor annuity in subparagraph (C) shall be determined as if the Participant terminated employment on the date of the offset, there was no offset, the Plan permitted commencement of benefits only on or after Normal Retirement Age, the Plan provided only the “minimum-required qualified joint and survivor annuity,” and the amount of the qualified preretirement survivor annuity under the Plan is equal to the amount of the survivor annuity payable under the “minimum-required qualified joint and survivor annuity.” For purposes of this paragraph only, the “minimum-required qualified joint and survivor annuity” is the qualified joint and survivor annuity which is the actuarial equivalent of the Participant’s accrued benefit (within the meaning of Code §411(a)(7)) and under which the survivor annuity is 50% of the amount of the annuity which is payable during the joint lives of the Participant and his Spouse.

The Committee shall temporarily prevent the Account Owner from borrowing from his Accounts and shall temporarily suspend distributions and withdrawals from his Accounts, except to the extent necessary to make the required minimum distributions under Code §401(a)(9), when the Committee has reason to believe that the Plan may be entitled to an offset of the Participant’s benefits described in this subsection. The Committee shall promulgate reasonable and non-discriminatory rules regarding such suspensions, including but not limited to how long such suspensions remain in effect

(h) Exception for Federal Liens. Subsection (a) shall 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). The Committee may temporarily suspend distributions and withdrawals from an Account, except to the extent necessary to make the required minimum distributions under Code §401(a)(9), when the Committee has reason to believe that such a federal tax levy or other obligation has or will be received. The Committee shall promulgate reasonable and non-discriminatory rules regarding such suspensions, including but not limited to how long such suspensions remain in effect.

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13.10 Payments due Minors or Incapacitated Individuals.

If any individual entitled to payment under the Plan is a minor, the Committee shall cause the payment to be made to the custodian or representative who, under the state law of the minor’s domicile, is authorized to receive funds on behalf of the minor. If any individual entitled to payment under this Plan has been legally adjudicated to be mentally incompetent or incapacitated, the Committee shall cause the payment to be made to the custodian or representative who, under the state law of the incapacitated individual’s domicile, is authorized to receive funds on behalf of the incapacitated individual. Payments made pursuant to such power shall operate as a complete discharge of the Trust Fund, the Trustee, and the Committee.

13.11 Uniformity of Application.

The provisions of this Plan shall be applied in a uniform and non-discriminatory manner in accordance with rules adopted by the Committee, which rules shall be systematically followed and consistently applied so that all individuals similarly situated shall be treated alike.

13.12 Disposition of Unclaimed Payments.

Each Participant, Alternate Payee, or beneficiary with an Account balance in this Plan must file with the Committee from time to time in writing his address, the address of each beneficiary (if applicable), and each change of address. Any communication, statement, or notice addressed to such individual at the last address filed with the Committee (or if no address is filed with the Committee then at the last address as shown on the Company’s records) will be binding on such individual for all purposes of the Plan. Neither the Committee nor the Trustee shall be required to search for or locate any missing individual. If the Committee notifies an individual that he is entitled to a distribution and also notifies him that a failure to respond may result in a forfeiture of benefits, and the individual fails to claim his benefits under the Plan or make his address known to the Committee within a reasonable period of time after the notification, then the benefits under the Plan of such individual shall be forfeited. Any amount forfeited pursuant to this section shall be allocated pursuant to subsection 5.4(d). If the individual should later make a claim for this forfeited amount, the Company shall, if the Plan is still in existence, make a special contribution to the Plan equal to the forfeiture, and such amount shall be distributed to the individual; if the Plan is not then in existence, the Company shall pay the amount of the forfeiture to the individual.

13.13 Applicable Law.

This Plan shall be construed and regulated by ERISA, the Code, and, unless otherwise specified herein and to the extent applicable, the laws of the State of Texas excluding any conflicts-of-law provisions.

ARTICLE XIV

Matters Affecting Company Stock

14.1 Voting, Etc.

The shares of Company Stock in Accounts, whether or not vested, may be voted by the Account Owner to the same extent as if duly registered in the Account Owner’s name. The Trustee or its nominee in which the shares are registered shall vote the shares solely as agent of the Account Owner and in accordance with the instructions of the Account Owner. If no instructions are received, the Trustee shall vote the shares of Company Stock for which it has received no voting instructions in the same proportions as the Account Owners affirmatively directed their shares of Company Stock to be voted unless the Trustee determines that a pro rata vote would be inconsistent with its fiduciary duties under ERISA. If the Trustee makes such a determination, the Trustee shall vote the Company Stock as it determines to be consistent with its fiduciary duties under ERISA. Each Account Owner who has Company Stock allocated to his Accounts shall direct the Trustee concerning the tender (as provided below) and the exercise of any other rights appurtenant to the Company Stock. The Trustee shall follow the directions of the Account Owner with respect to the tender.

14.2 Notices.

Apache shall cause to be mailed or delivered to each Account Owner copies of all notices and other communications sent to the Apache shareholders at the same times so mailed or delivered by Apache to its other shareholders.

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14.3 Retention/Sale of Company Stock and Other Securities.

The Trustee is authorized and directed to retain the Company Stock and any other Apache securities acquired by the Trust except as follows:

(a) In the normal course of Plan administration, the Trustee shall sell Company Stock to satisfy Plan administration and distribution requirements as directed by the Committee or in accordance with provisions of the Plan specifically authorizing such sales.

(b) In the event of a transaction involving the Company Stock evidenced by the filing of Schedule 14D-1 with the Securities and Exchange Commission (“SEC”) or any other similar transaction by which any person or entity seeks to acquire beneficial ownership of 50% or more of the shares of Company Stock outstanding and authorized to be issued from time to time under Apache’s articles of incorporation (“tender offer”), the Trustee shall sell, convey, or transfer Company Stock pursuant to written instructions of Account Owners delivered to the Trustee in accordance with the following sections 14.4 through 14.15. For purposes of such provisions, the term “filing date” means the date relevant documents concerning a tender offer are filed with the SEC or, if such filing is not required, the date the Trustee receives actual notice that a tender offer has commenced.

(c) If Apache makes any distribution of Apache securities with respect to the shares of Company Stock held in the Plan, other than additional shares of Company Stock (any such securities are hereafter referred to as “stock rights”), the Trustee shall sell, convey, transfer, or exercise such stock rights pursuant to written instructions of Account Owners delivered to the Trustee in accordance with the following sections of this Article.

14.4 Tender Offers.

(a) Allocated Stock. In the event of any tender offer, each Account Owner shall have the right to instruct the Trustee to tender any or all shares of Company Stock, whether or not vested, that are allocated to his Accounts under the Plan on or before the filing date. The Trustee shall follow the instructions of the Account Owner. The Trustee shall not tender any Company Stock for which no instructions are received.

(b) Unallocated Stock. The Trustee shall tender all shares of Company Stock that are not allocated to Accounts in the same proportion as the Account Owners directed the tender of Company Stock allocated to their Accounts unless the Trustee determines that a pro rata tender would be inconsistent with its fiduciary duties under ERISA. If the Trustee makes such a determination, the Trustee shall tender or not tender the unallocated Company Stock as it determines to be consistent with its fiduciary duties under ERISA.

(c) Suspension of Share Purchases. In the event of a tender offer, the Trustee shall suspend all purchases of Company Stock pursuant to the Plan unless the Committee otherwise directs. Until the termination of such tender offer and pending such Committee direction, the Trustee shall invest available cash pursuant to the applicable provisions of the Plan and the Trust Agreement.

(d) Temporary Suspension of Certain Cash Distributions. Notwithstanding anything in the Plan to the contrary, no option to receive cash in lieu of Company Stock shall be honored during the pendency of a tender offer unless the Committee otherwise directs.

14.5 Stock Rights.

(a) General. If Apache makes a distribution of stock rights with respect to the Company Stock held in the Plan and if the stock rights become exercisable or transferable (the date on which the stock rights become exercisable or transferable shall be referred to as the “exercise date”), each Account Owner shall determine whether to exercise the stock rights, sell the stock rights, or hold the stock rights allocated to his Accounts. The provisions of this section shall apply to all stock rights received with respect to Company Stock held in Accounts, whether or not the Company Stock with respect to which the stock rights were issued are vested.

(b) Independent Fiduciary. The Independent Fiduciary provided for in this section 14.15 below shall act with respect to the stock rights. All Account Owner directions concerning the exercise or disposition of the stock rights shall be given to the Independent Fiduciary, who shall have the sole responsibility of assuring that the Account Owners’ directions are followed.

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(c) Exercise of Stock Rights. If, on or after the exercise date, an Account Owner wishes to exercise all or a portion of the stock rights allocated to his Accounts, the Independent Fiduciary shall follow the Account Owner’s direction to the extent that there is cash or other liquid assets available in his Accounts to exercise the stock rights. Notwithstanding any other provision of the Plan, each Account Owner who has stock rights allocated to his Accounts shall have a period of five business days following the exercise date in which he may give instructions to the Committee to liquidate any of the assets held in his Accounts (except shares of Company Stock or assets such as guaranteed investment contracts or similar investments), but only if he does not have sufficient cash or other liquid assets in his Accounts to exercise the stock rights. The liquidation of any necessary investments pursuant to an Account Owner’s direction shall be accomplished as soon as reasonably practicable, taking into account any timing restrictions with respect to the investment funds involved. The cash obtained shall be used to exercise the stock rights, as the Account Owner directs. Any cash that is not so used shall be invested in a cash equivalent until the next date on which the Account Owner may change his investment directions under the Plan.

(d) Sale of Stock Rights. On and after the exercise date, the Independent Fiduciary shall sell all or a portion of the stock rights allocated to Accounts, as the Account Owner shall direct.

14.6 Other Rights Appurtenant to the Company Stock.

If there are any rights appurtenant to the Company Stock, other than voting, tender, or stock rights, each Account Owner shall exercise or take other appropriate action concerning such rights with respect to the Company Stock, whether or not vested, that is allocated to their Accounts in the same manner as the other holders of the Company Stock, by giving written instructions to the Trustee. The Trustee shall follow all such instructions, but shall take no action with respect to allocated Company Stock for which no instructions are received. The Trustee shall exercise or take other appropriate action concerning any such rights appurtenant to unallocated Company Stock.

14.7 Information to Trustee.

Promptly after the filing date, the exercise date, or any other event that requires action with respect to the Company Stock, the Committee shall deliver or cause to be delivered to the Trustee or the Independent Fiduciary, as appropriate, a list of the names and addresses of Account Owners showing (i) the number of shares of Company Stock allocated to each Account Owner’s Accounts under the Plan, (ii) each Account Owner’s pro rata portion of any unallocated Company Stock, and (iii) each Account Owner’s share of any stock rights distributed by Apache. The Committee shall date and certify the accuracy of such information, and such information shall be updated periodically by the Committee to reflect changes in the shares of Company Stock and other assets allocated to Accounts.

14.8 Information to Account Owners.

The Trustee or the Independent Fiduciary, as appropriate, shall distribute and/or make available to each affected Account Owner the following materials:

(a) A copy of the description of the terms and conditions of any tender offer filed with the SEC on Schedule 14D-1, or any similar materials if such filing is not required, any material distributed to shareholders generally with respect to the stock rights, and any proxy statements and any other material distributed to shareholders generally with respect to any action to be taken with respect to the Company Stock.

(b) If requested by Apache, a statement from Apache’s management setting forth its position with respect to a tender offer that is filed with the SEC on Schedule 14D-9 and/or a communication from Apache given pursuant to 17 C.F.R. 240.14d-9(e), or any similar materials if such filing or communications are not required.

(c) An instruction form prepared by Apache and approved by the Trustee or the Independent Fiduciary, to be used by an Account Owner who wishes to instruct the Trustee to tender Company Stock in response to the tender offer, to instruct the Independent Fiduciary to sell or exercise stock rights, or to instruct

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the Trustee or Independent Fiduciary with respect to any other action to be taken with respect to the Company Stock. The instruction form shall state that (i) if the Account Owner fails to return an instruction form to the Trustee by the indicated deadline, the Trustee will not tender any shares of Company Stock the Account Owner is otherwise entitled to tender, (ii) the Independent Fiduciary will not sell or exercise any right allocated to the Account except upon the written direction of the Account Owner, (iii) the Trustee or Independent Fiduciary will not take any other action that the Account Owner could have directed, and (iv) Apache acknowledges and agrees to honor the confidentiality of the Account Owner’s directions to the Trustee.

(d) Such additional material or information as the Trustee or the Independent Fiduciary may consider necessary to assist the Account Owner in making an informed decision and in completing or delivering the instruction form (and any amendments thereto) to the Trustee or the Fiduciary on a timely basis.

14.9 Expenses.

The Trustee and the Independent Fiduciary shall have the right to require payment in advance by Apache and the party making the tender offer of all reasonably anticipated expenses of the Trustee and the Independent Fiduciary, respectively, in connection with the distribution of information to and the processing of instructions received from Account Owners.

14.10 Former Account Owners.

Apache shall furnish former Account Owners who have received distributions of Company Stock so recently as to not be shareholders of record with the information furnished pursuant to section 14.8. The Trustee and the Independent Fiduciary are hereby authorized to take action with respect to the Company Stock distributed to such former Account Owners in accordance with appropriate instructions from them. If the Trustee does not receive appropriate instructions, it shall take no action with respect to the distributed Company Stock.

14.11 No Recommendations.

Neither the Committee, the Committee Fiduciary, the Trustee, nor the Independent Fiduciary shall express any opinion or give any advice or recommendation to any Account Owner concerning voting the Company Stock, any tender offer, stock rights, or the exercise of any other rights appurtenant to the Company Stock, nor shall they have any authority or responsibility to do so. Neither the Trustee nor the Independent Fiduciary has any duty to monitor or police the party making a tender offer or Apache in promoting or resisting a tender offer; provided, however, that if the Trustee or the Independent Fiduciary becomes aware of activity that on its face reasonably appears to the Trustee or Independent Fiduciary to be materially false, misleading, or coercive, the Trustee or the Independent Fiduciary, as the case may be, shall promptly demand that the offending party take appropriate corrective action. If the offending party fails or refuses to take appropriate corrective action, the Trustee or the Independent Fiduciary, as the case may be, shall communicate with affected Account Owners in such manner as it deems advisable.

14.12 Trustee to Follow Instructions.

(a) So long as the Trustee and the Independent Fiduciary, as the case may be, have determined that the Plan is in compliance with ERISA §404(c), the Trustee or the Independent Fiduciary shall tender, deal with stock rights, and act with respect to any other rights appurtenant to the Company Stock, pursuant to the terms and conditions of the particular transaction or event, and in accordance with instructions received from Account Owners. Except for voting, the Trustee or the Independent Fiduciary shall take no action with respect to Company Stock, stock rights, or other appurtenant rights for which no instructions are received, and such Company Stock, stock rights, or other appurtenant rights shall be treated like all other Company Stock, stock rights, or other appurtenant rights for which no instructions are received. The Trustee, or if an Independent Fiduciary has been appointed, the Independent Fiduciary, shall vote the allocated Company Stock that an Account Owner does not vote as specified in section 14.1.

(b) If the Trustee or Independent Fiduciary determines that the Plan does not satisfy the requirements of ERISA §404(c), the Trustee or Independent Fiduciary shall follow the instructions of the Account Owner with respect to voting, tender, stock rights, or other rights appurtenant to the Company Stock unless the Trustee or Independent Fiduciary determines that to do so would be inconsistent with its fiduciary duties under ERISA. In such case, the Trustee or the Independent Fiduciary shall take such action as it determines to be consistent with its fiduciary duties under ERISA.

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14.13 Confidentiality.

(a) The Committee shall designate one of its members (the “Committee Fiduciary”) to receive investment directions and to transmit such directions to the Trustee or Independent Fiduciary, as the case may be. The Committee Fiduciary shall also receive all Account Owner instructions concerning voting, tender, stock rights, and other rights appurtenant to the Company Stock. The Committee Fiduciary shall communicate the instructions to the Trustee or the Fiduciary, as appropriate.

(b) Neither the Committee Fiduciary, the Trustee, nor the Independent Fiduciary shall reveal or release any instructions received from Account Owners concerning the Company Stock to Apache, an Affiliated Entity, or the officers, directors, employees, agents, or representatives of Apache and Affiliated Entities, except to the extent necessary to comply with Federal or state law not preempted by ERISA. If disclosure is required by Federal or state law, the information shall be disclosed to the extent possible in the aggregate rather than on an individual basis.

(c) The Committee Fiduciary shall be responsible for reviewing the confidentiality procedures from time to time to determine their adequacy. The Committee Fiduciary shall ensure that the confidentiality procedures are followed. The Committee Fiduciary shall also ensure that the Independent Fiduciary provided for in section 14.15 is appointed.

(d) Apache, with the Trustee’s cooperation, shall take such action as is necessary to maintain the confidentiality of Account records including, without limitation, establishment of security systems and procedures which restrict access to Account records and retention of an independent agent to maintain such records. If an independent recordkeeping agent is retained, such agent must agree, as a condition of its retention by Apache, not to disclose the composition of any Accounts to Apache, an Affiliated Entity or an officer, director, employee, or representative of Apache or an Affiliated Entity.

(e) Apache acknowledges and agrees to honor the confidentiality of the Account Owners’ instructions to the Committee Fiduciary, the Trustee, and the Independent Fiduciary. If Apache, by its own act or omission, breaches the confidentiality of Account Owner instructions, Apache agrees to indemnify and hold harmless the Committee Fiduciary, the Trustee, or the Independent Fiduciary, as the case may be, against and from all liabilities, claims and demands, damages, costs, and expenses, including reasonable attorneys’ fees, that the Committee Fiduciary, the Trustee, or the Independent Fiduciary may incur as a result thereof.

14.14 Investment of Proceeds.

If Company Stock or the rights are sold pursuant to the tender offer or the provisions of the rights, the proceeds of such sale shall be invested in accordance with the provisions of the Plan and the Trust Agreement.

14.15 Independent Fiduciary.

Apache shall appoint a fiduciary (the “Independent Fiduciary”) to act solely with respect to the Company Stock in situations which the Committee Fiduciary determines involve a potential for undue influence by Apache in connection with the Company Stock and the exercise of any rights appurtenant to the Company Stock. If the Committee Fiduciary so determines, it shall give written notice to the Independent Fiduciary, which shall have sole responsibility for assuring that Account Owners receive the information necessary to make informed decisions concerning the Company Stock, are free from undue influence or coercion, and that their instructions are followed to the extent proper under ERISA. The Independent Fiduciary shall act until it receives written notice to the contrary from the Committee Fiduciary.

14.16 Method of Communications.

Several provisions in this Article specify that various communications to or from an Account Owner must be in writing. The Committee, the Committee Fiduciary, the Independent Fiduciary, the Company, and the Trustee, as appropriate, shall each have full authority to treat other forms of communication, such as electronic mail or telephone voice-response, as satisfying any “written” requirement specified in this Article, but only to the extent permitted by the IRS, the Department of Labor, and the Securities Exchange Commission, as appropriate.

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ARTICLE XV

Uniformed Services Employment and Reemployment Rights Act of 1994

15.1 General.

(a) Scope. The Uniformed Services Employment and Reemployment Rights Act of 1994 (the “USERRA”), which is codified at 38 USCA §§4301-4318, confers certain rights on individuals who leave civilian employment to perform certain services in the Armed Forces, the National Guard, the commissioned corps of the Public Health Service, or in any other category designated by the President of the United States in time of war or emergency (collectively, the “Uniformed Services”). An Employee who joins the Uniformed Services shall be referred to as a “Serviceman” in this Article. This Article shall be interpreted to provide such individuals with all the benefits required by the USERRA but no greater benefits than those required by the USERRA. This Article shall supersede any contrary provisions in the remainder of the Plan.

(b) Rights of Servicemen. When a Serviceman leaves the Uniformed Services, he may have reemployment rights with the Company or Affiliated Entities, depending on many factors, including the length of his stay in the Uniformed Services and the type of discharge he received. When this Article speaks of the date a Serviceman’s potential USERRA reemployment rights expire, it means the date on which the Serviceman fails to qualify for reemployment rights (if, for example, he is dishonorably discharged, or, in general, remains in the Uniformed Services for more than 5 years) or, if the Serviceman obtains reemployment rights, the date his reemployment rights lapse because the Serviceman failed to timely exercise those rights.

15.2 While a Serviceman.

In general, a Serviceman shall be treated as an Employee while he continues to receive wages or Differential Pay from the Company or an Affiliated Entity, and once the Serviceman’s wages and Differential Pay from the Company or Affiliated Entity cease, the Serviceman shall be treated as if he were on an approved, unpaid leave of absence. For purposes of this Article, “Differential Pay” means the pay received by a Serviceman from Apache and Affiliated Entities, pursuant to their military leave policies, that is generally equal to the difference between his pay from the Armed Forces and his regular pay from Apache and Affiliated Entities before his military leave began. Differential Pay must also come within the meaning of “differential wage payment” in Code §3401(h)(2). The definition of “Compensation” in Article I shall include Differential Pay for all purposes.

(a) Participant Contributions. For purposes of making Participant Contributions under section 3.2, if the Serviceman was a Covered Employee when he became a Serviceman, he shall continue to be treated as a Covered Employee while he continues to receive wages or Differential Pay from the Company. As a consequence, (i) if he was a Covered Employee who had satisfied the requirements of Article II when he became a Serviceman, he may continue to make Participant Contributions from his wages and Differential Pay from the Company, and (ii) if he had not satisfied the requirements of section 2.1 when he became a Serviceman, his service in the Uniformed Services shall be treated as service with the Company in determining when he will be able to begin making Participant Contributions under section 2.1, and if his wages or Differential Pay from the Company continue beyond that eligibility date, the Serviceman may begin to make Participant Contributions on such date. A Serviceman may change his rate of contributions in the same manner as an Employee. A Serviceman’s Participant Contributions shall cease when his wages and Differential Pay from the Company cease.

(b) Company Contributions. Wages and Differential Pay paid by the Company to a Serviceman shall be included in his Compensation as if the Serviceman were an Employee. A Serviceman’s Participant Contributions shall be matched according to the formula in paragraph 3.1(b)(i). If the Employee was a Covered Employee when he became a Serviceman and his wages or Differential Pay continue through the last business day of a Plan Year, then (i) the Serviceman shall be treated as an “eligible Participant” under subsection 3.1(a) for that Plan Year (and shall therefore receive an allocation of any Company Discretionary Contribution); (ii) the Serviceman shall be treated as an “eligible Participant” under

Page 47 of 51 Prepared May 13, 2013

paragraph 3.1(b)(ii) for that Plan Year (and shall therefore receive an allocation of any additional match provided under such paragraph); (iii) if he was a Non-Highly Compensated Employee when he became a Serviceman, he shall be eligible to receive an allocation of any QNECs and QMACs provided under subsections 3.7(c) and 3.8(c); and (iv) he shall be treated as an Employee under subsection 12.4(a) (and, if he is a Non-Key Employee, he shall therefore receive any minimum required allocation if the Plan is top-heavy).

(c) Investments. If the Serviceman has an account balance in the Plan, he is an Account Owner and may therefore direct the investment of his Accounts pursuant to section 9.3 and Article XIV.

(d) Loans. For purposes of borrowing from the Plan under Article VII, a Serviceman shall be treated as an Employee until the day on which his potential USERRA reemployment rights expire. If a Serviceman with an outstanding loan continues to receive wages or Differential Pay from the Company or an Affiliated Entity after joining the Uniformed Services, his loan payments shall continue to be deducted from those wages and Differential Pay. Once the Serviceman’s wages and Differential Pay cease, his loan payments shall be suspended until the earlier of (i) his reemployment with the Company or an Affiliated Entity or (ii) the day on which his potential USERRA reemployment rights expire. The Serviceman may repay all or part of his loan at any time during the suspension. During the payment suspension, interest shall accrue on the unpaid balance of the loan. See subsections 15.3(b) and 15.4(c) for the resumption of loan payments for a reemployed Serviceman, and subsection 15.3(a) for the timing of the loan’s default if the Serviceman is not reemployed.

(e) Distributions and Withdrawals. For purposes of Article VI (relating to distributions and in-service withdrawals), the Serviceman shall be treated as an Employee until the day on which his potential USERRA reemployment rights expire, with one exception. The Serviceman shall be treated as having had a severance from employment on the date he became a Serviceman with respect to any benefits accrued from his Differential Pay; however, if the Serviceman takes such a distribution, his Participant Contributions [and any deemed Participant Contributions under subsection (h)] shall cease for six months from the date of the distribution. See section 15.3 once his potential USERRA rights expire.

(f) QDROs. QDROs shall be processed while the Participant is a Serviceman. The Committee has the discretion to establish special procedures under subsection 13.9(e) for Servicemen, by, for example, extending the usual deadlines to accommodate any practical difficulties encountered by the Serviceman that are attributable to his service in the Uniformed Services.

(g) Rollovers. If the Serviceman was a Covered Employee when he became a Serviceman, the Serviceman may make Rollover Contributions pursuant to subsection 3.2(d) until the day on which his potential USERRA reemployment rights expire.

(h) Death or Disability. If a Serviceman dies or becomes disabled while he is a Serviceman, his Account shall be fully vested. In addition, the Serviceman will be treated as if he had returned to active employment and then died or became disabled, with the result that he will receive the make-up contributions under subsections 15.4(e), 15.4(f), and 15.4(g), and to the extent those are based on his Participant Contributions, he shall be also treated as if he had continued making Participant Contributions from his Deemed Compensation at the average rate he actually made Participant Contributions during the 12 months (or, if less his actual length of service with Apache and Affiliated Entities) immediately before he became a Serviceman.

15.3 Expiration of USERRA Reemployment Rights.

(a) Consequences. If a Serviceman is not reemployed before his potential USERRA reemployment rights expire, the Committee shall determine his Termination From Service Date by treating his service in the Uniformed Services as an approved leave of absence but treating the expiration of his potential USERRA reemployment rights as the failure to timely return from his leave of absence, with the consequence that his Termination From Service Date will generally be the date his potential USERRA rights expired. Once his Termination From Service Date has been determined, the Committee shall determine his vested percentage. For purposes of Article VI (relating to distributions), the day the Serviceman’s potential USERRA reemployment rights expired shall be treated as the day of his Termination from Service. For purposes of subsection 5.4(b) (relating to the timing of forfeitures), the Serviceman’s last day of employment shall be the day his potential USERRA reemployment rights

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expired. If the Serviceman has an outstanding loan from this Plan when his potential USERRA reemployment rights expire, his loan shall go into default on the last day of the calendar quarter after the calendar quarter in which his potential USERRA reemployment rights expired, unless, before the loan goes into default, he repays the loan or is rehired pursuant to subsection (b).

(b) Rehire after Expiration of Reemployment Rights. If the Company or an Affiliated Company hires a former Serviceman after his potential USERRA reemployment rights have expired, he shall be treated like any other former employee who is rehired. If he had an outstanding loan and is reemployed before the loan goes into default pursuant to subsection (a), his loan payments shall be recalculated and the Company or Affiliated Entity shall immediately resume withholding the revised loan payments from his pay. The term of the loan when payments resume shall be equal to the remaining term of the loan when payments were suspended.

15.4 Return From Uniformed Service.

This section applies solely to a Serviceman who returns to employment with the Company or an Affiliated Entity because he exercised his reemployment rights under the USERRA.

(a) Credit for Service. A Serviceman’s length of time in the Uniformed Services shall be treated as service with the Company for purposes of vesting and determining his eligibility to participate in the Plan upon reemployment.

(b) Participation. If the Serviceman satisfies the eligibility requirements of section 2.1 before his reemployment, and he is a Covered Employee upon his reemployment, he may participate in the Plan immediately upon his return.

(c) Loans. If the Serviceman’s loan payments were suspended under subsection 15.2(d) during his time in the Uniformed Services, his loan payments shall be recalculated and the Company or Affiliated Entity shall immediately resume withholding the revised loan payments from his pay. The term of the loan when payments resume shall be equal to the remaining term of the loan when payments were suspended.

(d) Make-Up Participant Contributions. In addition to his regular Participant Contributions, a returning Serviceman shall be permitted to make additional contributions up to the amount of Participant Contributions he could have made if, instead of becoming a Serviceman, he had remained employed by the Company or Affiliated Entity and been paid his Deemed Compensation during that time. See subsection (h) for guidance on applying the various limits contained in the Code to the calculation of the maximum additional contribution the returning Serviceman may make. Such additional contributions may only be made within a period that begins on his reemployment date and whose duration is the lesser of five years or three times his length of time in the Uniformed Services. The additional contributions shall be withheld from his Compensation pursuant to the Serviceman’s election. The Committee shall establish administrative procedures for such elections. The additional contributions shall be allocated to Participant Contributions Accounts or Roth Contributions Accounts, as applicable.

(e) Make-Up Match. For each additional contribution that the Serviceman contributes pursuant to subsection (d), the Company shall promptly contribute to his Accounts an additional matching contribution. The additional matching contribution shall be equal to the Company Matching Contribution (including forfeitures treated as Company Matching Contributions) that he would have received if (i) his additional contributions were Participant Contributions made during his time in the Uniformed Services, and (ii) he was paid his Deemed Compensation during his time in the Uniformed Services. The Serviceman’s additional contributions shall be spread over the pay periods in which they could have occurred in such a way as to maximize the additional matching contribution. See subsection (h) for guidance on applying the various limits contained in the Code to the calculation of the additional matching contribution. The additional matching contribution shall be allocated to the Participant’s Company Contributions Account unless the additional matching contribution would have been designated a QMAC, in which case it shall be allocated to his Participant Contributions Account.

(f) Make-Up Company Discretionary Contribution. The Company shall contribute an additional contribution to a Serviceman’s Accounts equal to the Company Discretionary Contribution (including

Page 49 of 51 Prepared May 13, 2013

any forfeitures treated as Company Discretionary Contributions) that would have been allocated to such Accounts if the Serviceman had remained employed during his time in the Uniformed Services, and had earned his Deemed Compensation during that time. See subsection (h) for guidance on applying the various limits contained in the Code to the calculation of the additional discretionary contribution. The additional discretionary contribution shall be allocated to the Participant’s Company Contributions Account unless the additional discretionary contribution would have been designated a QNEC, in which case it shall be allocated to his Participant Contributions Account.

(g) Make-Up Miscellaneous Contributions. The Company shall contribute to the Serviceman’s Accounts any QNECs and QMACs that the Serviceman would have received pursuant to subsection 3.7(c) or 3.8(c), and any top-heavy minimum contribution he would have received pursuant to section 12.4, (including any forfeitures treated as QNECs, QMACs, or top-heavy minimum contributions) if he had remained employed during his time in the Uniformed Services, and had earned Deemed Compensation during that time. See subsection (h) for guidance on applying the various limits contained in the Code to the calculation of the QNECs, QMACs, and top-heavy minimum contribution. These additional top-heavy minimum contributions shall be allocated to Company Contributions Accounts. The additional QNECs and QMACs shall be allocated to Participant Contributions Accounts.

(h) Application of Limitations.

(i) The make-up contributions under subsections (d), (e), (f), and (g) (the “Make-Up Contributions”) shall be ignored for purposes of determining the Company’s maximum contribution under subsection 3.1(d), the limits on Participant Contributions under paragraphs 3.2(a)(ii) and 3.2(b)(ii), the limits on Annual Additions under section 3.4, the ADP test of section 3.5, the ACP test of section 3.6, the non-discrimination requirements of Code §401(a)(4), and (if the Serviceman is a Key Employee) calculating the minimum required top-heavy contribution under section 12.4.

(ii) In order to determine the maximum Make-Up Contributions, the following limitations shall apply.

(A) The Serviceman’s “Aggregate Compensation” for each year shall be calculated. His Aggregate Compensation shall be equal to his actual Compensation, plus his Deemed Compensation that would have been paid during that year. Each type of Aggregate Compensation (for benefit purposes, deferral purposes, etc.) shall be determined separately.

(B) The Serviceman’s Aggregate Compensation each Plan Year shall be limited to the dollar limit in effect for that Plan Year under Code §401(a)(17), for the purposes and in the manner specified in subsection 1.14(f).

(C) The limits of subsection 3.1(d) (relating to the maximum contribution by the Company to the Plan) for each Plan Year shall be calculated by using the Serviceman’s Aggregate Compensation for that Plan Year, and by treating the Make-Up Contributions that are attributable to that Plan Year’s Deemed Compensation as having been made during that Plan Year.

(D) The limits of paragraph 3.2(a)(ii) (relating to the maximum 401(k) Contributions) and paragraph 3.2(b)(ii) (relating to the maximum Catch-Up Contributions) for each calendar year shall be calculated by treating as 401(k) and Catch-Up Contributions his additional contributions pursuant to subsection (d) that are attributable to that calendar year’s Deemed Compensation.

(E) The limits of section 3.4 (relating to the maximum Annual Additions to a Participant’s Accounts) shall be calculated for each Limitation Year by using the Serviceman’s Aggregate Compensation for that Limitation Year, and by treating as Annual Additions all the Make-Up Contributions that are attributable to that Limitation Year’s Deemed Compensation.

(F) The Serviceman’s maximum Make-Up Contributions shall not be limited by the results of the Plan’s ADP test or ACP test for any Plan Year in which the Serviceman has Deemed Compensation, even if the Serviceman is treated as a Highly Compensated Employee (using his Aggregate Compensation) for that Plan Year.

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(i) Deemed Compensation. A Serviceman’s Deemed Compensation is the Compensation that he would have received (including raises) had he remained employed by the Company or Affiliated Entity during his time in the Uniformed Services, unless it is not reasonably certain what his Compensation would have been, in which case his Deemed Compensation shall be based on his average rate of compensation during the 12 months (or, if shorter, his period of employment with the Company and Affiliated Entities) immediately before he entered the Uniformed Services. A Serviceman’s Deemed Compensation shall be reduced by any Compensation actually paid to him during his time in the Uniformed Services (such as vacation pay, wages, and Differential Pay). Deemed Compensation shall cease when the Serviceman’s potential USERRA reemployment rights expire. Each type of Deemed Compensation (for benefit purposes, deferral purposes, etc.) shall be determined separately.

		APACHE CORPORATION
Date: May 14, 2013	By:	/s/ Margery M. Harris
	Title:	Executive VP, Human Resources

Page 51 of 51 Prepared May 13, 2013

APPENDIX A

Participating Companies

The following Affiliated Entities were actively participating in the Plan as of the following dates:

Business	Participation Began As Of	Participation Ended As Of
Apache International, Inc.	September 22, 1987	N/A
Apache Energy Resources Corporation (known as Hadson Energy Resources Corporation before January 1, 1995)	January 1, 1994	December 31, 1995
Apache Canada Ltd.	May 17, 1995	N/A
Apache Deepwater LLC	November 10, 2010	N/A

— END OF APPENDIX A —

A-1 Prepared May 13, 2013

APPENDIX B

Hadson Energy Resources Corporation

Introduction

Apache acquired Hadson Energy Resources Corporation (“HERC”) as of November 12, 1993. HERC and its wholly owned subsidiary, Hadson Energy Limited (“HEL”), maintained the Hadson Energy Resources Corporation Employee 401(k) Plan (the “HERC Plan”), a profit sharing plan containing a cash or deferred arrangement. The HERC Plan was terminated as of December 31, 1993, and amounts were transferred from the HERC Plan to this Plan.

The transferred amounts that are subject to the distribution restrictions of Code §401(k) shall be placed in the Participant Contributions Accounts. Any remaining transferred amounts that represent after-tax contributions, rollovers, or the associated investment earnings shall be placed in the Rollover Account. All remaining transferred amounts shall be placed in the Company Contributions Account.

— END OF APPENDIX B —

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APPENDIX C

Corporate Transactions

Over the years, Apache and its Affiliated Entities have engaged in numerous corporate transactions, both acquisitions and sales. This Appendix contains any special provisions that apply to employees affected by the corporate transaction, including both those who become Employees and those who cease to be Employees.

Sales

For an Employee who transferred to Natural Gas Clearinghouse (“NGC”) pursuant to the terms of the Employee Benefits Agreement effective April 1, 1990 between Apache and NGC, a Period of Service shall be calculated by treating as employment with Apache any period(s) of employment after April 1, 1990 with NGC or any business that is then treated as a single employer with NGC pursuant to Code §414(b), §414(c), §414(m), or §414(o).

Employees terminated in connection with the summer 1995 sale of certain properties to Citation 1994 Investment Limited Partnership are fully vested in their Plan Accounts as of September 1, 1995.

An Employee who transferred to Producers Energy Marketing LLC (“ProEnergy”) in the first half of 1996 is fully vested in his Plan Accounts as of the date of transfer. If such an individual becomes an Employee again, all new contributions to his Plan Accounts shall vest according to the regular rules.

Acquisitions

A Period of Service for vesting purposes for a New Employee (listed below) shall be determined by treating all periods of employment with the Former Employer Controlled Group as periods of employment with Apache. The “Former Employer Controlled Group” means the Former Employer (listed below), its predecessor company/ies, and any business while such business was treated as a single employer with the Former Employer or predecessor company pursuant to Code §414(b), §414(c), §414(m), or §414(o).

[Remainder of Page Intentionally Left Blank]

C-1 Prepared May 13, 2013

The following individuals are “New Employees” and the following companies are “Former Employers”:

Former Employer	New Employees
Amoco Production Company (“Amoco”)	All individuals who became an Employee of the Company pursuant to the provisions of the Stock Purchase Agreement effective June 30, 1991, between Amoco Production Company, Apache, and others.
Hadson Energy Resources Corporation (“HERC”) and Hadson Energy Limited (“HEL”)	All individuals employed by HERC or HEL on November 12, 1993.
Crystal Oil Company (“Crystal”)	All individuals hired from Crystal or related companies within a week of the closing date on an asset purchase that was originally scheduled to close on December 31, 1994.
Texaco Exploration & Production, Inc. (“TEPI”)	All individuals hired from TEPI or related companies in late February and early March 1995 in connection with an acquisition of assets from TEPI at that time.
DEKALB Energy Company (“DEKALB”)	All individuals who became an employee of Apache on or after May 17, 1995 — their Period of Service shall include any periods of employment with DEKALB before May 17, 1995
The Phoenix Resource Companies, Inc. (“Phoenix”)	All individuals hired by Apache in 1996 who were Phoenix employees on May 20, 1996.
Crescendo Resources, L.P. (“Crescendo”)	All individuals hired from April 30, 2000 through June 1, 2000 from Crescendo and related companies in connection with an April 30, 2000 asset acquisition from Crescendo.
Collins & Ware (“C&W”) and Longhorn Disposal, Inc. (“Longhorn”)	All individuals hired from C&W and Longhorn and related companies in connection with a May 23, 2000 asset acquisition from C&W and Longhorn.
Occidental Petroleum Corporation (“Oxy”)	All individuals hired from Oxy and related companies in connection with an August 2000 asset acquisition from an Oxy subsidiary.
Private company (“Private”)	All individuals hired in January 2003 from Private and related companies in connection with an asset acquisition of certain property in Louisiana effective as of December 1, 2002.
Devon Energy Corporation (“Devon”)	All individuals hired on June 10, 2010 from Devon and related companies in connection with Apache’s acquisition of certain property on such date.

C-2 Prepared May 13, 2013

Mariner Energy, Inc. (“Mariner”)	All individuals who became Covered Employees on the date of the merger between Apache and Mariner are New Employees. The amount of a New Employee’s pre-Apache service with Mariner shall be equal to his service credited under the Mariner Energy, Inc. Employee Capital Accumulation Plan (or the service that would have been credited under such plan if the New Employee had been a participant in it). A New Employee shall be eligible to make Participant Contributions from Compensation paid after the date of the merger. See Appendix E for additional provisions related to the merger of the Mariner Energy Inc. Employee Capital Accumulation Plan into this Plan.
BP, p.l.c. (“BP”)	The New Employees are those who were hired by Apache in connection with property acquisitions from BP during 2010.
Phoenix Exploration Company LP (“Phoenix”)	Individuals hired by Apache on September 1, 2011 from Phoenix. A New Employee shall be eligible to make Participant Contributions from Compensation paid after September 1, 2011.

—END OF APPENDIX C—

C-3 Prepared May 13, 2013

APPENDIX D

DEKALB Energy Company / Apache Canada Ltd.

Introduction

Through a merger effective as of May 17, 1995, Apache then held 100% of the stock of DEKALB Energy Company (which has been renamed Apache Canada Ltd.). Apache Canada Ltd. has adopted this Plan, and Apache has approved its adoption, as of May 17, 1995, for the eligible employees of Apache Canada Ltd.

Capitalized terms in this Appendix have the same meanings as those given to them in the Plan. The regular terms of the Plan shall apply to the employees of Apache Canada Ltd., except as provided below.

Eligibility to Participate

Notwithstanding the definition of “Covered Employee,” an employee of Apache Canada Ltd. shall be a Covered Employee only if (1) he is either a U.S. citizen or a U.S. resident, and (2) he was employed by Apache or another Company immediately before becoming an employee of Apache Canada Ltd.

Compensation

If the payroll of the Apache Canada Ltd. employee is handled in the United States, then the definitions of Compensation in section 1.14 apply. To the extent that the payroll of the Apache Canada Ltd. employee is handled outside of the United States, section 1.14 shall apply except that paragraph 1.14(a)(i) shall be replaced by:

(i) For purposes of determining the limitation on Annual Additions under section 3.4, Compensation means the items specified in the safe-harbor definition in Treasury Regulation §1.415(c)-2(d)(2).

— END OF APPENDIX D –

D-1 Prepared May 13, 2013

APPENDIX E

Mariner Energy, Inc.

Introduction

Through a merger effective as of November 10, 2010 (the “Closing Date”), Apache acquired Mariner Energy, Inc., (“Mariner”) which sponsored the Mariner Energy, Inc. Employee Capital Accumulation Plan (“Mariner’s 401(k) Plan”). Mariner’s 401(k) Plan is merged into this Plan as of November 16, 2010. This Appendix describes the special rules that apply to amounts transferred from Mariner’s 401(k) Plan to this Plan, and also describes how the match is calculated for 2010 in this Plan.

Capitalized terms in this Appendix have the same meanings as those given to them in the Plan. The regular terms of the Plan shall apply, except as provided below.

Match

The Company Matching Contribution for 2010 shall be determined pursuant to section 3.2 of the Plan, based on the Participant Contributions and Compensation paid to a Covered Employee after the date of the merger, except as provided in the next sentence. If a Covered Employee’s Participant Contributions to this Plan and his contributions to Mariner’s 401(k) Plan that are subject to the limits of Code §402(g) are $16,500 or (because of catch-up contributions) more during 2010, his Company Matching Contribution for 2010 will be the greater of (a) the aggregate matching contributions he would have received in both this Plan and Mariner’s 401(k) Plan had equal salary deferrals of $16,500 in the aggregate been withheld from each regular paycheck during 2010, minus the match allocated to him for 2010 in Mariner’s 401(k) Plan, or (b) the amount described in the preceding sentence.

The Company Matching Contribution shall vest pursuant to the usual rules in Article V. See Appendix C for additional (pre-Apache) service that is taken into account for vesting purposes.

Incoming Assets

A participant in Mariner’s 401(k) Plan may have as many as seven different types of accounts in that plan. The following distribution rules apply to those incoming accounts (the “Old Mariner Accounts”).

1. Accounts.

(a) Employee Deferrals. Any Old Mariner Account that is subject to Code §401(k) shall be transferred to the Participant Contributions Account. No special distribution rules apply to such amounts.

(b) Regular Match. Matching contributions to Mariner’s 401(k) Plan and the earnings thereon shall be transferred to a separate subaccount of the Company Contributions Account in this Plan. These amounts vest 33% when his Period of Service is one year, 66% when his Period of Service is two years, and 100% when his Period of Service is three years or more. These amounts are subject to the distribution rules that apply to Company Contributions Accounts, except as noted below in section 2 below.

(c) Discretionary Company Contribution. Discretionary employer contributions to Mariner’s 401(k) Plan and the earnings thereon that were subject to a 6-year vesting schedule shall be transferred to a separate subaccount of the Company Contribution Account in this Plan that is subject to the regular 5-year vesting schedule described in Article V. The additional vesting shall apply to this subaccount on the date of the merger of the plans, even to those subaccounts of individuals who are no longer employees. This subaccount is subject to the distribution rules that apply to Company Contributions Accounts, except as noted in section 2 below.

E-1 Prepared May 13, 2013

(d) Pre-Tax Rollover Account. Pre-tax rollovers contributions to Mariner’s 401(k) Plan and the earnings thereon shall be transferred to the Rollover Account. No special distribution rules apply to such amounts.

(e) After-Tax Rollover Account. After-tax rollovers contributions to Mariner’s 401(k) Plan and the earnings thereon shall be transferred to a separate, fully vested, subaccount of the Rollover Account in this Plan. No special distribution rules apply to this subaccount.

(f) After-Tax Account. A participant’s after-tax contributions to Mariner’s 401(k) Plan and the earnings thereon shall be transferred to a separate, fully vested, subaccount of the Participant Contributions Account in this Plan. The same distribution rules that apply to the Rollover Account will apply to this subaccount.

(g) FERI Accounts. Both matching and discretionary employer contributions to a plan sponsored by Forest Oil and transferred to Mariner’s 401(k) Plan and the earnings thereon shall be transferred to separate, fully vested, subaccounts of the Company Contributions Account in this Plan. These subaccounts are subject to the distribution rules that apply to Company Contributions Accounts, except as noted in section 2 below.

2. Special Distribution Rules.

(a) Installments. Except as provided in the next sentence, in subsection 6.4(b) of the Plan (relating to in-service withdrawals, minimum required withdrawals, and installments to beneficiaries), and in subsection 13.9(f) of the Plan (relating to QDROs), all distributions shall be in the form of a lump sum of the Account Owner’s entire vested account balance in the Plan. Any Account Owner who elected installment payments from the Old Mariner Accounts before the merger of Mariner’s 401(k) Plan and this Plan shall be paid the installments in the amount and on the schedule he had elected.

(b) Hardship Withdrawals. A Participant may take an in-service hardship withdrawal that meets the requirements of paragraphs 6.5(c)(i) and 6.5(c)(ii) of the Plan from the subaccounts of the Company Contribution Account that were established in subsections 1(b), 1(c), and 1(g) of this Appendix, to the extent such subaccounts are vested.

(c) Two-Year Rule. Once the funds have actually been in either the Plan or Mariner’s 401(k) Plan for 24 months, a Participant may take an in-service withdrawal from the vested portion of the subaccounts of the Company Contribution Account that were established in subsections 1(b), 1(c), and 1(g) of this Appendix.

(d) Five-Year Rule. Once a Participant has been a Participant in this Plan and Mariner’s 401(k) Plan for 60 months, the Participant may take an in-service withdrawal from the vested portion of the subaccounts of the Company Contribution Account that were established in subsections 1(b), 1(c), and 1(g) of this Appendix.

E-2 Prepared May 13, 2013

3. Investments.

The Plan may accept an in-kind transfer of assets from Mariner’s 401(k) Plan, as determined by the Committee.

4. Loans.

Loans in Mariner’s 401(k) Plan will be transferred to the Plan. The repayment schedule of the loans may be modified to accommodate the Borrower’s new pay schedule. Participants cannot borrow from the Plan again until all prior loans have been repaid.

5. Enrollment.

Individuals who were employed by Mariner or related companies and become Covered Employees on the Closing Date will be deemed to have elected to make Participant Contributions to this Plan at the same rate that they had been making similar contributions to Mariner’s 401(k) Plan immediately before the plans’ merger. If any such individual was not contributing to Mariner’s 401(k) Plan when the plan merger occurred, he will not be automatically enrolled in the Plan, even if he was hired by Mariner as recently as one day before the plans’ merger.

6. Vesting.

If (a) the Participant was an employee of Mariner on the Closing Date, (b) his severance from employment occurs on or before June 30, 2011, (c) Apache decided to terminate the Participant or the Participant decided not to accept Apache’s offer of employment, and (d) the Participant’s termination is not for cause, then the Participant’s Old Mariner Accounts shall become fully vested upon his severance from employment.

— END OF APPENDIX E —

E-3 Prepared May 13, 2013

EX-10.17

Exhibit 10.17

APACHE CORPORATION

2011 Omnibus Equity Compensation Plan

As Amended and Restated Effective February 3, 2014

Section 1

Introduction

1.1 Establishment. Apache Corporation, a Delaware corporation (hereinafter referred to, together with its Affiliates (as defined below) as the “Company” except where the context otherwise requires), previously established the Apache Corporation 2011 Omnibus Equity Compensation Plan, effective May 5, 2011, which plan was amended and restated effective May 16, 2013, and is hereby amended and restated effective February 3, 2014 (the “Plan”), as it may be further amended and restated from time to time.

1.2 Purpose. The purpose of the Plan is to provide Eligible Persons designated by the Committee for participation in the Plan with equity-based incentives to: (i) encourage such individuals to continue in the long-term service of the Company and its Affiliates, (ii) create in such individuals a more direct interest in the future success of the operations of the Company, (iii) attract outstanding individuals, and (iv) retain and motivate such individuals. The Plan is intended to provide eligible individuals with the opportunity to invest in the Company, thereby relating incentive compensation to increases in stockholder value and more closely aligning the compensation of such individuals with the interests of the Company’s stockholders.

Accordingly, this 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, as the Committee determines is best suited to the circumstances of the particular individual as provided herein.

1.3 Effective Date. The Effective Date of the Plan (the “Effective Date”) is May 5, 2011. This Plan and each Award granted hereunder are conditioned on and shall be of no force or effect until the Plan is approved by the stockholders of the Company. The Committee (or its delegate in accordance with Section 3.4(b) hereof) may award grants, the entitlement to which shall be expressly subject to the condition that the Plan shall have been approved by the stockholders of the Company.

Section 2

Definitions

2.1 Definitions. The following terms shall have the meanings set forth below:

(a) “Administrative Agent” means any designee or agent that may be appointed by the Committee pursuant to subsections 3.1(h) and 3.4 hereof.

(b) “Affiliate” means any entity other than the Company that is affiliated with the Company through stock or equity ownership or otherwise and is designated as an Affiliate for

1

purposes of the Plan by the Committee; provided, however, that, notwithstanding any other provisions of the Plan to the contrary, for purposes of NQSOs and SARs, if an individual who otherwise qualifies as an Eligible Person provides services to such an entity and not to the Company, such entity may only be designated an Affiliate if the Company qualifies as a “service recipient,” within the meaning of Internal Revenue Code Section 409A, with respect to such individual; provided further that such definition of “service recipient” shall be determined by (a) applying Internal Revenue Code Section 1563(a)(1), (2), and (3), for purposes of determining a controlled group of corporations under Internal Revenue Code Section 414(b), using the language “at least 50 percent” instead of “at least 80 percent” each place it appears in Internal Revenue Code Section 1563(a)(1), (2), and (3), and by applying Treasury Regulations Section 1.414(c)-2, for purposes of determining trades or businesses (whether or not incorporated) that are under common control for purposes of Internal Revenue Code Section 414(c), using the language “at least 50 percent” instead of “at least 80 percent” each place it appears in Treasury Regulations Section 1.414(c)-2, and (b) where the use of Shares with respect to the grant of an Option or SAR to such an individual is based upon legitimate business criteria, by applying Internal Revenue Code Section 1563(a)(1), (2), and (3), for purposes of determining a controlled group of corporations under Internal Revenue Code Section 414(b), using the language “at least 20 percent” instead of “at least 80 percent” at each place it appears in Internal Revenue Code Section 1563(a)(1), (2), and (3), and by applying Treasury Regulations Section 1.414(c)-2, for purposes of determining trades or businesses (whether or not incorporated) that are under common control for purposes of Internal Revenue Code Section 414(c), using the language “at least 20 percent” instead of “at least 80 percent” at each place it appears in Treasury Regulations Section 1.414(c)-2; provided further that for purposes of ISOs, “Affiliate” shall mean any present or future corporation which is or would be a “subsidiary corporation” of the Company as the term is defined in Section 424(f) of the Internal Revenue Code.

(c) “Award” means any Stock Option, Stock Appreciation Right, Restricted Stock, Restricted Stock Unit, Performance Award, Dividend Equivalent or any other stock-based award granted to a Participant under the Plan.

(d) “Board” means the Board of Directors of the Company.

(e) “Change of Control” shall have the meaning assigned to such term in the Company’s Income Continuance Plan as in effect on the Effective Date.

(f) “Committee” means the Stock Option Plan Committee of the Board or such other Committee of the Board that is empowered hereunder to administer the Plan. 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 Exchange Act) and “outside directors” (as defined in Treasury Regulations Section 1.162-27 (e)(3)) and to satisfy such additional regulatory or listing requirements as the Board may determine to be applicable or appropriate.

(g) “Deferred Delivery Plan” means the Company’s Deferred Delivery Plan, as it has been or may be amended from time to time, or any successor plan.

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(h) “Dividend Equivalent” means a right, granted to an Eligible Person to receive cash, Stock, other Awards or other property equal in value to dividends paid with respect to a specified number of shares of Stock, or other periodic payments.

(i) “Eligible Persons” means those employees of the Company or of any Affiliates, members of the Board, and members of the board of directors of any Affiliates who are designated as Eligible Persons by the Committee. Notwithstanding the foregoing, grants of Incentive Stock Options may not be granted to anyone who is not an employee of the Company or an Affiliate.

(j) “Exchange Act” means the Securities Exchange Act of 1934, as amended.

(k) “Exercise Date” means the date of exercise determined in accordance with subsection 6.2(g) hereof.

(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 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; provided further, however, that, with respect to ISOs, such Fair Market Value shall be determined subject to Section 422(c)(7) of the Internal Revenue Code. For purposes of the foregoing, a valuation prepared in accordance with any of the methods set forth in Treasury Regulation Section 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 Section 1.409A-1(b)(5)(iv) and should be interpreted consistently therewith.

(m) “Incentive Stock Option” or “ISO” means any Option intended to be and designated as an incentive stock option and which satisfies the requirements of Section 422 of the Internal Revenue Code or any successor provision thereto.

(n) “Internal Revenue Code” or “Code” means the Internal Revenue Code of 1986, as it may be amended from time to time, and any successor thereto. Any reference to a section of the Internal Revenue Code or Treasury Regulation shall be treated as a reference to any successor section.

(o) “Involuntary Termination” means the termination of employment of the Participant by the Company or its successor for any reason on or after a Change of Control; provided, that the termination does not result from an act of the Participant that (i) constitutes common-law fraud, a felony, or a gross malfeasance of duty, or (ii) is materially detrimental to the best interests of the Company or its successor.

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(p) “Non-Qualified Stock Option” or “NQSO” means any Option that is not intended to qualify as an “incentive stock option” under Section 422 of the Internal Revenue Code.

(q) “Option” means an option to purchase a number of shares of Stock granted pursuant to subsection 6.1.

(r) “Option Price” means the price at which shares of Stock subject to an option may be purchased, determined in accordance with subsection 6.2(b) hereof.

(s) “Participant” means an Eligible Person designated by the Committee, from time to time during the term of the Plan to receive one or more Awards under the Plan.

(t) “Performance Award” is a right to either a number of shares of Stock or SARs (“Performance Shares”) determined (in either case) in accordance with subsection 9.1 of this Plan based on the extent to which the applicable Performance Goals are achieved. A Performance Share shall be of no value to a Participant unless and until earned in accordance with subsection 9.2 hereof.

(u) “Performance Goals” are the performance conditions, if any, established pursuant to subsection 9.1 by the Committee in connection with an Award.

(v) “Performance Period” with respect to a Performance Award is a period not less than one calendar year or one fiscal year of the Company, beginning not earlier than the year in which such Performance Award is granted, which may be referred to herein and by the Committee by use of the calendar of fiscal year in which a particular Performance Period commences.

(w) “Restricted Stock” means Stock granted to an Eligible Person under Section 8 hereof, that is subject to certain restrictions and to a risk of forfeiture.

(x) “Restricted Stock Unit” means a right, granted to an Eligible Person under Section 8 hereof, to receive Stock, cash or a combination thereof at the end of a specified vesting period.

(y) “Restriction Period” shall have the meaning assigned to such term in subsection 8.1.

(z) “Stock” means the $0.625 par value common stock of the Company and or any security into which such common stock is converted or exchanged upon merger, consolidation, or any capital restructuring (within the meaning of Section 13) of the Company.

(aa) “Stock Appreciation Right” or “SAR” means a right granted to an Eligible Person to receive an amount in cash, Stock, or other property equal to the excess of the Fair Market Value as of the Exercise Date of one share of Stock over the SAR Price times the number of shares of Stock to which the Stock Appreciation Right relates. Stock Appreciation Rights may be granted in tandem with Options or other Awards or may be freestanding.

(bb) “SAR Price” means the price at which the Stock Appreciation Right was granted, which shall be determined in the same manner as the Option Price of an Option in accordance with subsection 6.2 hereof.

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(cc) “Voluntary Termination with Cause” occurs upon a Participant’s separation from service of his own volition and one or more of the following conditions occurs without the Participant’s consent on or after a Change of Control:

(i) There is a material diminution in the Participant’s base compensation, compared to his rate of base compensation on the date of the Change of Control.

(ii) There is a material diminution in the Participant’s authority, duties or responsibilities.

(iii) There is a material diminution in the authority, duties or responsibilities of the Participant’s supervisor, such as a requirement that the Participant (or his supervisor) report to a corporate officer or employee instead of reporting directly to the board of directors.

(iv) There is a material diminution in the budget over which the Participant retains authority.

(v) There is a material change in the geographic location at which the Participant must perform his service, including, for example the assignment of the Participant to a regular workplace that is more than 50 miles from his regular workplace on the date of the Change of Control.

The Participant must notify the Company of the existence of one or more adverse conditions specified in clauses (i) through (v) above within 90 days of the initial existence of the adverse condition. The notice must be provided in writing to Apache Corporation’s Senior Vice President, Human Resources or his/her delegate. The notice may be provided by personal delivery or it may be sent by email, inter-office mail, regular mail (whether or not certified), fax, or any similar method. Apache Corporation’s Senior Vice President, Human Resources or his/her delegate shall acknowledge receipt of the notice within 5 business days; the acknowledgement shall be sent to the Participant by certified mail. Notwithstanding the foregoing provisions of this definition, if the Company remedies the adverse condition within 30 days of being notified of the adverse condition, no Voluntary Termination with Cause shall occur.

2.2 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.

Section 3

Plan Administration

3.1 Administration by the Committee. The Plan shall be administered by the Committee. In accordance with the provisions of the Plan, the Committee shall, in its sole discretion, adopt rules and regulations for carrying out the purposes of the Plan, including, without limitation, the authority to:

(a) Grant Awards;

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(b) Select the Eligible Persons and the time or times at which Awards shall be granted;

(c) Determine the type and number of Awards to be granted, the number of shares of Stock to which an Award may relate and the terms, conditions, restrictions, and Performance Goals relating to any Award;

(d) Determine whether, to what extent, and under what circumstances an Award may be settled, canceled, forfeited, exchanged, or surrendered;

(e) Construe and interpret the Plan and any Award;

(f) Prescribe, amend, and rescind rules and procedures relating to the Plan;

(g) Determine the terms and provisions of Award agreements;

(h) Appoint designees or agents (who need not be members of the Committee or employees of the Company) to assist the Committee with the administration of the Plan;

(i) Communicate the material terms of each Award to its recipient within a relatively short period of time after approval; and

(j) Make all other determinations deemed necessary or advisable for the administration of the Plan.

3.2 Committee Discretion. The Committee shall, in its absolute discretion, and without amendment to the Plan, have the power to accelerate, waive or modify, at any time, any term or condition of an Award that is not mandatory under this Plan; provided, however, that the Committee shall not have any discretion to accelerate, waive or modify any term or condition of an Award that is intended to qualify as “performance-based compensation” for purposes of Section 162(m) of the Internal Revenue Code if such discretion would cause the Award to not so qualify. In the event of a Change of Control, the provisions of Section 12 hereof shall be mandatory and shall govern the vesting and exercisability schedule of any Award granted hereunder.

3.3 Indemnification. No member of the Committee shall be liable for any action, omission, or determination made in good faith. The Company shall indemnify (to the extent permitted under Delaware law) and hold harmless each member of the Committee and each other director or employee of the Company to whom any duty or power relating to the administration or interpretation of the Plan has been delegated against any cost or expense (including counsel fees) or liability (including any sum paid in settlement of a claim with the approval of the Committee) arising out of any action, omission or determination relating to the Plan, unless, in either case, such action, omission or determination was taken or made by such member, director or employee in bad faith and without reasonable belief that it was in the best interests of the Company. The determination, interpretations and other actions of the Committee pursuant to the provisions of the Plan shall be binding and conclusive for all purposes and on all persons.

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3.4 Committee Delegation.

(a) The Committee may from time to time adopt such rules and regulations for carrying out the purposes of the Plan as it may deem proper and in the best interests of the Company. The Committee may appoint an Administrative 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 correct any defect, supply any omission or reconcile any inconsistency in the Plan, or in any Award agreement entered into hereunder, in the manner and to the extent it shall deem expedient, and it shall be the sole and final judge of such inconsistency;

(b) The Committee has delegated authority to the Chief Executive Officer of the Company to grant Awards to employees of the Company who are not the Company’s executive officers (as such term is defined for purposes of Section 16 of the Exchange Act) and who are below the level of Regional Vice President or Staff Vice President; provided, that any such Awards may only be granted in accordance with guidelines established by the Committee.

3.5 Compliance with Section 162(m). Except as expressly otherwise stated in any resolution of the Committee, the Plan is intended to comply with the requirements of Section 162(m) or any successor section(s) of the Internal Revenue Code (“Section 162(m)”) as to any “covered employee” as defined in Section 162(m), and shall be administered, interpreted, and construed consistently therewith. The Committee is authorized to take such additional action, if any, that may be required to ensure that the Plan and any Award under the Plan satisfy the requirements of Section 162(m), taking into account any regulations or other guidance issued by the Internal Revenue Service.

Section 4

Stock Subject to the Plan

4.1 Number of Shares. Subject to adjustments pursuant to Section 4.4 hereof, up to (a) 25,500,000 shares of Stock are authorized for issuance under the Plan plus (b) effective May 16, 2013, 17,000,000 additional shares of Stock are authorized for issuance under the Plan in accordance with the Plan’s terms and subject to such restrictions or other provisions as the Committee may from time to time deem necessary. Notwithstanding the foregoing, the number of aggregate shares of Stock available for issuance under the Plan at any given time shall be reduced by (i) 1.0 share for each share of Stock granted in the form of Stock Options or Stock Appreciation Rights, or (ii) 2.39 shares for each share of Stock granted in the form of any Award that is not a Stock Option or Stock Appreciation Right. During the duration of the Plan, no Eligible Person may be granted Options which in the aggregate cover in excess of 5 percent of the total shares of Stock authorized under the Plan. No Award may be granted under the Plan on or after the 10-year anniversary of the Effective Date. The foregoing to the contrary notwithstanding, within the aggregate limit described in the first sentence of this Section 4.1, up to 25,500,000 (effective May 16, 2013, up to 42,500,000) shares of Stock may be issued pursuant to ISOs granted under the Plan.

4.2 Availability of Shares Not Issued under Awards. If shares of Stock which may be issued pursuant to the terms of the Plan awarded hereunder are forfeited, cancelled, exchanged or surrendered or if an Award otherwise terminates or expires without a distribution of shares to the holder of such

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Award, the shares of Stock with respect to such Award shall, to the extent of any such forfeiture, cancellation, exchange, surrender, termination or expiration, again be available for Awards under the Plan; provided, however, that in such case, the number of shares of Stock that may be issued under the Plan shall increase by 1.0 share for each share related to a Stock Option or a Stock Appreciation Right that is so forfeited, cancelled, exchanged or surrendered or expired and by 2.39 shares for each such share which is not related to a Stock Option or a Stock Appreciation Right. The number of shares available shall not be increased by shares tendered, surrendered or withheld in connection with the exercise or settlement of an Award or the related tax withholding obligations. Furthermore, when a SAR is settled in shares, the number of shares subject to the SAR under the SAR Award agreement will be counted against the aggregate number of shares with respect to which Awards may be granted under the Plan as one share for every share subject to the SAR, regardless of the number of shares used to settle the SAR upon exercise.

4.3 Stock Offered. The Company shall at all times during the term of the Plan retain as authorized and unissued Stock and/or Stock in the Company’s treasury, at least the number of shares from time to time require under the provisions of the Plan, or otherwise assure itself of its ability to perform its obligations hereunder.

4.4 Adjustments for Stock Split, Stock Dividend, Etc. If the Company 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 rights to acquire Stock, or through a Stock split, reverse Stock split, subdivision, consolidation, combination, reclassification or recapitalization involving the Stock (any of the foregoing being herein called a “capital restructuring”), 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, in each case, equitably and proportionally adjusted to take into account the occurrence of any of the above events, (i) the number and kind of shares of Stock or other property (including cash) that may thereafter be issued pursuant to subsections 4.1 and 4.10, (ii) the number and kind of shares of Stock or other property (including cash) issued or issuable in respect of outstanding Awards; and (iii) the exercise price, grant price, or purchase price relating to any Award; provided that, with respect to Incentive Stock Options, such adjustment shall be made in accordance with Section 424(h) of the Internal Revenue Code; (iv) the Performance Goals, and (v) the individual limitations applicable to Awards.

4.5 Other Changes in Stock. In the event there shall be any change, other than as specified in subsections 4.4 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 subject to outstanding Awards or which have been reserved for issuance pursuant to the Plan but are not then subject to an Award, then such adjustments shall be made by the Committee and shall be effective for all purposes of the Plan and on each outstanding Award that involves the particular type of stock for which a change was effected.

4.6 Rights to Subscribe. If the Company 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 the Company or of any other corporation, there shall be reserved with respect to the shares then under an outstanding Award to any Participant of the particular class of Stock involved the Stock or other securities which the Participant would have been entitled to subscribe for if immediately prior to such grant the Participant had exercised his entire Option. If, upon exercise of any such Option, the Participant subscribes for the additional shares or other securities, the aggregate Option Price shall be increased by the amount of the price that is payable by the Participant for such additional shares or other securities as if the Participant had exercised his entire Option immediately prior to the grant of such additional shares or other securities.

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4.7 General Adjustment Rules. No adjustment or substitution provided for in this Section 4 shall require the Company to sell a fractional share of Stock under any Option, or otherwise issue a fractional share of Stock, and the total substitution or adjustment with respect to each Option shall be limited by deleting any fractional share. In the case of any such substitution or adjustment, the aggregate Option Price for the shares of Stock then subject to the Option shall remain unchanged but the Option Price per share under each such Option shall be equitably adjusted by the Committee to reflect the greater or lesser number of shares of Stock or other securities into which the Stock subject to the Option may have been changed.

4.8 Determination by the Committee, Etc. Adjustments under this Section 4 shall be made by the Committee, whose determinations with regard thereto shall be final and binding upon all parties.

4.9 Code Section 409A. For any Award that is not subject to Internal Revenue Code Section 409A before the adjustments identified in the preceding sections of this Section 4, no adjustment shall be made that would cause the Award to become subject to Internal Revenue Code Section 409A. For an Award that is subject to Internal Revenue Code Section 409A before the adjustments identified in the preceding sections of this Section 4, no adjustment shall cause the Award to violate Internal Revenue Code Section 409A, without the prior written consent of both the Participant and the Committee.

4.10 Award Limits. The following limits shall apply to grants of all Awards under the Plan:

(a) Options: The maximum aggregate number of shares of Stock that may be subject to Options granted in any calendar year to any one Participant shall be 250,000 shares.

(b) SARs: The maximum aggregate number of shares that may be subject to Stock Appreciation Rights granted in any calendar year to any one Participant shall be 250,000 shares. Any shares covered by Options which include tandem SARs granted to one Participant in any calendar year shall reduce this limit on the number of shares subject to SARs that can be granted to such Participant in such calendar year.

(c) Restricted Stock or Restricted Stock Units: The maximum aggregate number of shares of Stock that may be subject to Awards of Restricted Stock or Restricted Stock Units granted in any calendar year to any one Participant shall be 250,000 shares.

(d) Performance Awards: The maximum aggregate grant with respect to Performance Awards granted in any calendar year to any one Participant shall be 250,000 shares (or SARs based on the value of such number of shares).

To the extent required by Section 162(m) of the Code, shares subject to Options or SARs which are canceled shall continue to be counted against the limits set forth in paragraphs (a) and (b) immediately preceding.

4.11 Repayment/Forfeiture of Awards. If required by the Sarbanes-Oxley Act of 2002 and/or by the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010, each Participant’s Award shall be conditioned on repayment or forfeiture in accordance with applicable law and the related Award agreement shall reflect any such condition. In addition, the Committee may establish such conditions for repayment or forfeiture of Awards as the Committee may adopt by policy for the Company or any Affiliate.

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Section 5

Granting of Awards to Participants

5.1 Participation. Participants in the Plan shall be those Eligible Persons who, in the judgment of the Committee (or, pursuant to Section 3.4(b), the Chief Executive Officer of the Company), are performing, or during the term of their incentive arrangement will perform, vital services in the management, operation, and development of the Company or an Affiliate, and significantly contribute, or are expected to significantly contribute, to the achievement of the Company’s long-term corporate economic objectives. Participants may be granted from time to time one or more Awards; provided, however, that the grant of each such Award shall be separately approved by the Committee or granted in accordance with Section 3.4(b) hereof, and receipt of one such Award shall not result in automatic receipt of any other Award. Upon determination that an Award is to be granted to a Participant, as soon as practicable, written notice shall be given to such person, specifying the terms, conditions, rights and duties related thereto. Each Participant shall, if required by the Committee, enter into an agreement with the Company, in such form as the Committee shall determine and which is consistent with the provisions of the Plan, specifying such terms, conditions, rights, and duties. Awards shall be deemed to be granted as of the date specified in the grant resolution of the Committee (or, in the case of grants made pursuant to Section 3.4(b), in accordance with the guidelines established by the Committee), which date shall be the date of any related agreement with the Participant. In the event of any inconsistency between the provisions of the Plan and any such agreement entered into hereunder, the provisions of the Plan shall govern.

Awards granted to members of the Board shall be recommended to the full Board by the Management Development and Compensation Committee and approved by the full Board.

5.2 Notification to Participants and Delivery of Documents. As soon as practicable after such determinations have been made, each Participant shall be notified of (a) his/her designation as a Participant, (b) the date of grant, (c) the number and type of Awards granted to the Participant, (d) in the case of Performance Awards, the Performance Period and Performance Goals, (e) in the case of Restricted Stock or Restricted Stock Units, the Restriction Period (as defined in subsection 8.1), and (f) any other terms or conditions imposed by the Committee with respect to the Award.

5.3 Delivery of Award Agreement. This requirement for delivery of a written Award agreement is satisfied by electronic delivery of such agreement provided that evidence of the Participant’s receipt of such electronic delivery is available to the Company and such delivery is not prohibited by applicable laws and regulations.

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Section 6

Stock Options

6.1 Grant of Stock Options. Coincident with or following designation for participation in the Plan, an Eligible Person may be granted one or more Options. Grants of Options under the Plan shall be made by the Committee or in accordance with Section 3.4(b). In no event shall the exercise of one Option affect the right to exercise any other Option or affect the number of shares of Stock for which any other Option may be exercised, except as provided in subsection 6.2(j) hereof.

6.2 Stock Option Agreements. Each Option granted under the Plan shall be identified as either an Incentive Stock Option or a Non-Qualified Stock Option (or, if no such identification is made, then it shall be a Non-Qualified Stock Option) and evidenced by a written agreement which shall be entered into by the Company and the Participant to whom the Option is granted, and which shall contain the following terms and conditions set out in this subsection 6.2, as well as such other terms and conditions, not inconsistent therewith, as the Committee may consider appropriate.

(a) Number of Shares. Each Stock Option agreement shall state that it covers a specified number of shares of Stock, as determined by the Committee.

(b) Price. The price at which each share of Stock covered by an Option may be purchased, the Option Price, shall be determined in each case by the Committee and set forth in the Stock Option agreement. The price may vary according to a formula specified in the Stock Option agreement, but in no event shall the Option Price ever be less than the Fair Market Value of the Stock on the date the Option is granted.

(c) No Backdating. There shall be no backdating of Options, and each Option shall be dated the actual date that the Committee adopts the resolution awarding the grant of such Option.

(d) Limitations on Incentive Stock Options. No Incentive Stock Option may be granted to an individual if, at the time of the proposed grant, such individual owns (or is attributed to own by virtue of the Internal Revenue Code) Stock possessing more than 10 percent of the total combined voting power of all classes of stock of the Company or any Affiliate unless (i) the exercise price of such Incentive Stock Option is at least 110 percent of the Fair Market Value of a share of Stock at the time such Incentive Stock Option is granted and (ii) such Incentive Stock Option is not exercisable after the expiration of five years from the date such Incentive Stock Option is granted.

To the extent that the aggregate Fair Market Value of Stock of the Company with respect to which Incentive Stock Options are exercisable for the first time by a Participant during any calendar year under the Plan and any other option plan of the Company (or any Affiliate) shall exceed $100,000, such Options shall be treated as Non-Qualified Stock Options. Such Fair Market Value shall be determined as of the date on which each such Incentive Stock Option is granted.

(e) Duration of Options. Each Stock Option agreement shall state the period of time, determined by the Committee, within which the Option may be exercised by the Participant (the “Option Period”). The Option Period must end, in all cases, not more than ten years from the date an Option is granted.

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(f) Termination of Options. During the lifetime of a Participant to whom a Stock Option is granted, the Stock Option may be exercised only by such Participant or, in the case of disability (as determined pursuant to the Company’s Long-Term Disability Plan or any successor plan) by the Participant’s designated legal representative, except to the extent such exercise would cause any Award intended to qualify as an ISO not to so qualify. Once a Participant to whom a Stock Option was granted dies, the Stock Option may be exercised only by the personal representative of the Participant’s estate or, with respect to Stock Options that are not Incentive Stock Options, as otherwise provided in Section 14.2. Unless the Stock Option agreement shall specify a longer or shorter period, at the discretion of the Committee, then the Participant (or representative, or, if applicable pursuant to Section 14.2, designated beneficiary) may exercise the Stock Option for a period of up to three months after such Participant terminates employment or ceases to be a member of the Board.

(g) Exercise, Payments, Etc.

(i) Each Stock Option agreement shall provide that the method for exercising the Option granted therein shall be by delivery to the Office of the Secretary of the Company or to the Administrative Agent of written notice specifying the number of shares of Stock with respect to which such Option is exercised and payment to the Company of the aggregate Option Price. Such notice shall be in a form satisfactory to the Committee and shall specify the particular Options (or portions thereof) which are being exercised and the number of shares of Stock with respect to which the Options are being exercised. The Participant’s obligation to deliver written notice of exercise is satisfied by electronic delivery of such notice through means satisfactory to the Committee and prescribed by the Company. The exercise of the Option shall be deemed effective on the date such notice is received by the Office of the Secretary or by the Administrative Agent and payment is made to the Company of the aggregate Option Price (the “Exercise Date”); however, if payment of the aggregate Option Price is made pursuant to a sale of shares of Stock as contemplated by subsection 6.2(g)(iv)(E) below, the Exercise Date shall be deemed to be the date of such sale. If requested by the Company, such notice shall contain the Participant’s representation that he or she is purchasing the Stock for investment purposes only and his or her agreement not to sell any Stock so purchased in any manner that is in violation of the Exchange Act or any applicable state law, and such restriction, or notice thereof, shall be placed on the certificates representing the Stock so purchased. The purchase of such Stock shall take place upon delivery of such notice to the Office of the Secretary of the Company or to the Administrative Agent, at which time the aggregate Option Price shall be paid in full to the Company by any of the methods or any combination of the methods set forth in subsection 6.2(g)(iv) below.

(ii) The shares of Stock to which the Participant is entitled as a result of the exercise of the Option shall be issued by the Company and either (A) delivered by electronic means to an account designated by the Participant or (B) delivered to the Participant in the form of a properly executed certificate or certificates representing such shares of Stock. If shares of Stock are used to pay all or part of the aggregate Option Price, the Company shall issue and deliver to the Participant the additional shares of Stock, in excess of the aggregate Option Price or portion thereof paid using shares of Stock, to which the Participant is entitled as a result of the Option exercise.

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(iii) The Company’s obligation to deliver the shares of Stock to which the Participant is entitled as a result of the exercise of the Option shall be subject to the payment in full to the Company of the aggregate Option Price and the required tax withholding.

(iv) The aggregate Option Price shall be paid by any of the following methods or any combination of the following methods:

(A) in cash, including the wire transfer of funds in U.S. dollars to one of the Company’s bank accounts located in the United States, with such bank account to be designated from time to time by the Company;

(B) by personal, certified or cashier’s check payable in U.S. dollars to the order of the Company;

(C) by delivery to the Company or the Administrative Agent of certificates representing a number of shares of Stock then owned by the Participant, the aggregate Fair Market Value of which (as of the Exercise Date) is equal to the aggregate Option Price of the Option being exercised, properly endorsed for transfer to the Company, provided that the shares of Stock used for this purpose must have been owned by the Participant for a period of at least six months;

(D) by certification or attestation to the Company or the Administrative Agent of the Participant’s ownership (as of the Exercise Date) of a number of shares of Stock, the aggregate Fair Market Value of which (as of the Exercise Date) is not greater than the aggregate Option Price of the Option being exercised, provided that the shares of Stock used for this purpose have been owned by the Participant for a period of at least six months; or

(E) by delivery to the Company or the Administrative Agent of a properly executed notice of exercise together with irrevocable instructions to a broker to promptly deliver to the Company, by wire transfer or check as noted in subsection 6.2(g)(iv)(A) and (B) above, the amount of the proceeds of the sale of all or a portion of the Stock or of a loan from the broker to the Participant necessary to pay the aggregate Option Price.

(h) Tax Withholding. Each Stock Option agreement shall provide that, upon exercise of the Option, the Participant shall make appropriate arrangements with the Company to provide for not less than the minimum amount of tax withholding required by law, including without limitation Sections 3102 and 3402 or any successor section(s) of the Internal Revenue Code and applicable state and local income and other tax laws, by payment of such taxes in cash (including wire transfer), by check, or as provided in Section 11 hereof.

(i) Repricing Prohibited. Subject to Sections 4, 6, 12, 13, and 16, outstanding Stock Options granted under this Plan shall not be repriced without approval by the Company’s stockholders. In particular, neither the Board nor the Committee may take any action: (1) to amend the terms of an outstanding Option or SAR to reduce the Option Price or grant price thereof, cancel an Option or SAR and replace it with a new Option or SAR with a lower Option Price or grant price, or take any other action (whether in the form of an amendment, cancellation or replacement grant, or a cash-out of underwater options) that has an economic effect that is the same as any such reduction or cancellation or (2) to

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cancel an outstanding Option or SAR having an Option Price or grant price above the then-current Fair Market Value of the Stock in exchange for the grant of another type of Award, without, in each such case, first obtaining approval of the stockholders of the Company of such action.

(j) Stockholder Privileges. No Participant shall have any rights as a stockholder with respect to any shares of Stock covered by an Option until the Participant becomes the holder of record of such Stock. Except as provided in Section 4 hereof, no adjustments shall be made for dividends or other distributions or other rights as to which there is a record date preceding the date on which such Participant becomes the holder of record of such Stock.

(k) Section 409A Avoidance. Once granted, no Stock Option shall be modified, extended, or renewed in any way that would cause the Stock Option to be subject to Internal Revenue Code Section 409A. The Option Period shall not be extended to any date that would cause the Stock Option to become subject to Internal Revenue Code Section 409A. The Option Price shall not be adjusted to reflect any dividends declared and paid on the Stock between the date of grant and the date the Stock Option is exercised.

Section 7

7.1 Stock Appreciation Rights. The Committee (or, if so provided pursuant to Section 3.4(b), the Chief Executive Officer of the Company) is authorized to grant SARs to Participants either alone (“freestanding”) or in tandem with other Awards, including Performance Awards, Options, and Restricted Stock. Stock Appreciation Rights granted in tandem with any Award must be granted at the same time as the Award is granted. Stock Appreciation Rights granted in tandem with Options shall terminate and no longer be exercisable upon the termination or exercise of the related Stock Options. Options granted in tandem with Stock Appreciation Rights shall terminate and no longer be exercisable upon the termination or exercise of the related Stock Appreciation Rights. The Committee shall establish the terms and conditions applicable to any Stock Appreciation Rights, which terms and conditions need not be uniform but may not be inconsistent with the terms of the Plan. Freestanding Stock Appreciation Rights shall generally be subject to terms and conditions substantially similar to those described in Section 4 and subsection 6.2 for Options, including, but not limited to, the requirements of subsections 6.2(b), (d), and (i) and subsection 4.7 regarding general adjustment rules, minimum price, duration, and prohibition on repricing.

7.2 Section 409A Avoidance. The SAR Price may be fixed on the date it is granted or the SAR Price may vary according to an objective formula specified by the Committee at the time of grant. However, the SAR Price can never be less than the Fair Market Value of the Stock on the date of grant. The SAR grant must specify the number of shares to which it applies, which must be fixed at the date of grant (subject to adjustment pursuant to Sections 4, 6, and 11). Once granted, no SAR shall be modified, extended, or renewed in any way that would cause the SAR to be subject to Internal Revenue Code Section 409A. The period during which the SAR may be exercised shall not be extended to any date that would cause the SAR to become subject to Internal Revenue Code Section 409A. The value of the SAR shall not be adjusted to reflect any dividends declared and paid on the Stock between the date of grant and the date the SAR is exercised; however, the right to one or more dividends declared and paid on the Stock between the date of grant and the date the SAR is exercised may be set forth in a separate arrangement.

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Section 8

Restricted Stock and Restricted Stock Units

8.1 Restriction Period. At the time an Award of Restricted Stock or Restricted Stock Units is made, the Committee shall establish the terms and conditions applicable to such Award, including the period of time (the “Restriction Period”) and attainment of performance goals during which certain restrictions established by the Committee shall apply to the Award. Awards of Restricted Stock or Restricted Stock Units may also be made in accordance with Section 3.4(b). Each such Award, and designated portions of the same Award, may have a different Restriction Period. Except as permitted or pursuant to Sections 12 and 13 hereof, the Restriction Period applicable to a particular Award shall not be changed. Restricted Stock or Restricted Stock Units may or may not be subject to Internal Revenue Code Section 409A. If they are subject to Internal Revenue Code Section 409A, the grant of the Restricted Stock or Restricted Stock Units must contain the provisions needed to comply with the requirements of Internal Revenue Code Section 409A, including but not limited to (i) the timing of any election to defer receipt of the Restricted Stock or Restricted Stock Units beyond the date of vesting, (ii) the timing of any payout election, and (iii) the timing of the settlement of Restricted Stock or a Restricted Stock Unit. Restricted Stock or Restricted Stock Units that are subject to Internal Revenue Code Section 409A may be adjusted to reflect any dividends declared and paid on the Stock between the date of grant and the date the Restricted Stock or Restricted Stock Unit vests, but only to the extent permitted in IRS guidance of general applicability.

8.2 Certificates for Stock. Restricted Stock shall be evidenced in such manner as the Committee shall determine. If certificates representing Restricted Stock are registered in the name of the Participant, the Committee may require that such certificates bear an appropriate legend referring to the terms, conditions, and restrictions applicable to such Restricted Stock, that the Company retain physical possession of the certificates, and that the Participant deliver a stock power to the Company, endorsed in blank, relating to the Restricted Stock represented by a stock certificate registered in the name of the Participant.

8.3 Restricted Stock Terms and Conditions. Participants shall have the right to enjoy all shareholder rights during the Restriction Period except that:

(a) The Participant shall not be entitled to delivery of the Stock certificate until the Restriction Period shall have expired.

(b) The Participant may not sell, transfer, pledge, exchange, hypothecate, or otherwise dispose of the Stock during the Restriction Period.

(c) A breach of the terms and conditions established by the Committee with respect to the Restricted Stock shall cause a forfeiture of the Restricted Stock and any dividends withheld thereon.

(d) Dividends and Splits. As a condition to the grant of an Award of Restricted Stock, the Committee may specify whether any cash dividends paid on a share of Restricted Stock be automatically reinvested in additional shares of Restricted Stock or applied to the purchase of additional Awards under this Plan. Unless otherwise determined by the Committee, Stock distributed in connection with a Stock split or Stock dividend, and other property distributed as a dividend, shall be subject to restrictions and a risk of forfeiture to the same extent as the Restricted Stock with respect to which such Stock or other property has been distributed.

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8.4 Restricted Stock Units. The Committee (or, if so provided pursuant to Section 3.4(b), the Chief Executive Officer of the Company) is authorized to grant Restricted Stock Units to Participants, which are rights to receive Stock at the end of a specified deferral period, subject to the following terms and conditions:

Award and Restrictions. Settlement of an Award of Restricted Stock Units shall occur upon expiration of the vesting period specified for such Restricted Stock Unit by the Committee (or, if permitted by the Committee, as elected by the Participant pursuant to Section 8.5). In addition, Restricted Stock Units shall be subject to such restrictions (which may include a risk of forfeiture) as the Committee may impose, if any, which restrictions may lapse at the expiration of the vesting or deferral period, as the case may be, or at earlier specified times (including based on achievement of performance goals and/or future service requirements), separately or in combination, in installments or otherwise, as the Committee may determine. Restricted Stock Units shall be satisfied by the delivery of cash or Stock in the amount equal to the Fair Market Value of the specified number of shares of Stock covered by the Restricted Stock Units, or a combination thereof, as determined by the Committee at the date of grant or thereafter.

8.5 Deferral of Receipt of Restricted Stock Units. With the consent of the Committee, a Participant who has been granted a Restricted Stock Unit may by compliance with the then applicable procedures under the Plan irrevocably elect in writing to defer receipt of all or any part of any distribution associated with that Restricted Stock Unit Award in accordance with either the terms and conditions of the Deferred Delivery Plan or the terms and conditions specified under the grant agreement and related documents. The terms and conditions of any such deferral, including, but not limited to, the period of time for, and form of, election; the manner and method of payout; and the use and form of Dividend Equivalents in respect of stock-based units resulting from such deferral, shall be as determined by the Committee. The Committee may, at any time and from time to time, but prospectively only except as hereinafter provided, amend, modify, change, suspend, or cancel any and all of the rights, procedures, mechanics, and timing parameters relating to such deferrals. In addition, the Committee may, in its sole discretion, accelerate the pay out of such deferrals (and any earnings thereon), or any portion thereof, either in a lump sum or in a series of payments, but only to the extent that the payment or the change in timing of the payment will not cause a violation of Internal Revenue Code Section 409A.

8.6 Bonus Stock and Awards in Lieu of Obligations. The Committee is authorized to grant Stock as a bonus, or to grant Stock or other Awards in lieu of obligations to pay cash or deliver other property under this Plan or under plans or compensatory arrangements, provided that, in the case of Participants subject to Section 16 of the Exchange Act, the amount of such grants remains within the discretion of the Committee to the extent necessary to ensure that acquisitions of Stock or other Awards are exempt from liability under Section 16(b) of the Exchange Act. Stock or Awards granted hereunder shall be subject to such other terms as shall be determined by the Committee. In the case of any grant of Stock to an officer of the Company or an Affiliate in lieu of salary or other cash compensation, the number of shares granted in place of such compensation shall be reasonable, as determined by the Committee.

8.7 Dividend Equivalents. The Committee is authorized to grant Dividend Equivalents to a Participant, entitling the Participant to receive cash, Stock, other Awards, or other property equal in value to dividends paid with respect to a specified number of shares of Stock, or other periodic payments. Dividend Equivalents may be awarded on a free-standing basis or in connection with another

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Award. The Committee may provide that Dividend Equivalents shall be paid or distributed when accrued or shall be deemed to have been reinvested in additional Stock, Awards, or other investment vehicles, and subject to risk of forfeiture, as the Committee may specify. Notwithstanding the foregoing, Dividend Equivalents shall not be granted in connection with the grant of any Options or Stock Appreciation Right.

Section 9

Performance Awards

9.1 Establishment of Performance Goals for Company. Performance Goals applicable to a Performance Award shall be established by the Committee in its absolute discretion on or before the date of grant and within the time period prescribed by, and shall otherwise comply with the requirements of, Code Section 162(m)(4)(C), or any successor provision thereto, and the regulations thereunder, for performance-based compensation. Such Performance Goals may include or be based upon any of the following criteria, either in absolute amount, per share, or per barrel of oil equivalent (boe): pretax income or after tax income, operating profit, return on equity, capital or investment, earnings, book value, increase in cash flow return, sales or revenues, operating expenses (including, but not limited to, lease operating expenses, severance taxes and other production taxes, gathering and transportation, general and administrative costs, and other components of operating expenses), stock price appreciation, implementation or completion of critical projects or processes, production growth, reserve growth, and/or corporate acquisition goals based on value of assets acquired or similar objective measures.

Where applicable, the Performance Goals may be expressed in terms of attaining a specified level of a particular criteria or attaining a percentage increase or decrease in a particular criteria, and may be applied relative to internal goals or levels attained in prior years or related to other companies or indices or as ratios expressing relationship between Performance Goals, or any combination thereof, as determined by the Committee.

The Performance Goals may include a threshold level of performance below which no vesting will occur, levels of performance at which specified vesting will occur, and a maximum level of performance at which full vesting will occur.

The Committee may in its discretion classify Participants into as many groups as it determines, and as to any Participant relate his/her Performance Goals partially, or entirely, to the measured performance, either absolutely or relatively, of an identified subsidiary, division, operating company, test strategy, or new venture of the Company and/or its Affiliates.

Notwithstanding any other provision of the Plan, payment or vesting of any Performance Award shall not be made until the applicable Performance Goals have been satisfied and any other material terms of such Award were in fact satisfied. The Committee shall certify in writing the attainment of each Performance Goal. Notwithstanding any provision of the Plan to the contrary, with respect to any Performance Award, (a) the Committee may not adjust, downwards or upwards, any amount payable, or other benefits granted, issued, retained, and/or vested pursuant to such an Award on account of satisfaction of the applicable Performance Goals and (b) the Committee may not waive the achievement of the applicable Performance Goals, except in the case of the Participant’s death or disability, or a Change of Control.

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9.2 Levels of Performance Required to Earn Performance Awards. At or about the same time that Performance Goals are established for a specific period, the Committee shall in its absolute discretion establish the percentage of the Performance Awards granted for such Performance Period which shall be earned by the Participant for various levels of performance measured in relation to achievement of Performance Goals for such Performance Period.

9.3 Other Restrictions. The Committee shall determine the terms and conditions applicable to any Performance Award, which may include restrictions on the delivery of Stock payable in connection with the Performance Award and restrictions that could result in the future forfeiture of all or part of any Stock earned. The Committee may provide that shares of Stock issued in connection with a Performance Award be held in escrow and/or legended. Performance Awards may or may not be subject to Internal Revenue Code Section 409A. If a Performance Award is subject to Internal Revenue Code Section 409A, the Performance Award grant agreement shall contain the terms and conditions needed to comply with the requirements of Internal Revenue Code Section 409A, including but not limited to (i) the timing of any election to defer receipt of the Performance Award, (ii) the timing of any payout election, and (iii) the timing of the actual payment of the Performance Award. Performance Awards that are subject to Internal Revenue Code Section 409A may be adjusted to reflect any dividends declared and paid on the Stock between the date of grant and the date the Performance Award is paid, but only to the extent permitted in IRS guidance of general applicability.

9.4 Notification to Participants. Promptly after the Committee has established the Performance Goals with respect to a Performance Award, the Participant shall be provided with written notice of the Performance Goals so established.

9.5 Measurement of Performance against Performance Goals. The Committee shall, as soon as practicable after the close of a Performance Period, determine (a) the extent to which the Performance Goals for such Performance Period have been achieved and (b) the percentage of the Performance Awards earned as a result.

These determinations shall be absolute and final as to the facts and conclusions therein made and be binding on all parties. Promptly after the Committee has made the foregoing determination, each Participant who has earned Performance Awards shall be notified. For all purposes of this Plan, notice shall be deemed to have been given the date action is taken by the Committee making the determination. Participants may not sell, transfer, pledge, exchange, hypothecate, or otherwise dispose of all or any portion of their Performance Awards during the Performance Period.

9.6 Treatment of Performance Awards Earned. Upon the Committee’s determination that a percentage of any Performance Award has been earned for a Performance Period, Participants to whom such earned Performance Awards have been granted and who have been in the employ of the Company or Affiliates continuously from the date of grant until the end of the Performance Period, subject to the exceptions set forth in the Performance Award agreement and in Sections 10 and 12 hereof, shall be entitled, subject to the other conditions of this Plan, to payment in accordance with the terms and conditions of the Performance Awards. Performance Awards shall under no circumstances become earned or have any value whatsoever for any Participant who is not in the employ of the Company or its Affiliates continuously during the entire Performance Period for which such Performance Award was granted, except as provided in Sections 10 and 12.

9.7 Subsequent Performance Award Grants. Following the grant of Performance Awards with respect to a Performance Period, additional Participants may be designated by the Committee for grant

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of Performance Awards for such Performance Period subject to the same terms and conditions set forth for the initial grants, except that the Committee, in its sole discretion, may reduce the value of the amounts to which subsequent Participants may become entitled, prorated according to reduced time spent during the Performance Period, and the applicable Performance Award agreement shall be modified to reflect such reduction.

9.8 Stockholder Privileges. No Participant shall have any rights as a stockholder with respect to any shares of Stock covered by a Performance Award until the Participant becomes the holder of record of such Stock.

Section 10

Termination of Employment, Death, Disability, etc.

10.1 Termination of Employment. Except as provided herein, the treatment of an Award upon a termination of employment or any other service relationship by and between a Participant and the Company or an Affiliate shall be specified in the agreement controlling such Award. To the extent such Award is subject to Section 409A of the Code, such termination of employment or any other service relationship shall be a “separation from service” within the meaning of Treasury Regulation Section 1.409A-1(h) with respect to any Award intended to comply with Section 409A of the Internal Revenue Code; provided, that a “separation from service” shall occur only if both the Company and the Participant expect the Participant’s level of services to permanently drop by more than half.

10.2 Termination for Cause. If the employment of the Participant by the Company is terminated for cause, as determined by the Committee, all Awards to such Participant shall thereafter be void for all purposes. As used in subsections 9.1, 10.2, and 10.3 hereof, “cause” shall mean a gross violation, as determined by the Committee, of the Company’s established policies and procedures, provided that the effect of this subsection 10.2 shall be limited to determining the consequences of a termination and that nothing in this subsection 10.2 shall restrict or otherwise interfere with the Company’s discretion with respect to the termination of any employee.

10.3 Performance Awards. Except as set forth below, each Performance Award shall state that each such Award shall be subject to the condition that the Participant has remained an Eligible Person from the date of grant until the applicable vesting date as follows:

(a) If the Participant voluntarily leaves the employment of the Company or an Affiliates, or if the employment of the Participant is terminated by the Company for cause or otherwise, any Performance Award to such Participant not previously vested shall thereafter be void and forfeited for all purposes.

(b) A Participant shall become vested in all Performance Awards that have met the Performance Goals within the Performance Period on the date the Participant retires from employment with the Company on or after attaining retirement age (which for all purposes of this Plan is determined to be age 65, unless otherwise designated by the Committee at the time the Award is granted), on the date the Participant dies while employed by the Company, or on the date the Participant terminates service with the Company and the Affiliates due to permanent disability (as determined pursuant to the Company’s Long-Term Disability Plan or any successor plan, unless the Performance award is subject to

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Internal Revenue Code Section 409A, in which case “permanent disability” must also fall within the meaning specified in Internal Revenue Code Section 409A(a)(2)(C) or a more restrictive meaning established by the Committee) while employed by the Company. Such Participant shall not become entitled to any payment which may arise due to the occurrence of a Performance Goal after the Participant dies, terminates service due to permanent disability, or retires. Payment shall occur as soon as administratively convenient following the date the Participant dies, terminates service due to permanent disability, or retires, but in no event shall the payment occur later than March 15 in the calendar year immediately following the calendar year in which the Participant died, so terminates service, or retired. If the Participant dies before receiving payment, the payment shall be made to those entitled pursuant to Section 14.2 of this Plan.

10.4 Forfeiture Provisions. Subject to Sections 12 and 14, in the event a Participant terminates employment during a Restriction Period for the Participant’s Restricted Stock or Restricted Stock Units, such Awards will be forfeited; provided, however, that the Committee may provide for proration or full payout in the event of (a) death, (b) permanent disability, or (c) any other circumstances the Committee may determine.

Section 11

Tax Withholding

11.1 Withholding Requirement. The Company and any Affiliate is authorized to withhold from any Award granted, or any payment relating to an Award under this Plan, including from a distribution of Stock, amounts of withholding and other taxes or social security payments due or potentially payable in connection with any transaction involving an Award, and to take such other action as the Committee may deem advisable to enable the Company and Participants to satisfy obligations for the payment of withholding taxes and other tax or social security obligations relating to any Award. This authority shall include authority to withhold or receive Stock or other property and to make cash payments in respect thereof, in satisfaction of a Participant’s tax obligations, either on a mandatory or elective basis at the discretion of the Committee.

11.2 Withholding Requirement – Stock Options and SARs. The Company’s obligations to deliver shares of Stock upon the exercise of an Option or SAR shall be subject to the Participant’s satisfaction of all applicable federal, state, and local income and other tax and social security withholding requirements.

At the time the Committee grants an Option, it may, in its sole discretion, grant the Participant an election to pay all such amounts of required tax withholding, or any part thereof:

(a) by the delivery to the Company or the Administrative Agent of a number of shares of Stock then owned by the Participant, the aggregate Fair Market Value of which (as of the Exercise Date) is not greater than the amount required to be withheld, provided that such shares have been held by the Participant for a period of at least six months;

(b) by certification or attestation to the Company or the Administrative Agent of the Participant’s ownership (as of the Exercise Date) of a number of shares of Stock, the aggregate Fair Market Value of which (as of the Exercise Date) is not greater than the amount required to be withheld, provided that such shares of Stock have been owned by the Participant for a period of at least six months; or

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(c) by the Company or the Administrative Agent withholding from the shares of Stock otherwise issuable to the Participant upon exercise of the Option, a number of shares of Stock, the aggregate Fair Market Value of which (as of the Exercise Date) is not greater than the amount required to be withheld. Any such elections by Participants to have shares of Stock withheld for this purpose will be subject to the following restrictions:

(i) all elections shall be made on or prior to the Exercise Date; and

(ii) all elections shall be irrevocable.

11.3 Section 16 Requirements. If the Participant is an officer or director of the Company within the meaning of Section 16 or any successor section(s) of the Exchange Act (“Section 16”), the Participant must satisfy the requirements of Section 16 and any applicable rules and regulations thereunder with respect to the use of shares of Stock to satisfy such tax withholding obligation.

11.4 Restricted Stock and Performance Award Payment and Tax Withholding. Each Restricted Stock and Performance Award agreement shall provide that, upon payment of any entitlement under such an Award, the Participant shall make appropriate arrangements with the Company to provide for the amount of minimum tax and social security withholding required by law, including without limitation Sections 3102 and 3402 or any successor section(s) of the Internal Revenue Code and applicable state and local income and other tax and social security laws. The withholding may be deducted from the Award. Any payment under such an Award shall be made in a proportion of cash and shares of Stock, determined by the Committee, such that the cash portion shall be sufficient to cover the withholding amount required by this Section. The cash portion of any payment shall be based on the Fair Market Value of the shares of Stock on the applicable date of vesting to which such tax withholding relates. Such cash portion shall be withheld by the Company to satisfy applicable tax and social security withholding requirements.

Section 12

Change of Control

12.1 In General. In the event of the occurrence of a Change of Control of the Company:

(a) Without further action by the Committee or the Board,

all outstanding Options shall fully vest upon the Participant’s Involuntary Termination or Voluntary Termination with Cause occurring on or after a Change of Control. Such newly vested Options shall be fully exercisable as of the date of the Involuntary Termination or Voluntary Termination with Cause on or after a Change of Control occurs.

(b) Without further action by the Committee or the Board,

all unvested Restricted Stock Awards and Restricted Stock Units shall fully vest upon the Participant’s Involuntary Termination or Voluntary Termination with Cause occurring on or after a Change of

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Control. Such newly vested Restricted Stock Units shall be converted to Stock and the Participant shall be issued the requisite number of shares, after any withholding under Section 11, as soon as administratively practicable after the Involuntary Termination or Voluntary Termination with Cause on or after a Change of Control occurs, unless the Participant had elected to defer Restricted Stock Units to the Deferred Delivery Plan in which case the Participant’s account in the Deferred Delivery Plan shall be credited with deferred Restricted Stock Units as of the date of the Involuntary Termination or Voluntary Termination with Cause on or after the Change of Control occurs.

(c) Assuming the achievement of a Performance Goal, the entitlement to receive cash and Stock under any outstanding Performance Award grants shall vest automatically, without further action by the Committee or the Board, and shall become payable as follows:

(i) If such Change of Control occurs subsequent to the achievement of a Performance Goal, any remainder of such payout amount shall vest as of the date of the Participant’s Involuntary Termination or Voluntary Termination with Cause occurring on or after the date of such Change of Control and shall be paid by the Company to the Participant within thirty (30) days of the date of such Involuntary Termination or Voluntary Termination with Cause which occurs on or after the date of the Change of Control in the manner set out in subsection 12.1 hereof.

(ii) If the achievement of a Performance Goal occurs subsequent to the date of a Change of Control, the applicable payout amount shall vest in full for which the Performance Period has not yet ended as of the date of the Participant’s Involuntary Termination or Voluntary Termination with Cause occurring on or after such Change of Control and shall be paid by the Company to the Participant within thirty (30) days after the later of (1) the date of the Participant’s Involuntary Termination or Voluntary Termination with Cause or (2) the date that the Performance Goal is reached. The payment will occur only if the Participant is employed at the time that the Performance Goal is reached or if the Performance Goal is reached after the Participant’s Involuntary Termination or Voluntary Termination with Cause occurring on or after the Change of Control.

(d) To the extent that any Award is subject to Internal Revenue Code Section 409A, the Award shall contain appropriate provisions to comply with Internal Revenue Code Section 409A, which shall supersede the provisions of subsections (a), (b), and (c).

Section 13

Reorganization or Liquidation

In the event that the Company is merged or consolidated with another corporation and the Company 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 the Company 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, then the Committee, or the board of directors of any corporation assuming the obligations of the Company, shall, as to the Plan and outstanding Awards make appropriate provision for the adoption and continuation of the Plan by the acquiring or successor corporation and for the protection of any holders of such outstanding Awards by the substitution on an equitable basis of

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appropriate stock of the Company or of the merged, consolidated, or otherwise reorganized corporation which will be issuable with respect to the Stock. Additionally, upon the occurrence of such an event and provided that a Performance Goal has occurred, upon written notice to the Participants, the Committee may accelerate the vesting and payment dates of the entitlement to receive cash and Stock under outstanding Awards so that all such existing entitlements are paid prior to any such event. If a Performance Goal has not yet been attained, the Committee in its discretion may make equitable payment or adjustment.

In its discretion, and on such terms and conditions as it deems appropriate, the Committee may provide, either by the terms of an agreement applicable to any Award or by resolution adopted prior to the occurrence of a Change of Control or an event described in this Section 13, that any outstanding Award (or portion thereof) shall be converted into a right to receive cash, on or as soon as practicable following the closing date or expiration date of the transaction resulting in the Change of Control or such event in an amount equal to the highest value of the consideration to be received in connection with such transaction for one share of Stock, or, if higher, the highest Fair Market Value of a share of Stock during the thirty (30) consecutive business days immediately prior to the closing date or expiration date of such transaction, less the per-share Option Price or grant price of SARs, as applicable to the Award, multiplied by the number of shares subject to such Award, or the applicable portion thereof.

Section 14

Rights of Employees and Participants

14.1 Employment. Neither anything contained in the Plan or any agreement nor the granting of any Award under the Plan shall confer upon any Participant any right with respect to the continuation of his or her employment by the Company or any Affiliate, or interfere in any way with the right of the Company or any Affiliate, at any time, to terminate such employment or to increase or decrease the level of the Participant’s compensation from the level in existence at the time of the Award.

An Eligible Person who has been granted an Award in one year shall not necessarily be entitled to be granted Awards in subsequent years.

14.2 Non-transferability. Except as otherwise determined at any time by the Committee as to any Awards other than ISOs, no right or interest of any Participant in an Award granted pursuant to the Plan shall be assignable or transferable during the lifetime of the Participant, either voluntarily or involuntarily, or subjected to any lien, directly or indirectly, by operation of law, or otherwise, including execution, levy, garnishment, attachment, pledge, bankruptcy, or court order; provided that the Committee may permit further transferability of Awards other than ISOs, on a general or a specific basis, and may impose conditions and limitations on any permitted transferability, subject to any applicable Restriction Period; provided further, however, that no Award may be transferred for value or other consideration without first obtaining approval thereof by the stockholders of the Company. In the event of a Participant’s death, a Participant’s rights and interests in any Award as set forth in an Award agreement, shall be transferable by testamentary will or the laws of descent and distribution, or, with respect to Awards other than Incentive Stock Options, a beneficiary designation that is in a form approved by the Committee and in compliance with the provisions of this Plan, applicable law, and the applicable Award agreement, and payment of any entitlements due under the Plan shall be made to the Participant’s designated beneficiary, legal representatives, heirs, or legatees, as applicable. If in the opinion of the Committee a person entitled to payments or to exercise rights with respect to the Plan is

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disabled from caring for his or her affairs because of mental condition, physical condition, or age, payment due such person may be made to, and such rights shall be exercised by, such person’s guardian, conservator, or other legal personal representative upon furnishing the Committee with evidence satisfactory to the Committee of such status. If any individual entitled to payment or to exercise rights with respect to the Plan is a minor, the Committee shall cause the payment to be made to (or the right to be exercised by) the custodian or representative who, under the state law of the minor’s domicile, is authorized to act on behalf of the minor or is authorized to receive funds on behalf of the minor. With respect to those Awards, if any, that are permitted to be transferred to another individual, references in the Plan to exercise or payment related to such Awards by or to the Participant shall be deemed to include, as determined by the Committee, the Participant’s permitted transferee. A Participant’s unexercised Option or SAR, or amounts due but remaining unpaid to such Participant, at the Participant’s death, shall be exercised or paid as designated by the Participant by will or by the laws of descent and distribution, or, with respect to any unexercised Option or SAR other than an Incentive Stock Option, in accordance with the Participant’s beneficiary designation in a form approved by the Committee and in compliance with the provisions of this Plan, applicable law and the applicable Award agreement. In the event any Award is exercised by or otherwise paid to the executors, administrators, heirs or distributees of the estate of a deceased Participant, or the transferee or designated beneficiary of an Award, in any such case, pursuant to the terms and conditions of the Plan and the applicable Award agreement and in accordance with such terms and conditions as may be specified from time to time by the Committee, the Company shall be under no obligation to issue shares of Stock thereunder unless and until the Company is satisfied, as determined in the discretion of the Committee, that the person or persons exercising such Award, or to receive such payment, are the duly appointed legal representative of the deceased Participant’s estate or the proper legatees or distributees thereof, or the valid transferee or designated beneficiary of such Award, as applicable. Any purported assignment, transfer or encumbrance of an Award that does not comply with this Section 14.2 shall be void and unenforceable against the Company.

14.3 Noncompliance with Internal Revenue Code Section 409A. If an Award is subject to the requirements of Internal Revenue Code Section 409A, to the extent that the Company or an Affiliate takes any action that causes a violation of Internal Revenue Code Section 409A or fails to take reasonable actions required to comply with Internal Revenue Code Section 409A, in each case as determined by the Committee, the Company shall pay an additional amount to the Participant (or beneficiary) equal to the additional income tax imposed pursuant to Internal Revenue Code Section 409A on the Participant as a result of such violation, plus any taxes imposed on this additional payment.

Section 15

Other Employee Benefits

The amount of any income deemed to be received by a Participant as a result of the payment under an Award or exercise shall not constitute “earnings” or “compensation” with respect to which any other employee benefits of such Participant are determined, including without limitation benefits under any pension, profit sharing, life insurance, or salary continuation plan.

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Section 16

Amendment, Modification, and Termination

The Committee or the Board may at any time terminate, and from time to time may amend or modify the Plan, and the Committee or the Board may, to the extent permitted by the Plan, from time to time amend or modify the terms of any Award theretofore granted, including any Award agreement, in each case, retroactively or prospectively; provided, however, that no amendment or modification of the Plan may become effective without approval of the amendment or modification by the Company’s stockholders if stockholder approval is required to enable the Plan to satisfy an applicable statutory or regulatory requirements, unless the Company, on the advice of outside counsel, determines that stockholder approval is not necessary.

Notwithstanding any other provision of this Plan, no amendment, modification, or termination of the Plan or any Award shall adversely affect the previously accrued material rights or benefits of a Participant under any outstanding Award theretofore awarded under the Plan, without the consent of such Participant holding such Award, except to the extent necessary to avoid a violation of Internal Revenue Code Section 409A or the Board or the Committee determines, on advice of outside counsel or the Company’s independent accountants, that such amendment or modification is required for the Company, the Plan, or the Award to satisfy, comply with, or meet the requirements of any law, regulation, listing rule, or accounting standard applicable to the Company.

The Committee shall have the authority to adopt (without the necessity for further stockholder approval) 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.

Section 17

Requirements of Law

17.1 Requirements of Law. The issuance of Stock and the payment of cash pursuant to the Plan shall be subject to all applicable laws, rules, and regulations, including applicable federal and state securities laws. The Company may require a Participant, as a condition of receiving payment under an Award, to give written assurances in substance and form satisfactory to the Company and its counsel to such effect as the Company deems necessary or appropriate in order to comply with federal and applicable state securities laws.

17.2 Section 409A of the Code. It is intended that this Plan shall comply with the provisions of, or an exemption from, Internal Revenue Code Section 409A and the Treasury regulations relating thereto. Awards are intended to be exempt from Internal Revenue Code Section 409A to the extent possible. Any Award or payment that qualifies for an exemption shall be considered as the first payment(s) made under the Plan. For purposes of the limitations on nonqualified deferred compensation under Internal Revenue Code Section 409A, each payment of compensation under this Plan shall be treated as a separate payment of compensation for purposes of applying the deferral election rules and the exemption for certain short-term deferral amounts under Internal Revenue Code Section 409A. In no event may the Participant, directly or indirectly, designate the calendar year of any payment subject to Internal Revenue Code Section 409A under this Plan.

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Six-month Delay for Specified Participants. Notwithstanding any other provision of this Plan, to the extent that the right to any payment (including the provision of benefits) hereunder provides for the “deferral of compensation” within the meaning of Internal Revenue Code Section 409A(d)(1), the payment shall be paid (or provided) in accordance with the following: If the Participant is a “Specified Employee” within the meaning of Internal Revenue Code Section 409A(a)(2)(B)(i) on the date of the Participant’s Separation from Service (the “Separation Date”), and if an exemption from the six (6) month delay requirement of Internal Revenue Code Section 409A(a)(2)(B)(i) is not available, then no such payment shall be made or commence during the period beginning on the Separation Date and ending on the date that is six months following the Separation Date or, if earlier, on the date of the Participant’s death. The amount of any payment that would otherwise be paid to the Participant during this period shall instead be paid to the Participant on the first day of the first calendar month following the end of the period.

Prohibition on Acceleration. Unless a payment is exempt from Internal Revenue Code Section 409A, the date of payment may not be accelerated and any payment made pursuant to the termination and liquidation of the Plan shall not be accelerated except in compliance with Internal Revenue Code Section 409A generally and Treasury Regulation § 1.409A-3(j)(4)(ix) specifically.

17.3 Section 16 Requirements. If a Participant is an officer or director of the Company within the meaning of Section 16 of the Exchange Act, Awards granted hereunder shall be subject to all conditions required under Rule 16b-3, or any successor rule(s) promulgated under the Exchange Act, to qualify the Award for any exemption from the provisions of Section 16 available under such Rule. Such conditions are hereby incorporated herein by reference and shall be set forth in the agreement with the Participant, which describes the Award.

17.4 Governing Law. The Plan and all agreements hereunder shall be construed in accordance with and governed by the laws of the State of Texas.

Section 18

Duration of the Plan

The Plan shall terminate on the ten year anniversary of the Effective Date. No grants shall be awarded after such termination; however, the terms of the Plan shall continue to apply to all Awards outstanding when the Plan terminates.

Dated: February 3, 2014

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-10.23

Exhibit 10.23

APACHE CORPORATION

DEFERRED DELIVERY PLAN

As Amended and Restated November 11, 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 November 11, 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.

(k) “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.

(l) “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.

(m) “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.

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

(o) “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.

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

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

(r) “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.”

(s) “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.

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

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

(v) “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.

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

(x) “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. Paragraph (iv) contains special rules that apply when Stock Units vest after the Participant’s Separation from Service.

(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

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Separation from Service or as soon thereafter as is administratively convenient; subsequent 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.

(iv) Vesting After Separation from Service. An award of nonqualified deferred compensation may provide that some or all of the award may vest after the Participant Separates from Service. Typically, this occurs when a Participant retires under certain conditions specified in the award. Regardless of what payout elections were made under paragraphs, (i), (ii), or (iii), payment of that portion of an award that vests after the Participant’s Separation from Service will be made on the later of (A) the date that portion of the award vests or (B) six months after the Participant’s Separation from Service, or as soon thereafter as is administratively convenient.

(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, Disability, or Change of Control. If there is a Change of Control or the Participant dies or becomes disabled before receiving all vested Stock Units, the remaining vested Stock Units, as well as any additional Stock Units that vest because of the death, disability, Change of Control, 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 Account six months after he Separates from Service is less than $100,000, (i) 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, and (ii) he shall receive a lump sum payment of any additional amounts that vest after the Separation from Service on the later of (A) the date that additional vesting occurs or (B) six months after the Participant’s Separation from Service, or 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.

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(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 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, including any amounts that vest upon the Change of Control, 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

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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 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.

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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.

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.

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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).

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.

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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 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.

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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.

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

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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 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.

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(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 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 November 11, 2013

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

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EX-10.28

Exhibit 10.28

Apache Corporation

Non-Employee Directors’ Restricted Stock Units Program Specifications

As Amended and Restated May 15, 2013

Share Plan: 2011 Omnibus Equity Compensation Plan (the “Omnibus Plan”), the terms of which are incorporated herein by reference.

Administration: This Program will be administered by the Stock Option Plan Committee of the Company’s Board of Directors.

Eligible Participants: Members of the Company’s Board of Directors who are neither officers nor employees of the Company.

Objective: The program is designed to be administered in conjunction with the provisions of the current Non-Employee Directors’ Compensation Plan as a means to recognize the non-employee directors for services rendered through the awarding of equity compensation.

Grant Date: August 15, 2013, and annually thereafter

Grant*: Restricted Stock Units (“RSUs”) the number of which is calculated by dividing the target dollar value set by the Board of Directors from time to time by the Fair Market Value (as defined in the Omnibus Plan) of a share of Apache Common Stock on the date of grant. If the calculated number of RSUs includes a fraction, the number shall be rounded down to the nearest whole number.

Program Term: Until termination of the Omnibus Plan

Vesting: 50% - 30 days after grant

50% - 12 months after grant

Payment: Payment upon vesting shall be made, at the election of the director, either (i) 100 percent in shares of Apache Common Stock or (ii) 40 percent in cash and 60 percent in shares of Apache Common Stock. Election must be made at time of grant and will be applicable to both vestings.

Dividend Equivalents No dividend equivalents on grants made under the Program on or after July 19, 2012.

Other Events: Accelerated vesting upon death or termination without cause, including retirement.

*These grants do not result in any change to the cash retainers for board and committee service paid under the provisions of the Non-Employee Directors’ Compensation Plan.

EX-10.46

Exhibit 10.46

SCHEDULE A

Apache Corporation

2014 Performance Program

(Total Shareholder Return)

AWARD NOTICE

Recipient Name:	[Name]
Company:	Apache Corporation
Notice:	A summary of the terms of Conditional Grants of Restricted Stock Units (“RSUs”) under the 2014 Performance Program (Total Shareholder Return) is set out in this notice (the “Award Notice”) but subject always to the terms of the Apache Corporation 2011 Omnibus Equity Compensation Plan (the “Plan”) and the 2014 Performance Program Agreement (the “Agreement”). In the event of any inconsistency between the terms of this Award Notice, the terms of the Plan and the Agreement, the terms of the Plan and the Agreement shall prevail.
	Selected Eligible Persons have been awarded a conditional grant of Apache Corporation RSUs in accordance with the terms of the Plan and the Agreement.
	Details of the RSUs which you are conditionally entitled to receive is provided to you in this Award Notice and maintained on your account at netbenefits.fidelity.com
Type of Award:	A conditional award of RSUs based on a target percentage of annual base salary determined immediately prior to the beginning of the Performance Period derived from job level (the “Conditional Grant”).
Restricted Stock Unit:	A Restricted Stock Unit (“RSU”) as defined in the Plan and meaning the right granted to the Recipient of the Conditional Grant, as adjusted at the end of the Performance Period, to receive one share of Stock for each Restricted Stock Unit at the end of the specified Vesting Period.
Stock:	The $0.625 par value common stock of the Company or as otherwise defined in the Plan.
Grant:	A Conditional Grant related to                  Restricted Stock Units (Target Amount)
Grant Date:	[Date]

1

Conditions:	Subject always to the terms of the Plan and the Agreement, the Conditional Grant of RSUs shall be made as of the Grant Date. At the end of the Performance Period, the Committee shall derive and confirm the number of Conditional Grant RSUs that will actually be awarded as RSUs to the Recipient based upon measurement of total shareholder return (“TSR”) of Stock as compared to a designated Peer Group during the Performance Period, provided that the Recipient remains an Eligible Person and employed by the Company or its Affiliate as of the final day of the Performance Period. Once granted at the conclusion of the Performance Period, such RSUs shall remain subject to a vesting schedule (as set forth below) (the “Vesting Period”). Once vested, the Recipient shall be paid the value of his or her RSUs in shares of Stock (net of shares withheld for applicable tax withholdings) provided that the Recipient remains employed as an Eligible Person during the Vesting Period including the vesting date.
Performance Measure:	The performance measure for the Conditional Grant is Apache Corporation’s TSR over the Performance Period compared to the TSR of the Company’s Peer Group over the Performance Period. TSR shall be determined by dividing (i) the sum of the cumulative amount of a company’s Dividends for the Performance Period (assuming same-day reinvestment into the company’s common stock on the ex-dividend date) and the company’s End Price at the end of the Performance Period minus the Begin Price at the beginning of the Performance Period, by (ii) the Begin Price at the beginning of the Performance Period.
	Begin Price = the average per share closing price of a share or share equivalent on the applicable stock exchange for the 60 business (trading) days preceding the beginning of the Performance Period.
	End Price = the average per share closing price of a share or share equivalent on the applicable stock exchange for the last 60 business (trading) days of the Performance Period.
	Dividend = dividends paid throughout the Performance Period.
	Stock Price = the closing price for the day and will be adjusted for stock splits, spin-offs, mergers or any other corporate securities transaction affecting stock price, as determined by the Committee.
	At the end of the Performance Period, the Peer Group companies and the Company will be ranked together based on their TSR for the Performance Period from the highest TSR being number 1 to the lowest TSR being the number of Peer Group companies,

2

including the Company, remaining in the group at the end of the Performance Period. Based on the Company’s relative TSR rank amongst the Peer Group companies for the Performance Period, Recipient will be issued RSUs as determined by the Company’s percentile rank as follows:

Rank Against Peers	Multiple of Target Amount (Conditional Number of RSUs Granted)
1	2.00
2	1.80
3	1.60
4	1.40
5	1.20
6	1.00
7	0.80
8	0.60
9	0.40
10	0.00
11	0.00
12	0.00

Performance Period:	The three-year period commencing January 1, 2014 and ending December 31, 2016.
Peer Group:	For the Performance Period, the following companies shall comprise the peer group of companies (applicable ticker symbol included):

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APC	Anadarko Petroleum Corporation	MRO	Marathon Oil Corporation
CHK	Chesapeake Energy Corporation	MUR	Murphy Oil Corporation
COP	ConocoPhillips Company	NBL	Noble Energy Inc.
DVN	Devon Energy Corporation	OXY	Occidental Petroleum Corporation
EOG	EOG Resources, Inc.	PXD	Pioneer Natural Resources Co.
HES	Hess Corporation

	Should consolidation among any Peer Group companies in the marketplace occur during the Performance Period, the Committee will determine the appropriate adjustments to accommodate the reduced number of Peer Group companies for the Performance Period. Should a Change of Control of the Company occur during the Performance Period, the Committee will determine the appropriate adjustments to measure Apache Corporation’s TSR for the Performance Period. The Peer Group companies for any particular Performance Period shall be determined at the commencement of such Performance Period.
Vesting Period:	Except upon a change of control (as described below), death, or total and permanent disability (as described below), cessation of employment during the Performance Period shall result in the immediate forfeiture of the entire amount of the Conditional Grant. To the extent all or a part of a Conditional Grant RSU award is earned as of the end of the Performance Period, an award equal to the Final Amount shall be made in RSUs to the Recipient as soon as administratively practical, but not later than March 15 following the end of the Performance Period. Any such RSUs awarded shall vest in accordance with the following schedule, provided that the Recipient remains employed as an Eligible Person as of such vesting date:
	At the close of the Performance Period – 50% vested.
	12 months following the close of the Performance Period – an additional 50% vested.
	Except as described below, cessation of employment will result in the immediate forfeiture of all unvested RSUs.
	Vesting is accelerated to 100% upon the Recipient’s death or total and permanent Disability during the Performance Period or the subsequent Vesting Period. Upon death or total and permanent Disability during the Performance Period, the number of RSUs

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(and related shares of Stock) granted shall be deemed to be 1.00 times the Conditional Grant amount of RSUs (the Target Amount). Upon vesting, the applicable shares of Stock, subject to required tax withholding, shall be transferred by the Company to the Recipient (or, in the event of the Recipient’s death, to his beneficiary) within thirty (30) days of the vesting date. The Recipient can name a beneficiary on a form approved by the Committee.

Vesting is accelerated to 100% upon a Recipient’s Involuntary Termination or Voluntary Termination with Cause occurring (i) on or after a 409A Change of Control during the Vesting Period provided that the Recipient is an Eligible Person at the time of such termination and (ii) after completion of the Performance Period. Upon vesting, the applicable shares of Stock, subject to required tax withholding, shall be transferred by the Company to the Recipient within thirty (30) days of the vesting date.

In the event of the Recipient’s Involuntary Termination or Voluntary Termination with Cause which occurs (i) on or after a 409A Change of Control of the Company and (ii) on or prior to the end of the Performance Period, the Recipient will become 100% fully vested upon the occurrence of his Involuntary Termination or Voluntary Termination with Cause on or after the 409A Change of Control in the number of RSUs determined by applying the multiple under the Performance Measure determined through the date of the Recipient’s Involuntary Termination or Voluntary Termination with Cause (based upon actual TSR results as of such date) to the Target Amount. Upon vesting, the applicable shares of Stock, subject to required tax withholding, shall be transferred by the Company to the Recipient within thirty (30) days of the later of (i) the date of the Recipient’s Involuntary Termination or Voluntary Termination with Cause or (ii) the end of the Performance Period. Notwithstanding the foregoing, if the payment of the Final Amount is subject to Internal Revenue Code Section 409A, payment will not occur until the earlier of (1) the date payment would have been due if the 409A Change of Control had not occurred or (2) the date that the 409A Change of Control constitutes a “change in the ownership or effective control of the corporation, or in the ownership of a substantial portion of the assets of the corporation” within the meaning of Internal Revenue Code Section 409A(a)(2)(A)(v).

If, during the Vesting Period, and after the end of the Performance Period, the Recipient’s termination of employment from the Company and the Affiliates occurs by reason of his or her Retirement, the Recipient may be deemed to continue to be

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	employed as an Eligible Person for purposes of this Grant and may continue to vest over the Vesting Period provided that the Recipient meets the Retirement Conditions set forth in section 6 of the Agreement. In the event of a 409A Change of Control during such continued Vesting Period, vesting is accelerated to 100%.
Withholding:	The Company and the Recipient will comply with all federal and state laws and regulations respecting the required withholding, deposit and payment of any income, employment or other taxes relating to the Grant.
Acceptance	Please complete the on-line grant acceptance as promptly as possible to accept or reject your Conditional Grant. You can access this through your account at netbenefits.fidelity.com. By accepting your Conditional Grant, you will have agreed to the terms and conditions set forth in the Agreement, including, but not limited to, the non-compete and non-disparagement provisions set forth in section 6 of the Agreement, and the terms and conditions of the Plan. If you do not accept your grant you will be unable to receive your Conditional Grant or the related RSUs.

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Apache Corporation

2014 Performance Program Agreement

(Total Shareholder Return)

This 2014 Performance Program Agreement (Total Shareholder Return) (the “Agreement”) relating to a conditional grant of Restricted Stock Units (as defined in the rules of the Apache Corporation 2011 Omnibus Equity Compensation Plan (the “Plan”) (the “Conditional Grant”), dated as of the Grant Date set forth in the Notice of Award under the 2014 Performance Program (Total Shareholder Return) attached as Schedule A hereto (the “Award Notice”), is made between Apache Corporation (together with its Affiliates, the “Company”) and each Recipient. The Award Notice is included in and made part of this Agreement.

In this Agreement and each Award Notice, unless the context otherwise requires, words and expressions shall have the meanings given to them in the Plan except as herein defined.

Definitions

“409A Change of Control” means a Change of Control that constitutes, with respect to the Company, a “change in the ownership or effective control of the corporation, or in the ownership of a substantial portion of the assets of the corporation” within the meaning of Section 409A(a)(2)(A)(v) of the Internal Revenue Coe of 1986, as amended (the “Code”) and Treasury Regulations Section 1.409A-3(i)(5).

“Award Notice” means the separate notice given to each Recipient specifying the Target Amount for that individual.

“Base Salary” means, with regard to any Recipient, such Recipient’s annual base compensation as an employee of the Company determined immediately prior to the beginning of the Performance Period, without regard to any bonus, pension, profit sharing, stock option, life insurance or salary continuation plan which the Recipient either receives or is otherwise entitled to have paid on his or her behalf.

“Conditional Grant” means the conditional entitlement, evidenced by this Agreement to receive all or a portion of a Target Amount and Final Amount, subject to and in accordance with the provisions of this Agreement.

“Disability” means total and permanent disability as determined pursuant to the Company’s Group Long-Term Disability Plan or any successor.

“Fair Market Value” means the closing price of the Stock as reported on The New York Stock Exchange, Inc. Composite Transactions Reporting System (“Composite Tape”) for a particular date or, if the Stock is not so listed at any time, as reported on NASDAQ or on such other exchange or electronic trading system as, on the date in question, reports the largest number of traded shares of stock. If there are no Stock transactions on such date, the Fair Market Value shall be determined as of the immediately preceding date on which there were Stock transactions. If the foregoing provisions are not applicable, the fair market value of a share of the Stock shall be as determined by the Committee by the reasonable application of such reasonable valuation method, consistently applied, as the Committee deems appropriate.

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“Final Amount” means with regard to any Recipient, such number of shares of Restricted Stock Units (“RSUs”) as specified in each Recipient’s Award Notice, times the applicable multiple factor determined under the Performance Measure at the end of the Performance Period.

“Involuntary Termination” means the termination of employment of the Recipient by the Company or its successor for any reason on or after a 409A Change of Control; provided, that the termination does not result from an act of the Recipient that (i) constitutes common-law fraud, a felony, or a gross malfeasance of duty, or (ii) is materially detrimental to the best interests of the Company or its successor.

“Payout Amount” means the vested portion of the Final Amount expressed as shares of Stock underlying the RSUs.

“Peer Group” means the group of companies selected by the Committee for purposes of this Agreement as set forth in the Award Notice. Should consolidation among any Peer Group companies in the marketplace occur during the Performance Period, the Committee will determine the appropriate adjustments to accommodate the reduced number of Peer Group companies for the Performance Period. Should a Change of Control of the Company occur during the Performance Period, the Committee will determine the appropriate adjustments to measure Apache Corporation’s TSR for the Performance Period. The Peer Group companies for any particular Performance Period shall be determined at the commencement of such Performance Period.

“Performance Measure” means Apache Corporation’s TSR over the Performance Period compared to the TSR of the Company’s Peer Group over the Performance Period. At the end of the Performance Period, the Peer Group companies and the Company will be ranked together based on their TSR for the Performance Period from the highest TSR being number 1 to the lowest TSR being the number of Peer Group companies, including the Company, remaining in the group at the end of the Performance Period. Based on the Company’s relative TSR rank amongst the Peer Group companies for the Performance Period, a Recipient who remains employed as of the last day of the Performance Period will be issued RSUs at the close of the Performance Period as determined by the Company’s percentile rank as set forth in the Award Notice (the Final Amount).

“Performance Period” means the three-year period as specified in the Award Notice.

“Recipient” means an Eligible Person who has been designated by the Committee at the Grant Date at the beginning of the Performance Period to receive one or more Conditional Grants under the Plan. For purposes of this Agreement, the group of Eligible Persons shall include all full-time and designated part-time employees of the Company who are employed as employees of the Company (as designated by the Company for payroll purposes) on the date immediately prior to the beginning of the Performance Period, but excluding Egyptian nationals employed outside of the United States, employees categorized by the Company (for payroll purposes) as non-exempt support and field staff, leased employees, interns, or, except for employees who are members of the Hierarchical Union Neuquén and the Union of Hierarchical Personnel of Private Oil and Gas for Neuquén, Rio Negro and La Pampa, any employee of the Company who is covered under a collective bargaining agreement, unless such collective bargaining agreement specifically provides for coverage under the Plan.

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“Retirement” means, with respect to a Recipient and for purposes of this Agreement, the date the Recipient terminates employment with the Company after (i) attaining age 65 and (ii) earning at least 15 Years of Service.

“Years of Service” means the total number of months from the Recipient’s date of hire by the Company to the date of termination of employment divided by 12.

“Target Amount” means, with regard to any Recipient, such number of RSUs as specified in each Recipient’s Award Notice. Such Target Amount shall be based upon a target percentage of annual Base Salary determined immediately prior to the beginning of the Performance Period derived from job level.

“Total Shareholder Return” or “TSR” is determined by dividing (i) the sum of the cumulative amount of a company’s dividends for the Performance Period (assuming same-day reinvestment into the company’s common stock on the ex-dividend date) and the share price of the company at the end of the Performance Period minus the share price at the beginning of the Performance Period, by (ii) the share price at the beginning of the Performance Period.

“Voluntary Termination with Cause” occurs upon a Recipient’s separation from service of his own volition and one or more of the following conditions occurs without the Recipient’s consent on or after a 409A Change of Control:

(a) There is a material diminution in the Recipient’s base compensation, compared to his rate of base compensation on the date of the 409A Change of Control.

(b) There is a material diminution in the Recipient’s authority, duties or responsibilities.

(c) There is a material diminution in the authority, duties or responsibilities of the Recipient’s supervisor, such as a requirement that the Recipient (or his supervisor) report to a corporate officer or employee instead of reporting directly to the board of directors.

(d) There is a material diminution in the budget over which the Recipient retains authority.

(e) There is a material change in the geographic location at which the Recipient must perform his service, including, for example the assignment of the Recipient to a regular workplace that is more than 50 miles from his regular workplace on the date of the 409A Change of Control.

The Recipient must notify the Company of the existence of one or more adverse conditions specified in clauses (a) through (e) above within 90 days of the initial existence of the adverse condition. The notice must be provided in writing to Apache Corporation’s Executive Vice President, Human Resources or his/her delegate. The notice may be provided by personal delivery or it may be sent by email, inter-office mail, regular mail (whether or not certified), fax, or any similar method. Apache Corporation’s

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Executive Vice President, Human Resources or his/her delegate shall acknowledge receipt of the notice within 5 business days; the acknowledgement shall be sent to the Recipient by certified mail. Notwithstanding the foregoing provisions of this definition, if the Company remedies the adverse condition within 30 days of being notified of the adverse condition, no Voluntary Termination with Cause shall occur.

Terms

1. Conditional Grant of RSUs. Subject to the provisions of this Agreement and the provisions of the Plan and Award Notice, the Company shall conditionally grant to the Recipient, pursuant to the Plan, a right to receive the Target Amount of RSUs set forth in the Recipient’s Award Notice. Such Target Amount shall be adjusted to a Final Amount at the end of the Performance Period based upon the results of the Performance Measure, as determined by the Committee. Notwithstanding the foregoing, the Target Amount shall be adjusted to a Final Amount of RSUs at the conclusion of the Performance Period solely for each Recipient who remains employed as of the last day of the Performance Period. The award of the Final Amount shall give the Recipient the right, upon vesting, to an equal number of shares of $0.625 par value common stock of the Company (“Stock”).

2. Vesting and Payment of Stock. Subject to the provisions of section 3 and section 4 of this Agreement, the Payout Amounts shall be payable in increments strictly in accordance with the following schedule:

(a) The entitlement to receive the number of shares of Stock pursuant to the RSUs comprising the Final Amount shall vest fifty percent (50%) on the final date of the Performance Period provided that the Recipient remains employed as an Eligible Person on such date. Such Stock, subject to applicable withholding, shall be transferred by the Company to the Recipient within thirty (30) days of the end of the Performance Period (subject to the Committee’s confirmation) and not later than March 15 of the year following the year in which the RSUs vest.

(b) The entitlement to receive the remaining fifty percent (50%) of the shares of Stock pursuant to the RSUs comprising the Final Amount shall vest and become transferable twelve months from the close of the Performance Period, provided that the Recipient remains employed as an Eligible Person on such applicable vesting date. Such Stock, subject to applicable withholding, shall be transferred by the Company to the Recipient within thirty (30) days of the respective vesting date and not later than March 15 of the year following the year in which the RSUs vest.

3. Termination of Employment, Death, or Disability on or prior to the end of the Performance Period. Except as set forth below, a cessation of employment with the Company prior to the end of the Performance Period will result in the Target Amount being forfeited for all purposes.

(a) If the Recipient dies while employed by the Company, or on the date the Recipient becomes Disabled (as defined in this Agreement), during the Performance Period, the Recipient shall immediately receive an amount equal to the Target Amount of RSUs and shall

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become 100% vested in such Target Amount. Payment shall occur as soon as administratively convenient following the date the Recipient dies or becomes Disabled, but in no event shall the payment occur later than March 15 of the calendar year immediately following the calendar year in which the Recipient died or became Disabled. If the Recipient dies before receiving payment, the payment shall be made to the Recipient’s designated beneficiary, legal representatives, heirs, or legatees, as applicable. Each Recipient may designate a beneficiary on a form approved by the Committee.

4. Termination of Employment, Retirement, Death or Disability after the end of the Performance Period. Except as set forth below, each Conditional Grant shall be subject to the condition that the Recipient has remained an Eligible Person from the award of the Conditional Grant of RSUs until the applicable vesting date as follows:

(a) If the Recipient voluntarily leaves the employment of the Company (other than for reason of Retirement), or if the employment of the Recipient is terminated by the Company for any reason or no reason, any Final Amounts not previously vested shall thereafter be void and forfeited for all purposes.

(b) A Recipient shall become 100% fully vested in all Final Amounts on the date the Recipient dies while employed by the Company (or while continuing to vest pursuant to section 4(c) below), or on the date the Recipient becomes Disabled (as defined for purposes of this Agreement) while employed by the Company. Payment shall occur as soon as administratively convenient following the date the Recipient dies or becomes Disabled, but in no event shall the payment occur later than March 15 of the calendar year immediately following the calendar year in which the Recipient died or became Disabled. If the Recipient dies before receiving payment, the payment shall be made to the Recipient’s designated beneficiary, legal representatives, heirs, or legatees, as applicable. Each Recipient may designate a beneficiary on a form approved by the Committee.

(c) If the Recipient leaves the employment of the Company by reason of Retirement, any Final Amounts not previously vested may continue to vest following the Recipient’s termination of employment by reason of Retirement after the end of the Performance Period as if the Recipient remained an Eligible Person in the employ of the Company, provided that such Recipient shall be entitled to continue vesting only if such Recipient satisfies the Retirement Conditions set forth in section 6 below (except in the case of death).

5. Change of Control.

(a) Pursuant to Section 12.1(d) of the Plan, the following provisions of this section 5 of the Agreement shall supersede Sections 12.1(a), (b) and (c) of the Plan. Without any further action by the Committee or the Board, in the event of the Recipient’s Involuntary Termination or Voluntary Termination with Cause which occurs (i) on or after a 409A Change of Control of the Company and (ii) prior to the end of the Performance Period, the Recipient shall become 100% fully vested upon the occurrence of his Involuntary Termination or Voluntary Termination with Cause on or after the 409A Change of Control in the number of RSUs determined by applying the multiple under the Performance Measure determined through the date of the Recipient’s Involuntary Termination or Voluntary Termination with Cause (based upon actual TSR results as of such date) to the Target Amount. Subject to section 12(d) of this Agreement, payment shall occur within thirty (30) days of the later of (1) the date of the Involuntary Termination or Voluntary Termination with Cause of the Recipient following the 409A Change of Control or (2) the end of the Performance Period.

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(b) In the event of a Recipient’s Involuntary Termination or Voluntary Termination with Cause occurring on or after a 409A Change of Control of the Company which occurs after the end of the Performance Period, the Recipient shall become 100% fully vested in the Final Amount of RSUs as of the date of his Involuntary Termination or Voluntary Termination with Cause. Subject to section 12(d) of this Agreement, payment shall occur within thirty (30) days of the date of such Involuntary Termination or Voluntary Termination with Cause.

(c) In the event of a 409A Change of Control of the Company following the Recipient’s termination of employment by reason of Retirement after the end of the Performance Period while the Recipient is continuing to vest pursuant to section 4(c), the Recipient shall become 100% fully vested in the unvested Final Amount of RSUs as of the date of the 409A Change of Control. Subject to section 12(d) of this Agreement, payment shall occur within thirty (30) days of the 409A Change of Control.

6. Conditions to Post-Retirement Vesting. If the Recipient has attained age 65 and has completed at least 15 Years of Service and such Recipient terminates employment with the Company and the Affiliates by reason of Retirement, it is agreed by the Company and the Recipient that

(a) subject to the provisions of this section 6(a) and sections 6(b) and 6(c), such Recipient may continue to vest in the unvested Final Amount of RSUs following the date of his or her termination by reason of Retirement as if the Recipient continued in employment as an Eligible Person provided that the Recipient (i) is an employee of the Company or an Affiliate in good standing and not on a performance improvement plan as of such termination date; (ii) has provided not less than three (3) months’ advance written notice prior to such termination date to Apache Corporation’s Executive Vice President, Human Resources, or his or her delegate, and to his or her direct manager, regarding the Recipient’s intent to terminate employment for reason of Retirement; and (iii) cooperates with the Company in the training of a replacement during the three-month period prior to Retirement; and it is further agreed that

(b) in consideration for the continued vesting treatment afforded to the Recipient under section 6(a), Recipient shall, during the continuing Vesting Period after Retirement (the “Continued Vesting Period”) refrain from becoming employed by, or consulting with, or becoming substantially involved in the business of, any business that competes with the Company or its Affiliate in the business of exploration or production of oil or natural gas within the geographic area in which the Recipient is working or has worked for the Company or its Affiliate, and/or for which the Recipient is or was responsible, at the time of termination of employment or the immediately preceding three-year period (a “Competitive Business”); provided, that the Recipient may purchase and hold for investment purposes less than five percent (5%) of the shares of any Competitive Business whose shares are regularly traded on a national securities exchange or inter-dealer quotation system, and provided further, that the Recipient may provide services solely as a director to a Competitive Business if, during the Continued Vesting Period, the Recipient is not involved directly in the day-to-day management, supervision or operations of such Competitive Business; and it is further agreed that

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(c) in consideration for the continued vesting treatment afforded to the Recipient under section 6(a), Recipient shall, during the Continued Vesting Period, refrain from making, or causing or assisting any other person to make, any oral or written communication to any third party about the Company, any Affiliate and/or any of the employees, officers or directors of the Company or any Affiliate which impugns or attacks, or is otherwise critical of, the reputation, business or character of such entity or person; or that discloses private or confidential information about their business affairs; or that constitutes an intrusion into their seclusion or private lives; or that gives rise to unreasonable publicity about their private lives; or that places them in a false light before the public; or that constitutes a misappropriation of their name or likeness.

Notwithstanding the foregoing provisions of this section 6 of the Agreement, in the event that the Recipient fails to satisfy any of the conditions set forth in sections 6(a), (b) and (c) above, the Recipient shall not be entitled to vest in any unvested Final Amount of RSUs after the date of Retirement and the unvested Final Amount of RSUs subject to this Agreement shall be forfeited.

7. Payment and Tax Withholding. Upon receipt of any entitlement to Stock under this Agreement and, if applicable, upon the Recipient’s attainment of eligibility to terminate employment by reason of Retirement pursuant to section 4(c), the Recipient shall make appropriate arrangements with the Company to provide for the amount of minimum tax withholding required by law, including without limitation Sections 3102 and 3402 or any successor section(s) of the Internal Revenue Code and applicable state and local income and other tax laws. Upon receipt of entitlement to Stock under this Agreement, each payment of the Payout Amount shall be made in shares of Stock, determined by the Committee, such that the withheld number of shares shall be sufficient to cover the withholding amount required by this Section (including any amount to cover benefit tax charges arising thereon). The payment of a Payout Amount shall be based on the Fair Market Value of the shares of Stock on the applicable date of vesting to which such tax withholding relates. Where appropriate, shares shall be withheld by the Company to satisfy applicable tax withholding requirements rather than paid directly to the Recipient.

8. No Ownership Rights Prior to Issuance of Stock. Neither the Recipient nor any other person shall become the beneficial owner of the Stock underlying the Conditional Grant, nor have any rights of a shareholder (including, without limitation, dividend and voting rights) with respect to any such Stock, unless and until and after such Stock has been actually issued to the recipient and transferred on the books and records of the Company or its agent in accordance with the terms of the Plan and this Agreement.

9. Non-Transferability of Stock. Stock issued pursuant to a Conditional Grant shall not be transferable otherwise than by will or the laws of descent and distribution, subject to the conditions and exceptions set forth in Section 14.2 of the Plan.

10. No Right to Continued Employment. Neither the RSUs or Stock issued pursuant to a Conditional Grant nor any terms contained in this Agreement shall confer upon the Recipient any express or implied right to be retained in the employment or service of the Company for any period, nor restrict in any way the right of the Company, which right is hereby

13

expressly reserved, to terminate the Recipient’s employment or service at any time for any reason or no reason. The Recipient acknowledges and agrees that any right to receive RSUs or Stock pursuant to a Conditional Grant is earned only by continuing as an employee of the Company at the will of the Company, or satisfaction of any other applicable terms and conditions contained in the Plan and this Agreement, and not through the act of being hired, being granted the Conditional Grant, or acquiring RSUs or Stock pursuant to the Conditional Grant hereunder.

11. The Plan. In consideration for this Conditional Grant, the Recipient agrees to comply with the terms of the Plan and this Agreement. This Agreement is subject to all the terms, provisions and conditions of the Plan, which are incorporated herein by reference, and to such regulations as may from time to time be adopted by the Committee. Unless defined herein, capitalized terms are used herein as defined in the Plan. In the event of any conflict between the provisions of the Plan and this Agreement, the provisions of the Plan shall control, and this Agreement shall be deemed to be modified accordingly. The Plan and the prospectus describing the Plan can be found on the Company’s HR intranet and the Plan document can be found on Fidelity’s website (netbenefits.fidelity.com). A paper copy of the Plan and the prospectus shall be provided to the recipient upon the Recipient’s written request to the Company at 2000 Post Oak Blvd., Suite 100, Houston, Texas 77056-4400, Attention: Corporate Secretary.

12. Compliance with Laws and Regulations.

(a) The Conditional Grant and any obligation of the Company to deliver RSUs or Stock hereunder shall be subject in all respects to (i) all applicable laws, rules and regulations and (ii) any registration, qualification, approvals or other requirements imposed by any government or regulatory agency or body which the Committee shall, in its discretion, determine to be necessary or applicable. Moreover, the Company shall not deliver any certificates for Stock to the Recipient or any other person pursuant to this Agreement if doing so would be contrary to applicable law. If at any time the Company determines, in its discretion, that the listing, registration or qualification of Stock upon any national securities exchange or under any applicable law, or the consent or approval of any governmental regulatory body, is necessary or desirable, the Company shall not be required to deliver any certificates for Stock to the Recipient or any other person pursuant to this Agreement unless and until such listing, registration, qualification, consent or approval has been effected or obtained, or otherwise provided for, free of any conditions not acceptable to the Company.

(b) It is intended that any Stock received in respect of the Conditional Grant shall have been registered under the Securities Act of 1933 (“Securities Act”). If the Recipient is an “affiliate” of the Company, as that term is defined in Rule 144 under the Securities Act (“Rule 144”), the Recipient may not sell the Stock received except in compliance with Rule 144. Certificates representing Stock issued to an “affiliate” of the Company may bear a legend setting forth such restrictions on the disposition or transfer of the Stock as the Company deems appropriate to comply with Federal and state securities laws.

(c) If, at any time, the Stock is not registered under the Securities Act, and/or there is no current prospectus in effect under the Securities Act with respect to the Stock, the Recipient shall execute, prior to the delivery of any Stock to the Recipient by the Company pursuant to this Agreement, an agreement (in such form as the Company may specify) in which the Recipient represents and warrants that the Recipient is purchasing or acquiring the Stock acquired under

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this Agreement for the Recipient’s own account, for investment only and not with a view to the resale or distribution thereof, and represents and agrees that any subsequent offer for sale or distribution of any kind of such Stock shall be made only pursuant to either (i) a registration statement on an appropriate form under the Securities Act, which registration statement has become effective and is current with regard to the Stock being offered or sold, or (ii) a specific exemption from the registration requirements of the Securities Act, but in claiming such exemption the Recipient shall, prior to any offer for sale of such Stock, obtain a prior favorable written opinion, in form and substance satisfactory to the Company, from counsel for or approved by the Company, as to the applicability of such exemption thereto.

(d) This Conditional Grant is intended to comply with, or be exempt from, the applicable requirements of Section 409A of the Code and the rules and regulations issued thereunder and shall be administered accordingly. Notwithstanding anything in this Agreement to the contrary, if the RSUs constitute “deferred compensation” under Section 409A of the Code and any RSUs become payable pursuant to the Recipient’s termination of employment, settlement of the RSUs shall be delayed for a period of six months after the Recipient’s termination of employment if the Recipient is a “specified employee” as defined under Code Section 409A(a)(2)(B)(i) and if required pursuant to Section 409A of the Code. If settlement of the RSUs is delayed, the RSUs shall be settled on the first day of the first calendar month following the end of the six-month delay period. If the Recipient dies during the six-month delay, the RSUs shall be settled and paid to the Recipient’s designated beneficiary, legal representatives, heirs or legatees, as applicable, as soon as practicable after the date of death. Notwithstanding any provision to the contrary herein, payments made with respect to this Conditional Grant may only be made in a manner and upon an event permitted by Section 409A of the Code, and all payments to be made upon a termination of employment hereunder may only be made upon a “separation from service,” as such term is defined in Section 10.1 of the Plan. This Agreement may be amended without the consent of the Recipient in any respect deemed by the Board or the Committee to be necessary in order to preserve compliance with Section 409A of the Code.

13. Notices. All notices by the Recipient or the Recipient’s assignees shall be addressed to the Administrative Agent, Fidelity, through the Recipient’s account at netbenefits.fidelity.com, or such other address as the Company may from time to time specify. All notices to the Recipient shall be addressed to the Recipient at the Recipient’s address in the Company’s records.

14. Other Plans. The Recipient acknowledges that any income derived from the Conditional Grant shall not affect the Recipient’s participation in, or benefits under, any other benefit plan or other contract or arrangement maintained by the Company or any Affiliate.

15. Terms of Employment. The Plan is a discretionary plan. The Recipient hereby acknowledges that neither the plan nor this Agreement forms part of his terms of employment and nothing in the Plan may be construed as imposing on the Company or any Affiliate a contractual obligation to offer participation in the Plan to any employee of the Company or any Affiliate. The Company or any Affiliate is under no obligation to grant further Stock to any Recipient under the Plan. The Recipient hereby acknowledges that if he ceases to be an employee of the Company or any Affiliate for any reason or no reason, he shall not be entitled by way of compensation for loss of office or otherwise howsoever to any sum.

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16. Data Protection. By accepting this Agreement (whether by electronic means or otherwise), the Recipient hereby consents to the holding and processing of personal data provided by him to the Company for all purposes necessary for the operation of the Plan. These include, but are not limited to:

(a) administering and maintaining Recipient records;

(b) providing information to any registrars, brokers or third party administrators of the Plan; and

(c) providing information to future purchasers of the Company or the business in which the Recipient works.

17. Severability. If any provision of this Agreement is held invalid or unenforceable, the remainder of this Agreement shall nevertheless remain in full force and effect, and if any provision is held invalid or unenforceable with respect to particular circumstances, it shall nevertheless remain in full force and effect in all other circumstances, to the fullest extent permitted by law.

*****

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EX-10.47

Exhibit 10.47

SCHEDULE A

Apache Corporation

2014 Performance Program

(Business Performance)

AWARD NOTICE

Recipient Name: [Name]

Company: Apache Corporation

Notice: A summary of the terms of Conditional Grants of Restricted Stock Units (“RSUs”) under the 2014 Performance Program is set out in this notice (the “Award Notice”) but subject always to the terms of the Apache Corporation 2011 Omnibus Equity Compensation Plan (the “Plan”) and the 2014 Performance Program Agreement (Business Performance) (the “Agreement”). In the event of any inconsistency between the terms of this Award Notice, the terms of the Plan and the Agreement, the terms of the Plan and the Agreement shall prevail.

Selected Eligible Persons have been awarded a conditional grant of Apache Corporation RSUs in accordance with the terms of the Plan and the Agreement.

Details of the RSUs which you are conditionally entitled to receive is provided to you in this Award Notice and maintained on your account at netbenefits.fidelity.com

Type of Award: A conditional award of RSUs based on a target percentage of annual base salary determined immediately prior to the beginning of the Performance Period derived from job level (the “Conditional Grant”). RSUs granted pursuant to this Conditional Grant are not eligible for dividends or dividend equivalents.

Restricted Stock Unit: A Restricted Stock Unit (“RSU”) as defined in the Plan and meaning the right granted to the Recipient of the Conditional Grant, as adjusted at the end of the Performance Period, to receive one share of Stock for each Restricted Stock Unit at the end of the specified Vesting Period.

Stock: The $0.625 par value common stock of the Company or as otherwise defined in the Plan.

Grant: A Conditional Grant related to              Restricted Stock Units (Target Amount)

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Grant Date: [Date]

Conditions: Subject always to the terms of the Plan and the Agreement, the Conditional Grant of RSUs shall be made as of the Grant Date. At the end of the Performance Period, the Committee shall derive and confirm the number of Conditional Grant RSUs that will actually be awarded as RSUs to the Recipient based upon measurement of the specific performance goals, applicable performance percentage levels and applicable weighting percentages during the Performance Period as set forth in Schedule B to the Agreement, provided that the Recipient remains an Eligible Person and employed by the Company or its Affiliate as of the final day of the Performance Period. Once granted at the conclusion of the Performance Period, such RSUs shall remain subject to a vesting schedule (as set forth below) (the “Vesting Period”). Once vested, the Recipient shall be paid the value of his or her RSUs in shares of Stock (net of shares withheld for applicable tax withholdings) provided that the Recipient remains employed as an Eligible Person during the Vesting Period including the vesting date.

Performance Measure: The performance measures for the Conditional Grant, the performance percentage levels, and the applicable weighting percentages to be applied over the Performance Period are set forth on Schedule B to the Agreement.

At the end of the Performance Period, the Committee shall determine and certify the attainment of each performance goal based on the established performance percentage levels and apply the applicable weighting percentages to determine the Final Amount of RSUs to be awarded to each Recipient.

Performance Period: The one-year period commencing January 1, 2014 and ending December 31, 2014.

Vesting Period: Except upon a change of control (as described below), death, or total and permanent disability (as described below), cessation of employment during the Performance Period shall result in the immediate forfeiture of the entire amount of the Conditional Grant. To the extent all or a part of a Conditional Grant RSU award is earned as of the end of the Performance Period, an award equal to the Final Amount shall be made in RSUs to the Recipient as soon as administratively practical, but not later than March 15 following the end of the Performance Period. Any such RSUs awarded shall vest in accordance with the following schedule, provided that the Recipient remains employed as an Eligible Person as of such vesting date:

24 months following the close of the Performance Period – 50% vested.

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36 months following the close of the Performance Period – an additional 50% vested.

Except as described below, cessation of employment will result in the immediate forfeiture of all unvested RSUs.

Vesting is accelerated to 100% upon the Recipient’s death or total and permanent Disability during the Performance Period or the subsequent Vesting Period. Upon death or total and permanent Disability during the Performance Period, the number of RSUs (and related shares of Stock) granted shall be deemed to be 1.00 times the Conditional Grant amount of RSUs (the Target Amount). Upon vesting, the applicable shares of Stock, subject to required tax withholding, shall be transferred by the Company to the Recipient (or, in the event of the Recipient’s death, to his beneficiary) within thirty (30) days of the vesting date. The Recipient can name a beneficiary on a form approved by the Committee.

Vesting is accelerated to 100% upon a Recipient’s Involuntary Termination or Voluntary Termination with Cause occurring (i) on or after a 409A Change of Control during the Vesting Period provided that the Recipient is an Eligible Person at the time of such termination and (ii) after completion of the Performance Period. Upon vesting, the applicable shares of Stock, subject to required tax withholding, shall be transferred by the Company to the Recipient within thirty (30) days of the vesting date.

In the event of the Recipient’s Involuntary Termination or Voluntary Termination with Cause which occurs (i) on or after a 409AChange of Control of the Company and (ii) on or prior to the end of the Performance Period, the Recipient will become 100% fully vested upon the occurrence of his Involuntary Termination or Voluntary Termination with Cause on or after the 409A Change of Control in the number of RSUs determined by applying the multiple of 1.00 to the Target Amount. Upon vesting, the applicable shares of Stock, subject to required tax withholding, shall be transferred by the Company to the Recipient within thirty (30) days of the later of (i) the date of the Recipient’s Involuntary Termination or Voluntary Termination with Cause or (ii) the end of the Performance Period. Notwithstanding the foregoing, if the payment of the Final Amount is subject to Internal Revenue Code Section 409A, payment will not occur until the earlier of (1) the date payment would have been due if the 409A Change of Control had not occurred or (2) the date that the 409A Change of Control

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constitutes a “change in the ownership or effective control of the corporation, or in the ownership of a substantial portion of the assets of the corporation” within the meaning of Internal Revenue Code Section 409A(a)(2)(A)(v).

If, during the Vesting Period, and after the end of the Performance Period, the Recipient’s termination of employment from the Company and the Affiliates occurs by reason of his or her Retirement, the Recipient may be deemed to continue to be employed as an Eligible Person for purposes of this Grant and may continue to vest over the Vesting Period provided that the Recipient meets the Retirement Conditions set forth in section 6 of the Agreement. In the event of a 409A Change of Control during such continued Vesting Period, vesting is accelerated to 100%.

Withholding: The Company and the Recipient will comply with all federal and state laws and regulations respecting the required withholding, deposit and payment of any income, employment or other taxes relating to the Grant.

Acceptance Please complete the on-line grant acceptance as promptly as possible to accept or reject your Conditional Grant. You can access this through your account at netbenefits.fidelity.com. By accepting your Conditional Grant, you will have agreed to the terms and conditions set forth in the Agreement, including, but not limited to, the non-compete and non-disparagement provisions set forth in section 6 of the Agreement, and the terms and conditions of the Plan. If you do not accept your grant you will be unable to receive your Conditional Grant or the related RSUs.

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SCHEDULE B

Apache Corporation

2014 Performance Program

(Business Performance)

PERFORMANCE MEASURES

Metric	Threshold (50%)			Target (100%)			Max (150%)		Target Points
Proforma Production Growth Per Share1 (Additional 5 points for each 1% growth above 5% target)		—			5	%		—		25.0
Replace 115% of 2014 production through E&D adds		115	%		130	%		—		20.0
Maximize Cash Flow per Barrel Sold through Cost Management2:										20.0
• LOE per BOE	$	11.00		$	10.82		$	10.07
• G&A per BOE (Gross G&A Spend/GAAP BOE)	$	3.89		$	3.73		$	3.55
After Tax Rate of Return on 2014 Drilling Program (Additional 1 point for each 1% return above 15% target)		12	%		15	%		—		25.0
Health, Safety, Security, and Environmental:										10.0
• Worldwide, total workforce (employees and contractors) recordable incident rate (TRIR) per 200,000 man-hours worked		1.05			0.92			0.83
• Worldwide, total workforce (employees and contractors) days-away-restricted-time rate (DART) per 200,000 man-hours worked		0.52			0.44			0.40
• Worldwide employee vehicle incident rate (VIR) per 1,000,000 miles driven		1.91			1.78			1.60
Total Points3										100.0

¹ Production per share compares 2014 total BOE production per share to 2013 total BOE production per share.

² All BOE-related targets will use a conversion of 6 mcf/boe.

³  Actual points achieved will be applied as a percentage to target number of performance shares awarded.

Note: Payout may not exceed 150% of target shares granted.

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Apache Corporation

2014 Performance Program Agreement

(Business Performance)

This 2014 Performance Program Agreement (Business Performance) (the “Agreement”) relating to a conditional grant of Restricted Stock Units (as defined in the rules of the Apache Corporation 2011 Omnibus Equity Compensation Plan (the “Plan”) (the “Conditional Grant”), dated as of the Grant Date set forth in the Notice of Award under the 2014 Performance Program (Business Performance) attached as Schedule A hereto (the “Award Notice”), is made between Apache Corporation (together with its Affiliates, the “Company”) and each Recipient. The Award Notice is included in and made part of this Agreement.

In this Agreement and each Award Notice, unless the context otherwise requires, words and expressions shall have the meanings given to them in the Plan except as herein defined.

Definitions

“409A Change of Control” means a Change of Control that constitutes, with respect to the Company, a “change in the ownership or effective control of the corporation, or in the ownership of a substantial portion of the assets of the corporation” within the meaning of Section 409A(a)(2)(A)(v) of the Internal Revenue Coe of 1986, as amended (the “Code”) and Treasury Regulations Section 1.409A-3(i)(5).

“Award Notice” means the separate notice, along with Schedule B, given to each Recipient specifying the Target Amount and other applicable performance percentage levels, performance criteria and applicable weighting percentages for that individual.

“Base Salary” means, with regard to any Recipient, such Recipient’s annual base compensation as an employee of the Company determined immediately prior to the beginning of the Performance Period, without regard to any bonus, pension, profit sharing, stock option, life insurance or salary continuation plan which the Recipient either receives or is otherwise entitled to have paid on his or her behalf.

“Conditional Grant” means the conditional entitlement, evidenced by this Agreement to receive all or a portion of a Target Amount and Final Amount, subject to and in accordance with the provisions of this Agreement.

“Disability” means total and permanent disability as determined pursuant to the Company’s Group Long-Term Disability Plan or any successor.

“Fair Market Value” means the closing price of the Stock as reported on The New York Stock Exchange, Inc. Composite Transactions Reporting System (“Composite Tape”) for a particular date or, if the Stock is not so listed at any time, as reported on NASDAQ or on such other exchange or electronic trading system as, on the date in question, reports the largest number of traded shares of stock. If there are no Stock transactions on such date, the Fair Market Value shall be determined as of the immediately preceding date on which there were Stock transactions. If the foregoing provisions are not applicable, the fair market value of a share of the Stock shall be as determined by the Committee by the reasonable application of such reasonable valuation method, consistently applied, as the Committee deems appropriate.

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“Final Amount” means with regard to any Recipient, such number of shares of Restricted Stock Units (“RSUs”) as specified in each Recipient’s Award Notice, times the applicable multiple factor determined under the Performance Measures at the end of the Performance Period.

“Involuntary Termination” means the termination of employment of the Recipient by the Company or its successor for any reason on or after a 409A Change of Control; provided, that the termination does not result from an act of the Recipient that (i) constitutes common-law fraud, a felony, or a gross malfeasance of duty, or (ii) is materially detrimental to the best interests of the Company or its successor.

“Payout Amount” means the vested portion of the Final Amount expressed as shares of Stock underlying the RSUs.

“Performance Measures” means Apache Corporation’s achievement of pre-established performance goals over the Performance Period. At the end of the Performance Period, the Committee shall determine and certify the levels of specific performance goals achieved and apply the applicable performance percentage levels and weighting percentages as set forth in the Award Notice. Based on the Company’s level of goal achievement, a Recipient who remains employed as of the last day of the Performance Period will be issued RSUs at the close of the Performance Period as determined by the Committee as set forth in the Award Notice (the Final Amount).

“Performance Period” means the one-year period as specified in the Award Notice.

“Recipient” means an Eligible Person who has been designated by the Committee at the Grant Date at the beginning of the Performance Period to receive one or more Conditional Grants under the Plan. For purposes of this Agreement, the group of Eligible Persons shall include all full-time and designated part-time employees of the Company who are employed as employees of the Company (as designated by the Company for payroll purposes) on the date immediately prior to the beginning of the Performance Period, but excluding Egyptian nationals employed outside of the United States, employees categorized by the Company (for payroll purposes) as non-exempt support and field staff, leased employees, interns, or, except for employees who are members of the Hierarchical Union Neuquén and the Union of Hierarchical Personnel of Private Oil and Gas for Neuquén, Rio Negro and La Pampa, any employee of the Company who is covered under a collective bargaining agreement, unless such collective bargaining agreement specifically provides for coverage under the Plan.

“Retirement” means, with respect to a Recipient and for purposes of this Agreement, the date the Recipient terminates employment with the Company after (i) attaining age 65 and (ii) earning at least 15 Years of Service.

“Years of Service” means the total number of months from the Recipient’s date of hire by the Company to the date of termination of employment divided by 12.

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“Target Amount” means, with regard to any Recipient, such number of RSUs as specified in each Recipient’s Award Notice. Such Target Amount shall be based upon a target percentage of annual Base Salary determined immediately prior to the beginning of the Performance Period derived from job level.

“Voluntary Termination with Cause” occurs upon a Recipient’s separation from service of his own volition and one or more of the following conditions occurs without the Recipient’s consent on or after a 409A Change of Control:

(a) There is a material diminution in the Recipient’s base compensation, compared to his rate of base compensation on the date of the 409A Change of Control.

(b) There is a material diminution in the Recipient’s authority, duties or responsibilities.

(c) There is a material diminution in the authority, duties or responsibilities of the Recipient’s supervisor, such as a requirement that the Recipient (or his supervisor) report to a corporate officer or employee instead of reporting directly to the board of directors.

(d) There is a material diminution in the budget over which the Recipient retains authority.

(e) There is a material change in the geographic location at which the Recipient must perform his service, including, for example the assignment of the Recipient to a regular workplace that is more than 50 miles from his regular workplace on the date of the 409A Change of Control.

The Recipient must notify the Company of the existence of one or more adverse conditions specified in clauses (a) through (e) above within 90 days of the initial existence of the adverse condition. The notice must be provided in writing to Apache Corporation’s Executive Vice President, Human Resources or his/her delegate. The notice may be provided by personal delivery or it may be sent by email, inter-office mail, regular mail (whether or not certified), fax, or any similar method. Apache Corporation’s Executive Vice President, Human Resources, or his/her delegate shall acknowledge receipt of the notice within 5 business days; the acknowledgement shall be sent to the Recipient by certified mail. Notwithstanding the foregoing provisions of this definition, if the Company remedies the adverse condition within 30 days of being notified of the adverse condition, no Voluntary Termination with Cause shall occur.

Terms

1. Conditional Grant of RSUs. Subject to the provisions of this Agreement and the provisions of the Plan and Award Notice, the Company shall conditionally grant to the Recipient, pursuant to the Plan, a right to receive the Target Amount of RSUs set forth in the Recipient’s Award Notice. Such Target Amount shall be adjusted to a Final Amount at the end of the Performance Period based upon the results of the Performance Measures, as determined by the Committee. Notwithstanding the foregoing, the Target Amount shall be adjusted to a Final

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Amount of RSUs at the conclusion of the Performance Period solely for each Recipient who remains employed as of the last day of the Performance Period. The award of the Final Amount shall give the Recipient the right, upon vesting, to an equal number of shares of $0.625 par value common stock of the Company (“Stock”).

2. Vesting and Payment of Stock. Subject to the provisions of Section 3, the Payout Amounts shall be payable in increments strictly in accordance with the following schedule:

(a) The entitlement to receive the number of shares of Stock pursuant to the RSUs comprising the Final Amount shall vest fifty percent (50%) and become transferable twenty-four (24) months from the final date of the Performance Period provided that the Recipient remains employed as an Eligible Person on such date. Such Stock, subject to applicable withholding, shall be transferred by the Company to the Recipient within thirty (30) days of the end of the vesting date and not later than March 15 of the year following the year in which the RSUs vest.

(b) The entitlement to receive the remaining fifty percent (50%) of the shares of Stock pursuant to the RSUs comprising the Final Amount shall vest and become transferable thirty-six (36) months from the close of the Performance Period, provided that the Recipient remains employed as an Eligible Person on such applicable vesting date. Such Stock, subject to applicable withholding, shall be transferred by the Company to the Recipient within thirty (30) days of the respective vesting date and not later than March 15 of the year following the year in which the RSUs vest.

3. Termination of Employment, Death, or Disability on or prior to the end of the Performance Period. Except as set forth below, a cessation of employment with the Company prior to the end of the Performance Period will result in the Target Amount being forfeited for all purposes.

(a) If the Recipient dies while employed by the Company, or on the date the Recipient becomes Disabled (as defined in this Agreement), during the Performance Period, the Recipient shall immediately receive an amount equal to the Target Amount of RSUs and shall become 100% vested in such Target Amount. Payment shall occur as soon as administratively convenient following the date the Recipient dies or becomes Disabled, but in no event shall the payment occur later than March 15 of the calendar year immediately following the calendar year in which the Recipient died or became Disabled. If the Recipient dies before receiving payment, the payment shall be made to the Recipient’s designated beneficiary, legal representatives, heirs, or legatees, as applicable. Each Recipient may designate a beneficiary on a form approved by the Committee.

4. Termination of Employment, Retirement, Death or Disability after the end of the Performance Period. Except as set forth below, each Conditional Grant shall be subject to the condition that the Recipient has remained an Eligible Person from the award of the Conditional Grant of RSUs until the applicable vesting date as follows:

(a) If the Recipient voluntarily leaves the employment of the Company (other than for reason of Retirement), or if the employment of the Recipient is terminated by the Company for any reason or no reason, any Final Amounts not previously vested shall thereafter be void and forfeited for all purposes.

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(b) A Recipient shall become 100% fully vested in all Final Amounts on the date the Recipient dies while employed by the Company (or while continuing to vest pursuant to section 4(c) below), or on the date the Recipient becomes Disabled (as defined for purposes of this Agreement) while employed by the Company. Payment shall occur as soon as administratively convenient following the date the Recipient dies or becomes Disabled, but in no event shall the payment occur later than March 15 of the calendar year immediately following the calendar year in which the Recipient died or became Disabled. If the Recipient dies before receiving payment, the payment shall be made to the Recipient’s designated beneficiary, legal representatives, heirs, or legatees, as applicable. Each Recipient may designate a beneficiary on a form approved by the Committee.

(c) If the Recipient leaves the employment of the Company by reason of Retirement, any Final Amounts not previously vested may continue to vest following the Recipient’s termination of employment by reason of Retirement after the end of the Performance Period as if the Recipient remained an Eligible Person in the employ of the Company, provided that such Recipient shall be entitled to continue vesting only if such Recipient satisfies the Retirement Conditions set forth in section 6 below (except in the case of death).

5. Change of Control.

(a) Pursuant to Section 12.1(d) of the Plan, the following provisions of this section 5 of the Agreement shall supersede Sections 12.1(a), (b) and (c) of the Plan. Without any further action by the Committee or the Board, in the event of the Recipient’s Involuntary Termination or Voluntary Termination with Cause which occurs (i) on or after a 409A Change of Control of the Company and (ii) prior to the end of the Performance Period, the Recipient shall become 100% fully vested upon the occurrence of his Involuntary Termination or Voluntary Termination with Cause on or after the 409A Change of Control in the number of RSUs determined by applying the multiple of 1.00 to the Target Amount. Subject to section 12(d) of this Agreement, payment shall occur within thirty (30) days of the later of (1) the date of the Involuntary Termination or Voluntary Termination with Cause of the Recipient following the 409A Change of Control or (2) the end of the Performance Period.

(b) In the event of a Recipient’s Involuntary Termination or Voluntary Termination with Cause occurring on or after a 409A Change of Control of the Company which occurs after the end of the Performance Period, the Recipient shall become 100% fully vested in the Final Amount of RSUs as of the date of his Involuntary Termination or Voluntary Termination with Cause. Subject to section 12(d) of this Agreement, payment shall occur within thirty (30) days of the date of such Involuntary Termination or Voluntary Termination with Cause.

(c) In the event of a 409A Change of Control of the Company following the Recipient’s termination of employment by reason of Retirement after the end of the Performance Period while the Recipient is continuing to vest pursuant to section 4(c), the Recipient shall become 100% fully vested in the unvested Final Amount of RSUs as of the date of the 409A Change of Control. Subject to section 12(d) of this Agreement, payment shall occur within thirty (30) days of the 409A Change of Control.

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6. Conditions to Post-Retirement Vesting. If the Recipient has attained age 65 and has completed at least 15 Years of Service and such Recipient terminates employment with the Company and the Affiliates by reason of Retirement, it is agreed by the Company and the Recipient that:

(a) subject to the provisions of this section 6(a) and sections 6(b) and 6(c), such Recipient may continue to vest in the unvested Final Amount of RSUs following the date of his or her termination by reason of Retirement as if the Recipient continued in employment as an Eligible Person provided that the Recipient (i) is an employee of the Company or an Affiliate in good standing and not on a performance improvement plan as of such termination date; (ii) has provided not less than three (3) months’ advance written notice prior to such termination date to Apache Corporation’s Executive Vice President, Human Resources, or his or her delegate, and to his or her direct manager, regarding the Recipient’s intent to terminate employment for reason of Retirement; and (iii) cooperates with the Company in the training of a replacement during the three-month period prior to Retirement; and it is further agreed that

(b) in consideration for the continued vesting treatment afforded to the Recipient under section 6(a), Recipient shall, during the continuing Vesting Period after Retirement (the “Continued Vesting Period”) refrain from becoming employed by, or consulting with, or becoming substantially involved in the business of, any business that competes with the Company or its Affiliate in the business of exploration or production of oil or natural gas within the geographic area in which the Recipient is working or has worked for the Company or its Affiliate, and/or for which the Recipient is or was responsible, at the time of termination of employment or the immediately preceding three-year period (a “Competitive Business”); provided, that the Recipient may purchase and hold for investment purposes less than five percent (5%) of the shares of any Competitive Business whose shares are regularly traded on a national securities exchange or inter-dealer quotation system, and provided further, that the Recipient may provide services solely as a director to a Competitive Business if, during the Continued Vesting Period, the Recipient is not involved directly in the day-to-day management, supervision or operations of such Competitive Business; and it is further agreed that

(c) in consideration for the continued vesting treatment afforded to the Recipient under section 6(a), Recipient shall, during the Continued Vesting Period, refrain from making, or causing or assisting any other person to make, any oral or written communication to any third party about the Company, any Affiliate and/or any of the employees, officers or directors of the Company or any Affiliate which impugns or attacks, or is otherwise critical of, the reputation, business or character of such entity or person; or that discloses private or confidential information about their business affairs; or that constitutes an intrusion into their seclusion or private lives; or that gives rise to unreasonable publicity about their private lives; or that places them in a false light before the public; or that constitutes a misappropriation of their name or likeness.

Notwithstanding the foregoing provisions of this section 6 of the Agreement, in the event that the Recipient fails to satisfy any of the conditions set forth in sections 6(a), (b) and (c) above, the Recipient shall not be entitled to vest in any unvested Final Amount of RSUs after the date of Retirement and the unvested Final Amount of RSUs subject to this Agreement shall be forfeited.

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7. Payment and Tax Withholding. Upon receipt of any entitlement to Stock under this Agreement and, if applicable, upon the Recipient’s attainment of eligibility to terminate employment by reason of Retirement pursuant to section 4(c), the Recipient shall make appropriate arrangements with the Company to provide for the amount of minimum tax withholding required by law, including without limitation Sections 3102 and 3402 or any successor section(s) of the Internal Revenue Code and applicable state and local income and other tax laws. Upon receipt of entitlement to Stock under this Agreement, each payment of the Payout Amount shall be made in shares of Stock, determined by the Committee, such that the withheld number of shares shall be sufficient to cover the withholding amount required by this Section (including any amount to cover benefit tax charges arising thereon). The payment of a Payout Amount shall be based on the Fair Market Value of the shares of Stock on the applicable date of vesting to which such tax withholding relates. Where appropriate, shares shall be withheld by the Company to satisfy applicable tax withholding requirements rather than paid directly to the Recipient.

8. No Ownership Rights Prior to Issuance of Stock. Neither the Recipient nor any other person shall become the beneficial owner of the Stock underlying the Conditional Grant, nor have any rights of a shareholder (including, without limitation, dividend and voting rights) with respect to any such Stock, unless and until and after such Stock has been actually issued to the recipient and transferred on the books and records of the Company or its agent in accordance with the terms of the Plan and this Agreement.

9. Non-Transferability of Stock. Stock issued pursuant to a Conditional Grant shall not be transferable otherwise than by will or the laws of descent and distribution, subject to the conditions and exceptions set forth in Section 14.2 of the Plan.

10. No Right to Continued Employment. Neither the RSUs or Stock issued pursuant to a Conditional Grant nor any terms contained in this Agreement shall confer upon the Recipient any express or implied right to be retained in the employment or service of the Company for any period, nor restrict in any way the right of the Company, which right is hereby expressly reserved, to terminate the Recipient’s employment or service at any time for any reason or no reason. The Recipient acknowledges and agrees that any right to receive RSUs or Stock pursuant to a Conditional Grant is earned only by continuing as an employee of the Company at the will of the Company, or satisfaction of any other applicable terms and conditions contained in the Plan and this Agreement, and not through the act of being hired, being granted the Conditional Grant, or acquiring RSUs or Stock pursuant to the Conditional Grant hereunder.

11. The Plan. In consideration for this Conditional Grant, the Recipient agrees to comply with the terms of the Plan and this Agreement. This Agreement is subject to all the terms, provisions and conditions of the Plan, which are incorporated herein by reference, and to such regulations as may from time to time be adopted by the Committee. Unless defined herein, capitalized terms are used herein as defined in the Plan. In the event of any conflict between the provisions of the Plan and this Agreement, the provisions of the Plan shall control, and this Agreement shall be deemed to be modified accordingly. The Plan and the prospectus describing the Plan can be found on the Company’s HR intranet and the Plan document can be found on Fidelity’s website (netbenefits.fidelity.com). A paper copy of the Plan and the prospectus shall be provided to the recipient upon the Recipient’s written request to the Company at 2000 Post Oak Blvd., Suite 100, Houston, Texas 77056-4400, Attention: Corporate Secretary.

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12. Compliance with Laws and Regulations.

(a) The Conditional Grant and any obligation of the Company to deliver RSUs or Stock hereunder shall be subject in all respects to (i) all applicable laws, rules and regulations and (ii) any registration, qualification, approvals or other requirements imposed by any government or regulatory agency or body which the Committee shall, in its discretion, determine to be necessary or applicable. Moreover, the Company shall not deliver any certificates for Stock to the Recipient or any other person pursuant to this Agreement if doing so would be contrary to applicable law. If at any time the Company determines, in its discretion, that the listing, registration or qualification of Stock upon any national securities exchange or under any applicable law, or the consent or approval of any governmental regulatory body, is necessary or desirable, the Company shall not be required to deliver any certificates for Stock to the Recipient or any other person pursuant to this Agreement unless and until such listing, registration, qualification, consent or approval has been effected or obtained, or otherwise provided for, free of any conditions not acceptable to the Company.

(b) It is intended that any Stock received in respect of the Conditional Grant shall have been registered under the Securities Act of 1933 (“Securities Act”). If the Recipient is an “affiliate” of the Company, as that term is defined in Rule 144 under the Securities Act (“Rule 144”), the Recipient may not sell the Stock received except in compliance with Rule 144. Certificates representing Stock issued to an “affiliate” of the Company may bear a legend setting forth such restrictions on the disposition or transfer of the Stock as the Company deems appropriate to comply with Federal and state securities laws.

(c) If, at any time, the Stock is not registered under the Securities Act, and/or there is no current prospectus in effect under the Securities Act with respect to the Stock, the Recipient shall execute, prior to the delivery of any Stock to the Recipient by the Company pursuant to this Agreement, an agreement (in such form as the Company may specify) in which the Recipient represents and warrants that the Recipient is purchasing or acquiring the Stock acquired under this Agreement for the Recipient’s own account, for investment only and not with a view to the resale or distribution thereof, and represents and agrees that any subsequent offer for sale or distribution of any kind of such Stock shall be made only pursuant to either (i) a registration statement on an appropriate form under the Securities Act, which registration statement has become effective and is current with regard to the Stock being offered or sold, or (ii) a specific exemption from the registration requirements of the Securities Act, but in claiming such exemption the Recipient shall, prior to any offer for sale of such Stock, obtain a prior favorable written opinion, in form and substance satisfactory to the Company, from counsel for or approved by the Company, as to the applicability of such exemption thereto.

(d) This Conditional Grant is intended to comply with, or be exempt from, the applicable requirements of Section 409A of the Code and the rules and regulations issued thereunder and shall be administered accordingly. Notwithstanding anything in this Agreement to the contrary, if the RSUs constitute “deferred compensation” under Section 409A of the Code and any RSUs become payable pursuant to the Recipient’s termination of employment, settlement of the RSUs shall be delayed for a period of six months after the Recipient’s termination of employment if the Recipient is a “specified employee” as defined under Code Section 409A(a)(2)(B)(i) and if required pursuant to Section 409A of the Code. If settlement of the RSUs is delayed, the RSUs shall be settled on the first day of the first calendar month

13

following the end of the six-month delay period. If the Recipient dies during the six-month delay, the RSUs shall be settled and paid to the Recipient’s designated beneficiary, legal representatives, heirs or legatees, as applicable, as soon as practicable after the date of death. Notwithstanding any provision to the contrary herein, payments made with respect to this Conditional Grant may only be made in a manner and upon an event permitted by Section 409A of the Code, and all payments to be made upon a termination of employment hereunder may only be made upon a “separation from service,” as such term is defined in Section 10.1 of the Plan. This Agreement may be amended without the consent of the Recipient in any respect deemed by the Board or the Committee to be necessary in order to preserve compliance with Section 409A of the Code.

13. Notices. All notices by the Recipient or the Recipient’s assignees shall be addressed to the Administrative Agent, Fidelity, through the Recipient’s account at netbenefits.fidelity.com, or such other address as the Company may from time to time specify. All notices to the Recipient shall be addressed to the Recipient at the Recipient’s address in the Company’s records.

14. Other Plans. The Recipient acknowledges that any income derived from the Conditional Grant shall not affect the Recipient’s participation in, or benefits under, any other benefit plan or other contract or arrangement maintained by the Company or any Affiliate.

15. Terms of Employment. The Plan is a discretionary plan. The Recipient hereby acknowledges that neither the plan nor this Agreement forms part of his terms of employment and nothing in the Plan may be construed as imposing on the Company or any Affiliate a contractual obligation to offer participation in the Plan to any employee of the Company or any Affiliate. The Company or any Affiliate is under no obligation to grant further Stock to any Recipient under the Plan. The Recipient hereby acknowledges that if he ceases to be an employee of the Company or any Affiliate for any reason or no reason, he shall not be entitled by way of compensation for loss of office or otherwise howsoever to any sum.

16. Data Protection. By accepting this Agreement (whether by electronic means or otherwise), the Recipient hereby consents to the holding and processing of personal data provided by him to the Company for all purposes necessary for the operation of the Plan. These include, but are not limited to:

(a) administering and maintaining Recipient records;

(b) providing information to any registrars, brokers or third party administrators of the Plan; and

(c) providing information to future purchasers of the Company or the business in which the Recipient works.

14

17. Severability. If any provision of this Agreement is held invalid or unenforceable, the remainder of this Agreement shall nevertheless remain in full force and effect, and if any provision is held invalid or unenforceable with respect to particular circumstances, it shall nevertheless remain in full force and effect in all other circumstances, to the fullest extent permitted by law.

*****

15

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)	2013		2012		2011		2010		2009
EARNINGS
Pretax income from continuing operations	$	4,216	$	4,877	$	8,093	$	5,206	$	326
Add: Fixed charges excluding capitalized interest		286		255		246		306		286
Adjusted Earnings	$	4,502	$	5,132	$	8,339	$	5,512	$	612
FIXED CHARGES AND PREFERRED STOCK DIVIDENDS
Interest expense including capitalized interest (1)	$	571	$	509	$	433	$	345	$	310
Amortization of debt expense		9		7		6		18		5
Interest component of lease rental expenditures (2)		81		73		70		64		31
Fixed charges		661		589		509		427		346
Preferred stock dividend requirements (3)		81		185		134		55		12
Noncontrolling interest		44		—		—		—		—
Combined Fixed Charges and Preferred Stock Dividends (1)	$	786	$	774	$	643	$	482	$	358
Ratio of Earnings to Fixed Charges		6.82		8.71		16.39		12.93		1.77
Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends		5.72		6.63		12.97		11.44		1.71

⁽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 32 to 34 percent applies 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-14.1

Exhibit 14.1

CODE OF BUSINESS CONDUCT

From the Chairman and Chief Executive Officer

Since 1954, Apache employees have pursued our mission to grow a profitable global exploration and production company in a safe and environmentally responsible manner for the long term benefit of our stockholders. The pursuit of our mission is guided by our values: conducting our business with honesty and integrity, investing in our people, expecting top performance, and treating people with respect and dignity.

We take on each new challenge with a sense of urgency, acting decisively, involving the right people, and overcoming obstacles. We identify issues and problems quickly and deal with them, without compromise, and make certain that we do the right thing for Apache and our stockholders.

Apache’s Code of Business Conduct sets out the ethical standards that we have set for ourselves. While no single document can address every circumstance that we may face in our jobs, this code provides a framework for our decisions: We are going to conduct our business fairly, with the highest ethical standards and in a way that complies with laws, regulations and government requirements. We will avoid both misconduct and the appearance of misconduct.

To do our jobs properly, we all need to understand these standards and the requirements of our jobs, be accountable for our actions, and to report any violations of Apache’s Code of Business Conduct expeditiously. To do any less would be a disservice to ourselves and to our fellow Apaches. If you have any questions, please discuss them with your supervisor or one of Apache’s executives.

When confronted with a difficult situation, we all want to make the right decision. We trust that Apache’s values and culture along with this code will continue to serve as guides to the right course of action.

Sincerely,

G. Steven Farris

Chairman and Chief Executive Officer

Revised: 13 November 2013 Page 1 of 7

  CODE OF BUSINESS CONDUCT

Our Policy

Apache will conduct its business fairly and ethically, and will comply with applicable laws, regulations, and government requirements. All conduct inconsistent with this policy is prohibited.

Apache Corporation is committed to conducting our business in accordance with the highest ethical standards. It is the policy of Apache Corporation and each of its subsidiaries (collectively and severally, herein referred to as “Apache” or “the Company”) to conduct its business fairly, ethically, and in compliance with applicable laws, regulations, and government requirements. All conduct inconsistent with this policy is prohibited.

This Code of Business Conduct requires not only the avoidance of misconduct, but also the avoidance of acts or omissions that give the appearance of misconduct. Apache directors, officers, employees, and representatives shall not enter into any activity or incur any expense or liability which would compromise our commitment to these high standards. Failure to comply with this Code of Business Conduct by an officer or employee will subject the officer or employee to disciplinary action, up to and including termination of employment. Any failure by a director to comply with this Code of Business Conduct shall be reported to the Corporate Governance and Nominating (“CG&N”) Committee of the board of directors for review, and the committee shall make a recommendation to the board of directors on appropriate action, which may include removal of such director from the board of directors.

This Code of Business Conduct is designed to deter wrong-doing and to promote:

1. honest and ethical conduct, including the ethical handling of actual or apparent conflicts of interest between personal and professional relationships;

2. fair, full, accurate, timely and understandable disclosure in reports and documents that the Company (a “registrant”) files with, or submits to, the Securities and Exchange Commission (“SEC”) and in other public communications made by the Company;

3. compliance with applicable governmental laws, rules and regulations;

4. prompt internal reporting of violations of the Code to an appropriate person or persons identified in the Code; and

5. accountability for adherence to the Code.

It is not possible to enumerate all of the situations which could result in an actual or apparent violation of this policy. However, the following areas are of particular concern to Apache with respect to the ethical conduct of the Company’s business. These principles must be interpreted using good judgment and common sense. Employees and officers are encouraged to discuss questions or concerns relating to this Code of Business Conduct with their supervisors or other members of management, while directors should direct their questions and concerns to the CG&N Committee.

Revised: 13 November 2013 Page 2 of 7

  CODE OF BUSINESS CONDUCT

No Conflicts of Interest

All business decisions for Apache should be based upon what a director, officer, or employee honestly believes to be in the best interests of the Company and in the long term interest of our stockholders.

Any direct or indirect conflict of interest between a director, officer, or employee and the Company is prohibited, unless the Company specifically grants its consent. A director, officer, or employee has a conflict of interest if, in the course of his or her duties for the Company, his or her judgment and discretion is or may be influenced by considerations of personal gain or benefit, or gain or benefit to a third party other than the Company.

All business decisions for Apache should be based upon what a director, officer, or employee honestly believes to be in the best interests of the Company and in the long term interest of its stockholders. Potential conflicts of interest should be immediately reported by directors notifying the CG&N Committee and by officers and employees notifying their supervisors of the potential conflict so that an appropriate determination can be made as to whether or not a conflict exists and what remedial action, if any, should be taken.

Protecting Corporate Opportunities

Apache officers and employees are prohibited from using corporate property, information, or position for personal gain.

Directors, officers, and employees are prohibited from:

1. taking for themselves or associates opportunities that are discovered through the use of corporate property, information, or position;

2. using corporate property, information, or position for personal gain; and

3. competing with the Company.

Receiving or Providing Gifts and Entertainment in Furtherance of Legitimate Company Interests

No Apache employee may accept or provide a gift or entertainment that is excessive in value or frequency considering the circumstances.

The Company recognizes that customary business practices on occasion may include the provision of travel, meals, token gifts and/or entertainment by or to current or prospective customers, vendors and business partners in the course of pursuing the legitimate business interests of the Company. This policy is not intended to prohibit such legitimate customary business practices that are meant to create goodwill and enhance business relationships. No employee may accept or provide a gift or entertainment that:

1. is not consistent with customary business practices;

Revised: 13 November 2013 Page 3 of 7

  CODE OF BUSINESS CONDUCT

2. is excessive in value or frequency considering the circumstances;

3. could be construed as a bribe or a payoff; or

4. violates any laws or regulations.

Employees must not accept or give gifts, travel or entertainment that violate legal standards or suggest any appearance of impropriety.

Gifts of cash or cash equivalent, including gift cards (except gift cards that are redeemed for the designated merchandise and not for cash and that do not exceed $100 from one vendor, or more than $250 in the aggregate from all vendors, per calendar year), are strictly prohibited. Employees must obtain approval from their Vice President in writing (or by email) before extending or accepting an invitation to golfing, hunting, fishing or other trips and outings.

Special rules, such as the Foreign Corrupt Practices Act (FCPA) in the U.S. and similar laws of other nations, apply to those dealing with domestic and foreign government agencies and companies owned by foreign governments and agencies, and the legal rules may differ in various countries. Partners and customers may have policies of their own with which Apache employees are expected to comply in our business relationships. Gifts to government employees and officials, generally, are not permitted under U.S. law or laws in the countries in which we do business and any gift to a government employee, official or their family members must be nominal in amount, must not violate local or U.S. law, and must be approved by the Regional vice president for the relevant area before such gift is made.

Remember to exercise caution by asking questions first and accepting or giving gifts later. Questions to ask yourself that can assist you in making this determination include:

• Is it legal?

• Is it ethical?

• Does it feel right?

• Have I discussed it with my supervisor?

• Am I trying to hide this from anyone?

• Am I trying to fool anyone, including myself?

• Would it embarrass Apache, myself or my family if it were discovered?

Lastly, there is another tool that you can use to help you in deciding whether to accept a gift; it is called “the Newspaper Test.” Think to yourself, “Before I accept (or give) this gift, I should consider how it would look in a newspaper story.” If you are uncomfortable with the answer, then don’t accept (or give) the gift. If you are uncomfortable disclosing the gift to senior management, then don’t accept (or give) the gift.

Revised: 13 November 2013 Page 4 of 7

  CODE OF BUSINESS CONDUCT

Proper Handling of Confidential Information

Employees shall not divulge to third parties any confidential information obtained during employment or service for Apache.

During and after employment by or service with Apache, directors, officers, and employees shall not divulge to third parties, or appropriate to their own use, or to the use of others, any confidential information obtained during employment or service for Apache. The term “confidential information” as used in this policy includes but is not limited to:

1. trade secrets;

2. technical materials and information;

3. geological and geophysical information, reserve data, prospect data, maps and logs;

4. bid data and transaction information;

5. processes and technology;

6. compilations of information, engineering information, financial information, or specifications that are used in the operation of Apache’s business or that may eventually be used in the operation of Apache’s business, and

7. other information relating to the Company’s business that is not public knowledge.

Fair Dealing

No officer, director or employee is authorized to use unfair techniques, misrepresentation, bribes or kickbacks to gain a business advantage.

Apache is committed to conducting its business fairly and in accordance with the highest ethical standards. No director, officer, or employee is authorized to use unfair techniques, such as misrepresentation of material facts or improper concealment of business information to gain a business advantage. Additionally, no director, officer, or employee or representative of the Company shall offer or accept a bribe, kickback, or improper favor in order to secure a business advantage.

Ensuring the Protection and Proper Use of Apache Assets

Use or access to Company property for any unlawful or improper purpose is strictly prohibited.

This prohibition includes any use that is unlawful or improper under applicable law or ethical standards, regardless of the practices of other companies or individuals. As part of this obligation, officers and employees shall follow Company procedures to ensure that business transactions are consistently executed, recorded, and reported in such a manner as to allow the Company to accurately compile and report its financial statements. Additionally, all transaction records shall be preserved for the appropriate amount of time in accordance with Company policy.

Revised: 13 November 2013 Page 5 of 7

  CODE OF BUSINESS CONDUCT

Complying with Laws, Rules and Regulations

It is Apache’s policy to conduct its business in accordance with all applicable laws, rules, regulations, and government requirements.

Each director, officer, and employee of the Company is responsible for familiarizing himself or herself with the laws, rules, regulations, and government requirements applicable to his responsibilities within the Company.

Reporting Illegal or Unethical Behavior

Each officer or employee of the Company is directly responsible for promptly reporting to the Company any actual, attempted, or apparent violation of laws, rules, regulations, or this Code of Business Conduct.

In the event that a violation is observed by, responsibly reported to, or is indicated by records or other information of which the officer or employee becomes aware, the person should report the event to his immediate supervisor, the Human Resources Department, Internal Audit, or any member of management with whom the person is comfortable discussing the matter. Any concerns regarding accounting, internal accounting controls, or auditing matters should be reported to the Audit Committee of the board of directors through the Company’s procedures for such reporting set forth in “Procedures for the submission of complaints and concerns regarding accounting, internal accounting controls, or auditing matters” available on Apache’s website at www.apachecorp.com. Officers and employees should always keep in mind that the Company supports the good faith reporting and investigation of potential violations of this Code of Business Conduct. In no event will the Company take or threaten any action against an officer or employee for making a complaint or disclosing information in good faith. Retaliation or retribution against any officer or employee who in good faith reports a violation pursuant to this Code of Business Conduct is cause for disciplinary action, up to and including termination of employment.

Enforcement

Each officer and employee of the company will be responsible for enforcement of the Code of Business Conduct in his or her activity and in the activities of his or her direct reports, in consultation with the Company’s General Counsel and Human Resources Department.

Disciplinary actions with regard to officers and employees of the Company will be implemented by the Human Resources Department in accordance with the Company’s disciplinary procedures. Under certain circumstances, violation of this Code of Business Conduct may also result in referral for civil action or criminal prosecution.

Revised: 13 November 2013 Page 6 of 7

  CODE OF BUSINESS CONDUCT

Waivers

The Company does not approve of the types of conduct prohibited by this Code of Business Conduct and would grant exceptions very rarely.

In the rare circumstance where a waiver of the Code of Business Conduct would be appropriate, such a waiver for an employee who is not an executive officer must be approved by the Chief Executive Officer (CEO), his designee, or pursuant to policies and procedures approved by the CEO. Any waiver of the code for a director or executive officer of the Company must be approved by the CG&N Committee and the full board, with a majority of the members of the CG&N Committee voting to approve the waiver being directors who are disinterested, as defined by applicable law, with respect to the matter giving rise to the need for a waiver. Any waiver of the Code of Business Conduct approved for a director or executive officer will be promptly disclosed to the extent required by law, regulations, or listing standards.

Revised: 13 November 2013 Page 7 of 7

EX-21.1

Exhibit 21.1

Page 1 of 4

Apache Corporation (a Delaware corporation)

Listing of Subsidiaries as of February 20, 2014

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 Holdings, Inc.	Delaware
Apache International Employment Inc.	Delaware
Apache International LLC	Delaware
Apache JS Holdings, Inc.	Delaware
Apache LNG, Inc.	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 New Zealand Corporation LDC	Cayman Islands
Apache Oil Corporation	Texas
Apache Overseas, Inc.	Delaware
Apache Argentina Corporation	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

Exhibit 21.1

Page 2 of 4

Apache Corporation (a Delaware corporation)

Listing of Subsidiaries as of February 20, 2014

Exact Name of Subsidiary and Name under which Subsidiary does Business	Jurisdiction of Incorporation or Organization
Apache East Bahariya Corporation LDC	Cayman Islands
Apache El Diyur Corporation LDC	Cayman Islands
Apache Faiyum 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 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 Egypt Holdings III Corporation LDC	Cayman Islands
Apache Egypt Holdings IV Corporation LDC	Cayman Islands
Apache Egypt GP 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 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 Finance Pty Limited	Australian Capital Territory
Apache Australia Management Pty Limited	Victoria, Australia
Apache Australia Holdings Pty Limited	Western Australia
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
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 III Limited	England and Wales
Beryl North Sea II Limited	Cayman Islands
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

Exhibit 21.1

Page 3 of 4

Apache Corporation (a Delaware corporation)

Listing of Subsidiaries as of February 20, 2014

Exact Name of Subsidiary and Name under which Subsidiary does Business	Jurisdiction of Incorporation or Organization
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 Onshore 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.	Singapore
Northwest Jetty Services Pty Ltd	Western Australia
Apache Latin America II Corporation LDC	Cayman Islands
Apache Madera Corporation LDC	Cayman Islands
Apache Netherlands Investment B.V.	The Netherlands
Apache Suriname Corporation LDC	Cayman Islands
Apache Overseas Holdings LLC	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
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 Exploration LLC	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 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

Exhibit 21.1

Page 4 of 4

Apache Corporation (a Delaware corporation)

Listing of Subsidiaries as of February 20, 2014

Exact Name of Subsidiary and Name under which Subsidiary does Business	Jurisdiction of Incorporation or Organization
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
CV Energy Corporation	Delaware
Clear Creek Hunting Preserve, Inc.	Wyoming
Cottonwood Aviation, Inc.	Delaware
DEK Energy Company	Delaware
Apache Canada Ltd.	Alberta, Canada
Apache Canada Chile Holdings ULC	Alberta, Canada
Apache Chile Energìa SPA	Chile
Apache Austria Investment LLC	Delaware
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 Capital Canada Inc.	Alberta, Canada
Apache FC Canada Enterprises Inc.	Alberta, Canada
KM LNG Operating Ltd.	British Columbia
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
MC Beltway 8, LLC	Delaware
Miller Exploration Company	Delaware
Kitimat Development Inc.	Delaware
Phoenix Exploration Resources, Ltd.	Delaware
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, 333-178672, and 333-190619) of Apache Corporation;

of our reports dated February 28, 2014, 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) of Apache Corporation for the year ended December 31, 2013.

/s/ Ernst & Young LLP

Houston, Texas

February 28, 2014

EX-23.2

EXHIBIT 23.2

TBPE REGISTERED ENGINEERING FIRM F-1580	FAX (713) 651-0849
1100 LOUISIANA             SUITE 4600             HOUSTON, TEXAS 77002-5294	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, 2013, 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, 333-178672, and 333-190619), and to the inclusion of our report, dated February 5, 2014, 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, 2014

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 of the Board, Chief Executive Officer, and President

Date: February 28, 2014

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

Senior Vice President, Finance

(principal financial officer)

Date: February 28, 2014

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, 2013, 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 of the Board, Chief Executive Officer, and President
	(principal executive officer)

Date: February 28, 2014

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, 2013, 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:	Senior Vice President, Finance
	(principal financial officer)

Date: February 28, 2014

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, 2013

\s\ Jennifer Fitzgerald

Jennifer A. Fitzgerald, P.E.

TBPE License No. 100572

Senior 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 STREET SUITE 4600 HOUSTON, TEXAS 77002-5294	TELEPHONE (713) 651-9191

February 5, 2014

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, 2013 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 February 2, 2014 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, 2013. 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, 2013. Based on the estimates of total net proved reserves prepared by Apache, the reserves audit conducted by Ryder Scott addresses 91 percent of the total proved developed net liquid hydrocarbon reserves, 86 percent of the total proved developed net gas reserves, 71 percent of the total proved undeveloped net liquid hydrocarbon reserves, and 87 percent of the total proved undeveloped net gas reserves of Apache.

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 5, 2014

Page 2

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 83 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, 2013. Total coverage of world-wide reserves is 92.5 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.”

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, 2013 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, 2013, 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, 2013

	% 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		91.2		88.2		86.4		726,402		190,092		4,253,791		69,998		25,432		672,177		796,400		215,524		4,925,968
Undeveloped		69.6		75.7		86.8		234,199		56,542		2,094,349		102,490		18,191		317,995		336,689		74,733		2,412,344
Total Proved		84.8		85.0		86.5		960,601		246,634		6,348,140		172,488		43,623		990,172		1,133,089		290,257		7,338,312

RYDER SCOTT COMPANY     PETROLEUM CONSULTANTS

Apache Corporation

February 5, 2014

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, 2013

	% 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
USA
Developed		92.7		88.6		82.9		424,645		163,378		1,662,342		33,336		21,107		343,623		457,981		184,485		2,005,965
Undeveloped		73.6		73.6		73.2		144,092		46,779		488,491		51,744		16,760		178,671		195,836		63,539		667,162
Total Proved		87.0		84.7		80.5		568,737		210,157		2,150,833		85,080		37,867		522,294		653,817		248,024		2,673,127
Canada
Developed		92.7		89.3		84.8		74,668		23,295		1,097,950		5,859		2,805		196,470		80,527		26,100		1,294,420
Undeveloped		43.4		91.6		84.9		24,442		9,133		372,886		31,924		837		66,151		56,366		9,970		439,037
Total Proved		72.4		89.9		84.9		99,110		32,428		1,470,836		37,783		3,642		262,621		136,893		36,070		1,733,457
Argentina
Developed		54.3		54.1		65.8		8,144		1,791		190,108		6,851		1,520		99,025		14,995		3,311		289,133
Undeveloped		74.0		51.5		65.4		1,650		520		79,557		580		489		42,027		2,230		1,009		121,584
Total Proved		56.9		53.5		65.7		9,794		2,311		269,665		7,431		2,009		141,052		17,225		4,320		410,717
Australia
Developed		97.9		N/A		99.0		22,039		0		620,131		484		0		6,412		22,523		0		626,543
Undeveloped		100.0		N/A		100.0		36,702		0		975,223		0		0		0		36,702		0		975,223
Total Proved		99.2		N/A		99.6		58,741		0		1,595,354		484		0		6,412		59,225		0		1,601,766
Egypt
Developed		85.5		N/A		96.3		101,981		0		598,779		17,259		0		22,951		119,240		0		621,730
Undeveloped		41.4		N/A		91.7		6,749		0		174,592		9,553		0		15,758		16,302		0		190,350
Total Proved		80.2		N/A		95.2		108,730		0		773,371		26,812		0		38,709		135,542		0		812,080
United Kingdom
Developed		93.9		100.0		95.8		94,925		1,628		84,481		6,209		0		3,696		101,134		1,628		88,177
Undeveloped		70.3		51.2		19.0		20,564		110		3,600		8,689		105		15,388		29,253		215		18,988
Total Proved		88.6		94.3		82.2		115,489		1,738		88,081		14,898		105		19,084		130,387		1,843		107,165

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.

RYDER SCOTT COMPANY     PETROLEUM CONSULTANTS

Apache Corporation

February 5, 2014

Page 4

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. 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. The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, 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

RYDER SCOTT COMPANY     PETROLEUM CONSULTANTS

Apache Corporation

February 5, 2014

Page 5

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 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 2013, 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 2013. 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.

RYDER SCOTT COMPANY     PETROLEUM CONSULTANTS

Apache Corporation

February 5, 2014

Page 6

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.

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, 2013 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.

RYDER SCOTT COMPANY     PETROLEUM CONSULTANTS

Apache Corporation

February 5, 2014

Page 7

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.

Geographic Area	Product	Price Reference	Average Benchmark Prices	Average Realized Prices
North America
United States	Oil/Condensate	WTI Cushing	$96.82/Bbl	$93.59/Bbl
	NGLs	Mt. Belvieu Non-Tet Propane	$41.38/Bbl	$34.48/Bbl
	Gas	Henry Hub	$3.67/MMBTU	$3.69/MCF
Canada	Oil/Condensate	WTI Cushing	$96.82/Bbl	$89.64/Bbl
	NGLs	WTI Cushing	$96.82/Bbl	$41.23/Bbl
	Gas	AECO	$2.94/MMBTU	$2.85/MCF
Argentina	Oil/Condensate	Govt. Regulated	$77.51/Bbl	$76.70/Bbl
	NGLs	Nqn LPG	$28.65/Bbl	$28.08/Bbl
	Gas	Contracts	Contract	$3.80/MCF
Australia	Oil/Condensate	NW Shelf	$104.15/Bbl	$107.61/Bbl
	Gas	Contracts	Contract	$9.95/MCF
Egypt	Oil/Condensate	Brent	$108.02/Bbl	$106.69/Bbl
	Gas	Contracts	Contract	$2.96/MCF
United Kingdom	Oil/Condensate	Brent	$108.02/Bbl	$108.02/Bbl
	NGLs	Brent	$108.02/Bbl	$73.80/Bbl
	Gas	NBP	$9.77/MMBTU	$9.75/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 presented herein do not include volumes of 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

RYDER SCOTT COMPANY     PETROLEUM CONSULTANTS

Apache Corporation

February 5, 2014

Page 8

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, 2013. 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

RYDER SCOTT COMPANY     PETROLEUM CONSULTANTS

Apache Corporation

February 5, 2014

Page 9

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, 2013 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.

RYDER SCOTT COMPANY     PETROLEUM CONSULTANTS

Apache Corporation

February 5, 2014

Page 10

We were in reasonable agreement with Apache’s estimates of proved reserves for the properties which we reviewed; although in certain cases there was more than an acceptable variance between Apache’s estimates and our estimates due to a difference in interpretation of data or due to our having access to data which were not available to Apache when its reserve estimates were prepared. However not withstanding, 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 9 percent of the total proved developed net liquid hydrocarbon reserves, 14 percent of the total proved developed net gas reserves, 29 percent of the total proved undeveloped net liquid hydrocarbon reserves, and 13 percent of the total proved undeveloped net gas reserves based on estimates prepared by Apache as of December 31, 2013. The other properties represent 7.5 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, 2013.

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.

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Apache Corporation

February 5, 2014

Page 11

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.

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, 2013 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

Senior Vice President

[SEAL]

JAF (FWZ)/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 Senior 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 on the Board of Directors for 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 2013 continuing education hours, Mrs. Fitzgerald attended 8 hours of formalized training including the 2013 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 8 hours of formalized external training during 2013 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 2013 RSC Reserves Conference and the 2013 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 12 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.

RYDER SCOTT COMPANY     PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

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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.

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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

XML

SUPPLEMENTAL GUARANTOR INFORMATION (Tables)

12 Months Ended

Dec. 31, 2013

Guarantees [Abstract]

Supplemental Condensed Consolidating Statement of Operations And Comprehensive Income

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME

For the Year Ended December 31, 2013

	Apache Corporation			Apache Finance Canada		All Other Subsidiaries of Apache Corporation			Reclassifications & Eliminations			Consolidated
	(In millions)
REVENUES AND OTHER:
Oil and gas production revenues	$	4,585		$	—	$	11,817		$	—		$	16,402
Equity in net income (loss) of affiliates		2,313			17		36			(2,366	)		—
Derivative instrument gains (losses), net		(399	)		—		—			—			(399	)
Other		—			61		(6	)		(4	)		51
		6,499			78		11,847			(2,370	)		16,054
OPERATING EXPENSES:
Depreciation, depletion, and amortization		2,250			—		4,450			—			6,700
Asset retirement obligation accretion		67			—		176			—			243
Lease operating expenses		939			—		2,117			—			3,056
Gathering and transportation		61			—		236			—			297
Taxes other than income		190			—		642			—			832
General and administrative		408			—		99			(4	)		503
Acquisitions, divestitures, and transition		33			—		—			—			33
Financing costs, net		97			5		72			—			174
		4,045			5		7,792			(4	)		11,838
INCOME (LOSS) BEFORE INCOME TAXES		2,454			73		4,055			(2,366	)		4,216
Provision (benefit) for income taxes		222			20		1,686			—			1,928
NET INCOME (LOSS) INCLUDING
NONCONTROLLING INTEREST		2,232			53		2,369			(2,366	)		2,288
Net income attributable to noncontrolling interest		—			—		56			—			56
Preferred stock dividends		44			—		—			—			44
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	2,188		$	53	$	2,313		$	(2,366	)	$	2,188
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	2,204		$	53	$	2,313		$	(2,366	)	$	2,204

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME

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
Acquisitions, divestitures, and 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
NET 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 AND COMPREHENSIVE INCOME

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
Acquisitions, divestitures, and 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
NET 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

Supplemental Condensed Consolidating Statement of Cash Flows

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

For the Year Ended December 31, 2013

	Apache Corporation			Apache Finance Canada			All Other Subsidiaries of Apache Corporation			Reclassifications & Eliminations		Consolidated
	(In millions)
CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	$	1,421		$	315		$	8,099		$	—	$	9,835
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property		(4,291	)		—			(5,728	)		—		(10,019	)
Additions to gas gathering, transmission, and processing facilities		(124	)		—			(1,077	)		—		(1,201	)
Proceeds from divestiture of Gulf of Mexico Shelf properties		3,702			—			—			—		3,702
Acquisitions, other		—			—			(215	)		—		(215	)
Proceeds from Kitimat LNG transaction, net		—			—			396			—		396
Proceeds from sale of oil and gas properties		—			—			307			—		307
Other		(58	)		—			(28	)		—		(86	)
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES		(771	)		—			(6,345	)		—		(7,116	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Commercial paper, credit facility, and bank notes, net		(501	)		—			(12	)		—		(513	)
Intercompany borrowings		3,056			1			(3,057	)		—		—
Payments on fixed rate debt		(1,722	)		(350	)		—			—		(2,072	)
Dividends paid		(360	)		—			—			—		(360	)
Proceeds from sale of noncontrolling interest		—			—			2,948			—		2,948
Shares repurchased		(997	)		—			—			—		(997	)
Other		29			37			(45	)		—		21
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		(495	)		(312	)		(166	)		—		(973	)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		155			3			1,588			—		1,746
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR		—			—			160			—		160
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	155		$	3		$	1,748		$	—	$	1,906

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 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 (USED IN) OPERATING ACTIVITIES	$	2,191		$	13		$	7,749		$	—		$	9,953
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property		(1,478	)		—			(4,936	)		—			(6,414	)
Additions to gas gathering, transmission, and processing facilities		—			—			(664	)		—			(664	)
Acquisitions 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

Supplemental Condensed Consolidating Balance Sheet

CONDENSED CONSOLIDATING BALANCE SHEET

December 31, 2013

	Apache Corporation		Apache Finance Canada		All Other Subsidiaries of Apache Corporation		Reclassifications & Eliminations			Consolidated
	(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	155	$	3	$	1,748	$	—		$	1,906
Receivables, net of allowance		1,043		—		1,909		—			2,952
Inventories		48		—		843		—			891
Drilling advances		49		—		322		—			371
Derivative instruments		1		—		—		—			1
Prepaid assets and other		99		—		146		—			245
Intercompany receivable		5,357		—		—		(5,357	)		—
		6,752		3		4,968		(5,357	)		6,366
PROPERTY AND EQUIPMENT, NET		16,092		—		36,329		—			52,421
OTHER ASSETS:
Intercompany receivable		1,572		—		—		(1,572	)		—
Equity in affiliates		24,743		1,155		449		(26,347	)		—
Goodwill, net		173		—		1,196		—			1,369
Deferred charges and other		166		1,006		1,309		(1,000	)		1,481
	$	49,498	$	2,164	$	44,251	$	(34,276	)	$	61,637
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable	$	956	$	2	$	658	$	—		$	1,616
Current debt		—		—		53		—			53
Asset retirement obligation		115		—		6		—			121
Derivative instruments		299		—		—		—			299
Other current liabilities		896		10		1,705		—			2,611
Intercompany payable		—		—		5,357		(5,357	)		—
		2,266		12		7,779		(5,357	)		4,700
LONG-TERM DEBT		9,374		298		—		—			9,672
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Intercompany payable		—		—		1,572		(1,572	)		—
Income taxes		3,586		—		4,778		—			8,364
Asset retirement obligation		430		—		2,671		—			3,101
Other		446		250		711		(1,000	)		407
		4,462		250		9,732		(2,572	)		11,872
COMMITMENTS AND CONTINGENCIES APACHE SHAREHOLDERS’ EQUITY		33,396		1,604		24,743		(26,347	)		33,396
Noncontrolling interest		—		—		1,997		—			1,997
TOTAL EQUITY		33,396		1,604		26,740		(26,347	)		35,393
	$	49,498	$	2,164	$	44,251	$	(34,276	)	$	61,637

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		102		—		91		—			193
Intercompany receivable		3,766		—		—		(3,766	)		—
		4,891		1		3,836		(3,766	)		4,962
PROPERTY AND EQUIPMENT, NET		18,517		—		34,763		—			53,280
OTHER ASSETS:
Intercompany receivable		4,628		—		—		(4,628	)		—
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	$	40,864	$	(31,472	)	$	60,737
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable	$	639	$	1	$	452	$	—		$	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
Intercompany payable		—		—		3,766		(3,766	)		—
		3,011		4		6,287		(3,766	)		5,536
LONG-TERM DEBT		10,706		647		2		—			11,355
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Intercompany payable		—		—		4,628		(4,628	)		—
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		13,528		(5,628	)		12,515
COMMITMENTS AND CONTINGENCIES TOTAL EQUITY		31,331		1,031		21,047		(22,078	)		31,331
	$	49,408	$	1,937	$	40,864	$	(31,472	)	$	60,737

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Debt - Debt for Apache and Subsidiaries (Parenthetical) (Detail)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Debt Instrument [Line Items]
Notes interest rate	4.375%
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	7.325%	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	2016
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 - Commodity Derivative Activity in Accumulated Other Comprehensive Loss (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Unrealized gain (loss) on derivatives at beginning of period, Before tax	$ (10)	$ 145	$ (54)
Realized amounts reclassified into earnings, Before tax	16	(268)	13
Net change in derivative fair value, Before tax	(6)	113	188
Ineffectiveness reclassified into earnings, Before tax	1		(2)
Unrealized gain (loss) on derivatives at end of period, Before tax	1	(10)	145
Unrealized gain (loss) on derivatives at beginning of period, After tax	(6)	114	(19)
Realized amounts reclassified into earnings, After tax	11	(199)	19
Net change in derivative fair value, After tax	(5)	79	115
Ineffectiveness reclassified into earnings, After tax	1		(1)
Unrealized gain on derivatives at end of period, After tax	$ 1	$ (6)	$ 114

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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, 2013	Dec. 31, 2012
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	0.00%	1.00%
Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	50.00%
Percentage of Plan Assets at Year-End	51.00%	49.00%
Equity Securities [Member] | UK Quoted Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	17.00%
Percentage of Plan Assets at Year-End	18.00%	16.00%
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%	33.00%
Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	50.00%
Percentage of Plan Assets at Year-End	49.00%	50.00%
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	29.00%	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%	20.00%

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Debt - Schedule of Long Term Debt by Maturity (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Debt Disclosure [Abstract]
2014	$ 53
2015
2016	1
2017	900
2018	550
Thereafter	8,280
Total Debt, excluding discounts	$ 9,784	$ 12,411

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Capital Stock - Additional Information (Detail) (USD $)	1 Months Ended	12 Months Ended									2 Months Ended	12 Months Ended
	Jun. 30, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013 Restricted Stock [Member]	Dec. 31, 2012 Restricted Stock [Member]	Dec. 31, 2011 Restricted Stock [Member]	Dec. 31, 2013 Stock Appreciation Rights (SARs) [Member]	Dec. 31, 2012 Stock Appreciation Rights (SARs) [Member]	Dec. 31, 2013 Non Employee Director [Member]	Feb. 28, 2014 Subsequent Event [Member]	Dec. 31, 2013 Performance Program 2010 [Member]	Dec. 31, 2013 Equity Option [Member]	Dec. 31, 2012 Convertible Preferred Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options and restricted stock, anti-dilutive		4,900,000	4,400,000	2,500,000										14,300,000
Common stock share purchase, shares		30,000,000
Common stock share purchase, value		$ 2,000,000,000
Common stock share repurchase, shares	2,924,271	11,221,919									2,393,917
Common stock share repurchase, per share	$ 85.47	$ 90.08									$ 84.67
Dividends, Common stock		$ 0.77	$ 0.66	$ 0.60
Shares authorized and available for grant under 2011 Plan		27,300,000
Compensation expense		136,000,000	167,000,000	113,000,000	82,000,000	74,000,000	76,000,000
Stock-based compensation expenses, after tax		94,000,000	119,000,000	73,000,000	53,000,000	48,000,000	49,000,000
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		4,000,000	12,000,000	50,000,000
Cash received from exercise of options		24,000,000
Additional tax benefit for the amount of intrinsic value in excess of compensation cost		1,500,000
Total compensation cost related to non-vested options not yet recognized					242,000,000								60,000,000
Settlement period for SARs		10 years
Issuance of stock appreciation rights to non-executive employees									180,555
Weighted-average exercise price of SARs									$ 82.63
Nonvested shares outstanding					3,953,000	2,164,000		316,127
Nonvested shares exercisable								201,552
Weighted-average fair value of SARs outstanding								$ 33.41
SARs exercised								237,288
Aggregate cash payments made to settle SARs								11,000,000
Restricted stock units awarded					3,098,029	1,219,886	887,851
Granted, Weighted Average Grant-Date Fair Value		$ 82.95			$ 82.95	$ 85.67	$ 124.16
Restricted stock, capitalized		55,000,000	67,000,000	42,000,000	30,000,000	25,000,000	28,000,000
Weighted-average remaining life of unvested restricted stock units					1 year 3 months 18 days
Total fair value of restricted stock awards vested					$ 88,000,000	$ 114,000,000	$ 85,000,000
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												585,811
Number of restricted stock units awarded												0

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Supplemental Guarantor Information - Supplemental Condensed Consolidating Statement of Cash Flows (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Condensed Financial Statements, Captions [Line Items]
CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	$ 9,835	$ 8,504	$ 9,953
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property	(10,019)	(8,781)	(6,414)
Additions to gas gathering, transmission, and processing facilities	(1,201)	(750)	(664)
Proceeds from divestiture of Gulf of Mexico Shelf properties	3,702
Acquisition of Cordillera		(2,666)
Acquisitions of Mobil North Sea			(1,246)
Equity investment in Yara Pilbara Holdings Pty Limited		(439)
Acquisitions, other	(215)	(252)	(567)
Proceeds from Kitimat LNG transaction, net	396
Proceeds from sale of oil and gas properties	307	27	422
Other	(86)	(563)	(176)
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES	(7,116)	(13,424)	(8,645)
CASH FLOWS FROM FINANCING ACTIVITIES:
Commercial paper, credit facility, and bank notes, net	(513)	549	(925)
Fixed rate debt borrowings		4,978
Payments on fixed rate debt	(2,072)	(400)
Dividends paid	(360)	(332)	(306)
Proceeds from sale of noncontrolling interest	2,948
Shares repurchased	(997)
Other	21	(10)	84
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES	(973)	4,785	(1,147)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	1,746	(135)	161
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	160	295	134
CASH AND CASH EQUIVALENTS AT END OF PERIOD	1,906	160	295
Apache Corporation [Member]
Condensed Financial Statements, Captions [Line Items]
CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	1,421	2,357	2,191
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property	(4,291)	(3,313)	(1,478)
Additions to gas gathering, transmission, and processing facilities	(124)	(48)
Proceeds from divestiture of Gulf of Mexico Shelf properties	3,702
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
Other	(58)	(450)	(81)
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES	(771)	(7,175)	(1,031)
CASH FLOWS FROM FINANCING ACTIVITIES:
Commercial paper, credit facility, and bank notes, net	(501)	502	(927)
Intercompany borrowings	3,056
Fixed rate debt borrowings		4,978
Payments on fixed rate debt	(1,722)	(400)
Dividends paid	(360)	(332)	(306)
Shares repurchased	(997)
Other	29	29	108
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES	(495)	4,777	(1,125)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	155	(41)	35
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR		41	6
CASH AND CASH EQUIVALENTS AT END OF PERIOD	155		41
Apache Finance Canada [Member]
Condensed Financial Statements, Captions [Line Items]
CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	315	(40)	13
CASH FLOWS FROM FINANCING ACTIVITIES:
Intercompany borrowings	1		(1)
Payments on fixed rate debt	(350)
Other	37	35	(7)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES	(312)	35	(8)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	3	(5)	5
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR		5
CASH AND CASH EQUIVALENTS AT END OF PERIOD	3		5
All Other Subsidiaries of Apache Corporation [Member]
Condensed Financial Statements, Captions [Line Items]
CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	8,099	6,187	7,749
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property	(5,728)	(5,468)	(4,936)
Additions to gas gathering, transmission, and processing facilities	(1,077)	(702)	(664)
Acquisitions of Mobil North Sea			(1,246)
Equity investment in Yara Pilbara Holdings Pty Limited		(439)
Acquisitions, other	(215)	(186)	(119)
Proceeds from Kitimat LNG transaction, net	396
Proceeds from sale of oil and gas properties	307	2	218
Other	(28)	(113)	(95)
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES	(6,345)	(6,906)	(6,842)
CASH FLOWS FROM FINANCING ACTIVITIES:
Commercial paper, credit facility, and bank notes, net	(12)	47	2
Intercompany borrowings	(3,057)	697	(763)
Proceeds from sale of noncontrolling interest	2,948
Other	(45)	(114)	(25)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES	(166)	630	(786)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	1,588	(89)	121
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	160	249	128
CASH AND CASH EQUIVALENTS AT END OF PERIOD	1,748	160	249
Reclassifications & Eliminations [Member]
CASH FLOWS FROM INVESTING ACTIVITIES:
Investment in and advances to subsidiaries, net		657	(772)
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES		657	(772)
CASH FLOWS FROM FINANCING ACTIVITIES:
Intercompany borrowings		(697)	764
Other		40	8
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		$ (657)	$ 772

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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, 2013	Dec. 31, 2012
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total Assets	$ 1	$ 33
Total Liabilities	299	116
Derivative Instruments [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Current Assets: Derivative instruments	1	31
Current Liabilities: Derivative instruments	299	116
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

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RETIREMENT AND DEFERRED COMPENSATION PLANS (Tables)

12 Months Ended

Dec. 31, 2013

Compensation And Retirement Disclosure [Abstract]

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, 2013, 2012, and 2011, 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.

	2013						2012						2011
	Pension			Postretirement			Pension			Postretirement			Pension			Postretirement
	Benefits			Benefits			Benefits			Benefits			Benefits			Benefits
	(In millions)
Change in Projected Benefit Obligation
Projected benefit obligation beginning of year	$	177		$	35		$	150		$	30		$	136		$	29
Service cost		5			4			5			4			5			3
Interest cost		7			1			7			1			7			1
Foreign currency exchange rate changes		4			—			7			—			(1	)		—
Actuarial losses (gains)		—			(8	)		14			1			6			(2	)
Effect of curtailment and settlements		—			(3	)		—			—			—			—
Benefits paid		(4	)		(2	)		(6	)		(1	)		(3	)		(1	)
Retiree contributions		—			1			—			—			—			—
Projected benefit obligation at end of year		189			28			177			35			150			30
Change in Plan Assets
Fair value of plan assets at beginning of year		170			—			145			—			135			—
Actual return on plan assets		15			—			14			—			4			—
Foreign currency exchange rates		4			—			6			—			(1	)		—
Employer contributions		6			1			11			1			10			1
Benefits paid		(4	)		(2	)		(6	)		(1	)		(3	)		(1	)
Retiree contributions		—			1			—			—			—			—
Fair value of plan assets at end of year		191			—			170			—			145			—
Funded status at end of year	$	2		$	(28	)	$	(7	)	$	(35	)	$	(5	)	$	(30	)
Amounts recognized in Consolidated Balance Sheet
Current liability		—			(1	)		—			(1	)		—			(1	)
Non-current asset (liability)		2			(27	)		(7	)		(34	)		(5	)		(29	)
	$	2		$	(28	)	$	(7	)	$	(35	)	$	(5	)	$	(30	)
Pre-tax Amounts Recognized in Accumulated Other Comprehensive Income (Loss)
Accumulated gain (loss)		(22	)		1			(32	)		(7	)		(25	)		(6	)
	$	(22	)	$	1		$	(32	)	$	(7	)	$	(25	)	$	(6	)
Weighted Average Assumptions used as of December 31
Discount rate		4.60	%		4.33	%		4.30	%		3.43	%		4.70	%		4.04	%
Salary increases		4.90	%		N/A			4.60	%		N/A			4.60	%		N/A
Expected return on assets		5.60	%		N/A			4.70	%		N/A			4.85	%		N/A
Healthcare cost trend
Initial		N/A			7.00	%		N/A			7.25	%		N/A			7.50	%
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
	2013			2013			2012
Asset Category
Equity securities:
U.K. quoted equities		17	%		18	%		16	%
Overseas quoted equities		33	%		33	%		33	%
Total equity securities		50	%		51	%		49	%
Debt securities:
U.K. Government bonds		30	%		29	%		30	%
U.K. corporate bonds		20	%		20	%		20	%
Debt securities		50	%		49	%		50	%
Cash		0	%		0	%		1	%
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 tables present 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, 2013 and 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)
December 31, 2013
Equity securities:
U.K. quoted equities(1)	$	35	$	—	$	—	$	35
Overseas quoted equities(2)		63		—		—		63
Total equity securities		98		—		—		98
Debt securities:
U.K. Government bonds(3)		54		—		—		54
U.K. corporate bonds(4)		38		—		—		38
Total debt securities		92		—		—		92
Cash		1		—		—		1
Fair value of plan assets	$	191	$	—	$	—	$	191
December 31, 2012
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 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 the 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.

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, 2013, 2012, and 2011:

	2013						2012						2011
	Pension			Postretirement			Pension			Postretirement			Pension			Postretirement
	Benefits			Benefits			Benefits			Benefits			Benefits			Benefits
	(In millions)
Component of Net Periodic Benefit Costs
Service cost	$	5		$	4		$	5		$	4		$	5		$	3
Interest cost		7			1			7			1			7			1
Expected return on assets		(8	)		—			(7	)		—			(8	)		—
Amortization of actuarial (gain) loss		2			—			1			—			—			—
Curtailment (gain) loss		—			(3	)		—			—			—			—
Net periodic benefit cost	$	6		$	2		$	6		$	5		$	4		$	4
Weighted Average Assumptions used to determine Net Period Benefit Cost for the Years ended 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	%

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		6		(4	)

Expected Future Benefit Payment

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:

	Pension		Postretirement
	Benefits		Benefits
	(In millions)
2014	$	5	$	1
2015		5		1
2016		5		2
2017		5		2
2018		5		2
Years 2019-2023		30		16

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Capital Stock - Description of Stock Based Compensation Plans and Related Costs (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Stock-based compensation expensed:
Allocated Share-based Compensation Expense	$ 136	$ 167	$ 113
Restricted stock, capitalized	55	67	42
Total	191	234	155
General and Administrative Expense [Member]
Stock-based compensation expensed:
Allocated Share-based Compensation Expense	89	104	69
Lease Operating Expenses [Member]
Stock-based compensation expensed:
Allocated Share-based Compensation Expense	$ 47	$ 63	$ 44

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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, 2013	Dec. 31, 2012	Dec. 31, 2011
Pension Benefits [Member]
Component of Net Periodic Benefit Costs
Service cost	$ 5	$ 5	$ 5
Interest cost	7	7	7
Curtailment (gain) loss
Healthcare cost trend
Initial
Ultimate in 2022
Pension Benefits [Member] | Periodic Cost [Member]
Component of Net Periodic Benefit Costs
Service cost	5	5	5
Interest cost	7	7	7
Expected return on assets	(8)	(7)	(8)
Amortization of actuarial (gain) loss	2	1
Curtailment (gain) loss
Net periodic benefit cost	6	6	4
Weighted Average Assumptions used to determine Net Period Benefit Cost for the Years ended 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]
Component of Net Periodic Benefit Costs
Service cost	4	4	3
Interest cost	1	1	1
Curtailment (gain) loss	(3)
Healthcare cost trend
Initial	7.00%	7.25%	7.50%
Ultimate in 2022	5.00%	5.00%	5.00%
Postretirement Benefits [Member] | Periodic Cost [Member]
Component of Net Periodic Benefit Costs
Service cost	4	4	3
Interest cost	1	1	1
Expected return on assets
Amortization of actuarial (gain) loss
Curtailment (gain) loss	(3)
Net periodic benefit cost	$ 2	$ 5	$ 4
Weighted Average Assumptions used to determine Net Period Benefit Cost for the Years ended 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%

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Business Segment Information - Financial Segment Information (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Segment Reporting Information [Line Items]
Oil and gas production revenues	$ 16,402	$ 16,947	$ 16,810
Depreciation, depletion, and amortization
Recurring	5,114	4,812	3,814
Additional	1,176	1,926	109
Asset retirement obligation accretion	243	232	154
Lease operating expenses	3,056	2,968	2,605
Gathering and transportation	297	303	296
Taxes other than income	832	862	899
Operating Income (Loss)	5,274	5,473	8,652
Other Expense:
Derivative instrument gains (losses), net	(399)	(79)
Other	51	210	78
General and administrative	(503)	(531)	(459)
Acquisitions, divestitures, and transition	(33)	(31)	(20)
Financing costs, net	(174)	(165)	(158)
INCOME BEFORE INCOME TAXES	4,216	4,877	8,093
Net Property and Equipment	52,421	53,280	45,448
Total Assets	61,637	60,737	52,051
Additions to Net Property and Equipment	12,062	14,955	11,919
United States [Member]
Segment Reporting Information [Line Items]
Oil and gas production revenues	6,902	6,226	6,103
Depreciation, depletion, and amortization
Recurring	2,338	2,056	1,684
Additional	552
Asset retirement obligation accretion	94	112	97
Lease operating expenses	1,320	1,386	1,167
Gathering and transportation	84	69	64
Taxes other than income	335	292	259
Operating Income (Loss)	2,179	2,311	2,832
Other Expense:
Net Property and Equipment	27,010	28,552	21,038
Total Assets	29,940	31,175	23,499
Additions to Net Property and Equipment	6,404	9,586	3,854
Canada [Member]
Segment Reporting Information [Line Items]
Oil and gas production revenues	1,224	1,322	1,617
Depreciation, depletion, and amortization
Recurring	505	594	546
Additional		1,883
Asset retirement obligation accretion	49	41	26
Lease operating expenses	459	458	470
Gathering and transportation	155	163	165
Taxes other than income	45	50	51
Operating Income (Loss)	11	(1,867)	359
Other Expense:
Net Property and Equipment	6,058	6,640	8,022
Total Assets	6,952	7,142	8,816
Additions to Net Property and Equipment	1,082	1,096	1,288
Egypt [Member]
Segment Reporting Information [Line Items]
Oil and gas production revenues	3,917	4,554	4,791
Depreciation, depletion, and amortization
Recurring	1,005	925	818
Lease operating expenses	471	410	398
Gathering and transportation	42	39	35
Taxes other than income	8	14	13
Operating Income (Loss)	2,391	3,166	3,527
Other Expense:
Net Property and Equipment	5,454	5,151	4,923
Total Assets	8,121	7,311	6,656
Additions to Net Property and Equipment	1,309	1,153	1,015
Australia [Member]
Segment Reporting Information [Line Items]
Oil and gas production revenues	1,140	1,575	1,734
Depreciation, depletion, and amortization
Recurring	423	466	440
Asset retirement obligation accretion	27	17	10
Lease operating expenses	214	215	197
Taxes other than income	13	11	9
Operating Income (Loss)	463	866	1,078
Other Expense:
Net Property and Equipment	6,838	5,312	4,194
Total Assets	8,094	6,280	4,681
Additions to Net Property and Equipment	1,954	1,581	1,140
North Sea [Member]
Segment Reporting Information [Line Items]
Oil and gas production revenues	2,728	2,751	2,091
Depreciation, depletion, and amortization
Recurring	1,022	914	409
Additional	367
Asset retirement obligation accretion	68	58	17
Lease operating expenses	400	315	208
Gathering and transportation	7	24	25
Taxes other than income	384	451	539
Operating Income (Loss)	480	989	893
Other Expense:
Net Property and Equipment	5,622	5,927	5,737
Total Assets	6,902	6,874	6,600
Additions to Net Property and Equipment	1,084	1,104	4,175
Argentina [Member]
Segment Reporting Information [Line Items]
Oil and gas production revenues	491	519	474
Depreciation, depletion, and amortization
Recurring	230	228	198
Additional	181
Asset retirement obligation accretion	5	4	4
Lease operating expenses	192	184	165
Gathering and transportation	9	8	7
Taxes other than income	47	44	28
Operating Income (Loss)	(173)	51	72
Other Expense:
Net Property and Equipment	1,416	1,621	1,512
Total Assets	1,577	1,835	1,766
Additions to Net Property and Equipment	205	337	374
Other International [Member]
Depreciation, depletion, and amortization
Recurring	1
Additional	76	43	109
Operating Income (Loss)	(77)	(43)	(109)
Other Expense:
Net Property and Equipment	23	77	22
Total Assets	51	120	33
Additions to Net Property and Equipment	$ 24	$ 98	$ 73

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Debt - Financing Costs, Net (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Debt Disclosure [Abstract]
Interest expense	$ 571	$ 509	$ 433
Amortization of deferred loan costs	8	7	5
Capitalized interest	(374)	(334)	(263)
Gain on extinguishment of debt	(16)
Interest income	(15)	(17)	(17)
Financing costs, net	$ 174	$ 165	$ 158

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Capital Stock - Common Stock Outstanding (Detail)	1 Months Ended	12 Months Ended
	Jun. 30, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Equity [Abstract]
Balance, beginning of year		391,640,770	384,117,643	382,391,742
Shares issued for stock-based compensation plans:
Treasury shares issued		25,214	60,767	144,313
Common shares issued		929,596	1,189,693	1,581,588
Common shares issued for conversion of preferred shares		14,399,247
Treasury shares acquired	(2,924,271)	(11,221,919)
Cordillera consideration			6,272,667
Balance, end of year		395,772,908	391,640,770	384,117,643

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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, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Statement Of Income And Comprehensive Income [Abstract]
Currency translation adjustment	$ (109)	$ (109)	$ (109)
Unrealized gain (loss) on derivatives	1	(6)	114	(19)
Unfunded pension and postretirement benefit plan	(7)	(16)	(14)
Accumulated other comprehensive loss	$ (115)	$ (131)	$ (9)

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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, 2013	Dec. 31, 2012	Dec. 31, 2011
Equity [Abstract]
Weighted average remaining contractual life for options outstanding	6 years 1 month 6 days
Weighted average remaining contractual life for expected to vest	8 years 2 months 12 days
Weighted average remaining contractual life for exercisable	4 years 8 months 12 days
Aggregate intrinsic value of options outstanding	$ 43
Aggregate intrinsic value of expected to vest	7
Aggregate intrinsic value of exercisable	$ 34
Weighted average fair value of options granted during the year	$ 23.18	$ 26.41	$ 42.20

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Major Customers - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Shell Plc [Member]
Revenue, Major Customer [Line Items]
Entity wide revenue major customer percentage	24.00%	20.00%	11.00%
Vitol Group [Member]
Revenue, Major Customer [Line Items]
Entity wide revenue major customer percentage	13.00%

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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			36 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2012
Earnings Per Share [Abstract]
Net income attributable to common stock	$ 174	$ 300	$ 1,016	$ 698	$ 649	$ 161	$ 337	$ 778	$ 2,188	$ 1,925	$ 4,508	$ 1,925
Mandatory Convertible Preferred Stock									44		76
Net income attributable to common stock, including assumed conversions									$ 2,232	$ 1,925	$ 4,584
Net income attributable to common stock, shares									395	389	384
Mandatory Convertible Preferred Stock									9		14
Stock options and other									2	2	2
Net income attributable to common stock, including assumed conversions, Shares									406	391	400
Net income attributable to common stock, per share	$ 0.44	$ 0.75	$ 2.59	$ 1.78	$ 1.66	$ 0.41	$ 0.87	$ 2.02	$ 5.53	$ 4.95	$ 11.75	$ 4.95
Net income attributable to common stock, including assumed conversions, per share	$ 0.43	$ 0.75	$ 2.54	$ 1.76	$ 1.64	$ 0.41	$ 0.86	$ 2.00	$ 5.50	$ 4.92	$ 11.47	$ 4.92

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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	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 191	$ 170
Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	98	84
Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	92	85
Quoted Price in Active Markets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	191	170
Quoted Price in Active Markets (Level 1) [Member] | Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	98	84
Quoted Price in Active Markets (Level 1) [Member] | Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	92	85
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]
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
Overseas Quoted Equities [Member] | Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	63	56
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	63	56
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	54	51
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	54	51
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
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	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
U.K. Corporate Bonds [Member] | Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	38	34
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	38	34
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
Cash [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1	1
Cash [Member] | Quoted Price in Active Markets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	1	1
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
UK Quoted Equities [Member] | Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	35	28
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	35	28
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

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

12 Months Ended

Dec. 31, 2013

Accounting Policies [Abstract]

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 undivided interests in oil and gas exploration and production ventures and partnerships are proportionately consolidated. The Company consolidates all other investments in which, either through direct or indirect ownership, Apache has more than a 50 percent voting interest or controls the financial and operating decisions. Noncontrolling interests represent third-party ownership in the net assets of a consolidated Apache subsidiary and are reflected separately in the Company’s financial statements. For further information, please refer to Note 2 — Acquisitions and Divestitures. Investments in which Apache holds less than 50 percent of the voting interest are typically 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.

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 with regard to 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 estimate 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 and 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, 2013 and 2012, Apache had $1.9 billion and $160 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 an 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, 2013 and 2012, the Company had an allowance for doubtful accounts of $96 million and $82 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, and similar activities are expensed as incurred. Apache capitalized $401 million, $402 million, and $335 million of internal costs in 2013, 2012, and 2011, respectively.

Proved properties are amortized on a country-by-country basis using the units of production method (UOP). The UOP calculation 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 prospects 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 2013, Apache’s statement of consolidated operations includes additional DD&A of $75 million related to exiting operations in Kenya. In 2012, Apache recorded 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 designated 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 2013, Apache recorded non-cash write-downs of the carrying value of the Company’s proved oil and gas properties totaling $1.1 billion. The after-tax impact of these write-downs was $356 million in the U.S., $139 million in the North Sea, and $118 million in Argentina. Cash flow hedges did not materially affect the 2013 calculations. 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).

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. No gain or loss was recorded on the Company’s divestitures in 2013, 2012, or 2011.

Gathering, Transmission, and Processing Facilities

Gathering, Transmission, and Processing Facilities

Gathering, transmission, and processing facilities totaled $7.0 billion and $6.0 billion at December 31, 2013 and 2012, 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 2013, 2012, or 2011.

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 $2.1 billion and $1.9 billion at December 31, 2013 and 2012, 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 $1.4 billion and $1.3 billion at December 31, 2013 and 2012, respectively. As of December 31, 2013 and 2012, goodwill of $163 million and $84 million, respectively, was recorded in the North Sea. As of December 31, 2013 and 2012, goodwill of $1.0 billion, $103 million, and $86 million was recorded in the U.S., Canada, and Egypt, respectively. Each country was assessed as a reporting unit, and no impairment of goodwill was recognized during 2013, 2012, or 2011.

Accounts Payable

Accounts Payable

Included in accounts payable at December 31, 2013 and 2012, are liabilities of approximately $271 million and $255 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 $34 million, $27 million, and $28 million, for 2013, 2012, and 2011, 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 periods. 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 records all derivative instruments, other than those that meet the normal purchases and sales exception, 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. 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 “Derivative instrument gains (losses), net” under “Revenues and Other” in the statement of consolidated operations. 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. 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.

Apache does not recognize U.S. deferred income taxes on the unremitted earnings of its foreign subsidiaries that are deemed to be indefinitely reinvested. When such earnings are no longer deemed permanently reinvested, Apache recognizes the appropriate deferred or current income tax liabilities.

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.

Foreign currency transaction gains and losses related to current taxes payable and deferred tax assets and liabilities are recorded as components of the provision for income taxes. In 2013, Apache recorded a tax benefit of $154 million, including current and deferred taxes. In 2012 and 2011, the Company recorded tax expense of $16 million and a tax benefit of $66 million, respectively. For further discussion, please refer to 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 loss in 2013 of $30 million and gains in 2012 and 2011 of $24 million and $4 million, respectively.

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 calculations for the years ended December 31, 2011 and 2013, includes weighted-average shares of common stock from the assumed conversion of Apache’s convertible preferred stock. For the year ended December 31, 2012, the diluted EPS calculation excludes shares related to the assumed conversion of the convertible preferred stock as such conversion would have been anti-dilutive.

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.

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 July 2013, the FASB issued ASU No. 2013-11, which requires entities to present unrecognized tax benefits as a decrease in a net operating loss, similar tax loss, or tax credit carryforward if certain criteria are met. The guidance will eliminate the diversity in practice in the presentation of unrecognized tax benefits but will not alter the way in which entities assess deferred tax assets for realizability. ASU No. 2013-11 is effective for annual and interim reporting periods beginning after December 15, 2013. The Company will apply all changes prospectively and does not expect the adoption of this amendment to have a material impact on its consolidated financial statements.

In February 2013, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2013-04, which increases disclosures for certain liability arrangements. The guidance requires an entity that is joint and severally liable to measure the obligation as the sum of the amount the entity has agreed with co-obligors to pay and any additional amount it expects to pay on behalf of one or more co-obligors. Required disclosures include a description of the nature of the arrangement, how the liability arose, the relationship with co-obligors and the terms and conditions of the arrangement. ASU No. 2013-04 is effective for annual and interim reporting periods beginning after December 15, 2013. The Company does not expect the adoption of this amendment to have a material impact on its consolidated financial statements.

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Asset Retirement Obligation - Asset Retirement Obligation (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligation at beginning of year	$ 4,578	$ 3,887
Liabilities incurred	481	592
Liabilities acquired	53	72
Liabilities divested	(1,692)
Liabilities settled	(497)	(550)
Accretion expense	243	232	154
Revisions in estimated liabilities	56	345
Asset retirement obligation at end of year	3,222	4,578	3,887
Less current portion	(121)	(478)
Asset retirement obligation, long-term	$ 3,101	$ 4,100

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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, 2013	Dec. 31, 2012	Dec. 31, 2012 Cordillera Energy Partners [Member]	Dec. 30, 2011 Mobil North Sea Limited [Member]
Business Acquisition [Line Items]
Current assets			$ 39	$ 219
Proved properties	83,390	78,383	1,040	2,341
Unproved properties	8,363	8,754	2,299	476
Gathering, transmission, and processing facilities			1	338
Goodwill			173	84
Deferred tax asset			64
Total assets acquired			3,616	3,458
Current liabilities			88	148
Asset retirement obligation				517
Deferred income tax liabilities			237	1,546
Other long-term obligations			5	1
Total liabilities assumed			330	2,212
Net assets acquired			$ 3,286	$ 1,246

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Retirement and Deferred Compensation Plans - Expected Future Benefit Payment (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
2014	$ 5
2015	5
2016	5
2017	5
2018	5
Years 2019-2023	30
Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
2014	1
2015	1
2016	2
2017	2
2018	2
Years 2019-2023	$ 16

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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, 2013	Dec. 31, 2012
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Cash inflows	$ 154,598	$ 161,347
Production costs	(50,554)	(52,408)
Development costs	(15,155)	(17,225)
Income tax expense	(23,428)	(24,216)
Net cash flows	65,471	67,498
10 percent discount rate	(32,877)	(32,945)
Discounted future net cash flows	32,594	34,553
United States [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Cash inflows	79,654	84,060
Production costs	(26,032)	(27,230)
Development costs	(4,834)	(6,768)
Income tax expense	(12,832)	(12,740)
Net cash flows	35,956	37,322
10 percent discount rate	(20,117)	(19,464)
Discounted future net cash flows	15,839	17,858
Canada [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Cash inflows	19,260	20,512
Production costs	(8,105)	(8,543)
Development costs	(2,458)	(2,916)
Income tax expense	(678)	(754)
Net cash flows	8,019	8,299
10 percent discount rate	(3,987)	(4,472)
Discounted future net cash flows	4,032	3,827
Egypt [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Cash inflows	16,864	16,210
Production costs	(2,590)	(2,126)
Development costs	(1,899)	(1,756)
Income tax expense	(4,328)	(4,246)
Net cash flows	8,047	8,082
10 percent discount rate	(2,193)	(2,107)
Discounted future net cash flows	5,854	5,975
Australia [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Cash inflows	20,637	20,823
Production costs	(4,494)	(4,896)
Development costs	(2,283)	(2,484)
Income tax expense	(3,072)	(3,172)
Net cash flows	10,788	10,271
10 percent discount rate	(6,423)	(6,361)
Discounted future net cash flows	4,365	3,910
North Sea [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Cash inflows	15,359	16,732
Production costs	(8,147)	(8,451)
Development costs	(3,284)	(3,053)
Income tax expense	(2,376)	(3,163)
Net cash flows	1,552	2,065
10 percent discount rate	(85)	(98)
Discounted future net cash flows	1,637	1,967
Argentina [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Cash inflows	2,824	3,010
Production costs	(1,176)	(1,162)
Development costs	(397)	(248)
Income tax expense	(142)	(141)
Net cash flows	1,109	1,459
10 percent discount rate	(242)	(443)
Discounted future net cash flows	$ 867	$ 1,016

XML

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2013

Extractive Industries [Abstract]

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(3)		Australia		North Sea		Argentina			Other International			Total(3)
	(In millions, except per boe)
2013
Oil and gas production revenues	$	6,902	$	1,224		$	3,917	$	1,140	$	2,728	$	491		$	—		$	16,402
Operating cost:
Depreciation, depletion, and amortization
Recurring(1)		2,227		426			881		361		999		220			—			5,114
Additional		552		—			—		—		367		181			76			1,176
Asset retirement obligation accretion		94		49			—		27		68		5			—			243
Lease operating expenses		1,320		459			471		214		400		192			—			3,056
Gathering and transportation		84		155			42		—		7		9			—			297
Production taxes(2)		324		40			—		14		382		36			—			796
Income tax		817		24			1,161		157		313		(53	)		—			2,419
		5,418		1,153			2,555		773		2,536		590			76			13,101
Results of operation	$	1,484	$	71		$	1,362	$	367	$	192	$	(99	)	$	(76	)	$	3,301
Amortization rate per boe	$	18.39	$	10.89		$	16.21	$	17.47	$	37.25	$	14.13		$	—		$	18.42
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			—		—		—		—			109			1,992
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			109			14,207
Results of operation	$	1,545	$	(1,379	)	$	1,654	$	610	$	377	$	42		$	(109	)	$	2,740
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

(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) 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.

(3) 2013 includes a noncontrolling interest in Egypt.

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(2)			Australia			North Sea		Argentina		Other International		Total(2)
	(In millions)
2013
Acquisitions:
Proved	$	17	$	—	$	35		$	—		$	125	$	—	$	—	$	177
Unproved		—		137		11			—			17		—		—		165
Exploration		757		50		563			169			278		53		22		1,892
Development		5,435		722		618			996			635		142		—		8,548
Costs incurred(1)	$	6,209	$	909	$	1,227		$	1,165		$	1,055	$	195	$	22	$	10,782
(1) Includes capitalized interest and asset retirement costs as follows:
Capitalized interest	$	239	$	35	$	15		$	16		$	25	$	10	$	—	$	340
Asset retirement costs		480		17		—			(30	)		67		3		—		537
(2) Includes a noncontrolling interest in Egypt.
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

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(1)			Australia			North Sea			Argentina			Other International			Total(1)
	(In millions)
2013
Proved properties	$	41,904		$	13,231		$	8,418		$	7,298		$	9,378		$	2,933		$	228		$	83,390
Unproved properties		5,042			1,116			660			471			702			349			23			8,363
		46,946			14,347			9,078			7,769			10,080			3,282			251			91,753
Accumulated DD&A		(20,745	)		(9,310	)		(5,356	)		(2,839	)		(4,811	)		(1,964	)		(228	)		(45,253	)
	$	26,201		$	5,037		$	3,722		$	4,930		$	5,269		$	1,318		$	23		$	46,500
(1) Includes a noncontrolling interest in Egypt.
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

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, 2013, 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		2013		2012		2011		2010 and Prior
	(In millions)
Property acquisition costs	$	6,437	$	466	$	3,391	$	899	$	1,681
Exploration and development		1,666		1,138		388		88		52
Capitalized interest		260		48		48		30		134
Total	$	8,363	$	1,652	$	3,827	$	1,017	$	1,867

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 reserve data in the following tables only represent estimates and should not be construed as being exact.

	Crude Oil and Condensate
	(Thousands of barrels)
	United States			Canada			Egypt(1)			Australia			North Sea			Argentina			Total(1)
Proved developed reserves:
December 31, 2010		422,737			90,292			109,657			48,072			115,705			16,583			803,046
December 31, 2011		428,251			81,846			105,840			35,725			136,990			16,001			804,653
December 31, 2012		474,837			79,695			106,746			29,053			119,635			15,845			825,811
December 31, 2013		457,981			80,526			119,242			22,524			100,327			14,195			794,795
Proved undeveloped reserves:
December 31, 2010		214,117			56,855			17,470			18,064			38,663			4,062			349,231
December 31, 2011		205,763			59,746			22,195			32,220			32,415			4,585			356,924
December 31, 2012		203,068			70,650			17,288			34,808			28,019			2,981			356,814
December 31, 2013		195,835			56,366			16,302			36,703			29,253			2,231			336,690
Total proved reserves:
Balance December 31, 2010		636,855			147,146			127,127			66,136			154,368			20,645			1,152,277
Extensions, discoveries and other additions		45,676			16,712			45,021			15,762			332			3,230			126,733
Purchase of minerals in-place		5,097			705			—			—			34,612			—			40,414
Revisions of previous estimates		(8,904	)		(17,117	)		(6,185	)		—			—			215			(31,991	)
Production		(43,587	)		(5,202	)		(37,928	)		(13,953	)		(19,907	)		(3,503	)		(124,080	)
Sale of properties		(1,123	)		(653	)		—			—			—			—			(1,776	)
Balance December 31, 2011		634,014			141,591			128,035			67,945			169,405			20,587			1,161,577
Extensions, discoveries and other additions		84,656			18,935			36,188			6,277			346			1,133			147,535
Purchase of minerals in-place		15,942			188			—			276			2,143			—			18,549
Revisions of previous estimates		(7,474	)		(4,577	)		(3,678	)		(66	)		(928	)		671			(16,052	)
Production		(49,089	)		(5,792	)		(36,511	)		(10,571	)		(23,312	)		(3,565	)		(128,840	)
Sale of properties		(144	)		—			—			—			—			—			(144	)
Balance December 31, 2012		677,905			150,345			124,034			63,861			147,654			18,826			1,182,625
Extensions, discoveries and other additions		133,227			10,177			43,738			2,539			1,543			998			192,222
Purchase of minerals in-place		85			—			5			—			3,623			—			3,713
Revisions of previous estimates		1,683			(531	)		457			(118	)		18			24			1,533
Production		(53,621	)		(6,469	)		(32,690	)		(7,055	)		(23,258	)		(3,422	)		(126,515	)
Sale of properties		(105,463	)		(16,630	)		—			—			—			—			(122,093	)
Balance December 31, 2013		653,816			136,892			135,544			59,227			129,580			16,426			1,131,485

(1) 2013 includes proved reserves of 45 MMbbls as of December 31, 2013 attributable to a noncontrolling interest in Egypt.

	Natural Gas Liquids
	(Thousands of barrels)
	United States			Canada			Egypt			Australia		North Sea			Argentina			Total
Proved developed reserves:
December 31, 2010		91,800			23,701			—			—		—			5,875			121,376
December 31, 2011		107,490			23,256			—			—		8,753			5,939			145,438
December 31, 2012		154,508			21,996			—			—		2,438			5,007			183,949
December 31, 2013		184,485			26,099			—			—		2,435			4,110			217,129
Proved undeveloped reserves:
December 31, 2010		30,361			4,142			—			—		—			579			35,082
December 31, 2011		52,543			8,193			—			—		509			1,215			62,460
December 31, 2012		60,889			12,258			—			—		380			876			74,403
December 31, 2013		63,538			9,970			—			—		215			1,009			74,732
Total proved reserves:
Balance December 31, 2010		122,160			27,844			—			—		—			6,454			156,458
Extensions, discoveries and other additions		43,915			5,890			18			—		72			1,784			51,679
Purchase of minerals in-place		586			47			—			—		9,191			—			9,824
Revisions of previous estimates		1,713			774			—			—		—			17			2,504
Production		(8,071	)		(2,174	)		(18	)		—		(1	)		(1,102	)		(11,366	)
Sale of properties		(270	)		(931	)		—			—		—			—			(1,201	)
Balance December 31, 2011		160,033			31,450			—			—		9,262			7,153			207,898
Extensions, discoveries and other additions		71,965			7,655			—			—		246			—			79,866
Purchase of minerals in-place		230			9			—			—		231			—			470
Revisions of previous estimates		(4,559	)		(2,569	)		—			—		(6,329	)		(169	)		(13,626	)
Production		(12,272	)		(2,291	)		—			—		(592	)		(1,101	)		(16,256	)
Sale of properties		—			—			—			—		—			—			—
Balance December 31, 2012		215,397			34,254			—			—		2,818			5,883			258,352
Extensions, discoveries and other additions		69,231			4,014			—			—		—			—			73,245
Purchase of minerals in-place		45			—			—			—		295			—			340
Revisions of previous estimates		1,591			546			—			—		1			3			2,141
Production		(19,922	)		(2,442	)		—			—		(464	)		(767	)		(23,595	)
Sale of properties		(18,319	)		(303	)		—			—		—			—			(18,622	)
Balance December 31, 2013		248,023			36,069			—			—		2,650			5,119			291,861

	Natural Gas
	(Millions of cubic feet)
	United States			Canada			Egypt(1)			Australia			North Sea			Argentina			Total(1)
Proved developed reserves:
December 31, 2010		2,284,116			2,181,615			748,573			682,763			4,144			462,206			6,363,417
December 31, 2011		2,215,973			2,108,801			700,866			675,618			105,028			447,132			6,253,418
December 31, 2012		2,353,587			1,734,657			690,436			596,052			93,319			365,054			5,833,105
December 31, 2013		2,005,966			1,294,420			621,825			626,543			88,177			289,133			4,926,064
Proved undeveloped reserves:
December 31, 2010		988,869			1,310,352			328,344			805,735			—			70,465			3,503,765
December 31, 2011		760,238			1,438,710			282,100			893,966			3,414			90,427			3,468,855
December 31, 2012		832,320			403,227			205,055			1,074,018			18,985			97,496			2,631,101
December 31, 2013		667,160			439,037			190,355			975,224			18,988			121,584			2,412,348
Total proved reserves:
Balance December 31, 2010		3,272,985			3,491,967			1,076,917			1,488,498			4,144			532,671			9,867,182
Extensions, discoveries and other additions		169,506			505,049			77,049			148,640			475			81,274			981,993
Purchase of minerals in-place		67,595			8,838			—			—			104,658			—			181,091
Revisions of previous estimates		(7,716	)		(133,359	)		(37,623	)		—			—			1,107			(177,591	)
Production		(315,631	)		(230,880	)		(133,377	)		(67,554	)		(835	)		(77,493	)		(825,770	)
Sale of properties		(210,528	)		(94,104	)		—			—			—			—			(304,632	)
Balance December 31, 2011		2,976,211			3,547,511			982,966			1,569,584			108,442			537,559			9,722,273
Extensions, discoveries and other additions		365,863			252,130			55,967			176,969			16,397			2,623			869,949
Purchase of minerals in-place		313,885			2,503			—			1,745			8,494			—			326,627
Revisions of previous estimates		(156,840	)		(1,443,989	)		(13,974	)		101			—			496			(1,614,206	)
Production		(312,600	)		(219,849	)		(129,468	)		(78,329	)		(21,029	)		(78,128	)		(839,403	)
Sale of properties		(612	)		(422	)		—			—			—			—			(1,034	)
Balance December 31, 2012		3,185,907			2,137,884			895,491			1,670,070			112,304			462,550			8,464,206
Extensions, discoveries and other additions		306,721			359,493			44,382			13,351			2,750			16,515			743,212
Purchase of minerals in-place		855			—			—			—			10,680			—			11,535
Revisions of previous estimates		61,247			109,551			2,413			(101	)		32			49			173,191
Production		(285,187	)		(181,593	)		(130,106	)		(81,553	)		(18,601	)		(68,397	)		(765,437	)
Sale of properties		(596,417	)		(691,878	)		—			—			—			—			(1,288,295	)
Balance December 31, 2013		2,673,126			1,733,457			812,180			1,601,767			107,165			410,717			7,338,412

(1) 2013 includes proved reserves of 271 Bcf as of December 31, 2013 attributable to a noncontrolling interest in Egypt.

	Total Equivalent Reserves
	(Thousands barrels of oil equivalent)
	United States			Canada			Egypt(1)			Australia			North Sea			Argentina			Total(1)
Proved developed reserves:
December 31, 2010		895,223			477,594			234,419			161,866			116,396			99,493			1,984,991
December 31, 2011		905,069			456,569			222,651			148,328			163,248			96,462			1,992,327
December 31, 2012		1,021,610			390,800			221,819			128,395			137,626			81,695			1,981,945
December 31, 2013		976,795			322,362			222,880			126,948			117,457			66,494			1,832,936
Proved undeveloped reserves:
December 31, 2010		409,290			279,389			72,194			152,353			38,663			16,385			968,274
December 31, 2011		385,013			307,724			69,212			181,214			33,493			20,871			997,527
December 31, 2012		402,677			150,113			51,464			213,811			31,563			20,106			869,734
December 31, 2013		370,566			139,509			48,028			199,240			32,633			23,504			813,480
Total proved reserves:
Balance December 31, 2010		1,304,512			756,984			306,613			314,219			155,059			115,878			2,953,265
Extensions, discoveries and other additions		117,842			106,778			57,882			40,534			483			18,559			342,078
Purchase of minerals in-place		16,949			2,225			—			—			61,246			—			80,420
Revisions of previous estimates		(8,477	)		(38,570	)		(12,456	)		—			—			417			(59,086	)
Production		(104,263	)		(45,856	)		(60,176	)		(25,211	)		(20,047	)		(17,521	)		(273,074	)
Sale of properties		(36,481	)		(17,268	)		—			—			—			—			(53,749	)
Balance December 31, 2011		1,290,082			764,293			291,863			329,542			196,741			117,333			2,989,854
Extensions, discoveries and other additions		217,598			68,612			45,516			35,772			3,325			1,570			372,393
Purchase of minerals in-place		68,486			614			—			567			3,790			—			73,457
Revisions of previous estimates		(38,172	)		(247,811	)		(6,007	)		(49	)		(7,258	)		585			(298,712	)
Production		(113,461	)		(44,725	)		(58,089	)		(23,626	)		(27,409	)		(17,687	)		(284,997	)
Sale of properties		(246	)		(70	)		—			—			—			—			(316	)
Balance December 31, 2012		1,424,287			540,913			273,283			342,206			169,189			101,801			2,851,679
Extensions, discoveries and other additions		253,578			74,107			51,135			4,764			2,001			3,751			389,336
Purchase of minerals in-place		273			—			5			—			5,698			—			5,976
Revisions of previous estimates		13,482			18,274			859			(135	)		24			35			32,539
Production		(121,074	)		(39,177	)		(54,374	)		(20,647	)		(26,822	)		(15,589	)		(277,683	)
Sale of properties		(223,185	)		(132,246	)		—			—			—			—			(355,431	)
Balance December 31, 2013		1,347,361			461,871			270,908			326,188			150,090			89,998			2,646,416

(1) 2013 includes total proved reserves of 90 MMboe attributable to a noncontrolling interest in Egypt.

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(2)			Australia			North Sea			Argentina			Total(2)
	(In millions)
2013
Cash inflows	$	79,654		$	19,260		$	16,864		$	20,637		$	15,359		$	2,824		$	154,598
Production costs		(26,032	)		(8,105	)		(2,590	)		(4,494	)		(8,147	)		(1,176	)		(50,554	)
Development costs		(4,834	)		(2,458	)		(1,899	)		(2,283	)		(3,284	)		(397	)		(15,155	)
Income tax expense		(12,832	)		(678	)		(4,328	)		(3,072	)		(2,376	)		(142	)		(23,428	)
Net cash flows		35,956			8,019			8,047			10,788			1,552			1,109			65,471
10 percent discount rate		(20,117	)		(3,987	)		(2,193	)		(6,423	)		85			(242	)		(32,877	)
Discounted future net cash flows(1)	$	15,839		$	4,032		$	5,854		$	4,365		$	1,637		$	867		$	32,594
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

(1) Estimated future net cash flows before income tax expense, discounted at 10 percent per annum, totaled approximately $45.4 billion and $48.2 billion as of December 31, 2013 and 2012, respectively.

(2) Includes discounted future net cash flows of approximately $1.95 billion in 2013 attributable to a noncontrolling interest in Egypt.

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,
	2013			2012			2011
	(In millions)
Sales, net of production costs	$	(12,271	)	$	(12,589	)	$	(13,152	)
Net change in prices and production costs		1,438			(1,941	)		12,167
Discoveries and improved recovery, net of related costs		6,892			6,742			6,751
Change in future development costs		(2,017	)		(935	)		(2,250	)
Previously estimated development costs incurred during the period		4,654			4,359			2,479
Revision of quantities		500			(4,065	)		(1,475	)
Purchases of minerals in-place		227			1,181			2,139
Accretion of discount		4,823			5,234			4,161
Change in income taxes		855			2,711			(4,303	)
Sales of properties		(6,232	)		(3	)		(1,285	)
Change in production rates and other		(828	)		(2,088	)		273
	$	(1,959	)	$	(1,394	)	$	5,505

XML

Debt - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Debt Instrument [Line Items]
Payments on fixed rate debt	$ 2,072,000,000	$ 400,000,000
Margin over LIBOR for committed loans	4.375%
Marketable securities fixed maturities	850,000,000
Redemption of notes	350,000,000
Amount paid for redemption of notes	371,000,000
Gain on extinguishment of debt	16,000,000
Unsecured credit facility available to Company	3,300,000,000
Revolving bank facility	1,700,000,000
Line of Credit Facility, Remaining Borrowing Capacity	3,300,000,000
Line of Credit Facility, Interest Rate Description	At December 31, 2013, 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.
Debt to Capitalization ratio	0.22
Percentage of liens of companies consolidated asset	5.00%
Maximum potential lien on assets located in specified regions	3,100,000,000
Weighted average interest rate for commercial paper	0.38%
Available backstops	100.00%
Carrying Amount, Commercial paper	0	489,000,000
Debt before unamortized discount	9,784,000,000	12,411,000,000
Unamortized discount	59,000,000	66,000,000
Amortization of Debt Discount (Premium)	3,000,000	3,000,000	2,000,000
Unamortized deferred loan costs associated with its various debt obligations	73,000,000	70,000,000
Notes Payable, Other Payables [Member]
Debt Instrument [Line Items]
Period For Borrowing Funds	270 days
Apache finance Canada 7.75% notes due 2029 [Member]
Debt Instrument [Line Items]
Margin over LIBOR for committed loans	7.75%	7.75%
Debt before unamortized discount	300,000,000	300,000,000
United States [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	9,430,000,000	11,682,000,000
Australia [Member]
Debt Instrument [Line Items]
Revolving bank facility	300,000,000
Canada [Member]
Debt Instrument [Line Items]
Revolving bank facility	300,000,000
Money Market Lines of Credit [Member]
Debt Instrument [Line Items]
Outstanding balance under the facility secured revolving syndicated	53,000,000	91,000,000
Credit Facility One [Member] | United States [Member]
Debt Instrument [Line Items]
Revolving bank facility	1,700,000,000
Credit Facility Two [Member] | United States [Member]
Debt Instrument [Line Items]
Revolving bank facility	1,000,000,000
6.00 - Percent Notes [Member]
Debt Instrument [Line Items]
Payments on fixed rate debt	400,000,000
Margin over LIBOR for committed loans	6.00%
Credit facility maturity date	Sep. 15, 2013
6.00 - Percent Notes [Member] | 2.625 Percent Senior Notes due 2023 [Member]
Debt Instrument [Line Items]
Marketable securities fixed maturities	669,000,000
Payments to acquire available for sale securities debt	811,000,000
6.00 - Percent Notes [Member] | 3.25 Percent Senior Notes Due 2022 [Member]
Debt Instrument [Line Items]
Marketable securities fixed maturities	181,000,000
5.25 - Percent Notes [Member]
Debt Instrument [Line Items]
Margin over LIBOR for committed loans	5.25%
Credit facility maturity date	Apr. 15, 2013
5.25 - Percent Notes [Member] | 2.625 Percent Senior Notes due 2023 [Member]
Debt Instrument [Line Items]
Margin over LIBOR for committed loans	5.25%
Unsecured Committed Bank Credit Facilities [Member]
Debt Instrument [Line Items]
Margin over LIBOR for committed loans	0.875%
Quarterly facility fees	0.125 percent on the total amount
Unsecured Committed Bank Credit Facilities in U.S. [Member]
Debt Instrument [Line Items]
Margin over LIBOR for committed loans	0.90%
Quarterly facility fees	0.10 percent on the total amount
Unsecured Committed Bank Credit Facilities in Australia [Member]
Debt Instrument [Line Items]
Margin over LIBOR for committed loans	0.90%
Quarterly facility fees	0.10 percent on the total amount
Unsecured Committed Bank Credit Facilities in Canada [Member]
Debt Instrument [Line Items]
Margin over LIBOR for committed loans	0.90%
Quarterly facility fees	0.10 percent on the total amount
Revolving Credit Facility Due August 2016 [Member]
Debt Instrument [Line Items]
Credit facility maturity date	Aug. 31, 2016
Unsecured credit facility available to Company	1,000,000,000
Revolving Credit Facility Due June 2017 [Member]
Debt Instrument [Line Items]
Credit facility maturity date	Jun. 30, 2017
Unsecured credit facility available to Company	2,300,000,000
Maximum [Member]
Debt Instrument [Line Items]
Debt to Capitalization ratio	0.60
Commercial paper program	$ 3,000,000,000

XML

Commitments and Contingencies - Contractual Obligations (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013
Oil and Gas Delivery Commitments and Contracts [Line Items]
Total	$ 4,493
2014	1,772
2015-2016	1,581
2017-2018	778
2019 & Beyond	362
Drilling Rig Commitments [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Total	974
2014	376
2015-2016	429
2017-2018	157
2019 & Beyond	12
Purchase Obligations [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Total	1,759
2014	1,002
2015-2016	533
2017-2018	204
2019 & Beyond	20
Firm Transportation Agreements [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Total	683
2014	158
2015-2016	223
2017-2018	129
2019 & Beyond	173
Office Equipment [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Total	391
2014	46
2015-2016	101
2017-2018	95
2019 & Beyond	149
Other Contractual Obligation [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Total	686
2014	190
2015-2016	295
2017-2018	193
2019 & Beyond	$ 8

XML

Income Taxes - Net Deferred Tax Liability (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Deferred tax assets:
Deferred income	$ 153	$ 33
Federal and state net operating loss carryforwards	900	932
Foreign net operating loss carryforwards	156	61
Tax credits	66	78
Accrued expenses and liabilities	162	2
Asset retirement obligation	1,231	1,677
Total deferred tax assets	2,668	2,783
Valuation allowance	(651)	(419)
Net deferred tax assets	2,017	2,364
Deferred tax liabilities:
Other	29	23
Depreciation, depletion and amortization	10,224	10,213
Total deferred tax liabilities	10,253	10,236
Net deferred income tax liability	$ 8,236	$ 7,872

XML

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, 2013	Dec. 31, 2012	Dec. 31, 2011
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	$ (16)	$ 268	$ (13)
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	(1)		2
Derivative Instrument Gains (Losses), Net [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Loss on derivatives not designated as cash flow hedges	$ (399)	$ (79)

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

12 Months Ended

Dec. 31, 2013

Accounting Policies [Abstract]

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). The Company’s financial statements for prior periods may include reclassifications that were made to conform to the 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 undivided interests in oil and gas exploration and production ventures and partnerships are proportionately consolidated. The Company consolidates all other investments in which, either through direct or indirect ownership, Apache has more than a 50 percent voting interest or controls the financial and operating decisions. Noncontrolling interests represent third-party ownership in the net assets of a consolidated Apache subsidiary and are reflected separately in the Company’s financial statements. For further information, please refer to Note 2 — Acquisitions and Divestitures. Investments in which Apache holds less than 50 percent of the voting interest are typically 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.

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 with regard to 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 estimate 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 and 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, 2013 and 2012, Apache had $1.9 billion and $160 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 an 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, 2013 and 2012, the Company had an allowance for doubtful accounts of $96 million and $82 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, and similar activities are expensed as incurred. Apache capitalized $401 million, $402 million, and $335 million of internal costs in 2013, 2012, and 2011, respectively.

Proved properties are amortized on a country-by-country basis using the units of production method (UOP). The UOP calculation 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 prospects 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 2013, Apache’s statement of consolidated operations includes additional DD&A of $75 million related to exiting operations in Kenya. In 2012, Apache recorded 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 designated 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 2013, Apache recorded non-cash write-downs of the carrying value of the Company’s proved oil and gas properties totaling $1.1 billion. The after-tax impact of these write-downs was $356 million in the U.S., $139 million in the North Sea, and $118 million in Argentina. Cash flow hedges did not materially affect the 2013 calculations. 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).

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. No gain or loss was recorded on the Company’s divestitures in 2013, 2012, or 2011.

Gathering, Transmission, and Processing Facilities

Gathering, transmission, and processing facilities totaled $7.0 billion and $6.0 billion at December 31, 2013 and 2012, 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 2013, 2012, or 2011.

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 $2.1 billion and $1.9 billion at December 31, 2013 and 2012, 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 $1.4 billion and $1.3 billion at December 31, 2013 and 2012, respectively. As of December 31, 2013 and 2012, goodwill of $163 million and $84 million, respectively, was recorded in the North Sea. As of December 31, 2013 and 2012, goodwill of $1.0 billion, $103 million, and $86 million was recorded in the U.S., Canada, and Egypt, respectively. Each country was assessed as a reporting unit, and no impairment of goodwill was recognized during 2013, 2012, or 2011.

Accounts Payable

Included in accounts payable at December 31, 2013 and 2012, are liabilities of approximately $271 million and $255 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 $34 million, $27 million, and $28 million, for 2013, 2012, and 2011, 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 periods. 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 records all derivative instruments, other than those that meet the normal purchases and sales exception, 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. 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 “Derivative instrument gains (losses), net” under “Revenues and Other” in the statement of consolidated operations. 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. 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.

Apache does not recognize U.S. deferred income taxes on the unremitted earnings of its foreign subsidiaries that are deemed to be indefinitely reinvested. When such earnings are no longer deemed permanently reinvested, Apache recognizes the appropriate deferred or current income tax liabilities.

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.

Foreign currency transaction gains and losses related to current taxes payable and deferred tax assets and liabilities are recorded as components of the provision for income taxes. In 2013, Apache recorded a tax benefit of $154 million, including current and deferred taxes. In 2012 and 2011, the Company recorded tax expense of $16 million and a tax benefit of $66 million, respectively. For further discussion, please refer to 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 loss in 2013 of $30 million and gains in 2012 and 2011 of $24 million and $4 million, respectively.

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 calculations for the years ended December 31, 2011 and 2013, includes weighted-average shares of common stock from the assumed conversion of Apache’s convertible preferred stock. For the year ended December 31, 2012, the diluted EPS calculation excludes shares related to the assumed conversion of the convertible preferred stock as such conversion would have been anti-dilutive.

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 $1 million, $4 million, and $32 million as financing cash inflows in 2013, 2012, and 2011, 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 July 2013, the FASB issued ASU No. 2013-11, which requires entities to present unrecognized tax benefits as a decrease in a net operating loss, similar tax loss, or tax credit carryforward if certain criteria are met. The guidance will eliminate the diversity in practice in the presentation of unrecognized tax benefits but will not alter the way in which entities assess deferred tax assets for realizability. ASU No. 2013-11 is effective for annual and interim reporting periods beginning after December 15, 2013. The Company will apply all changes prospectively and does not expect the adoption of this amendment to have a material impact on its consolidated financial statements.

In February 2013, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2013-04, which increases disclosures for certain liability arrangements. The guidance requires an entity that is joint and severally liable to measure the obligation as the sum of the amount the entity has agreed with co-obligors to pay and any additional amount it expects to pay on behalf of one or more co-obligors. Required disclosures include a description of the nature of the arrangement, how the liability arose, the relationship with co-obligors and the terms and conditions of the arrangement. ASU No. 2013-04 is effective for annual and interim reporting periods beginning after December 15, 2013. The Company does not expect the adoption of this amendment to have a material impact on its consolidated financial statements.

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Income Taxes - Additional Information (Detail) (USD $)	0 Months Ended	12 Months Ended
	Nov. 14, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Tax Contingency [Line Items]
Increase in valuation allowances		$ 232,000,000	$ 359,000,000	$ 7,000,000
Proceeds against participation in business	2,950,000,000
Proceeds against participation in business	225,000,000
Cash repatriation from foreign subsidiaries	643,000,000
Tax expenses recorded		1,000,000	5,000,000	6,000,000
Accrued for payment of interest and penalties		1,000,000	5,000,000
Settlements			65,000,000	22,000,000
United States [Member]
Income Tax Contingency [Line Items]
Operating loss carryforwards		1,558,000,000
Mariner Energy Inc [Member]
Income Tax Contingency [Line Items]
Operating loss carryforwards		520,000,000
Cordillera Energy Partners [Member]
Income Tax Contingency [Line Items]
Operating loss carryforwards		183,000,000
Canada [Member]
Income Tax Contingency [Line Items]
Operating loss carryforwards		5,000,000
Capital loss carryforwards		186,000,000
Apache Egypt [Member]
Income Tax Contingency [Line Items]
Undistributed earnings of the foreign subsidiaries		$ 17,000,000,000

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Derivative Instruments and Hedging Activities - Additional Information (Detail)	Dec. 31, 2013 Counterparty
Derivative [Line Items]
Number of counterparties	14
Fixed-Price Swaps [Member] | 2014 [Member] | Nymex Henry Hub [Member] | Derivatives Not Designated as Cash Flow Hedging Instruments [Member] | Open Natural Gas Derivative Positions [Member]
Derivative [Line Items]
Open positions	55,900,000
Weighted average fixed price	4.35

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ASSET RETIREMENT OBLIGATION (Tables)

12 Months Ended

Dec. 31, 2013

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligation

The following table describes changes to the Company’s asset retirement obligation (ARO) liability for the years ended December 31, 2013 and 2012:

	2013			2012
	(In millions)
Asset retirement obligation at beginning of year	$	4,578		$	3,887
Liabilities incurred		481			592
Liabilities acquired		53			72
Liabilities divested		(1,692	)		—
Liabilities settled		(497	)		(550	)
Accretion expense		243			232
Revisions in estimated liabilities		56			345
Asset retirement obligation at end of year		3,222			4,578
Less current portion		(121	)		(478	)
Asset retirement obligation, long-term	$	3,101		$	4,100

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OTHER CURRENT LIABILITIES (Tables)

12 Months Ended

Dec. 31, 2013

Payables And Accruals [Abstract]

Detail of Other Current Liabilities

The following table provides detail of the Company’s other current liabilities at December 31, 2013 and 2012:

	December 31, 2013		December 31, 2012
	(In millions)
Accrued operating expenses	$	190	$	211
Accrued exploration and development		1,582		1,792
Accrued compensation and benefits		242		198
Accrued interest		161		160
Accrued income taxes		248		297
Accrued U.K. Petroleum Revenue Tax		9		53
Other		179		149
Total Other current liabilities	$	2,611	$	2,860

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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			36 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2012
Quarterly Financial Information Disclosure [Abstract]
Revenues and other	$ 3,576	$ 4,019	$ 4,383	$ 4,076	$ 4,391	$ 4,179	$ 3,972	$ 4,536	$ 16,054	$ 17,078	$ 16,888	$ 17,078
Expenses	3,346	3,713	3,348	3,359	3,723	3,999	3,616	3,739	11,838	12,201	8,795	15,077
Net income including noncontrolling interest	230	306	1,035	717	668	180	356	797	2,288	2,001	4,584	2,001
Net income attributable to common stock	174	300	1,016	698	649	161	337	778	2,188	1,925	4,508	1,925
Net income per common share(1):
Revenues and other	3,576	4,019	4,383	4,076	4,391	4,179	3,972	4,536	16,054	17,078	16,888	17,078
Expenses	3,346	3,713	3,348	3,359	3,723	3,999	3,616	3,739	11,838	12,201	8,795	15,077
Net income including noncontrolling interest	230	306	1,035	717	668	180	356	797	2,288	2,001	4,584	2,001
Net income attributable to common stock	$ 174	$ 300	$ 1,016	$ 698	$ 649	$ 161	$ 337	$ 778	$ 2,188	$ 1,925	$ 4,508	$ 1,925
Basic	$ 0.44	$ 0.75	$ 2.59	$ 1.78	$ 1.66	$ 0.41	$ 0.87	$ 2.02	$ 5.53	$ 4.95	$ 11.75	$ 4.95
Diluted	$ 0.43	$ 0.75	$ 2.54	$ 1.76	$ 1.64	$ 0.41	$ 0.86	$ 2.00	$ 5.50	$ 4.92	$ 11.47	$ 4.92

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Debt - Non-Recurring Fair Value Measurement (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Debt Instrument [Line Items]
Commercial paper, Carrying Amount	$ 0	$ 489
Total Debt, Carrying Amount	9,725	12,345
Total Debt, Fair Value	10,300	13,920
Money Market Lines of Credit [Member]
Debt Instrument [Line Items]
Money market lines of credit, Carrying Amount	53	91
Total Debt, Fair Value	53	91
Commercial Paper [Member]
Debt Instrument [Line Items]
Commercial paper, Carrying Amount		489
Total Debt, Fair Value		489
Notes and Debentures [Member]
Debt Instrument [Line Items]
Notes and debentures, Carrying Amount	9,672	11,765
Total Debt, Fair Value	$ 10,247	$ 13,340

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Derivative Instruments and Hedging Activities - Open Crude Oil and Natural Gas Derivative Positions (Detail) (2014 [Member], Fixed-Price Swaps [Member])	Dec. 31, 2013 MBbls
Open Crude Oil Derivative Positions [Member] | Derivatives Not Designated as Cash Flow Hedging Instruments [Member] | NYMEX WTI [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Open positions	22,889
Open positions	90.77
Open Crude Oil Derivative Positions [Member] | Derivatives Not Designated as Cash Flow Hedging Instruments [Member] | Dated Brent [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Open positions	22,812
Open positions	100.05
Open Natural Gas Derivative Positions [Member] | Derivative Asset Designated As Hedging Instruments [Member] | Nymex Henry Hub [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Open positions	1,295,000,000
Open positions	6.72

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DEBT (Tables)

12 Months Ended

Dec. 31, 2013

Debt Disclosure [Abstract]

Debt for Apache and Subsidiaries

The following table presents the carrying value of the Company’s debt at December 31, 2013 and 2012:

	December 31,
	2013			2012
	(In millions)
U.S.:
Money market lines of credit	$	—		$	13
Commercial paper		—			489
5.25% notes due 2013(1)		—			500
6.0% notes due 2013(1)		—			400
5.625% notes due 2017(1)		500			500
1.75% notes due 2017(1)		400			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)		919			1,100
2.625% notes due 2023(1)		531			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			1,500
4.25% notes due 2044(1)		800			800
7.375% debentures due 2047		150			150
7.625% debentures due 2096		150			150
		9,430			11,682
Subsidiary and other obligations:
Argentina overdraft lines of credit		51			69
Canada lines of credit		2			9
Apache Finance Canada 4.375% notes due 2015(1)		—			350
Notes due in 2016 and 2017		1			1
Apache Finance Canada 7.75% notes due 2029		300			300
		354			729
Debt before unamortized discount		9,784			12,411
Unamortized discount		(59	)		(66	)
Total debt	$	9,725		$	12,345
Current maturities	$	(53	)	$	(990	)
Long-term debt	$	9,672		$	11,355

⁽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, 2013, excluding discounts, are as follows:

	(In millions)
2014	$	53
2015		—
2016		1
2017		900
2018		550
Thereafter		8,280
Total Debt, excluding discounts	$	9,784

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 (a Level 2 fair value measurement).

	December 31, 2013				December 31, 2012
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)
Money market lines of credit	$	53	$	53	$	91	$	91
Commercial paper		—		—		489		489
Notes and debentures		9,672		10,247		11,765		13,340
Total Debt	$	9,725	$	10,300	$	12,345	$	13,920

Financing Costs, Net

Financing Costs, Net

The following table presents the components of Apache’s financing costs, net:

	For the Year Ended December 31,
	2013			2012			2011
	(In millions)
Interest expense	$	571		$	509		$	433
Amortization of deferred loan costs		8			7			5
Capitalized interest		(374	)		(334	)		(263	)
Gain on extinguishment of debt		(16	)		—			—
Interest income		(15	)		(17	)		(17	)
Financing costs, net	$	174		$	165		$	158

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INCOME TAXES (Tables)

12 Months Ended

Dec. 31, 2013

Income Tax Disclosure [Abstract]

Income Before Income Taxes

Income before income taxes is composed of the following:

	For the Year Ended December 31,
	2013		2012		2011
	(In millions)
U.S.	$	1,191	$	1,605	$	2,373
Foreign		3,025		3,272		5,720
Total	$	4,216	$	4,877	$	8,093

Total Provision for Income Taxes

The total provision for income taxes consists of the following:

	For the Year Ended December 31,
	2013			2012			2011
	(In millions)
Current taxes:
Federal	$	(29	)	$	(150	)	$	64
State		—			—			2
Foreign		1,694			2,349			2,197
		1,665			2,199			2,263
Deferred taxes:
Federal		509			596			656
State		44			10			17
Foreign		(290	)		71			573
		263			677			1,246
Total	$	1,928		$	2,876		$	3,509

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,
	2013			2012			2011
	(In millions)
Income tax expense at U.S. statutory rate	$	1,476		$	1,707		$	2,833
State income tax, less federal benefit		29			6			12
Taxes related to foreign operations		200			773			568
Tax credits		6			(4	)		(15	)
Deferred tax on distributed foreign earnings		225			—			—
Current and deferred taxes related to currency fluctuations		(154	)		16			(66	)
Change in U.K. tax rate		—			118			218
Net change in tax contingencies		(10	)		(115	)		(6	)
Valuation allowances		199			355			8
All other, net		(43	)		20			(43	)
	$	1,928		$	2,876		$	3,509

Net Deferred Tax Liability

The net deferred tax liability consists of the following:

	December 31,
	2013			2012
	(In millions)
Deferred tax assets:
Deferred income	$	153		$	33
Federal and state net operating loss carryforwards		900			932
Foreign net operating loss carryforwards		156			61
Tax credits		66			78
Accrued expenses and liabilities		162			2
Asset retirement obligation		1,231			1,677
Total deferred tax assets		2,668			2,783
Valuation allowance		(651	)		(419	)
Net deferred tax assets		2,017			2,364
Deferred tax liabilities:
Other		29			23
Depreciation, depletion and amortization		10,224			10,213
Total deferred tax liabilities		10,253			10,236
Net deferred income tax liability	$	8,236		$	7,872

Net Operating Losses

On December 31, 2013, the Company had net operating losses as follows:

	December 31, 2013
	Amount		Expiration
	(In millions)
Net operating losses:
U.S. — Federal	$	1,558		2032 - 2034
U.S. — Federal (Mariner IRC §382 limited)		520		2018 - 2030
U.S. — Federal (Cordillera IRC §382 limited)		183		2026 - 2032
U.S. — State		2,242		Various
Canada		5		2014
Australia		59		Indefinite
Argentina		299		2014

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:

	2013		2012			2011
	(In millions)
Balance at beginning of year	$	3	$	97		$	110
Additions based on tax positions related to the current year		—		4			13
Reductions for tax positions of prior years		—		(33	)		(4	)
Settlements		—		(65	)		(22	)
Balance at end of year	$	3	$	3		$	97

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.	2010
Canada	2009
Egypt	1998
Australia	2009
U.K.	2011
Argentina	2006

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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, 2013	Dec. 31, 2012	Dec. 31, 2011
Income tax benefit (expense) to post retirement	$ 9	$ 5	$ 7
Tax (benefit) expense to commodity hedges	4	35	66
Common stock, dividends, per share	$ 0.80	$ 0.68	$ 0.60
Retained Earnings [Member]
Common stock, dividends, per share	$ 0.80	$ 0.68	$ 0.60
Accumulated Other Comprehensive Income (Loss) [Member]
Income tax benefit (expense) to post retirement	9	5	7
Tax (benefit) expense to commodity hedges	4	35	66
Parent [Member]
Income tax benefit (expense) to post retirement	9	5	7
Tax (benefit) expense to commodity hedges	$ 4	$ 35	$ 66
Common stock, dividends, per share	$ 0.80	$ 0.68	$ 0.60

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COMMITMENTS AND CONTINGENCIES (Tables)

12 Months Ended

Dec. 31, 2013

Commitments And Contingencies Disclosure [Abstract]

Contractual Obligations

At December 31, 2013, contractual obligations for drilling rigs, purchase obligations, firm transportation agreements, and long-term operating leases are as follows:

									2019 &
Net Minimum Commitments	Total		2014		2015-2016		2017-2018		Beyond
	(In millions)
Drilling rig commitments(1)	$	974	$	376	$	429	$	157	$	12
Purchase obligations(2)		1,759		1,002		533		204		20
Firm transportation agreements(3)		683		158		223		129		173
Office and related equipment(4)		391		46		101		95		149
Other operating lease obligations(5)		686		190		295		193		8
Total Net Minimum Commitments	$	4,493	$	1,772	$	1,581	$	778	$	362

(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 $81 million, $76 million, and $64 million for 2013, 2012, and 2011, respectively.

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Capital Stock - Restricted Stock (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Non-vested at January 1, 2013, Weighted Average Grant Date Fair Value	$ 97.34
Granted, Weighted Average Grant-Date Fair Value	$ 82.95
Vested, Weighted Average Grant-Date Fair Value	$ 96.79
Forfeited, Weighted Average Grant-Date Fair Value	$ 88.61
Non-vested at December 31, 2013, Weighted Average Grant Date Fair Value	$ 86.70
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted Shares, nonvested, Beginning Balance, Shares	2,164,000
Granted, Shares	3,098,029	1,219,886	887,851
Vested, Shares	(907,000)
Forfeited or cancelled, Shares	(402,000)
Restricted Shares, nonvested, Ending Balance, Shares	3,953,000	2,164,000
Granted, Weighted Average Grant-Date Fair Value	$ 82.95	$ 85.67	$ 124.16

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Summary of Significant Accounting Policies - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Summary of Significant Accounting Policies [Line Items]
Cash and cash equivalents	$ 1,906,000,000	$ 160,000,000	$ 295,000,000	$ 134,000,000
Allowance for Doubtful Accounts	96,000,000	82,000,000
Capitalized internal costs	46,500,000,000	48,159,000,000
Impairment of operations	1,176,000,000	1,992,000,000	109,000,000
Seismic costs		15,000,000	49,000,000
Write-down of the carrying value of Oil and Gas properties	1,100,000,000
Write-down of the carrying value of Oil and Gas properties, net of tax	659,000,000
Significant portion of reserve quantity	Greater than 25 percent
Gain (loss) recorded on divestitures	0	0	0
Gathering, transmission and processing facilities	6,995,000,000	5,955,000,000
Accumulated depreciation	47,398,000,000	40,867,000,000
Goodwill	1,369,000,000	1,289,000,000
Accounts payable	271,000,000	255,000,000
Net cost of third party gas	34,000,000	27,000,000	28,000,000
Maximum percentage of production available to contract partners	40.00%
Additional net tax expense related to foreign currency translation gains and losses	154,000,000	16,000,000	66,000,000
Other foreign currency gains and losses	(30,000,000)	24,000,000	4,000,000
Benefit of tax deductions in excess of recognized compensation cost	1,000,000	4,000,000	32,000,000
Gas Gathering Transmission And Processing Facilities [Member]
Summary of Significant Accounting Policies [Line Items]
Accumulated depreciation	2,100,000,000	1,900,000,000
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
Kenya [Member]
Summary of Significant Accounting Policies [Line Items]
Impairment of operations	75,000,000
Canada [Member]
Summary of Significant Accounting Policies [Line Items]
Capitalized internal costs	5,037,000,000	5,637,000,000
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
United States [Member]
Summary of Significant Accounting Policies [Line Items]
Capitalized internal costs	26,201,000,000	27,836,000,000
Impairment of operations	552,000,000
Write-down of the carrying value of Oil and Gas properties, net of tax	356,000,000
Goodwill	1,000,000,000	1,000,000,000
North Sea [Member]
Summary of Significant Accounting Policies [Line Items]
Capitalized internal costs	5,269,000,000	5,582,000,000
Impairment of operations	367,000,000
Write-down of the carrying value of Oil and Gas properties, net of tax	139,000,000
Argentina [Member]
Summary of Significant Accounting Policies [Line Items]
Capitalized internal costs	1,318,000,000	1,526,000,000
Impairment of operations	181,000,000
Write-down of the carrying value of Oil and Gas properties, net of tax	118,000,000
Canada, Dollars
Summary of Significant Accounting Policies [Line Items]
Goodwill	103,000,000	103,000,000
Egypt [Member]
Summary of Significant Accounting Policies [Line Items]
Capitalized internal costs	3,722,000,000	3,377,000,000
Goodwill	86,000,000	86,000,000
Mobil North Sea Limited [Member]
Summary of Significant Accounting Policies [Line Items]
Goodwill	163,000,000	84,000,000
Apache Corporation [Member]
Summary of Significant Accounting Policies [Line Items]
Cash and cash equivalents	155,000,000		41,000,000	6,000,000
Capitalized internal costs	401,000,000	402,000,000	335,000,000
Goodwill	$ 173,000,000	$ 173,000,000
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]
Summary of Significant Accounting Policies [Line Items]
Voting interest required for consolidation of investments	50.00%
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

XML

Debt - Debt for Apache and Subsidiaries (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Debt Instrument [Line Items]
Debt before unamortized discount	$ 9,784	$ 12,411
Unamortized discount	(59)	(66)
Notes interest rate	4.375%
Total debt	9,725	12,345
Current maturities	(53)	(990)
Long-term debt	9,672	11,355
Commercial Paper [Member]
Debt Instrument [Line Items]
Debt before unamortized discount		489
United States [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	9,430	11,682
Argentina Overdraft Lines of Credit [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	51	69
Canada Lines Of Credit [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	2	9
Money Market Lines of Credit [Member]
Debt Instrument [Line Items]
Debt before unamortized discount		13
5.25% notes due 2013 [Member]
Debt Instrument [Line Items]
Debt before unamortized discount		500
Debt maturity year	2013	2013
Notes interest rate	5.25%	5.25%
6.0% notes due 2013 [Member]
Debt Instrument [Line Items]
Debt before unamortized discount		400
Debt maturity year	2013	2013
Notes interest rate	6.00%	6.00%
5.625% notes due 2017 [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	500	500
Debt maturity year	2017	2017
Notes interest rate	5.625%	5.625%
One Point Seven Five Percentage Notes Due Twenty Seventeen [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	400	400
Debt maturity year	2017	2017
Notes interest rate	1.75%	1.75%
6.9% notes due 2018 [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	400	400
Debt maturity year	2018	2018
Notes interest rate	6.90%	6.90%
7.0% notes due 2018 [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	150	150
Debt maturity year	2018	2018
Notes interest rate	7.00%	7.00%
7.625% notes due 2019 [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	150	150
Debt maturity year	2019	2019
Notes interest rate	7.625%	7.625%
3.625% notes due 2021 [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	500	500
Debt maturity year	2021	2021
Notes interest rate	3.625%	3.625%
Three Point Two Five Percentage Notes Due Twenty Twenty Two [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	919	1,100
Debt maturity year	2022	2022
Notes interest rate	3.25%	3.25%
Two Point Six Two Five Percentage Notes Due Twenty Twenty Three [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	531	1,200
Debt maturity year	2023	2023
Notes interest rate	2.625%	2.625%
7.7% notes due 2026 [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	100	100
Debt maturity year	2026	2026
Notes interest rate	7.70%	7.70%
7.95% notes due 2026 [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	180	180
Debt maturity year	2026	2026
Notes interest rate	7.95%	7.95%
6.0% notes due 2037 [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	1,000	1,000
Debt maturity year	2037	2037
Notes interest rate	6.00%	6.00%
5.1% notes due 2040 [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	1,500	1,500
Debt maturity year	2040	2040
Notes interest rate	5.10%	5.10%
5.25% notes due 2042 [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	500	500
Debt maturity year	2042	2042
Notes interest rate	5.25%	5.25%
Four Point Seven Five Percentage Notes Due Twenty Forty Three [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	1,500	1,500
Debt maturity year	2043	2043
Notes interest rate	4.75%	4.75%
Four Point Two Five Percentage Notes Due Twenty Forty Four [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	800	800
Debt maturity year	2044	2044
Notes interest rate	4.25%	4.25%
7.375% debentures due 2047 [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	150	150
Debt maturity year	2047	2047
Notes interest rate	7.325%	7.375%
7.625% debentures due 2096 [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	150	150
Debt maturity year	2096	2096
Notes interest rate	7.625%	7.625%
Apache Finance Canada 4.375% notes due 2015 [Member]
Debt Instrument [Line Items]
Debt before unamortized discount		350
Debt maturity year	2015	2015
Notes interest rate	4.375%	4.375%
Notes Due In Twenty Sixteen And Twenty Seventeen [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	1	1
Debt maturity year	2016	2016
Apache finance Canada 7.75% notes due 2029 [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	300	300
Debt maturity year	2029	2029
Notes interest rate	7.75%	7.75%
Subsidiary And Other Obligations [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	$ 354	$ 729

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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, 2013	Dec. 31, 2012
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%
Period for the portion of UK Equities, overseas equities, government bonds and corporate bonds, benchmarked against FTSE	3 years	3 years
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%	33.00%
Index - Linked Index [Member]
Defined Benefit Plan Disclosure [Line Items]
Portion of debt securities government bonds and corporate bonds benchmarked against FTSE	67.00%	67.00%
U.K. Corporate Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Benchmarked against iBoxx Sterling	50	50
Performance target per annum over benchmark against iBoxx Sterling Overall Index	0.75%	0.75%

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STATEMENT OF CONSOLIDATED OPERATIONS (USD $) In Millions, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Oil and gas production revenues:
Oil and gas production revenues	$ 16,402	$ 16,947	$ 16,810
Derivative instrument gains (losses), net	(399)	(79)
Other	51	210	78
Total revenues and other	16,054	17,078	16,888
Oil and gas property and equipment
Recurring	5,114	4,812	3,814
Additional	1,176	1,926	109
Other assets	410	371	281
Asset retirement obligation accretion	243	232	154
Lease operating expenses	3,056	2,968	2,605
Gathering and transportation	297	303	296
Taxes other than income	832	862	899
General and administrative	503	531	459
Acquisitions, divestitures and transition	33	31	20
Financing costs, net	174	165	158
Total operating expenses	11,838	12,201	8,795
INCOME BEFORE INCOME TAXES	4,216	4,877	8,093
Current income tax provision	1,665	2,199	2,263
Deferred income tax provision	263	677	1,246
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTEREST	2,288	2,001	4,584
Net income attributable to noncontrolling interest	56
Preferred stock dividends	44	76	76
NET INCOME ATTRIBUTABLE TO COMMON STOCK	2,188	1,925	4,508
NET INCOME PER COMMON SHARE:
Basic	$ 5.53	$ 4.95	$ 11.75
Diluted	$ 5.50	$ 4.92	$ 11.47
WEIGHTED-AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
Basic	395	389	384
Diluted	406	391	400
DIVIDENDS DECLARED PER COMMON SHARE	$ 0.80	$ 0.68	$ 0.60
Oil Reserves [Member]
Oil and gas production revenues:
Revenues	12,903	13,210	12,679
Natural Gas [Member]
Oil and gas production revenues:
Revenues	2,829	3,193	3,609
Natural Gas Liquids Revenues [Member]
Oil and gas production revenues:
Revenues	$ 670	$ 544	$ 522

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Derivative Instruments and Hedging Activities - Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) (Recurring [Member], USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Quoted Price in Active Markets (Level 1) [Member]
Assets:
Derivatives designated as cash flow hedges
Liabilities:
Derivatives designated as cash flow hedges
Derivatives not designated as cash flow hedges
Total Derivative liabilities
Significant Other Inputs (Level 2) [Member]
Assets:
Derivatives designated as cash flow hedges	3	48
Liabilities:
Derivatives designated as cash flow hedges	1	51
Derivatives not designated as cash flow hedges	300	80
Total Derivative liabilities	301	131
Unobservable Inputs (Level 3) [Member]
Assets:
Derivatives designated as cash flow hedges
Liabilities:
Derivatives designated as cash flow hedges
Derivatives not designated as cash flow hedges
Total Derivative liabilities
Total Fair Value [Member]
Assets:
Derivatives designated as cash flow hedges	3	48
Liabilities:
Derivatives designated as cash flow hedges	1	51
Derivatives not designated as cash flow hedges	300	80
Total Derivative liabilities	301	131
Netting [Member]
Assets:
Derivatives designated as cash flow hedges	(2)	(15)
Liabilities:
Total Derivative liabilities	(2)	(15)
Carrying Amount [Member]
Assets:
Derivatives designated as cash flow hedges	1	33
Liabilities:
Total Derivative liabilities	$ 299	$ 116

XML

Supplemental Oil and Gas Disclosures - Proved Reserve Data (Parenthetical) (Detail)	Dec. 31, 2013 MBbls	Dec. 31, 2012 MBbls	Dec. 31, 2011 MBbls	Dec. 31, 2010 MBbls
Reserve Quantities [Line Items]
Proved developed reserves	1,832,936	1,981,945	1,992,327	1,984,991
Crude Oil And Condensate [Member]
Reserve Quantities [Line Items]
Proved developed reserves	794,795	825,811	804,653	803,046
Natural Gas [Member]
Reserve Quantities [Line Items]
Proved developed reserves	4,926,064	5,833,105	6,253,418	6,363,417
Egypt [Member]
Reserve Quantities [Line Items]
Proved developed reserves	222,880	221,819	222,651	234,419
Egypt [Member] | Crude Oil And Condensate [Member]
Reserve Quantities [Line Items]
Proved developed reserves	119,242	106,746	105,840	109,657
Egypt [Member] | Crude Oil And Condensate [Member] | Noncontrolling Interest [Member]
Reserve Quantities [Line Items]
Proved developed reserves	45,000
Egypt [Member] | Natural Gas [Member]
Reserve Quantities [Line Items]
Proved developed reserves	621,825	690,436	700,866	748,573
Egypt [Member] | Natural Gas [Member] | Noncontrolling Interest [Member]
Reserve Quantities [Line Items]
Proved developed reserves	271,000

XML

CONSOLIDATED BALANCE SHEET (Parenthetical) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Statement Of Financial Position [Abstract]
Preferred stock, par value
Preferred stock, shares authorized	10,000,000	10,000,000
Preferred stock, shares issued		1,265,000
Preferred stock, shares outstanding		1,265,000
Preferred stock, liquidation preference per share	$ 1,000	$ 1,000
Preferred stock, converted	1,265,000
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	408,041,088	392,712,245
Treasury stock, shares	12,268,180	1,071,475

XML

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, 2013
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Property acquisition costs	$ 6,437
Exploration and development	1,666
Capitalized interest	260
Costs incurred	8,363
2013 [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Property acquisition costs	466
Exploration and development	1,138
Capitalized interest	48
Costs incurred	1,652
2012 [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Property acquisition costs	3,391
Exploration and development	388
Capitalized interest	48
Costs incurred	3,827
2011 [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Property acquisition costs	899
Exploration and development	88
Capitalized interest	30
Costs incurred	1,017
2010 and Prior [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Property acquisition costs	1,681
Exploration and development	52
Capitalized interest	134
Costs incurred	$ 1,867

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Income Taxes - Total Provision for Income Taxes (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Current taxes:
Federal	$ (29)	$ (150)	$ 64
State			2
Foreign	1,694	2,349	2,197
Current tax, net	1,665	2,199	2,263
Deferred taxes:
Federal	509	596	656
State	44	10	17
Foreign	(290)	71	573
Deferred taxes, net	263	677	1,246
Total	$ 1,928	$ 2,876	$ 3,509

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, 2013	Dec. 31, 2012	Dec. 31, 2011
Extractive Industries [Abstract]
Sales, net of production costs	$ (12,271)	$ (12,589)	$ (13,152)
Net change in prices and production costs	(1,438)	(1,941)	12,167
Discoveries and improved recovery, net of related costs	6,892	6,742	6,751
Change in future development costs	(2,017)	(935)	(2,250)
Previously estimated development costs incurred during the period	4,654	4,359	2,479
Revision of quantities	500	(4,065)	(1,475)
Purchases of minerals in-place	227	1,181	2,139
Accretion of discount	4,823	5,234	4,161
Change in income taxes	855	2,711	(4,303)
Sales of properties	(6,232)	(3)	(1,285)
Change in production rates and other	(828)	(2,088)	273
Change in the discounted future net cash flows, Total	$ (1,959)	$ (1,394)	$ 5,505

XML

ACCUMULATED OTHER COMPREHENSIVE LOSS (Tables)

12 Months Ended

Dec. 31, 2013

Equity [Abstract]

Components of Accumulated Other Comprehensive Income (Loss)

Components of accumulated other comprehensive loss include the following:

	For the Year Ended December 31,
	2013			2012			2011
	(In millions)
Currency translation adjustment(1)	$	(109	)	$	(109	)	$	(109	)
Unrealized gain (loss) on derivatives (Note 3)		1			(6	)		114
Unfunded pension and postretirement benefit plan (Note 9)		(7	)		(16	)		(14	)
Accumulated other comprehensive loss	$	(115	)	$	(131	)	$	(9	)

⁽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 - Key Jurisdictions of Company's Earliest Open Tax Years (Detail)	12 Months Ended
	Dec. 31, 2013
United States [Member]
Schedule Of Income Tax [Line Items]
Open Tax Years by Major Tax Jurisdiction	2010
Canada [Member]
Schedule Of Income Tax [Line Items]
Open Tax Years by Major Tax Jurisdiction	2009
Egypt [Member]
Schedule Of Income Tax [Line Items]
Open Tax Years by Major Tax Jurisdiction	1998
Australia [Member]
Schedule Of Income Tax [Line Items]
Open Tax Years by Major Tax Jurisdiction	2009
United Kingdom [Member]
Schedule Of Income Tax [Line Items]
Open Tax Years by Major Tax Jurisdiction	2011
Argentina [Member]
Schedule Of Income Tax [Line Items]
Open Tax Years by Major Tax Jurisdiction	2006

XML

SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited)

12 Months Ended

Dec. 31, 2013

Extractive Industries [Abstract]

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(3)		Australia		North Sea		Argentina			Other International			Total(3)
	(In millions, except per boe)
2013
Oil and gas production revenues	$	6,902	$	1,224		$	3,917	$	1,140	$	2,728	$	491		$	—		$	16,402
Operating cost:
Depreciation, depletion, and amortization
Recurring(1)		2,227		426			881		361		999		220			—			5,114
Additional		552		—			—		—		367		181			76			1,176
Asset retirement obligation accretion		94		49			—		27		68		5			—			243
Lease operating expenses		1,320		459			471		214		400		192			—			3,056
Gathering and transportation		84		155			42		—		7		9			—			297
Production taxes(2)		324		40			—		14		382		36			—			796
Income tax		817		24			1,161		157		313		(53	)		—			2,419
		5,418		1,153			2,555		773		2,536		590			76			13,101
Results of operation	$	1,484	$	71		$	1,362	$	367	$	192	$	(99	)	$	(76	)	$	3,301
Amortization rate per boe	$	18.39	$	10.89		$	16.21	$	17.47	$	37.25	$	14.13		$	—		$	18.42
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			—		—		—		—			109			1,992
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			109			14,207
Results of operation	$	1,545	$	(1,379	)	$	1,654	$	610	$	377	$	42		$	(109	)	$	2,740
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

(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) 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.

(3) 2013 includes a noncontrolling interest in Egypt.

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

	United States		Canada		Egypt(2)			Australia			North Sea		Argentina		Other International		Total(2)
	(In millions)
2013
Acquisitions:
Proved	$	17	$	—	$	35		$	—		$	125	$	—	$	—	$	177
Unproved		—		137		11			—			17		—		—		165
Exploration		757		50		563			169			278		53		22		1,892
Development		5,435		722		618			996			635		142		—		8,548
Costs incurred(1)	$	6,209	$	909	$	1,227		$	1,165		$	1,055	$	195	$	22	$	10,782
(1) Includes capitalized interest and asset retirement costs as follows:
Capitalized interest	$	239	$	35	$	15		$	16		$	25	$	10	$	—	$	340
Asset retirement costs		480		17		—			(30	)		67		3		—		537
(2) Includes a noncontrolling interest in Egypt.
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

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(1)			Australia			North Sea			Argentina			Other International			Total(1)
	(In millions)
2013
Proved properties	$	41,904		$	13,231		$	8,418		$	7,298		$	9,378		$	2,933		$	228		$	83,390
Unproved properties		5,042			1,116			660			471			702			349			23			8,363
		46,946			14,347			9,078			7,769			10,080			3,282			251			91,753
Accumulated DD&A		(20,745	)		(9,310	)		(5,356	)		(2,839	)		(4,811	)		(1,964	)		(228	)		(45,253	)
	$	26,201		$	5,037		$	3,722		$	4,930		$	5,269		$	1,318		$	23		$	46,500
(1) Includes a noncontrolling interest in Egypt.
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

Costs Not Being Amortized

The following table sets forth a summary of oil and gas property costs not being amortized at December 31, 2013, 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		2013		2012		2011		2010 and Prior
	(In millions)
Property acquisition costs	$	6,437	$	466	$	3,391	$	899	$	1,681
Exploration and development		1,666		1,138		388		88		52
Capitalized interest		260		48		48		30		134
Total	$	8,363	$	1,652	$	3,827	$	1,017	$	1,867

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 reserve data in the following tables only represent estimates and should not be construed as being exact.

	Crude Oil and Condensate
	(Thousands of barrels)
	United States			Canada			Egypt(1)			Australia			North Sea			Argentina			Total(1)
Proved developed reserves:
December 31, 2010		422,737			90,292			109,657			48,072			115,705			16,583			803,046
December 31, 2011		428,251			81,846			105,840			35,725			136,990			16,001			804,653
December 31, 2012		474,837			79,695			106,746			29,053			119,635			15,845			825,811
December 31, 2013		457,981			80,526			119,242			22,524			100,327			14,195			794,795
Proved undeveloped reserves:
December 31, 2010		214,117			56,855			17,470			18,064			38,663			4,062			349,231
December 31, 2011		205,763			59,746			22,195			32,220			32,415			4,585			356,924
December 31, 2012		203,068			70,650			17,288			34,808			28,019			2,981			356,814
December 31, 2013		195,835			56,366			16,302			36,703			29,253			2,231			336,690
Total proved reserves:
Balance December 31, 2010		636,855			147,146			127,127			66,136			154,368			20,645			1,152,277
Extensions, discoveries and other additions		45,676			16,712			45,021			15,762			332			3,230			126,733
Purchase of minerals in-place		5,097			705			—			—			34,612			—			40,414
Revisions of previous estimates		(8,904	)		(17,117	)		(6,185	)		—			—			215			(31,991	)
Production		(43,587	)		(5,202	)		(37,928	)		(13,953	)		(19,907	)		(3,503	)		(124,080	)
Sale of properties		(1,123	)		(653	)		—			—			—			—			(1,776	)
Balance December 31, 2011		634,014			141,591			128,035			67,945			169,405			20,587			1,161,577
Extensions, discoveries and other additions		84,656			18,935			36,188			6,277			346			1,133			147,535
Purchase of minerals in-place		15,942			188			—			276			2,143			—			18,549
Revisions of previous estimates		(7,474	)		(4,577	)		(3,678	)		(66	)		(928	)		671			(16,052	)
Production		(49,089	)		(5,792	)		(36,511	)		(10,571	)		(23,312	)		(3,565	)		(128,840	)
Sale of properties		(144	)		—			—			—			—			—			(144	)
Balance December 31, 2012		677,905			150,345			124,034			63,861			147,654			18,826			1,182,625
Extensions, discoveries and other additions		133,227			10,177			43,738			2,539			1,543			998			192,222
Purchase of minerals in-place		85			—			5			—			3,623			—			3,713
Revisions of previous estimates		1,683			(531	)		457			(118	)		18			24			1,533
Production		(53,621	)		(6,469	)		(32,690	)		(7,055	)		(23,258	)		(3,422	)		(126,515	)
Sale of properties		(105,463	)		(16,630	)		—			—			—			—			(122,093	)
Balance December 31, 2013		653,816			136,892			135,544			59,227			129,580			16,426			1,131,485

(1) 2013 includes proved reserves of 45 MMbbls as of December 31, 2013 attributable to a noncontrolling interest in Egypt.

	Natural Gas Liquids
	(Thousands of barrels)
	United States			Canada			Egypt			Australia		North Sea			Argentina			Total
Proved developed reserves:
December 31, 2010		91,800			23,701			—			—		—			5,875			121,376
December 31, 2011		107,490			23,256			—			—		8,753			5,939			145,438
December 31, 2012		154,508			21,996			—			—		2,438			5,007			183,949
December 31, 2013		184,485			26,099			—			—		2,435			4,110			217,129
Proved undeveloped reserves:
December 31, 2010		30,361			4,142			—			—		—			579			35,082
December 31, 2011		52,543			8,193			—			—		509			1,215			62,460
December 31, 2012		60,889			12,258			—			—		380			876			74,403
December 31, 2013		63,538			9,970			—			—		215			1,009			74,732
Total proved reserves:
Balance December 31, 2010		122,160			27,844			—			—		—			6,454			156,458
Extensions, discoveries and other additions		43,915			5,890			18			—		72			1,784			51,679
Purchase of minerals in-place		586			47			—			—		9,191			—			9,824
Revisions of previous estimates		1,713			774			—			—		—			17			2,504
Production		(8,071	)		(2,174	)		(18	)		—		(1	)		(1,102	)		(11,366	)
Sale of properties		(270	)		(931	)		—			—		—			—			(1,201	)
Balance December 31, 2011		160,033			31,450			—			—		9,262			7,153			207,898
Extensions, discoveries and other additions		71,965			7,655			—			—		246			—			79,866
Purchase of minerals in-place		230			9			—			—		231			—			470
Revisions of previous estimates		(4,559	)		(2,569	)		—			—		(6,329	)		(169	)		(13,626	)
Production		(12,272	)		(2,291	)		—			—		(592	)		(1,101	)		(16,256	)
Sale of properties		—			—			—			—		—			—			—
Balance December 31, 2012		215,397			34,254			—			—		2,818			5,883			258,352
Extensions, discoveries and other additions		69,231			4,014			—			—		—			—			73,245
Purchase of minerals in-place		45			—			—			—		295			—			340
Revisions of previous estimates		1,591			546			—			—		1			3			2,141
Production		(19,922	)		(2,442	)		—			—		(464	)		(767	)		(23,595	)
Sale of properties		(18,319	)		(303	)		—			—		—			—			(18,622	)
Balance December 31, 2013		248,023			36,069			—			—		2,650			5,119			291,861

	Natural Gas
	(Millions of cubic feet)
	United States			Canada			Egypt(1)			Australia			North Sea			Argentina			Total(1)
Proved developed reserves:
December 31, 2010		2,284,116			2,181,615			748,573			682,763			4,144			462,206			6,363,417
December 31, 2011		2,215,973			2,108,801			700,866			675,618			105,028			447,132			6,253,418
December 31, 2012		2,353,587			1,734,657			690,436			596,052			93,319			365,054			5,833,105
December 31, 2013		2,005,966			1,294,420			621,825			626,543			88,177			289,133			4,926,064
Proved undeveloped reserves:
December 31, 2010		988,869			1,310,352			328,344			805,735			—			70,465			3,503,765
December 31, 2011		760,238			1,438,710			282,100			893,966			3,414			90,427			3,468,855
December 31, 2012		832,320			403,227			205,055			1,074,018			18,985			97,496			2,631,101
December 31, 2013		667,160			439,037			190,355			975,224			18,988			121,584			2,412,348
Total proved reserves:
Balance December 31, 2010		3,272,985			3,491,967			1,076,917			1,488,498			4,144			532,671			9,867,182
Extensions, discoveries and other additions		169,506			505,049			77,049			148,640			475			81,274			981,993
Purchase of minerals in-place		67,595			8,838			—			—			104,658			—			181,091
Revisions of previous estimates		(7,716	)		(133,359	)		(37,623	)		—			—			1,107			(177,591	)
Production		(315,631	)		(230,880	)		(133,377	)		(67,554	)		(835	)		(77,493	)		(825,770	)
Sale of properties		(210,528	)		(94,104	)		—			—			—			—			(304,632	)
Balance December 31, 2011		2,976,211			3,547,511			982,966			1,569,584			108,442			537,559			9,722,273
Extensions, discoveries and other additions		365,863			252,130			55,967			176,969			16,397			2,623			869,949
Purchase of minerals in-place		313,885			2,503			—			1,745			8,494			—			326,627
Revisions of previous estimates		(156,840	)		(1,443,989	)		(13,974	)		101			—			496			(1,614,206	)
Production		(312,600	)		(219,849	)		(129,468	)		(78,329	)		(21,029	)		(78,128	)		(839,403	)
Sale of properties		(612	)		(422	)		—			—			—			—			(1,034	)
Balance December 31, 2012		3,185,907			2,137,884			895,491			1,670,070			112,304			462,550			8,464,206
Extensions, discoveries and other additions		306,721			359,493			44,382			13,351			2,750			16,515			743,212
Purchase of minerals in-place		855			—			—			—			10,680			—			11,535
Revisions of previous estimates		61,247			109,551			2,413			(101	)		32			49			173,191
Production		(285,187	)		(181,593	)		(130,106	)		(81,553	)		(18,601	)		(68,397	)		(765,437	)
Sale of properties		(596,417	)		(691,878	)		—			—			—			—			(1,288,295	)
Balance December 31, 2013		2,673,126			1,733,457			812,180			1,601,767			107,165			410,717			7,338,412

(1) 2013 includes proved reserves of 271 Bcf as of December 31, 2013 attributable to a noncontrolling interest in Egypt.

	Total Equivalent Reserves
	(Thousands barrels of oil equivalent)
	United States			Canada			Egypt(1)			Australia			North Sea			Argentina			Total(1)
Proved developed reserves:
December 31, 2010		895,223			477,594			234,419			161,866			116,396			99,493			1,984,991
December 31, 2011		905,069			456,569			222,651			148,328			163,248			96,462			1,992,327
December 31, 2012		1,021,610			390,800			221,819			128,395			137,626			81,695			1,981,945
December 31, 2013		976,795			322,362			222,880			126,948			117,457			66,494			1,832,936
Proved undeveloped reserves:
December 31, 2010		409,290			279,389			72,194			152,353			38,663			16,385			968,274
December 31, 2011		385,013			307,724			69,212			181,214			33,493			20,871			997,527
December 31, 2012		402,677			150,113			51,464			213,811			31,563			20,106			869,734
December 31, 2013		370,566			139,509			48,028			199,240			32,633			23,504			813,480
Total proved reserves:
Balance December 31, 2010		1,304,512			756,984			306,613			314,219			155,059			115,878			2,953,265
Extensions, discoveries and other additions		117,842			106,778			57,882			40,534			483			18,559			342,078
Purchase of minerals in-place		16,949			2,225			—			—			61,246			—			80,420
Revisions of previous estimates		(8,477	)		(38,570	)		(12,456	)		—			—			417			(59,086	)
Production		(104,263	)		(45,856	)		(60,176	)		(25,211	)		(20,047	)		(17,521	)		(273,074	)
Sale of properties		(36,481	)		(17,268	)		—			—			—			—			(53,749	)
Balance December 31, 2011		1,290,082			764,293			291,863			329,542			196,741			117,333			2,989,854
Extensions, discoveries and other additions		217,598			68,612			45,516			35,772			3,325			1,570			372,393
Purchase of minerals in-place		68,486			614			—			567			3,790			—			73,457
Revisions of previous estimates		(38,172	)		(247,811	)		(6,007	)		(49	)		(7,258	)		585			(298,712	)
Production		(113,461	)		(44,725	)		(58,089	)		(23,626	)		(27,409	)		(17,687	)		(284,997	)
Sale of properties		(246	)		(70	)		—			—			—			—			(316	)
Balance December 31, 2012		1,424,287			540,913			273,283			342,206			169,189			101,801			2,851,679
Extensions, discoveries and other additions		253,578			74,107			51,135			4,764			2,001			3,751			389,336
Purchase of minerals in-place		273			—			5			—			5,698			—			5,976
Revisions of previous estimates		13,482			18,274			859			(135	)		24			35			32,539
Production		(121,074	)		(39,177	)		(54,374	)		(20,647	)		(26,822	)		(15,589	)		(277,683	)
Sale of properties		(223,185	)		(132,246	)		—			—			—			—			(355,431	)
Balance December 31, 2013		1,347,361			461,871			270,908			326,188			150,090			89,998			2,646,416

(1) 2013 includes total proved reserves of 90 MMboe attributable to a noncontrolling interest in Egypt.

During 2013, Apache added 6 MMboe of estimated proved reserves through purchases of minerals in-place. We sold 355 MMboe through several divestiture transactions which included the majority of our Gulf of Mexico Shelf properties and certain fields in Canada. During 2013, Apache also added 389 MMboe from extensions, discoveries and other additions. In the U.S., the Company recorded 254 MMboe primarily associated with drilling successes in the Permian and Anadarko basins, which added 150 MMboe and 65 MMboe, respectively; 20 MMboe from appraisal drilling in the deepwater Gulf of Mexico; and 19 MMboe from various drilling programs in other U.S. regions. In Canada, additions of 74 MMboe were primarily a result of drilling activity for liquids-rich gas targets in the Kaybob field area, horizontal drilling in our House Mountain waterflood units, extensions of the Glauconitic trend in our West 5 area and shallow oil drilling in Brownfield and Consort field areas. Egypt contributed 51 MMboe from exploration and appraisal activity in the West Kalabsha, Shushan, Khalda and Ras Kanayes concessions along with continued development of the Razzak, Abu Gharadig and Meghar fields. Australia, Argentina and North Sea regions contributed 11 MMboe from their combined drilling programs.

Approximately 10 percent of Apache’s year-end 2013 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.”

Future Net Cash Flows

Future cash inflows as of December 31, 2013 and 2012 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(2)			Australia			North Sea			Argentina			Total(2)
	(In millions)
2013
Cash inflows	$	79,654		$	19,260		$	16,864		$	20,637		$	15,359		$	2,824		$	154,598
Production costs		(26,032	)		(8,105	)		(2,590	)		(4,494	)		(8,147	)		(1,176	)		(50,554	)
Development costs		(4,834	)		(2,458	)		(1,899	)		(2,283	)		(3,284	)		(397	)		(15,155	)
Income tax expense		(12,832	)		(678	)		(4,328	)		(3,072	)		(2,376	)		(142	)		(23,428	)
Net cash flows		35,956			8,019			8,047			10,788			1,552			1,109			65,471
10 percent discount rate		(20,117	)		(3,987	)		(2,193	)		(6,423	)		85			(242	)		(32,877	)
Discounted future net cash flows(1)	$	15,839		$	4,032		$	5,854		$	4,365		$	1,637		$	867		$	32,594
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

(1) Estimated future net cash flows before income tax expense, discounted at 10 percent per annum, totaled approximately $45.4 billion and $48.2 billion as of December 31, 2013 and 2012, respectively.

(2) Includes discounted future net cash flows of approximately $1.95 billion in 2013 attributable to a noncontrolling interest in Egypt.

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

	For the Year Ended December 31,
	2013			2012			2011
	(In millions)
Sales, net of production costs	$	(12,271	)	$	(12,589	)	$	(13,152	)
Net change in prices and production costs		1,438			(1,941	)		12,167
Discoveries and improved recovery, net of related costs		6,892			6,742			6,751
Change in future development costs		(2,017	)		(935	)		(2,250	)
Previously estimated development costs incurred during the period		4,654			4,359			2,479
Revision of quantities		500			(4,065	)		(1,475	)
Purchases of minerals in-place		227			1,181			2,139
Accretion of discount		4,823			5,234			4,161
Change in income taxes		855			2,711			(4,303	)
Sales of properties		(6,232	)		(3	)		(1,285	)
Change in production rates and other		(828	)		(2,088	)		273
	$	(1,959	)	$	(1,394	)	$	5,505

XML

BUSINESS SEGMENT INFORMATION (Tables)

12 Months Ended

Dec. 31, 2013

Segment Reporting [Abstract]

Financial Segment Information

Financial information for each country is presented below:

	United States		Canada			Egypt(1)		Australia		North Sea		Argentina			Other International			Total(1)
	(In millions)
2013
Oil and gas production revenues	$	6,902	$	1,224		$	3,917	$	1,140	$	2,728	$	491		$	—		$	16,402
Operating Expenses:
Depreciation, depletion, and amortization
Recurring		2,338		505			1,005		423		1,022		230			1			5,524
Additional		552		—			—		—		367		181			76			1,176
Asset retirement obligation accretion		94		49			—		27		68		5			—			243
Lease operating expenses		1,320		459			471		214		400		192			—			3,056
Gathering and transportation		84		155			42		—		7		9			—			297
Taxes other than income		335		45			8		13		384		47			—			832
Operating Income (Loss)	$	2,179	$	11		$	2,391	$	463	$	480	$	(173	)	$	(77	)		5,274
Other Income (Expense):
Derivative instrument gains (losses), net																			(399	)
Other																			51
General and administrative																			(503	)
Acquisitions, divestitures, and transition																			(33	)
Financing costs, net																			(174	)
Income Before Income Taxes																		$	4,216
Net Property and Equipment	$	27,010	$	6,058		$	5,454	$	6,838	$	5,622	$	1,416		$	23		$	52,421
Total Assets	$	29,940	$	6,952		$	8,121	$	8,094	$	6,902	$	1,577		$	51		$	61,637
Additions to Net Property and Equipment	$	6,404	$	1,082		$	1,309	$	1,954	$	1,084	$	205		$	24		$	12,062
(1) Includes a noncontrolling interest in Egypt.
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)	$	2,311	$	(1,867	)	$	3,166	$	866	$	989	$	51		$	(43	)		5,473
Other Income (Expense):
Derivative instrument gains (losses), net																			(79	)
Other																			210
General and administrative																			(531	)
Acquisitions, divestitures, and 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
	United States		Canada			Egypt		Australia		North Sea		Argentina			Other International			Total
	(In millions)
2011
Oil and gas production revenues	$	6,103	$	1,617		$	4,791	$	1,734	$	2,091	$	474		$	—		$	16,810
Operating Expenses:
Depreciation, depletion, and amortization
Recurring		1,684		546			818		440		409		198			—			4,095
Additional		—		—			—		—		—		—			109			109
Asset retirement obligation accretion		97		26			—		10		17		4			—			154
Lease operating expenses		1,167		470			398		197		208		165			—			2,605
Gathering and transportation		64		165			35		—		25		7			—			296
Taxes other than income		259		51			13		9		539		28			—			899
Operating Income (Loss)	$	2,832	$	359		$	3,527	$	1,078	$	893	$	72		$	(109	)		8,652
Other Expense:
Other																			78
General and administrative																			(459	)
Acquisitions, divestitures, and 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

XML

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, 2013	Dec. 31, 2012
Extractive Industries [Abstract]
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	$ 48.2
Total estimated future net cash flows	$ 1.95

XML

SUPPLEMENTAL GUARANTOR INFORMATION

12 Months Ended

Dec. 31, 2013

Guarantees [Abstract]

SUPPLEMENTAL GUARANTOR INFORMATION

16.     SUPPLEMENTAL GUARANTOR INFORMATION

In December 1999, Apache Finance Canada issued approximately $300 million of publicly-traded notes due in 2029, which 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 AND COMPREHENSIVE INCOME

For the Year Ended December 31, 2013

	Apache Corporation			Apache Finance Canada		All Other Subsidiaries of Apache Corporation			Reclassifications & Eliminations			Consolidated
	(In millions)
REVENUES AND OTHER:
Oil and gas production revenues	$	4,585		$	—	$	11,817		$	—		$	16,402
Equity in net income (loss) of affiliates		2,313			17		36			(2,366	)		—
Derivative instrument gains (losses), net		(399	)		—		—			—			(399	)
Other		—			61		(6	)		(4	)		51
		6,499			78		11,847			(2,370	)		16,054
OPERATING EXPENSES:
Depreciation, depletion, and amortization		2,250			—		4,450			—			6,700
Asset retirement obligation accretion		67			—		176			—			243
Lease operating expenses		939			—		2,117			—			3,056
Gathering and transportation		61			—		236			—			297
Taxes other than income		190			—		642			—			832
General and administrative		408			—		99			(4	)		503
Acquisitions, divestitures, and transition		33			—		—			—			33
Financing costs, net		97			5		72			—			174
		4,045			5		7,792			(4	)		11,838
INCOME (LOSS) BEFORE INCOME TAXES		2,454			73		4,055			(2,366	)		4,216
Provision (benefit) for income taxes		222			20		1,686			—			1,928
NET INCOME (LOSS) INCLUDING
NONCONTROLLING INTEREST		2,232			53		2,369			(2,366	)		2,288
Net income attributable to noncontrolling interest		—			—		56			—			56
Preferred stock dividends		44			—		—			—			44
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	2,188		$	53	$	2,313		$	(2,366	)	$	2,188
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	2,204		$	53	$	2,313		$	(2,366	)	$	2,204

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME

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
Acquisitions, divestitures, and 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
NET 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 AND COMPREHENSIVE INCOME

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
Acquisitions, divestitures, and 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
NET 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 CASH FLOWS

For the Year Ended December 31, 2013

	Apache Corporation			Apache Finance Canada			All Other Subsidiaries of Apache Corporation			Reclassifications & Eliminations		Consolidated
	(In millions)
CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	$	1,421		$	315		$	8,099		$	—	$	9,835
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property		(4,291	)		—			(5,728	)		—		(10,019	)
Additions to gas gathering, transmission, and processing facilities		(124	)		—			(1,077	)		—		(1,201	)
Proceeds from divestiture of Gulf of Mexico Shelf properties		3,702			—			—			—		3,702
Acquisitions, other		—			—			(215	)		—		(215	)
Proceeds from Kitimat LNG transaction, net		—			—			396			—		396
Proceeds from sale of oil and gas properties		—			—			307			—		307
Other		(58	)		—			(28	)		—		(86	)
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES		(771	)		—			(6,345	)		—		(7,116	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Commercial paper, credit facility, and bank notes, net		(501	)		—			(12	)		—		(513	)
Intercompany borrowings		3,056			1			(3,057	)		—		—
Payments on fixed rate debt		(1,722	)		(350	)		—			—		(2,072	)
Dividends paid		(360	)		—			—			—		(360	)
Proceeds from sale of noncontrolling interest		—			—			2,948			—		2,948
Shares repurchased		(997	)		—			—			—		(997	)
Other		29			37			(45	)		—		21
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		(495	)		(312	)		(166	)		—		(973	)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		155			3			1,588			—		1,746
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR		—			—			160			—		160
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	155		$	3		$	1,748		$	—	$	1,906

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 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 (USED IN) OPERATING ACTIVITIES	$	2,191		$	13		$	7,749		$	—		$	9,953
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property		(1,478	)		—			(4,936	)		—			(6,414	)
Additions to gas gathering, transmission, and processing facilities		—			—			(664	)		—			(664	)
Acquisitions 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 BALANCE SHEET

December 31, 2013

	Apache Corporation		Apache Finance Canada		All Other Subsidiaries of Apache Corporation		Reclassifications & Eliminations			Consolidated
	(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	155	$	3	$	1,748	$	—		$	1,906
Receivables, net of allowance		1,043		—		1,909		—			2,952
Inventories		48		—		843		—			891
Drilling advances		49		—		322		—			371
Derivative instruments		1		—		—		—			1
Prepaid assets and other		99		—		146		—			245
Intercompany receivable		5,357		—		—		(5,357	)		—
		6,752		3		4,968		(5,357	)		6,366
PROPERTY AND EQUIPMENT, NET		16,092		—		36,329		—			52,421
OTHER ASSETS:
Intercompany receivable		1,572		—		—		(1,572	)		—
Equity in affiliates		24,743		1,155		449		(26,347	)		—
Goodwill, net		173		—		1,196		—			1,369
Deferred charges and other		166		1,006		1,309		(1,000	)		1,481
	$	49,498	$	2,164	$	44,251	$	(34,276	)	$	61,637
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable	$	956	$	2	$	658	$	—		$	1,616
Current debt		—		—		53		—			53
Asset retirement obligation		115		—		6		—			121
Derivative instruments		299		—		—		—			299
Other current liabilities		896		10		1,705		—			2,611
Intercompany payable		—		—		5,357		(5,357	)		—
		2,266		12		7,779		(5,357	)		4,700
LONG-TERM DEBT		9,374		298		—		—			9,672
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Intercompany payable		—		—		1,572		(1,572	)		—
Income taxes		3,586		—		4,778		—			8,364
Asset retirement obligation		430		—		2,671		—			3,101
Other		446		250		711		(1,000	)		407
		4,462		250		9,732		(2,572	)		11,872
COMMITMENTS AND CONTINGENCIES APACHE SHAREHOLDERS’ EQUITY		33,396		1,604		24,743		(26,347	)		33,396
Noncontrolling interest		—		—		1,997		—			1,997
TOTAL EQUITY		33,396		1,604		26,740		(26,347	)		35,393
	$	49,498	$	2,164	$	44,251	$	(34,276	)	$	61,637

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		102		—		91		—			193
Intercompany receivable		3,766		—		—		(3,766	)		—
		4,891		1		3,836		(3,766	)		4,962
PROPERTY AND EQUIPMENT, NET		18,517		—		34,763		—			53,280
OTHER ASSETS:
Intercompany receivable		4,628		—		—		(4,628	)		—
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	$	40,864	$	(31,472	)	$	60,737
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable	$	639	$	1	$	452	$	—		$	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
Intercompany payable		—		—		3,766		(3,766	)		—
		3,011		4		6,287		(3,766	)		5,536
LONG-TERM DEBT		10,706		647		2		—			11,355
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Intercompany payable		—		—		4,628		(4,628	)		—
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		13,528		(5,628	)		12,515
COMMITMENTS AND CONTINGENCIES TOTAL EQUITY		31,331		1,031		21,047		(22,078	)		31,331
	$	49,408	$	1,937	$	40,864	$	(31,472	)	$	60,737

XML

Retirement and Deferred Compensation Plans - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
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	$ 123	$ 117	$ 93
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	160	139	119
Expected contribution towards pension and postretirement plans	6
Postretirement Benefits [Member]
Commitment And Contingencies [Line Items]
Expected contribution towards pension and postretirement plans	$ 1

XML

STATEMENT OF CONSOLIDATED SHAREHOLDERS EQUITY (USD $) In Millions	Total	Common Stock [Member]	Paid-In Capital [Member]	Retained Earnings [Member]	Treasury Stock [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Parent [Member]	Noncontrolling Interest [Member]	Series D Preferred Stock [Member]
BALANCE at Dec. 31, 2010	$ 24,377	$ 240	$ 8,864	$ 14,223	$ (36)	$ (141)	$ 24,377		$ 1,227
Net income	4,584			4,584			4,584
Postretirement, net of tax	(1)					(1)	(1)
Commodity hedges, net of tax	133					133	133
Preferred	(76)			(76)			(76)
Common ($0.60 per share)	(231)			(231)			(231)
Common stock activity, net	36	1	35				36
Treasury stock activity, net	6		2		4		6
Compensation expense	167		167				167
Other	(2)		(2)				(2)
BALANCE at Dec. 31, 2011	28,993	241	9,066	18,500	(32)	(9)	28,993		1,227
Net income	2,001			2,001			2,001
Postretirement, net of tax	(2)					(2)	(2)
Commodity hedges, net of tax	(120)					(120)	(120)
Preferred	(76)			(76)			(76)
Common ($0.60 per share)	(264)			(264)			(264)
Common shares issued	601	3	598				601
Common stock activity, net	(43)	1	(44)				(43)
Treasury stock activity, net	3		1		2		3
Compensation expense	238		238				238
BALANCE at Dec. 31, 2012	31,331	245	9,859	20,161	(30)	(131)	31,331		1,227
Net income	2,288			2,232			2,232	56
Postretirement, net of tax	9					9	9
Commodity hedges, net of tax	7					7	7
Preferred	(44)			(44)			(44)
Common ($0.60 per share)	(317)			(317)			(317)
Common stock activity, net	(6)	1	(7)				(6)
Treasury stock activity, net	(997)				(997)		(997)
Sale of noncontrolling interest	2,948		1,007				1,007	1,941
Conversion of Series D preferred stock		9	1,218						(1,227)
Compensation expense	189		189				189
BALANCE at Dec. 31, 2013	$ 35,393	$ 255	$ 12,251	$ 22,032	$ (1,027)	$ (115)	$ 33,396	$ 1,997

XML

STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Statement Of Income And Comprehensive Income [Abstract]
Net income including noncontrolling interest	$ 2,288	$ 2,001	$ 4,584
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and postretirement benefit plan, net of tax	9	(2)	(1)
Commodity cash flow hedge activity, net of tax:
Reclassification of (gain) loss on settled derivative instruments	11	(199)	19
Change in fair value of derivative instruments	(5)	79	115
Derivative hedge ineffectiveness reclassified into earnings	1		(1)
Commodity cash flow hedge activity, net of tax	16	(122)	132
COMPREHENSIVE INCOME INCLUDING NONCONTROLLING INTEREST	2,304	1,879	4,716
Comprehensive income attributable to noncontrolling interest	56
Preferred stock dividends	44	76	76
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON STOCK	$ 2,204	$ 1,803	$ 4,640

XML

RETIREMENT AND DEFERRED COMPENSATION PLANS

12 Months Ended

Dec. 31, 2013

Compensation And Retirement Disclosure [Abstract]

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 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 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. These plans allow 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 $123 million, $117 million, and $93 million for 2013, 2012, and 2011, 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, 2013, 2012, and 2011, 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.

	2013						2012						2011
	Pension			Postretirement			Pension			Postretirement			Pension			Postretirement
	Benefits			Benefits			Benefits			Benefits			Benefits			Benefits
	(In millions)
Change in Projected Benefit Obligation
Projected benefit obligation beginning of year	$	177		$	35		$	150		$	30		$	136		$	29
Service cost		5			4			5			4			5			3
Interest cost		7			1			7			1			7			1
Foreign currency exchange rate changes		4			—			7			—			(1	)		—
Actuarial losses (gains)		—			(8	)		14			1			6			(2	)
Effect of curtailment and settlements		—			(3	)		—			—			—			—
Benefits paid		(4	)		(2	)		(6	)		(1	)		(3	)		(1	)
Retiree contributions		—			1			—			—			—			—
Projected benefit obligation at end of year		189			28			177			35			150			30
Change in Plan Assets
Fair value of plan assets at beginning of year		170			—			145			—			135			—
Actual return on plan assets		15			—			14			—			4			—
Foreign currency exchange rates		4			—			6			—			(1	)		—
Employer contributions		6			1			11			1			10			1
Benefits paid		(4	)		(2	)		(6	)		(1	)		(3	)		(1	)
Retiree contributions		—			1			—			—			—			—
Fair value of plan assets at end of year		191			—			170			—			145			—
Funded status at end of year	$	2		$	(28	)	$	(7	)	$	(35	)	$	(5	)	$	(30	)
Amounts recognized in Consolidated Balance Sheet
Current liability		—			(1	)		—			(1	)		—			(1	)
Non-current asset (liability)		2			(27	)		(7	)		(34	)		(5	)		(29	)
	$	2		$	(28	)	$	(7	)	$	(35	)	$	(5	)	$	(30	)
Pre-tax Amounts Recognized in Accumulated Other Comprehensive Income (Loss)
Accumulated gain (loss)		(22	)		1			(32	)		(7	)		(25	)		(6	)
	$	(22	)	$	1		$	(32	)	$	(7	)	$	(25	)	$	(6	)
Weighted Average Assumptions used as of December 31
Discount rate		4.60	%		4.33	%		4.30	%		3.43	%		4.70	%		4.04	%
Salary increases		4.90	%		N/A			4.60	%		N/A			4.60	%		N/A
Expected return on assets		5.60	%		N/A			4.70	%		N/A			4.85	%		N/A
Healthcare cost trend
Initial		N/A			7.00	%		N/A			7.25	%		N/A			7.50	%
Ultimate in 2022		N/A			5.00	%		N/A			5.00	%		N/A			5.00	%

As of December 31, 2013, 2012, and 2011, the accumulated benefit obligation for the U.K. Pension Plan was $160 million, $139 million, and $119 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
	2013			2013			2012
Asset Category
Equity securities:
U.K. quoted equities		17	%		18	%		16	%
Overseas quoted equities		33	%		33	%		33	%
Total equity securities		50	%		51	%		49	%
Debt securities:
U.K. Government bonds		30	%		29	%		30	%
U.K. corporate bonds		20	%		20	%		20	%
Debt securities		50	%		49	%		50	%
Cash		0	%		0	%		1	%
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. The following tables present 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, 2013 and 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)
December 31, 2013
Equity securities:
U.K. quoted equities(1)	$	35	$	—	$	—	$	35
Overseas quoted equities(2)		63		—		—		63
Total equity securities		98		—		—		98
Debt securities:
U.K. Government bonds(3)		54		—		—		54
U.K. corporate bonds(4)		38		—		—		38
Total debt securities		92		—		—		92
Cash		1		—		—		1
Fair value of plan assets	$	191	$	—	$	—	$	191
December 31, 2012
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 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 the 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 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, out performance 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, 2013, 2012, and 2011:

	2013						2012						2011
	Pension			Postretirement			Pension			Postretirement			Pension			Postretirement
	Benefits			Benefits			Benefits			Benefits			Benefits			Benefits
	(In millions)
Component of Net Periodic Benefit Costs
Service cost	$	5		$	4		$	5		$	4		$	5		$	3
Interest cost		7			1			7			1			7			1
Expected return on assets		(8	)		—			(7	)		—			(8	)		—
Amortization of actuarial (gain) loss		2			—			1			—			—			—
Curtailment (gain) loss		—			(3	)		—			—			—			—
Net periodic benefit cost	$	6		$	2		$	6		$	5		$	4		$	4
Weighted Average Assumptions used to determine Net Period Benefit Cost for the Years ended 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	%

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		6		(4	)

Apache expects to contribute approximately $6 million to its pension plan and $1 million to its postretirement benefit plan in 2014. The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:

	Pension		Postretirement
	Benefits		Benefits
	(In millions)
2014	$	5	$	1
2015		5		1
2016		5		2
2017		5		2
2018		5		2
Years 2019-2023		30		16

XML

Supplemental Guarantor Information - Supplemental Condensed Consolidating Statement of Operations And Comprehensive Income (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended								12 Months Ended			36 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2012
REVENUES AND OTHER:
Oil and gas production revenues									$ 16,402	$ 16,947	$ 16,810
Derivative instrument gains (losses), net									(399)	(79)
Other									51	210	78
Total revenues and other	3,576	4,019	4,383	4,076	4,391	4,179	3,972	4,536	16,054	17,078	16,888	17,078
OPERATING EXPENSES:
Depreciation, depletion, and amortization									6,700	7,109	4,204
Asset retirement obligation accretion									243	232	154
Lease operating expenses									3,056	2,968	2,605
Gathering and transportation									297	303	296
Taxes other than income									832	862	899
General and administrative									503	531	459
Acquisitions, divestitures, and transition									33	31	20
Financing costs, net									174	165	158
Total operating expenses	3,346	3,713	3,348	3,359	3,723	3,999	3,616	3,739	11,838	12,201	8,795	15,077
INCOME (LOSS) BEFORE INCOME TAXES									4,216	4,877	8,093
Provision (benefit) for income taxes									1,928	2,876	3,509
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTEREST	230	306	1,035	717	668	180	356	797	2,288	2,001	4,584	2,001
Net income attributable to non controlling interest									56
Preferred stock dividends									44	76	76
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	174	300	1,016	698	649	161	337	778	2,188	1,925	4,508	1,925
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK									2,204	1,803	4,640
Apache Corporation [Member]
REVENUES AND OTHER:
Oil and gas production revenues									4,585	4,237	4,380
Equity in net income (loss) of affiliates									2,313	1,523	3,590
Derivative instrument gains (losses), net									(399)
Other										(80)	9
Total revenues and other									6,499	5,680	7,979
OPERATING EXPENSES:
Depreciation, depletion, and amortization									2,250	1,391	1,257
Asset retirement obligation accretion									67	76	70
Lease operating expenses									939	957	794
Gathering and transportation									61	51	51
Taxes other than income									190	185	170
General and administrative									408	425	365
Acquisitions, divestitures, and transition									33	25	14
Financing costs, net									97	94	149
Total operating expenses									4,045	3,204	2,870
INCOME (LOSS) BEFORE INCOME TAXES									2,454	2,476	5,109
Provision (benefit) for income taxes									222	475	525
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTEREST									2,232	2,001	4,584
Preferred stock dividends									44	76	76
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK									2,188	1,925	4,508
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK									2,204	1,803	4,640
Apache Finance Canada [Member]
REVENUES AND OTHER:
Equity in net income (loss) of affiliates									17	(737)	234
Other									61	69	125
Total revenues and other									78	(668)	359
OPERATING EXPENSES:
Financing costs, net									5	(20)	(18)
Total operating expenses									5	(20)	(18)
INCOME (LOSS) BEFORE INCOME TAXES									73	(648)	377
Provision (benefit) for income taxes									20	(159)	97
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTEREST									53	(489)	280
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK									53	(489)	280
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK									53	(489)	280
All Other Subsidiaries of Apache Corporation [Member]
REVENUES AND OTHER:
Oil and gas production revenues									11,817	12,710	12,430
Equity in net income (loss) of affiliates									36	248	46
Other									(6)	146	(52)
Total revenues and other									11,847	13,104	12,424
OPERATING EXPENSES:
Depreciation, depletion, and amortization									4,450	5,718	2,947
Asset retirement obligation accretion									176	156	84
Lease operating expenses									2,117	2,011	1,811
Gathering and transportation									236	252	245
Taxes other than income									642	677	729
General and administrative									99	110	98
Acquisitions, divestitures, and transition										6	6
Financing costs, net									72	91	27
Total operating expenses									7,792	9,021	5,947
INCOME (LOSS) BEFORE INCOME TAXES									4,055	4,083	6,477
Provision (benefit) for income taxes									1,686	2,560	2,887
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTEREST									2,369	1,523	3,590
Net income attributable to non controlling interest									56
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK									2,313	1,523	3,590
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK									2,313	1,523	3,590
Reclassifications & Eliminations [Member]
REVENUES AND OTHER:
Equity in net income (loss) of affiliates									(2,366)	(1,034)	(3,870)
Other									(4)	(4)	(4)
Total revenues and other									(2,370)	(1,038)	(3,874)
OPERATING EXPENSES:
General and administrative									(4)	(4)	(4)
Total operating expenses									(4)	(4)	(4)
INCOME (LOSS) BEFORE INCOME TAXES									(2,366)	(1,034)	(3,870)
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTEREST									(2,366)	(1,034)	(3,870)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK									(2,366)	(1,034)	(3,870)
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK									$ (2,366)	$ (1,034)	$ (3,870)

XML

Supplemental Oil and Gas Disclosures - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2013 MMBoe MBbls	Dec. 31, 2012 MBbls	Dec. 31, 2011 MBbls
Reserve Quantities [Line Items]
Anticipated Timing of Inclusion of Costs in Amortization Calculation	Five to ten years
Purchases of minerals in-place	6
Extensions, discoveries and other additions	389
Sale of minerals in-place	(355,431)	(316)	(53,749)
Percentage of estimated proved developed reserves classified as proved not producing	10.00%
United States [Member]
Reserve Quantities [Line Items]
Extensions, discoveries and other additions	254
Sale of minerals in-place	(223,185)	(246)	(36,481)
Permian and GOM [Member]
Reserve Quantities [Line Items]
Extensions, discoveries and other additions	20
Other Us Regions [Member]
Reserve Quantities [Line Items]
Extensions, discoveries and other additions	19
Canada [Member]
Reserve Quantities [Line Items]
Extensions, discoveries and other additions	74
Sale of minerals in-place	(132,246)	(70)	(17,268)
Egypt [Member]
Reserve Quantities [Line Items]
Extensions, discoveries and other additions	51
Australia Argentina And North Sea [Member]
Reserve Quantities [Line Items]
Extensions, discoveries and other additions	11
Permian Basin [Member]
Reserve Quantities [Line Items]
Extensions, discoveries and other additions	150
Anadarko Basin [Member]
Reserve Quantities [Line Items]
Extensions, discoveries and other additions	65

XML

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, 2013	Dec. 31, 2012	Dec. 31, 2011
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved	$ 177	$ 1,251	$ 2,755
Unproved	165	2,355	688
Exploration	1,892	2,689	1,762
Development	8,548	7,536	5,587
Costs incurred	215	13,831	10,792
Proved properties	83,390	78,383
Unproved properties	8,363	8,754
Capitalized costs, gross	91,753	87,137
Accumulated DD&A	(45,253)	(38,978)
Capitalized costs, net	46,500	48,159
United States [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved	17	1,076	368
Unproved		2,329	116
Exploration	757	1,369	418
Development	5,435	4,465	2,832
Costs incurred	6,209	9,239	3,734
Proved properties	41,904	40,163
Unproved properties	5,042	5,641
Capitalized costs, gross	46,946	45,804
Accumulated DD&A	(20,745)	(17,968)
Capitalized costs, net	26,201	27,836
Canada [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved		5
Unproved	137		33
Exploration	50	111	209
Development	722	762	883
Costs incurred	909	878	1,125
Proved properties	13,231	13,477
Unproved properties	1,116	1,059
Capitalized costs, gross	14,347	14,536
Accumulated DD&A	(9,310)	(8,899)
Capitalized costs, net	5,037	5,637
Egypt [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved	35	28	(12)
Unproved	11		2
Exploration	563	696	570
Development	618	394	344
Costs incurred	1,227	1,118	904
Proved properties	8,418	7,165
Unproved properties	660	686
Capitalized costs, gross	9,078	7,851
Accumulated DD&A	(5,356)	(4,474)
Capitalized costs, net	3,722	3,377
Australia [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved		32
Unproved			48
Exploration	169	149	286
Development	996	915	429
Costs incurred	1,165	1,096	763
Proved properties	7,298	6,319
Unproved properties	471	284
Capitalized costs, gross	7,769	6,603
Accumulated DD&A	(2,839)	(2,478)
Capitalized costs, net	4,930	4,125
North Sea [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved	125	110	2,399
Unproved	17	26	476
Exploration	278	111	18
Development	635	837	941
Costs incurred	1,055	1,084	3,834
Proved properties	9,378	8,401
Unproved properties	702	626
Capitalized costs, gross	10,080	9,027
Accumulated DD&A	(4,811)	(3,445)
Capitalized costs, net	5,269	5,582
Argentina [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Exploration	53	157	202
Development	142	161	156
Costs incurred	195	318	358
Proved properties	2,933	2,706
Unproved properties	349	382
Capitalized costs, gross	3,282	3,088
Accumulated DD&A	(1,964)	(1,562)
Capitalized costs, net	1,318	1,526
Other International [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Unproved			13
Exploration	22	96	59
Development		2	2
Costs incurred	22	98	74
Proved properties	228	152
Unproved properties	23	76
Capitalized costs, gross	251	228
Accumulated DD&A	(228)	(152)
Capitalized costs, net	$ 23	$ 76

XML

Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2013	Jan. 31, 2014	Jun. 30, 2013
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2013
Document Fiscal Year Focus	2013
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		394,724,983
Entity Public Float			$ 32,641,836,810

XML

CAPITAL STOCK

12 Months Ended

Dec. 31, 2013

Equity [Abstract]

CAPITAL STOCK

10.     CAPITAL STOCK

Common Stock Outstanding

	2013			2012		2011
Balance, beginning of year		391,640,770			384,117,643		382,391,742
Shares issued for stock-based compensation plans:
Treasury shares issued		25,214			60,767		144,313
Common shares issued		929,596			1,189,693		1,581,588
Common shares issued for conversion of preferred shares		14,399,247			—		—
Treasury shares acquired		(11,221,919	)		—		—
Cordillera consideration (Note 2)		—			6,272,667		—
Balance, end of year		395,772,908			391,640,770		384,117,643

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, 2013, 2012, and 2011 is presented in the table below.

	2013						2012						2011
	Income		Shares		Per Share		Income		Shares		Per Share		Income		Shares		Per Share
	(In millions, except per share amounts)
Basic:
Net income attributable to common stock	$	2,188		395	$	5.53	$	1,925		389	$	4.95	$	4,508		384	$	11.75
Effect of Dilutive Securities:
Mandatory Convertible Preferred Stock	$	44		9			$	—		—			$	76		14
Stock options and other		—		2				—		2				—		2
Diluted:
Net income attributable to common stock, including assumed conversions	$	2,232		406	$	5.50	$	1,925		391	$	4.92	$	4,584		400	$	11.47

The diluted EPS calculation excludes options and restricted shares that were anti-dilutive totaling 4.9 million, 4.4 million, and 2.5 million for the years ended December 31, 2013, 2012, and 2011, 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.

Stock Repurchase Program

In May 2013, Apache’s Board of Directors authorized the purchase of up to 30 million shares of the Company’s common stock, valued at approximately $2 billion when first announced. Shares may be purchased either in the open market or through privately held negotiated transactions. The Company initiated the buyback program on June 10, 2013, with the repurchase of 2,924,271 shares at an average price of $85.47 during the month of June. During the fourth quarter of 2013, 8,297,648 shares were repurchased at an average price of $90.08. An additional 2,393,917 shares were purchased subsequent to December 31, 2013 at an average cost of $84.67. The Company anticipates that further purchases will primarily be made with proceeds from asset dispositions, but the Company is not obligated to acquire any specific number of shares.

Common Stock Dividend

The Company paid common stock dividends of $0.77 per share in 2013, $0.66 per share in 2012, and $0.60 per share in 2011.

Stock Compensation Plans

The Company has several stock-based compensation plans, which include stock options, stock appreciation rights, restricted stock, and conditional restricted stock unit 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. A total of 27.3 million shares were authorized and available for grant under the 2011 Plan as of December 31, 2013. 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 2013, 2012, and 2011, stock-based compensation expensed was $136 million, $167 million, and $113 million ($94 million, $119 million, and $73 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:

	2013		2012		2011
	(In millions)
Stock-based compensation expensed:
General and administrative	$	89	$	104	$	69
Lease operating expenses		47		63		44
Stock-based compensation capitalized		55		67		42
	$	191	$	234	$	155

Stock Options

As of December 31, 2013, 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 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:

	2013
	Shares Under Option			Weighted Average Exercise Price
	(In thousands)
Outstanding, beginning of year		7,573		$	90.47
Granted		819			80.89
Exercised		(327	)		72.55
Forfeited or expired		(502	)		97.88
Outstanding, end of year(1)		7,563			89.71
Expected to vest(1)		2,370			92.50
Exercisable, end of year(1)		4,678			88.53
Weighted average fair value of options granted during the year	$	23.18

(1) As of December 31, 2013, the weighted average remaining contractual life for options outstanding, expected to vest, and exercisable is 6.1 years, 8.2 years, and 4.7 years, respectively. The aggregate intrinsic value of options outstanding, expected to vest, and exercisable at year-end was $43 million, $7 million, and $34 million, respectively. The weighted-average grant-date fair value of options granted during the years 2013, 2012, and 2011 was $23.18, $26.41, and $42.20, 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.

	2013			2012			2011
Expected volatility		33.60	%		34.94	%		34.47	%
Expected dividend yields		0.99	%		0.82	%		0.47	%
Expected term (in years)		5.5			5.5			5.5
Risk-free rate		0.79	%		0.78	%		1.95	%

The intrinsic value of options exercised during 2013, 2012, and 2011 was approximately $4 million, $12 million and $50 million, respectively. The cash received from exercise of options during 2013 was approximately $24 million. The Company realized an additional tax benefit of approximately $1.5 million for the amount of intrinsic value in excess of compensation cost recognized in 2013. As of December 31, 2013, the total compensation cost related to non-vested options not yet recognized was $60 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. As of December 31, 2013, a total of 316,127 SARs were outstanding, of which 201,552 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 $33.41 based on the Black-Scholes valuation methodology using assumptions comparable to those discussed above. During 2013, 237,288 SARs were exercised. The aggregate of cash payments made to settle SARs was $11 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 2013, the Company awarded 3,098,029 restricted stock units at a weighted-average per-share market price of $82.95. In 2012 and 2011, the Company awarded 1,219,886 and 887,851 restricted stock units at a weighted-average per-share market price of $85.67 and $124.16, 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 2013, 2012, and 2011, $82 million ($53 million after tax), $74 million ($48 million after tax), and $76 million ($49 million after tax), respectively, was charged to expense. In 2013, 2012, and 2011, $30 million, $25 million, and $28 million was capitalized, respectively. As of December 31, 2013, there was $242 million of total unrecognized compensation cost related to 3,952,539 unvested restricted stock units. The weighted-average remaining life of unvested restricted stock units is approximately 1.3 years.

The fair value of the awards vested during 2013, 2012 and 2011 was approximately $88 million, $114 million, and $85 million, respectively. A summary of restricted stock activity for the year ended December 31, 2013, is presented below.

	Shares			Weighted- Average Grant- Date Fair Value
	(In thousands)
Non-vested at January 1, 2013		2,164		$	97.34
Granted		3,098			82.95
Vested		(907	)		96.79
Forfeited		(402	)		88.61
Non-vested at December 31, 2013		3,953			86.70

Conditional Restricted Stock Units

To provide long-term incentives for Apache employees to deliver competitive returns to the Company’s stockholders, the Company has 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. Grants from two conditional restricted stock unit programs were outstanding at December 31, 2013, as described below:

• 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. Based on measurement of total shareholder return relative to the designated peer group at December 31, 2013, zero shares were awarded and all unvested conditional restricted stock units were cancelled. Upon cancellation, all remaining unamortized expense related to these awards was immediately amortized.

• 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 710,686 units were outstanding at December 31, 2013, from which a minimum of zero and a maximum of 1,776,715 units could be awarded.

• In January 2013 the Company’s Board of Directors approved the 2013 Performance Program, pursuant to the 2011 Plan. In January 2013 eligible employees received initial conditional restricted stock unit awards totaling 1,232,176 units. In May 2013, the Company’s Board of Directors cancelled 918,016 awards under the 2013 Performance Program for nonexecutive employees. A total of 310,091 awards were outstanding at December 31, 2013, from which a minimum of zero and a maximum of 775,228 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 2013, 2012, and 2011, $27 million ($17 million after tax), $47 million ($31 million after tax), and $12 million ($8 million after tax), respectively, was charged to expense. During 2013, 2012, and 2011, $13 million, $21 million, and $5 million was capitalized, respectively. As of December 31, 2013, there was $47 million of total unrecognized compensation cost related to 1,020,777 unvested conditional restricted stock units. The weighted-average remaining life of the unvested conditional restricted stock units is approximately 2.1 years.

	Shares			Weighted- Average Grant- Date Fair Value(1)
	(In thousands)
Non-vested at January 1, 2013		1,306		$	78.40
Granted		1,232			79.60
Vested		0			79.49
Cancelled		(1,369	)		83.34
Forfeited		(149	)		78.09
Non-vested at December 31, 2013		1,020			73.73

(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.

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). The Company’s 6.00 percent Mandatory Convertible Preferred Stock, Series D (the Series D Preferred Stock) were converted to Apache common shares in August 2013.

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.

On February 5, 2014, the Company’s Board of Directors voted to terminate the Company’s stockholder rights plan. As a result of this decision, the Board approved an amendment to the Rights Agreement that will have the effect of terminating the Rights. The amendment will change the expiration date to March 7, 2014 and, thereby, accelerate the expiration of the Rights. The Company expects that the amendment will be fully executed on March 7, 2014.

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. Upon conversion of the outstanding Preferred Shares on August 1, 2013, 14.4 million Apache common shares were issued.

XML

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, 2013	Dec. 31, 2012	Dec. 31, 2011
Equity [Abstract]
Outstanding, beginning of year, Shares	7,573
Granted, Shares	819
Exercised, Shares	(327)
Forfeited or expired, Shares	(502)
Outstanding, end of year, Shares	7,563	7,573
Expected to vest, Shares	2,370
Exercisable, end of year, Shares	4,678
Weighted average fair value of options granted during the year	$ 23.18	$ 26.41	$ 42.20
Outstanding, beginning of year, Weighted Average exercise Price	$ 90.47
Granted, Weighted Average Exercise Price	$ 80.89
Exercised, Weighted Average Exercise Price	$ 72.55
Forfeited or expired, Weighted Average Exercise Price	$ 97.88
Outstanding, end of year, Weighted Average Exercise Price	$ 89.71	$ 90.47
Expected to vest, Weighted Average Exercise Price	$ 92.50
Exercisable, end of year, Weighted Average Exercise Price	$ 88.53

XML

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, 2013	Dec. 31, 2012	Dec. 31, 2011
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Oil and gas production revenues	$ 16,402	$ 16,947	$ 16,810
Depreciation, depletion, and amortization
Recurring	5,114	5,085	4,024
Additional	1,176	1,992	109
Asset retirement obligation accretion	243	232	154
Lease operating expenses	3,056	2,968	2,605
Gathering and transportation	297	303	296
Production taxes	796	817	865
Income tax	2,419	2,810	3,730
Oil and gas properties production expense	13,101	14,207	11,783
Results of operation	3,301	2,740	5,027
Amortization rate per boe	18.42	16.88	13.97
United States [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Oil and gas production revenues	6,902	6,226	6,103
Depreciation, depletion, and amortization
Recurring	2,227	1,984	1,634
Additional	552
Asset retirement obligation accretion	94	112	97
Lease operating expenses	1,320	1,386	1,167
Gathering and transportation	84	69	64
Production taxes	324	279	255
Income tax	817	851	1,025
Oil and gas properties production expense	5,418	4,681	4,242
Results of operation	1,484	1,545	1,861
Amortization rate per boe	18.39	17.24	15.55
Canada [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Oil and gas production revenues	1,224	1,322	1,617
Depreciation, depletion, and amortization
Recurring	426	580	537
Additional		1,883
Asset retirement obligation accretion	49	41	26
Lease operating expenses	459	458	470
Gathering and transportation	155	163	165
Production taxes	40	42	44
Income tax	24	(466)	95
Oil and gas properties production expense	1,153	2,701	1,337
Results of operation	71	(1,379)	280
Amortization rate per boe	10.89	11.66	10.44
Egypt [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Oil and gas production revenues	3,917	4,554	4,791
Depreciation, depletion, and amortization
Recurring	881	924	818
Lease operating expenses	471	410	398
Gathering and transportation	42	39	35
Income tax	1,161	1,527	1,699
Oil and gas properties production expense	2,555	2,900	2,950
Results of operation	1,362	1,654	1,841
Amortization rate per boe	16.21	13.81	11.63
Australia [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Oil and gas production revenues	1,140	1,575	1,734
Depreciation, depletion, and amortization
Recurring	361	460	435
Asset retirement obligation accretion	27	17	10
Lease operating expenses	214	215	197
Production taxes	14	11	9
Income tax	157	262	325
Oil and gas properties production expense	773	965	976
Results of operation	367	610	758
Amortization rate per boe	17.47	17.67	16.59
North Sea [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Oil and gas production revenues	2,728	2,751	2,091
Depreciation, depletion, and amortization
Recurring	999	912	405
Additional	367
Asset retirement obligation accretion	68	58	17
Lease operating expenses	400	315	208
Gathering and transportation	7	24	25
Production taxes	382	451	538
Income tax	313	614	557
Oil and gas properties production expense	2,536	2,374	1,750
Results of operation	192	377	341
Amortization rate per boe	37.25	32.65	20.21
Argentina [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Oil and gas production revenues	491	519	474
Depreciation, depletion, and amortization
Recurring	220	225	195
Additional	181
Asset retirement obligation accretion	5	4	4
Lease operating expenses	192	184	165
Gathering and transportation	9	8	7
Production taxes	36	34	19
Income tax	(53)	22	29
Oil and gas properties production expense	590	477	419
Results of operation	(99)	42	55
Amortization rate per boe	14.13	12.39	10.87
Other International [Member]
Depreciation, depletion, and amortization
Additional	76	109	109
Oil and gas properties production expense	76	109	109
Results of operation	$ (76)	$ (109)	$ (109)

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STATEMENT OF CONSOLIDATED CASH FLOWS (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income including noncontrolling interest	$ 2,288	$ 2,001	$ 4,584
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, and amortization	6,700	7,109	4,204
Asset retirement obligation accretion	243	232	154
Provision for deferred income taxes	263	677	1,246
Other	260	226	46
Changes in operating assets and liabilities:
Receivables	124	12	(759)
Inventories	(70)	(59)	(37)
Drilling advances	230	(343)	26
Deferred charges and other	(124)	61	27
Accounts payable	479	(100)	241
Accrued expenses	(553)	(1,142)	90
Deferred credits and noncurrent liabilities	(5)	(170)	131
NET CASH PROVIDED BY OPERATING ACTIVITIES	9,835	8,504	9,953
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property	(10,019)	(8,781)	(6,414)
Additions to gas gathering, transmission, and processing facilities	(1,201)	(750)	(664)
Proceeds from divestiture of Gulf of Mexico Shelf properties	3,702
Proceeds from Kitimat LNG transaction, net	396
Proceeds from sale of oil and gas properties, other	307	27	422
Acquisition of Cordillera Energy Partners III, LLC		(2,666)
Acquisition of Yara Pilbara Holdings Pty Limited		(439)
Acquisition of Mobil North Sea Limited			(1,246)
Acquisitions, other	(215)	(252)	(567)
Other, net	(86)	(563)	(176)
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES	(7,116)	(13,424)	(8,645)
CASH FLOWS FROM FINANCING ACTIVITIES:
Commercial paper, credit facilities and bank notes, net	(513)	549	(925)
Fixed rate debt borrowings		4,978
Payments on fixed rate debt	(2,072)	(400)
Proceeds from sale of noncontrolling interest	2,948
Dividends paid	(360)	(332)	(306)
Shares repurchased	(997)
Other	21	(10)	84
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES	(973)	4,785	(1,147)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	1,746	(135)	161
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	160	295	134
CASH AND CASH EQUIVALENTS AT END OF PERIOD	1,906	160	295
SUPPLEMENTARY CASH FLOW DATA:
Interest paid, net of capitalized interest	192	146	156
Income taxes paid, net of refunds	$ 1,766	$ 2,590	$ 1,686

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OTHER CURRENT LIABILITIES

12 Months Ended

Dec. 31, 2013

Payables And Accruals [Abstract]

OTHER CURRENT LIABILITIES

4. OTHER CURRENT LIABILITIES

The following table provides detail of the Company’s other current liabilities at December 31, 2013 and 2012:

	December 31, 2013		December 31, 2012
	(In millions)
Accrued operating expenses	$	190	$	211
Accrued exploration and development		1,582		1,792
Accrued compensation and benefits		242		198
Accrued interest		161		160
Accrued income taxes		248		297
Accrued U.K. Petroleum Revenue Tax		9		53
Other		179		149
Total Other current liabilities	$	2,611	$	2,860

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DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

12 Months Ended

Dec. 31, 2013

Derivative Instruments And Hedging Activities Disclosure [Abstract]

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, 2013, Apache had derivative positions with 14 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. The Company’s net derivative liability position at December 31, 2013, represents the aggregate fair value of all derivative instruments with credit-risk-related contingent features that are in a net liability position. The Company has not provided any collateral to any of its counterparties as of December 31, 2013.

Derivative Instruments

As of December 31, 2013, Apache had the following open crude oil derivative positions which have not been designated as cash flow hedges:

		Fixed-Price Swaps
Production Period	Settlement Index	Mbbls		Weighted Average Fixed Price
2014	NYMEX WTI		22,889	$	90.77
2014	Dated Brent		22,812		100.05

As of December 31, 2013, Apache had the following open natural gas derivative positions which have been designated as cash flow hedges:

		Fixed-Price Swaps
Production Period	Settlement Index	MMBtu (in 000’s)		Weighted Average Fixed Price
2014	NYMEX Henry Hub		1,295	$	6.72

Subsequent to December 31, 2013, Apache entered into additional natural gas derivatives not designated as cash flow hedges totaling 55.9 million MMBtu for 2014. These contracts are settled against NYMEX Henry Hub and various Inside FERC indices, with a weighted average fixed price of $4.35.

Fair Value Measurements

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, 2013
Assets:
Derivatives designated as cash flow hedges	$	—	$	3	$	—	$	3	$	(2	)	$	1
Liabilities:
Derivatives designated as cash flow hedges	$	—	$	1	$	—	$	1
Derivatives not designated as cash flow hedges		—		300		—		300
Total Derivative liabilities	$	—	$	301	$	—	$	301	$	(2	)	$	299
December 31, 2012
Assets:
Derivatives designated as cash flow hedges	$	—	$	48	$	—	$	48	$	(15	)	$	33
Liabilities:
Derivatives designated as cash flow hedges	$	—	$	51	$	—	$	51
Derivatives not designated as cash flow hedges		—		80		—		80
Total Derivative liabilities	$	—	$	131	$	—	$	131	$	(15	)	$	116

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

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, 2013		December 31, 2012
	(In millions)
Current Assets: Derivative instruments	$	1	$	31
Other Assets: Deferred charges and other		—		2
Total Assets	$	1	$	33
Current Liabilities: Derivative instruments	$	299	$	116
Total Liabilities	$	299	$	116

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	For the Year Ended December 31,
	Recognized in Income	2013			2012			2011
		(In millions)
Gain (loss) on cash flow hedges reclassified from accumulated other comprehensive loss	Oil and Gas Production Revenues	$	(16	)	$	268		$	(13	)
Gain (loss) for ineffectiveness on cash flow hedges	Revenues and Other: Other	$	(1	)	$	—		$	2
Loss on derivatives not designated as cash flow hedges	Derivative instrument gains (losses), net	$	(399	)	$	(79	)	$	—

Unrealized gains and losses for derivative activity recorded in the statement of consolidated operations is reflected in the statement of consolidated cash flows as a component of “Other” in “Adjustments to reconcile net income to net cash provided by operating activities.”

Derivative Activity in Accumulated Other Comprehensive Income (Loss)

As of December 31, 2013, a portion of the Company’s derivative instruments were designated as cash flow hedges. A reconciliation of the components of accumulated other comprehensive income (loss) in the statement of consolidated changes in equity related to Apache’s cash flow hedges is presented in the table below:

	For the Year Ended December 31,
	2013						2012						2011
	Before			After			Before			After			Before			After
	tax			tax			tax			tax			tax			tax
	(In millions)
Unrealized gain (loss) on derivatives at beginning of year	$	(10	)	$	(6	)	$	145		$	114		$	(54	)	$	(19	)
Realized amounts reclassified into earnings		16			11			(268	)		(199	)		13			19
Net change in derivative fair value		(6	)		(5	)		113			79			188			115
Ineffectiveness reclassified into earnings		1			1			—			—			(2	)		(1	)
Unrealized gain (loss) on derivatives at end of period	$	1		$	1		$	(10	)	$	(6	)	$	145		$	114

Unrealized net gains on existing cash flow hedges as of December 31, 2013 will be realized in earnings through mid-2014, in the same period as the related sales of natural gas and crude oil production occur; however, estimated and actual amounts may vary materially as a result of changes in market conditions.

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SUPPLEMENTAL QUARTERLY FINANCIAL DATA (Unaudited)

12 Months Ended

Dec. 31, 2013

Quarterly Financial Information Disclosure [Abstract]

SUPPLEMENTAL QUARTERLY FINANCIAL DATA (Unaudited)

15.     SUPPLEMENTAL QUARTERLY FINANCIAL DATA (Unaudited)

	First		Second		Third		Fourth		Total
	(In millions, except per share amounts)
2013
Revenues and other	$	4,076	$	4,383	$	4,019	$	3,576	$	16,054
Expenses(2)		3,359		3,348		3,713		3,346		13,766
Net income including noncontrolling interest	$	717	$	1,035	$	306	$	230	$	2,288
Net income attributable to common stock	$	698	$	1,016	$	300	$	174	$	2,188
Net income per common share(1):
Basic	$	1.78	$	2.59	$	0.75	$	0.44	$	5.53
Diluted	$	1.76	$	2.54	$	0.75	$	0.43	$	5.50
2012
Revenues and other	$	4,536	$	3,972	$	4,179	$	4,391	$	17,078
Expenses(2)		3,739		3,616		3,999		3,723		15,077
Net income including noncontrolling interest	$	797	$	356	$	180	$	668	$	2,001
Net 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

(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.

(2) In 2013, operating expenses include non-cash write-downs of the Company’s oil and gas properties totaling $659 million, net of tax, in the U.S., North Sea, and Argentina regions and also the Company’s exit of operations in Kenya. In 2012, the Company recorded a $1.4 billion, net of tax, non-cash write-down of the carrying value of the Company’s Canadian proved oil and gas properties.

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ACCUMULATED OTHER COMPREHENSIVE LOSS

12 Months Ended

Dec. 31, 2013

Equity [Abstract]

ACCUMULATED OTHER COMPREHENSIVE LOSS

11. ACCUMULATED OTHER COMPREHENSIVE LOSS

Components of accumulated other comprehensive loss include the following:

	For the Year Ended December 31,
	2013			2012			2011
	(In millions)
Currency translation adjustment(1)	$	(109	)	$	(109	)	$	(109	)
Unrealized gain (loss) on derivatives (Note 3)		1			(6	)		114
Unfunded pension and postretirement benefit plan (Note 9)		(7	)		(16	)		(14	)
Accumulated other comprehensive loss	$	(115	)	$	(131	)	$	(9	)

⁽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 - Additional Information 1 (Detail) (USD $)	0 Months Ended	12 Months Ended			1 Months Ended	12 Months Ended	1 Months Ended	12 Months Ended	1 Months Ended	12 Months Ended	0 Months Ended	12 Months Ended
	Jul. 28, 2010	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Jan. 31, 2011 Performance Program 2011 [Member]	Dec. 31, 2013 Performance Program 2011 [Member]	Jan. 31, 2013 Performance Program 2012 [Member]	Dec. 31, 2012 Performance Program 2012 [Member]	May 31, 2013 Performance Program 2013 [Member]	Dec. 31, 2013 Series A Preferred Stock [Member]	Jul. 28, 2010 Series D Preferred Stock [Member]	Dec. 31, 2013 Series D Preferred Stock [Member]	Dec. 31, 2013 Conditional Restricted Stock [Member]	Dec. 31, 2012 Conditional Restricted Stock [Member]	Dec. 31, 2011 Conditional Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Initial conditional restricted stock unit awards granted to eligible employees					851,985		1,232,176
Nonvested shares outstanding						710,686		918,016					1,020,777	1,306,000
Minimum units awarded based upon measurement						0		0
Maximum units awarded based upon measurement						1,776,715		775,228
Range of ultimate number of restricted stock units awarded						Zero and a maximum of 1,776,715 units		Zero and a maximum of 775,228 units
Restricted stock awards cancelled									918,016				1,369,000
Stock-based compensation expense		$ 136,000,000	$ 167,000,000	$ 113,000,000									$ 27,000,000	$ 47,000,000	$ 12,000,000
Stock-based compensation expenses, after tax		94,000,000	119,000,000	73,000,000									17,000,000	31,000,000	8,000,000
Restricted stock capitalized		55,000,000	67,000,000	42,000,000									13,000,000	21,000,000	5,000,000
Total compensation cost related to non-vested options not yet recognized													47,000,000
Weighted-average remaining life of unvested restricted stock units													2 years 1 month 6 days
Preferred stock, shares authorized		10,000,000	10,000,000							10,000,000
Shares designated as Series A Junior Participating Preferred Stock										25,000
Mandatory convertibles preferred stock, Series D	6.00%											6.00%
Series A 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
Dividend right expiration date										Mar. 07, 2014
Depositary shares in separate underwriting	25,300,000
Depositary shares each representing	1/20th interest
Preferred stock, shares issued	1,265,000		1,265,000
Maximum common shares issued to convertible preferred stock											14,400,000

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INCOME TAXES

12 Months Ended

Dec. 31, 2013

Income Tax Disclosure [Abstract]

INCOME TAXES

7.     INCOME TAXES

Income before income taxes is composed of the following:

	For the Year Ended December 31,
	2013		2012		2011
	(In millions)
U.S.	$	1,191	$	1,605	$	2,373
Foreign		3,025		3,272		5,720
Total	$	4,216	$	4,877	$	8,093

The total provision for income taxes consists of the following:

	For the Year Ended December 31,
	2013			2012			2011
	(In millions)
Current taxes:
Federal	$	(29	)	$	(150	)	$	64
State		—			—			2
Foreign		1,694			2,349			2,197
		1,665			2,199			2,263
Deferred taxes:
Federal		509			596			656
State		44			10			17
Foreign		(290	)		71			573
		263			677			1,246
Total	$	1,928		$	2,876		$	3,509

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,
	2013			2012			2011
	(In millions)
Income tax expense at U.S. statutory rate	$	1,476		$	1,707		$	2,833
State income tax, less federal benefit		29			6			12
Taxes related to foreign operations		200			773			568
Tax credits		6			(4	)		(15	)
Deferred tax on distributed foreign earnings		225			—			—
Current and deferred taxes related to currency fluctuations		(154	)		16			(66	)
Change in U.K. tax rate		—			118			218
Net change in tax contingencies		(10	)		(115	)		(6	)
Valuation allowances		199			355			8
All other, net		(43	)		20			(43	)
	$	1,928		$	2,876		$	3,509

The net deferred tax liability consists of the following:

	December 31,
	2013			2012
	(In millions)
Deferred tax assets:
Deferred income	$	153		$	33
Federal and state net operating loss carryforwards		900			932
Foreign net operating loss carryforwards		156			61
Tax credits		66			78
Accrued expenses and liabilities		162			2
Asset retirement obligation		1,231			1,677
Total deferred tax assets		2,668			2,783
Valuation allowance		(651	)		(419	)
Net deferred tax assets		2,017			2,364
Deferred tax liabilities:
Other		29			23
Depreciation, depletion and amortization		10,224			10,213
Total deferred tax liabilities		10,253			10,236
Net deferred income tax liability	$	8,236		$	7,872

The Company has recorded a valuation allowance against the net deferred tax asset in Argentina and Canada and against certain state net operating losses. The Company has assessed the future potential realization of these deferred tax assets and has concluded that it is more likely than not that these deferred tax assets will not be realized based on current economic conditions. In 2013, 2012, and 2011, the Company increased its valuation allowance by $232 million, $359 million, and $7 million, respectively.

On November 14, 2013, the Company completed the formation of its strategic partnership with Sinopec, whereby the Company received $2.95 billion in exchange for a one-third minority participation interest in Apache’s Egypt oil and gas business. As a result of the transaction, the Company reassessed its position with respect to certain current year untaxed foreign earnings to treat the reinvestment of these earnings as not permanent in duration. As such, the Company recorded a $225 million deferred tax charge on current year foreign earnings deemed not permanently reinvested. The Company repatriated approximately $643 million of cash from foreign subsidiaries and utilized net operating losses to offset any U.S. current income tax expense.

The Company considers the undistributed earnings of its foreign subsidiaries to be permanently reinvested, as it has no current intention to repatriate these earnings. As such, deferred income taxes are not provided for temporary differences of approximately $17 billion at December 31, 2013, representing unremitted earnings of subsidiaries outside the United States intended to be permanently reinvested. Upon an actual or deemed 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 practicable, 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, 2013, the Company had net operating losses as follows:

	December 31, 2013
	Amount		Expiration
	(In millions)
Net operating losses:
U.S. — Federal	$	1,558		2032 - 2034
U.S. — Federal (Mariner IRC §382 limited)		520		2018 - 2030
U.S. — Federal (Cordillera IRC §382 limited)		183		2026 - 2032
U.S. — State		2,242		Various
Canada		5		2014
Australia		59		Indefinite
Argentina		299		2014

The Company has a federal net operating loss carryforward of $2.3 billion. Included in the federal net operating loss carryforward is $520 million of federal net operating losses related to the 2010 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 has $186 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 discussed above, the Company does not believe the utilization of the Argentine net operating losses, Canadian capital losses, and certain state net operating losses to be “more likely than not.” As such, a valuation allowance was provided against these deferred tax assets.

The Company 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:

	2013		2012			2011
	(In millions)
Balance at beginning of year	$	3	$	97		$	110
Additions based on tax positions related to the current year		—		4			13
Reductions for tax positions of prior years		—		(33	)		(4	)
Settlements		—		(65	)		(22	)
Balance at end of year	$	3	$	3		$	97

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, 2013, 2012, and 2011 the Company recorded tax expense of $1 million, $5 million, and $6 million, respectively, for interest and penalties. As of December 31, 2013 and 2012, the Company had approximately $1 million and $5 million, respectively, accrued for payment of interest and penalties.

The Company is under IRS audit for 2011 and 2012 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 2013, the Company reached an agreement with the IRS regarding an audit of the 2009 and 2010 tax years. There was no change in the Company’s unrecognized tax benefit as a result of the 2009 and 2010 IRS settlement. In 2012, the Company reached an agreement with the IRS Administrative Appeals office regarding the audits of tax years 2004 through 2008. As a result of this agreement, the Company reduced its 2012 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.	2010
Canada	2009
Egypt	1998
Australia	2009
U.K.	2011
Argentina	2006

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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, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Tax Disclosure [Abstract]
Income tax expense at U.S. statutory rate	$ 1,476	$ 1,707	$ 2,833
State income tax, less federal benefit	29	6	12
Taxes related to foreign operations	200	773	568
Tax credits	6	(4)	(15)
Deferred tax on distributed foreign earnings	225
Current and deferred taxes related to currency fluctuations	(154)	16	(66)
Change in U.K. tax rate		118	218
Net change in tax contingencies	(10)	(115)	(6)
Valuation allowances	199	355	8
All other, net	(43)	20	(43)
Total	$ 1,928	$ 2,876	$ 3,509

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ASSET RETIREMENT OBLIGATION

12 Months Ended

Dec. 31, 2013

Asset Retirement Obligation Disclosure [Abstract]

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, 2013 and 2012:

	2013			2012
	(In millions)
Asset retirement obligation at beginning of year	$	4,578		$	3,887
Liabilities incurred		481			592
Liabilities acquired		53			72
Liabilities divested		(1,692	)		—
Liabilities settled		(497	)		(550	)
Accretion expense		243			232
Revisions in estimated liabilities		56			345
Asset retirement obligation at end of year		3,222			4,578
Less current portion		(121	)		(478	)
Asset retirement obligation, long-term	$	3,101		$	4,100

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 2013 and 2012, the Company recorded $481 million and $592 million, respectively, in abandonment liabilities resulting from Apache’s active exploration and development capital program. Liabilities settled primarily relate to individual properties, platforms, and facilities plugged and abandoned during the period.

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DEBT

12 Months Ended

Dec. 31, 2013

Debt Disclosure [Abstract]

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.

During 2013, Apache repaid the $500 million aggregate principal amount of 5.25 percent notes that matured on April 15, 2013 and the $400 million aggregate principal amount of 6.00 percent notes that matured on September 15, 2013 by borrowing under our commercial paper program.

In November 2013 the Company announced a cash tender offer to purchase up to $850 million aggregate principal amount of five series of its outstanding notes. On December 20, 2013, the Company accepted for purchase $669 million principal amount of its 2.625 percent notes due 2023 and $181 million principal amount of its 3.25 percent notes due 2022. Apache paid the holders an aggregate of approximately $811 million in cash reflecting principal, the discount to par, and accrued and unpaid interest.

In December 2013, Apache Finance Canada Corporation (Apache Finance Canada) fully redeemed $350 million principal amount of 4.375 percent notes due in 2015. The notes were redeemed pursuant to the provisions of the note’s indenture. Apache paid the holders an aggregate of approximately $371 million in cash reflecting principal, the premium to par, and accrued and unpaid interest.

The Company recorded a net gain on extinguishment of debt totaling $16 million in connection with the cash tender offer and redemption of Apache Finance Canada notes.

The following table presents the carrying value of the Company’s debt at December 31, 2013 and 2012:

	December 31,
	2013			2012
	(In millions)
U.S.:
Money market lines of credit	$	—		$	13
Commercial paper		—			489
5.25% notes due 2013(1)		—			500
6.0% notes due 2013(1)		—			400
5.625% notes due 2017(1)		500			500
1.75% notes due 2017(1)		400			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)		919			1,100
2.625% notes due 2023(1)		531			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			1,500
4.25% notes due 2044(1)		800			800
7.375% debentures due 2047		150			150
7.625% debentures due 2096		150			150
		9,430			11,682
Subsidiary and other obligations:
Argentina overdraft lines of credit		51			69
Canada lines of credit		2			9
Apache Finance Canada 4.375% notes due 2015(1)		—			350
Notes due in 2016 and 2017		1			1
Apache Finance Canada 7.75% notes due 2029		300			300
		354			729
Debt before unamortized discount		9,784			12,411
Unamortized discount		(59	)		(66	)
Total debt	$	9,725		$	12,345
Current maturities	$	(53	)	$	(990	)
Long-term debt	$	9,672		$	11,355

⁽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, 2013, excluding discounts, are as follows:

	(In millions)
2014	$	53
2015		—
2016		1
2017		900
2018		550
Thereafter		8,280
Total Debt, excluding discounts	$	9,784

Fair Value

The Company’s debt is recorded at the carrying amount, net of unamortized discount, on its consolidated balance sheet. The carrying amount of the Company’s commercial paper and uncommitted credit facilities and overdraft lines 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 (a Level 2 fair value measurement).

	December 31, 2013				December 31, 2012
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)
Money market lines of credit	$	53	$	53	$	91	$	91
Commercial paper		—		—		489		489
Notes and debentures		9,672		10,247		11,765		13,340
Total Debt	$	9,725	$	10,300	$	12,345	$	13,920

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, 2013, $53 million was drawn on facilities in Argentina and Canada. As of December 31, 2012, $91 million was drawn on facilities in the U.S., Argentina, and Canada.

Unsecured Committed Bank Credit Facilities

As of December 31, 2013, 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. In July 2013, we amended our $1.0 billion U.S. credit facility to conform certain representations, covenants, and events of default to those in our $1.7 billion U.S. credit facility. The amendments did not affect the amount or repayment terms of the $1.0 billion U.S. facility. As of December 31, 2013, available borrowing capacity under the Company’s credit facilities was $3.3 billion. The committed credit facilities are used to support Apache’s commercial paper program.

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, 2013, 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, 2013, the Company’s debt-to-capitalization ratio was 22 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 $3.1 billion as of December 31, 2013. 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, 2013.

Commercial Paper Program

The Company has available a $3.0 billion commercial paper program, which generally enables Apache to borrow funds for up to 270 days at competitive interest rates. The commercial paper program is fully supported by available borrowing capacity under committed credit facilities. Our 2013 weighted-average interest rate for commercial paper was 0.38 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. The Company used proceeds from divestitures to repay commercial paper and at year end had no outstanding balance. At December 31, 2012, the Company had $489 million in commercial paper outstanding.

Subsidiary Notes – Apache Finance Canada

Apache Finance Canada Corporation (Apache Finance Canada) has approximately $300 million of publicly-traded notes due in 2029 that are fully and unconditionally guaranteed by Apache. For further discussion of subsidiary debt, please see Note 16—Supplemental Guarantor Information.

Financing Costs, Net

The following table presents the components of Apache’s financing costs, net:

	For the Year Ended December 31,
	2013			2012			2011
	(In millions)
Interest expense	$	571		$	509		$	433
Amortization of deferred loan costs		8			7			5
Capitalized interest		(374	)		(334	)		(263	)
Gain on extinguishment of debt		(16	)		—			—
Interest income		(15	)		(17	)		(17	)
Financing costs, net	$	174		$	165		$	158

The Company has $59 million of debt discounts as of December 31, 2013, which will be charged to interest expense over the life of the related debt issuances. Discount amortization of $3 million, $3 million, and $2 million were recorded as interest expense in 2013, 2012, and 2011, respectively.

As of December 31, 2013 and 2012, the Company had approximately $74 million and $118 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, 2013

Commitments And Contingencies Disclosure [Abstract]

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 $10 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 in 2012 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.

Argentine Tariff 

Enargas, an autonomous entity that functions under the Argentine Ministry of Economy, issued administrative orders pursuant to national executive Decree No. 2067/2008 creating a tariff charge on all fuel gas used by oil and gas producers in field operations effective December 1, 2011. The tariff charge, which is applicable to the operations of Company affiliates in Argentina, totaled approximately $39.5 million since inception, of which $11 million has been paid. The Company’s affiliates have initiated legal proceedings in the Provinces of Neuquén and Tierra del Fuego challenging the Enargas tariff charge and have obtained temporary injunctive relief that prohibits the collection of the charges pending final rulings on the merits of the legal challenges.

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 also denied, and petitioned the United States Court of Appeals for the Tenth Circuit to accept an appeal of the District Court’s ruling denying class certification. The plaintiff withdrew the petition to appeal following decisions on July 8, 2013, by the United States Court of Appeals for the Tenth Circuit to vacate District Court class certification orders in two unrelated lawsuits — Wallace B. Roderick Revocable Living Trust v. XTO Energy, Inc., No. 12-3176, and Chieftain Royalty Company v. XTO Energy, Inc., No. 12-7047. The plaintiff and Apache recently filed a joint stipulation to dismiss the Foster lawsuit with prejudice, which concludes the matter.

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.

On July 24, 2013, a lawsuit captioned Board of Commissioners of the Southeast Louisiana Flood Protection Authority — East v. Tennessee Gas Pipeline Company et al., Case No. 2013-6911 was filed in the Civil District Court for the Parish of Orleans, State of Louisiana, in which plaintiff on behalf of itself and as the board governing the levee districts of Orleans, Lake Borgne Basin, and East Jefferson alleges that Louisiana coastal lands have been damaged as a result of oil and gas industry activity, including a network of canals for access and pipelines. The plaintiff seeks damages and injunctive relief in the form of abatement and restoration based on claims of negligence, strict liability, natural servitude of drain, public nuisance, private nuisance, and breach of contract — third party beneficiary. Apache has been indiscriminately named as one of approximately 100 defendants in the lawsuit. Defendant Chevron U.S.A., Inc. filed a notice to remove the case to the United States District Court for the Eastern District of Louisiana, civil action No. 13-5410. The overall exposure related to this lawsuit is not currently determinable. While an adverse judgment against Apache might be possible, Apache intends to vigorously defend the case.

On November 8, 2013, the Parish of Plaquemines in Louisiana filed three lawsuits against the Company and other oil and gas producers alleging that certain of defendants’ oil and gas exploration, production, and transportation operations in specified fields were conducted in violation of the State and Local Coastal Resources Management Act of 1978, as amended, and applicable regulations, rules, orders, and ordinances promulgated or adopted thereunder by the State of Louisiana or the Parish of Plaquemines. The plaintiff alleges that defendants caused substantial damage to land and water bodies located in the coastal zone of Louisiana. The plaintiff seeks, among other things, unspecified damages for alleged violations of applicable state law within the coastal zone, the payment of costs necessary to clear, re-vegetate, detoxify, and otherwise restore the subject coastal zone as near as practicable to its original condition, and actual restoration of the coastal zone to its original condition. The lawsuits were all filed in Division A of the 25^th Judicial District Court for the Parish of Plaquemines, State of Louisiana, and are captioned as follows: Parish of Plaquemines v. Rozel Operating Company et al., Docket No. 60-996; Parish of Plaquemines v. Apache Oil Corporation et al., Docket No. 61-000; and Parish of Plaquemines v. HHE Energy Company et al., Docket No. 60-983. Defendants have filed notices to remove the cases to the United States District Court for the Eastern District of Louisiana, civil action Nos. 13-6722, 13-6711, and 13-6735. The plaintiff has moved to remand each of the lawsuits to state court, and plaintiff’s motions are pending. Many similar lawsuits have been filed against other oil and gas producers in the Parish of Plaquemines and in other Parishes across south Louisiana. The overall exposure related to these lawsuits is not currently determinable. While an adverse judgment against Apache might be possible, Apache intends to vigorously defend the cases.

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, alleged 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 sought 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 was one of numerous defendants. The District Court granted defendants’ motion to dismiss plaintiffs’ claims. Plaintiffs appealed the decision to the United States Court of Appeals for the Fifth Circuit, which affirmed dismissal of the suit. Plaintiffs did not appeal further, thus concluding the matter. 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 natural gas customer, Burrup Fertilisers Pty Ltd (Burrup Fertilisers), 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, in a case captionedBurrup Fertilisers Pty Ltd v. Apache Corporation, Apache Energy Limited, and Apache Northwest Pty Ltd, Cause No. 2009-79834, in the District Court of Harris County, Texas. The lawsuit concerned the interruption of deliveries of natural gas to Burrup Fertilisers following the pipeline explosion. Burrup Fertilisers and its underwriters asserted claims for negligence, breach of contract, alter ego, single business enterprise, res ipsa loquitur, and gross negligence/exemplary damages, and sought 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. On March 22, 2013, Burrup Fertilisers agreed to dismiss its Texas lawsuit based on Apache Corporation’s motion to dismiss on the ground offorum non conveniens. Accordingly, the District Court entered an agreed order dismissing Burrup Fertilisers’ Texas lawsuit on the ground of forum non conveniens. By its terms, the order of dismissal does not prevent Burrup Fertilisers from re-filing its lawsuit in the civil courts of Western Australia.

On March 24, 2011, another natural gas 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. On September 17, 2013, the Western Australia Court of Appeal dismissed the Company subsidiaries’ appeal concerning Alcoa’s remaining tort claim for economic loss. On October 15, 2013, the Company subsidiaries applied to the High Court of Australia for leave to appeal. The applications for leave to appeal are pending. If the High Court does not grant leave to appeal at this time, all of the Company subsidiaries’ defenses remain intact for further proceedings at the trial court level.

On October 31, 2013, a third natural gas customer, Barrick (Plutonic) Limited (“Barrick”), filed a lawsuit captioned Barrick (Plutonic) Limited v. Apache Energy Limited, Apache Northwest Pty Ltd, Harriet (Onyx) Pty Ltd, and Kufpec Australia Pty Ltd , Civ. 2656 of 2013, in the Supreme Court of Western Australia. The lawsuit concerns the interruption of gas deliveries to Barrick under certain gas supply contracts. Barrick asserts tort claims against the Company’s subsidiaries and seeks approximately $19 million USD in general damages, including for alleged lost gold production at the Plutonic mine in Western Australia.

The Company and its subsidiaries do not believe that the Burrup Fertilisers, Alcoa, and Barrick 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. At least one third party that is not a customer has also threatened to file suit. Contract prices under customer contracts are significantly below current 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 $50 million AUD exclusive of interest. This is a reduction from the previous estimate of $200 million AUD. No assurance can be given that customers would not assert claims in excess of contractual liquidated damages, and exposure related to such claims (or any claims by non-customers) is not currently determinable. While an adverse judgment against Company subsidiaries (and the Company, in the case of Burrup Fertilisers) 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 was $50,000 AUD. The Company subsidiary did not believe that the charge had 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 stated 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 was 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 would 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 were 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. On May 28, 2013, the United States District Court for the Southern District of Texas dismissed the plaintiffs’ claims and entered judgment in favor of the defendants. On June 3, 2013, the plaintiffs filed a notice of appeal in the United States Court of Appeals for the Fifth Circuit. The appeal is pending. The exposure related to the re-filed lawsuit is not currently determinable. While an adverse judgment against Apache is possible, Apache intends to vigorously 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 of Delaware. 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 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 Pankaj Oswal et al. v. Apache Corporation, Cause No. 2011-30302, in the District Court of Harris County, Texas, was filed in which plaintiffs asserted claims against the Company under the Australian Trade Practices Act. Following a hearing on March 22, 2013, the District Court on April 5, 2013, granted Apache Corporation’s motion to dismiss on the ground of forum non conveniens and entered an order dismissing the Texas lawsuit. On or about October 11, 2013, a statement of claim captioned Pankaj Oswal v. Apache Corporation, No. WAD 389/2013, in the Federal Court of Australia, District of Western Australia, General Division, was filed in which plaintiff Oswal once again asserts claims against the Company under the Australian Trade Practices Act. The Western Australia lawsuit is one of a number of legal actions involving the 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 Western Australia 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 and Western Australia lawsuits relate 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 operates the ammonia plant and is proceeding 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. 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). YPHPL share ownership, and the modified gas supply agreement, continues to be the subject of ongoing litigation in Australia with third parties, including Pankaj and Radhika Oswal. Two such cases directly involve the Company or certain of its subsidiaries. In a case captioned Radhika Oswal v. Australia and New Zealand Banking Group Limited (ANZ) et al., No. SCI 2011 4653, in the Supreme Court of Victoria, the defendants include a Company affiliate. The Court has denied plaintiff’s application seeking to amend her statement of claim in order to add parties as defendants to the proceedings, including the Company and certain of its other subsidiaries. Similarly, in a companion case captioned Pankaj Oswal v. Australia and New Zealand Banking Group Limited (ANZ) et al., No. SCI 2012 01995, in the Supreme Court of Victoria, the Court has also denied plaintiff’s application seeking to amend his statement of claim in order to add parties as defendants to the proceedings, including the Company and certain of its subsidiaries. The plaintiffs, either in their original claims or in their proposed amended claims, seek to set aside the YPHPL share sale, void the modified gas sale agreement, and recover unspecified damages. The plaintiffs’ in both cases have sought leave to appeal the Court’s denial of their applications. 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, 2013, the Company had an undiscounted reserve for environmental remediation of approximately $93 million. Apache is not aware of any environmental claims existing as of December 31, 2013 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.

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.

On June 1, 2013, Apache Canada Ltd. discovered a leak of produced water from a below ground pipeline in the Zama Operations area in northern Alberta. The pipeline was associated with a produced water disposal well. The spill resulted in approximately 97 thousand barrels of produced water being released to the marsh land environment. The applicable government agencies were immediately notified of the event and the line was shut down. Apache Canada Ltd. investigated the leak while conducting clean up and monitoring activities in the affected area and communicating with appropriate parties, including regulatory and First Nation representatives. The investigation revealed a pinhole feature in the outer polyethylene liner of the composite flex line. While the exposure related to this incident is not currently determinable, the Company does not expect the economic impact of this incident to have a material effect on the Company’s financial position, results of operations, or liquidity.

Contractual Obligations

At December 31, 2013, contractual obligations for drilling rigs, purchase obligations, firm transportation agreements, and long-term operating leases are as follows:

									2019 &
Net Minimum Commitments	Total		2014		2015-2016		2017-2018		Beyond
	(In millions)
Drilling rig commitments(1)	$	974	$	376	$	429	$	157	$	12
Purchase obligations(2)		1,759		1,002		533		204		20
Firm transportation agreements(3)		683		158		223		129		173
Office and related equipment(4)		391		46		101		95		149
Other operating lease obligations(5)		686		190		295		193		8
Total Net Minimum Commitments	$	4,493	$	1,772	$	1,581	$	778	$	362

(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 $81 million, $76 million, and $64 million for 2013, 2012, and 2011, respectively.

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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, 2013
Income Tax Disclosure [Abstract]
Balance at beginning of year	$ 97	$ 110	$ 3
Additions based on tax positions related to the current year	4	13
Reductions for tax positions of prior years	(33)	(4)
Settlements	(65)	(22)
Balance at end of year	$ 3	$ 97	$ 3

XML

Capital Stock - Conditional Restricted Stock (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Non-vested at January 1, 2013, Weighted Average Grant Date Fair Value	$ 97.34
Granted, Weighted Average Grant-Date Fair Value	$ 82.95
Vested, Weighted Average Grant-Date Fair Value	$ 96.79
Forfeited, Weighted Average Grant-Date Fair Value	$ 88.61
Non-vested at December 31, 2013, Weighted Average Grant Date Fair Value	$ 86.70
Conditional Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted Shares, nonvested, Beginning Balance, Shares	1,306,000
Granted, Shares	1,232,000
Vested, Shares	0
Cancelled, Shares	(1,369,000)
Forfeited or cancelled, Shares	(149,000)
Restricted Shares, nonvested, Ending Balance, Shares	1,020,777
Non-vested at January 1, 2013, Weighted Average Grant Date Fair Value	$ 78.40
Granted, Weighted Average Grant-Date Fair Value	$ 79.60
Vested, Weighted Average Grant-Date Fair Value	$ 79.49
Cancelled, Weighted Average Grant-Date Fair Value	$ 83.34
Forfeited, Weighted Average Grant-Date Fair Value	$ 78.09
Non-vested at December 31, 2013, Weighted Average Grant Date Fair Value	$ 73.73

XML

Commitments and Contingencies - Additional Information (Detail)	0 Months Ended	12 Months Ended				25 Months Ended			12 Months Ended
	Jun. 02, 2013 Barrels	Dec. 31, 2013 USD ($) Defendant Contract	Dec. 31, 2013 AUD	Dec. 31, 2012 USD ($)	Dec. 31, 2011 USD ($)	Dec. 31, 2013 USD ($)	Oct. 31, 2013 USD ($)	May 29, 2009 AUD	Dec. 31, 2013 Alcoa [Member] USD ($) Contract	Dec. 31, 2013 Oswal [Member] USD ($)	Jan. 31, 2012 Burrup Holdings Limited (Yara Pilbara Holdings Pty Limited ) [Member]	Jan. 31, 2012 Yara International [Member]
Commitment And Contingencies [Line Items]
Accrued liability for legal contingencies		$ 10,000,000				$ 10,000,000
Tariff charges on fuel gas						39,500,000
Tariff charges paid		11,000,000
Cost for the restoration of plaintiffs' property		61,000,000
Number of defendants		100	100
Maximum Expected contractual general damages							19,000,000		158,000,000	491,000,000
Number of Contract									2
Maximum expected contractual liquidated damages under long term contracts		5,700,000	50,000,000			5,700,000
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%
Reduction of previous estimate			200,000,000
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				300,000
Undiscounted reserve for environmental remediation		93,000,000				93,000,000
Quantity of water spill	97,000
Net rental expenses		$ 81,000,000		$ 76,000,000	$ 64,000,000
Lease Expiration		2035	2035

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Supplemental Guarantor Information - Additional Information (Detail) (Notes Due 2029 [Member], USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013
Notes Due 2029 [Member]
Condensed Financial Statements, Captions [Line Items]
Publicly traded notes	$ 300
Publicly-traded notes maturity date	2029

XML

Income Taxes - Net Operating Losses (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013
United States [Member]
Net operating losses:
Net operating losses	$ 1,558
United States State [Member]
Net operating losses:
Net operating losses	2,242
Net operating losses, Expiration	Various
Canada [Member]
Net operating losses:
Net operating losses	5
Net operating losses, Expiration	2014
Australia [Member]
Net operating losses:
Net operating losses	59
Net operating losses, Expiration	Indefinite
Argentina [Member]
Net operating losses:
Net operating losses	299
Net operating losses, Expiration	2014
Mariner Energy Inc [Member] | United States [Member]
Net operating losses:
Net operating losses	520
Cordillera Energy Partners [Member] | United States [Member]
Net operating losses:
Net operating losses	$ 183
Minimum [Member] | United States [Member]
Net operating losses:
Net operating losses, Expiration	2032
Minimum [Member] | Mariner Energy Inc [Member] | United States [Member]
Net operating losses:
Net operating losses, Expiration	2018
Minimum [Member] | Cordillera Energy Partners [Member] | United States [Member]
Net operating losses:
Net operating losses, Expiration	2026
Maximum [Member] | United States [Member]
Net operating losses:
Net operating losses, Expiration	2034
Maximum [Member] | Mariner Energy Inc [Member] | United States [Member]
Net operating losses:
Net operating losses, Expiration	2030
Maximum [Member] | Cordillera Energy Partners [Member] | United States [Member]
Net operating losses:
Net operating losses, Expiration	2032

XML

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, 2013	Dec. 31, 2012	Dec. 31, 2011
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Capitalized interest	$ 340	$ 316	$ 243
Asset retirement costs	537	1,032	1,411
United States [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Capitalized interest	239	215	152
Asset retirement costs	480	473	380
Canada [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Capitalized interest	35	38	47
Asset retirement costs	17	245	228
Egypt [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Capitalized interest	15	16	18
Australia [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Capitalized interest	16	12	14
Asset retirement costs	(30)	207	125
North Sea [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Capitalized interest	25	24
Asset retirement costs	67	89	678
Argentina [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Capitalized interest	10	11	12
Asset retirement costs	$ 3	$ 18

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CAPITAL STOCK (Tables)

12 Months Ended

Dec. 31, 2013

Equity [Abstract]

Common Stock Outstanding

Common Stock Outstanding

	2013			2012		2011
Balance, beginning of year		391,640,770			384,117,643		382,391,742
Shares issued for stock-based compensation plans:
Treasury shares issued		25,214			60,767		144,313
Common shares issued		929,596			1,189,693		1,581,588
Common shares issued for conversion of preferred shares		14,399,247			—		—
Treasury shares acquired		(11,221,919	)		—		—
Cordillera consideration (Note 2)		—			6,272,667		—
Balance, end of year		395,772,908			391,640,770		384,117,643

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, 2013, 2012, and 2011 is presented in the table below.

	2013						2012						2011
	Income		Shares		Per Share		Income		Shares		Per Share		Income		Shares		Per Share
	(In millions, except per share amounts)
Basic:
Net income attributable to common stock	$	2,188		395	$	5.53	$	1,925		389	$	4.95	$	4,508		384	$	11.75
Effect of Dilutive Securities:
Mandatory Convertible Preferred Stock	$	44		9			$	—		—			$	76		14
Stock options and other		—		2				—		2				—		2
Diluted:
Net income attributable to common stock, including assumed conversions	$	2,232		406	$	5.50	$	1,925		391	$	4.92	$	4,584		400	$	11.47

Description of Stock Based Compensation Plans and Related Costs

A description of the Company’s stock-based compensation plans and related costs follows:

	2013		2012		2011
	(In millions)
Stock-based compensation expensed:
General and administrative	$	89	$	104	$	69
Lease operating expenses		47		63		44
Stock-based compensation capitalized		55		67		42
	$	191	$	234	$	155

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:

	2013
	Shares Under Option			Weighted Average Exercise Price
	(In thousands)
Outstanding, beginning of year		7,573		$	90.47
Granted		819			80.89
Exercised		(327	)		72.55
Forfeited or expired		(502	)		97.88
Outstanding, end of year(1)		7,563			89.71
Expected to vest(1)		2,370			92.50
Exercisable, end of year(1)		4,678			88.53
Weighted average fair value of options granted during the year	$	23.18

(1) As of December 31, 2013, the weighted average remaining contractual life for options outstanding, expected to vest, and exercisable is 6.1 years, 8.2 years, and 4.7 years, respectively. The aggregate intrinsic value of options outstanding, expected to vest, and exercisable at year-end was $43 million, $7 million, and $34 million, respectively. The weighted-average grant-date fair value of options granted during the years 2013, 2012, and 2011 was $23.18, $26.41, and $42.20, 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.

	2013			2012			2011
Expected volatility		33.60	%		34.94	%		34.47	%
Expected dividend yields		0.99	%		0.82	%		0.47	%
Expected term (in years)		5.5			5.5			5.5
Risk-free rate		0.79	%		0.78	%		1.95	%

Restricted Stock

A summary of restricted stock activity for the year ended December 31, 2013, is presented below.

	Shares			Weighted- Average Grant- Date Fair Value
	(In thousands)
Non-vested at January 1, 2013		2,164		$	97.34
Granted		3,098			82.95
Vested		(907	)		96.79
Forfeited		(402	)		88.61
Non-vested at December 31, 2013		3,953			86.70

Conditional Restricted Stock

The weighted-average remaining life of the unvested conditional restricted stock units is approximately 2.1 years.

	Shares			Weighted- Average Grant- Date Fair Value(1)
	(In thousands)
Non-vested at January 1, 2013		1,306		$	78.40
Granted		1,232			79.60
Vested		0			79.49
Cancelled		(1,369	)		83.34
Forfeited		(149	)		78.09
Non-vested at December 31, 2013		1,020			73.73

(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.

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Asset Retirement Obligation - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Asset Retirement Obligation Disclosure [Abstract]
Additional abandonment liabilities associated with its drilling and development program	$ 481	$ 592

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BUSINESS SEGMENT INFORMATION

12 Months Ended

Dec. 31, 2013

Segment Reporting [Abstract]

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, 2013, the Company had production in six countries: the United States, 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. Financial information for each country is presented below:

	United States		Canada			Egypt(1)		Australia		North Sea		Argentina			Other International			Total(1)
	(In millions)
2013
Oil and gas production revenues	$	6,902	$	1,224		$	3,917	$	1,140	$	2,728	$	491		$	—		$	16,402
Operating Expenses:
Depreciation, depletion, and amortization
Recurring		2,338		505			1,005		423		1,022		230			1			5,524
Additional		552		—			—		—		367		181			76			1,176
Asset retirement obligation accretion		94		49			—		27		68		5			—			243
Lease operating expenses		1,320		459			471		214		400		192			—			3,056
Gathering and transportation		84		155			42		—		7		9			—			297
Taxes other than income		335		45			8		13		384		47			—			832
Operating Income (Loss)	$	2,179	$	11		$	2,391	$	463	$	480	$	(173	)	$	(77	)		5,274
Other Income (Expense):
Derivative instrument gains (losses), net																			(399	)
Other																			51
General and administrative																			(503	)
Acquisitions, divestitures, and transition																			(33	)
Financing costs, net																			(174	)
Income Before Income Taxes																		$	4,216
Net Property and Equipment	$	27,010	$	6,058		$	5,454	$	6,838	$	5,622	$	1,416		$	23		$	52,421
Total Assets	$	29,940	$	6,952		$	8,121	$	8,094	$	6,902	$	1,577		$	51		$	61,637
Additions to Net Property and Equipment	$	6,404	$	1,082		$	1,309	$	1,954	$	1,084	$	205		$	24		$	12,062
(1) Includes a noncontrolling interest in Egypt.
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)	$	2,311	$	(1,867	)	$	3,166	$	866	$	989	$	51		$	(43	)		5,473
Other Income (Expense):
Derivative instrument gains (losses), net																			(79	)
Other																			210
General and administrative																			(531	)
Acquisitions, divestitures, and 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
	United States		Canada			Egypt		Australia		North Sea		Argentina			Other International			Total
	(In millions)
2011
Oil and gas production revenues	$	6,103	$	1,617		$	4,791	$	1,734	$	2,091	$	474		$	—		$	16,810
Operating Expenses:
Depreciation, depletion, and amortization
Recurring		1,684		546			818		440		409		198			—			4,095
Additional		—		—			—		—		—		—			109			109
Asset retirement obligation accretion		97		26			—		10		17		4			—			154
Lease operating expenses		1,167		470			398		197		208		165			—			2,605
Gathering and transportation		64		165			35		—		25		7			—			296
Taxes other than income		259		51			13		9		539		28			—			899
Operating Income (Loss)	$	2,832	$	359		$	3,527	$	1,078	$	893	$	72		$	(109	)		8,652
Other Expense:
Other																			78
General and administrative																			(459	)
Acquisitions, divestitures, and 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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ACQUISITIONS AND DIVESTITURES (Tables)

12 Months Ended

Dec. 31, 2013

2012 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.

2011 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	$	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.

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Supplemental Oil and Gas Disclosures - Proved Reserve Data (Detail)	12 Months Ended
	Dec. 31, 2013 MBbls	Dec. 31, 2012 MBbls	Dec. 31, 2011 MBbls	Dec. 31, 2010 MBbls
Reserve Quantities [Line Items]
Beginning balance	2,851,679	2,989,854	2,953,265
Proved developed reserves	1,832,936	1,981,945	1,992,327	1,984,991
Proved undeveloped reserves	813,480	869,734	997,527	968,274
Extensions, discoveries and other additions	389,336	372,393	342,078
Purchase of minerals in-place	5,976	73,457	80,420
Revisions of previous estimates	32,539	(298,712)	(59,086)
Production	(277,683)	(284,997)	(273,074)
Sale of properties	(355,431)	(316)	(53,749)
Ending balance	2,646,416	2,851,679	2,989,854
United States [Member]
Reserve Quantities [Line Items]
Beginning balance	1,424,287	1,290,082	1,304,512
Proved developed reserves	976,795	1,021,610	905,069	895,223
Proved undeveloped reserves	370,566	402,677	385,013	409,290
Extensions, discoveries and other additions	253,578	217,598	117,842
Purchase of minerals in-place	273	68,486	16,949
Revisions of previous estimates	13,482	(38,172)	(8,477)
Production	(121,074)	(113,461)	(104,263)
Sale of properties	(223,185)	(246)	(36,481)
Ending balance	1,347,361	1,424,287	1,290,082
Canada [Member]
Reserve Quantities [Line Items]
Beginning balance	540,913	764,293	756,984
Proved developed reserves	322,362	390,800	456,569	477,594
Proved undeveloped reserves	139,509	150,113	307,724	279,389
Extensions, discoveries and other additions	74,107	68,612	106,778
Purchase of minerals in-place		614	2,225
Revisions of previous estimates	18,274	(247,811)	(38,570)
Production	(39,177)	(44,725)	(45,856)
Sale of properties	(132,246)	(70)	(17,268)
Ending balance	461,871	540,913	764,293
Egypt [Member]
Reserve Quantities [Line Items]
Beginning balance	273,283	291,863	306,613
Proved developed reserves	222,880	221,819	222,651	234,419
Proved undeveloped reserves	48,028	51,464	69,212	72,194
Extensions, discoveries and other additions	51,135	45,516	57,882
Purchase of minerals in-place	5
Revisions of previous estimates	859	(6,007)	(12,456)
Production	(54,374)	(58,089)	(60,176)
Ending balance	270,908	273,283	291,863
Australia [Member]
Reserve Quantities [Line Items]
Beginning balance	342,206	329,542	314,219
Proved developed reserves	126,948	128,395	148,328	161,866
Proved undeveloped reserves	199,240	213,811	181,214	152,353
Extensions, discoveries and other additions	4,764	35,772	40,534
Purchase of minerals in-place		567
Revisions of previous estimates	(135)	(49)
Production	(20,647)	(23,626)	(25,211)
Ending balance	326,188	342,206	329,542
North Sea [Member]
Reserve Quantities [Line Items]
Beginning balance	169,189	196,741	155,059
Proved developed reserves	117,457	137,626	163,248	116,396
Proved undeveloped reserves	32,633	31,563	33,493	38,663
Extensions, discoveries and other additions	2,001	3,325	483
Purchase of minerals in-place	5,698	3,790	61,246
Revisions of previous estimates	24	(7,258)
Production	(26,822)	(27,409)	(20,047)
Ending balance	150,090	169,189	196,741
Argentina [Member]
Reserve Quantities [Line Items]
Beginning balance	101,801	117,333	115,878
Proved developed reserves	66,494	81,695	96,462	99,493
Proved undeveloped reserves	23,504	20,106	20,871	16,385
Extensions, discoveries and other additions	3,751	1,570	18,559
Revisions of previous estimates	35	585	417
Production	(15,589)	(17,687)	(17,521)
Ending balance	89,998	101,801	117,333
Crude Oil And Condensate [Member]
Reserve Quantities [Line Items]
Beginning balance	1,182,625	1,161,577	1,152,277
Proved developed reserves	794,795	825,811	804,653	803,046
Proved undeveloped reserves	336,690	356,814	356,924	349,231
Extensions, discoveries and other additions	192,222	147,535	126,733
Purchase of minerals in-place	3,713	18,549	40,414
Revisions of previous estimates	1,533	(16,052)	(31,991)
Production	(126,515)	(128,840)	(124,080)
Sale of properties	(122,093)	(144)	(1,776)
Ending balance	1,131,485	1,182,625	1,161,577
Crude Oil And Condensate [Member] | United States [Member]
Reserve Quantities [Line Items]
Beginning balance	677,905	634,014	636,855
Proved developed reserves	457,981	474,837	428,251	422,737
Proved undeveloped reserves	195,835	203,068	205,763	214,117
Extensions, discoveries and other additions	133,227	84,656	45,676
Purchase of minerals in-place	85	15,942	5,097
Revisions of previous estimates	1,683	(7,474)	(8,904)
Production	(53,621)	(49,089)	(43,587)
Sale of properties	(105,463)	(144)	(1,123)
Ending balance	653,816	677,905	634,014
Crude Oil And Condensate [Member] | Canada [Member]
Reserve Quantities [Line Items]
Beginning balance	150,345	141,591	147,146
Proved developed reserves	80,526	79,695	81,846	90,292
Proved undeveloped reserves	56,366	70,650	59,746	56,855
Extensions, discoveries and other additions	10,177	18,935	16,712
Purchase of minerals in-place		188	705
Revisions of previous estimates	(531)	(4,577)	(17,117)
Production	(6,469)	(5,792)	(5,202)
Sale of properties	(16,630)		(653)
Ending balance	136,892	150,345	141,591
Crude Oil And Condensate [Member] | Egypt [Member]
Reserve Quantities [Line Items]
Beginning balance	124,034	128,035	127,127
Proved developed reserves	119,242	106,746	105,840	109,657
Proved undeveloped reserves	16,302	17,288	22,195	17,470
Extensions, discoveries and other additions	43,738	36,188	45,021
Purchase of minerals in-place	5
Revisions of previous estimates	457	(3,678)	(6,185)
Production	(32,690)	(36,511)	(37,928)
Ending balance	135,544	124,034	128,035
Crude Oil And Condensate [Member] | Australia [Member]
Reserve Quantities [Line Items]
Beginning balance	63,861	67,945	66,136
Proved developed reserves	22,524	29,053	35,725	48,072
Proved undeveloped reserves	36,703	34,808	32,220	18,064
Extensions, discoveries and other additions	2,539	6,277	15,762
Purchase of minerals in-place		276
Revisions of previous estimates	(118)	(66)
Production	(7,055)	(10,571)	(13,953)
Ending balance	59,227	63,861	67,945
Crude Oil And Condensate [Member] | North Sea [Member]
Reserve Quantities [Line Items]
Beginning balance	147,654	169,405	154,368
Proved developed reserves	100,327	119,635	136,990	115,705
Proved undeveloped reserves	29,253	28,019	32,415	38,663
Extensions, discoveries and other additions	1,543	346	332
Purchase of minerals in-place	3,623	2,143	34,612
Revisions of previous estimates	18	(928)
Production	(23,258)	(23,312)	(19,907)
Ending balance	129,580	147,654	169,405
Crude Oil And Condensate [Member] | Argentina [Member]
Reserve Quantities [Line Items]
Beginning balance	18,826	20,587	20,645
Proved developed reserves	14,195	15,845	16,001	16,583
Proved undeveloped reserves	2,231	2,981	4,585	4,062
Extensions, discoveries and other additions	998	1,133	3,230
Revisions of previous estimates	24	671	215
Production	(3,422)	(3,565)	(3,503)
Ending balance	16,426	18,826	20,587
Natural Gas Liquids [Member]
Reserve Quantities [Line Items]
Beginning balance	258,352	207,898	156,458
Proved developed reserves	217,129	183,949	145,438	121,376
Proved undeveloped reserves	74,732	74,403	62,460	35,082
Extensions, discoveries and other additions	73,245	79,866	51,679
Purchase of minerals in-place	340	470	9,824
Revisions of previous estimates	2,141	(13,626)	2,504
Production	(23,595)	(16,256)	(11,366)
Sale of properties	(18,622)		(1,201)
Ending balance	291,861	258,352	207,898
Natural Gas Liquids [Member] | United States [Member]
Reserve Quantities [Line Items]
Beginning balance	215,397	160,033	122,160
Proved developed reserves	184,485	154,508	107,490	91,800
Proved undeveloped reserves	63,538	60,889	52,543	30,361
Extensions, discoveries and other additions	69,231	71,965	43,915
Purchase of minerals in-place	45	230	586
Revisions of previous estimates	1,591	(4,559)	1,713
Production	(19,922)	(12,272)	(8,071)
Sale of properties	(18,319)		(270)
Ending balance	248,023	215,397	160,033
Natural Gas Liquids [Member] | Canada [Member]
Reserve Quantities [Line Items]
Beginning balance	34,254	31,450	27,844
Proved developed reserves	26,099	21,996	23,256	23,701
Proved undeveloped reserves	9,970	12,258	8,193	4,142
Extensions, discoveries and other additions	4,014	7,655	5,890
Purchase of minerals in-place		9	47
Revisions of previous estimates	546	(2,569)	774
Production	(2,442)	(2,291)	(2,174)
Sale of properties	(303)		(931)
Ending balance	36,069	34,254	31,450
Natural Gas Liquids [Member] | Egypt [Member]
Reserve Quantities [Line Items]
Extensions, discoveries and other additions			18
Production			(18)
Natural Gas Liquids [Member] | North Sea [Member]
Reserve Quantities [Line Items]
Beginning balance	2,818	9,262
Proved developed reserves	2,435	2,438	8,753
Proved undeveloped reserves	215	380	509
Extensions, discoveries and other additions		246	72
Purchase of minerals in-place	295	231	9,191
Revisions of previous estimates	1	(6,329)
Production	(464)	(592)	(1)
Ending balance	2,650	2,818	9,262
Natural Gas Liquids [Member] | Argentina [Member]
Reserve Quantities [Line Items]
Beginning balance	5,883	7,153	6,454
Proved developed reserves	4,110	5,007	5,939	5,875
Proved undeveloped reserves	1,009	876	1,215	579
Extensions, discoveries and other additions			1,784
Revisions of previous estimates	3	(169)	17
Production	(767)	(1,101)	(1,102)
Ending balance	5,119	5,883	7,153
Natural Gas [Member]
Reserve Quantities [Line Items]
Beginning balance	8,464,206	9,722,273	9,867,182
Proved developed reserves	4,926,064	5,833,105	6,253,418	6,363,417
Proved undeveloped reserves	2,412,348	2,631,101	3,468,855	3,503,765
Extensions, discoveries and other additions	743,212	869,949	981,993
Purchase of minerals in-place	11,535	326,627	181,091
Revisions of previous estimates	173,191	(1,614,206)	(177,591)
Production	(765,437)	(839,403)	(825,770)
Sale of properties	(1,288,295)	(1,034)	(304,632)
Ending balance	7,338,412	8,464,206	9,722,273
Natural Gas [Member] | United States [Member]
Reserve Quantities [Line Items]
Beginning balance	3,185,907	2,976,211	3,272,985
Proved developed reserves	2,005,966	2,353,587	2,215,973	2,284,116
Proved undeveloped reserves	667,160	832,320	760,238	988,869
Extensions, discoveries and other additions	306,721	365,863	169,506
Purchase of minerals in-place	855	313,885	67,595
Revisions of previous estimates	61,247	(156,840)	(7,716)
Production	(285,187)	(312,600)	(315,631)
Sale of properties	(596,417)	(612)	(210,528)
Ending balance	2,673,126	3,185,907	2,976,211
Natural Gas [Member] | Canada [Member]
Reserve Quantities [Line Items]
Beginning balance	2,137,884	3,547,511	3,491,967
Proved developed reserves	1,294,420	1,734,657	2,108,801	2,181,615
Proved undeveloped reserves	439,037	403,227	1,438,710	1,310,352
Extensions, discoveries and other additions	359,493	252,130	505,049
Purchase of minerals in-place		2,503	8,838
Revisions of previous estimates	109,551	(1,443,989)	(133,359)
Production	(181,593)	(219,849)	(230,880)
Sale of properties	(691,878)	(422)	(94,104)
Ending balance	1,733,457	2,137,884	3,547,511
Natural Gas [Member] | Egypt [Member]
Reserve Quantities [Line Items]
Beginning balance	895,491	982,966	1,076,917
Proved developed reserves	621,825	690,436	700,866	748,573
Proved undeveloped reserves	190,355	205,055	282,100	328,344
Extensions, discoveries and other additions	44,382	55,967	77,049
Revisions of previous estimates	2,413	(13,974)	(37,623)
Production	(130,106)	(129,468)	(133,377)
Ending balance	812,180	895,491	982,966
Natural Gas [Member] | Australia [Member]
Reserve Quantities [Line Items]
Beginning balance	1,670,070	1,569,584	1,488,498
Proved developed reserves	626,543	596,052	675,618	682,763
Proved undeveloped reserves	975,224	1,074,018	893,966	805,735
Extensions, discoveries and other additions	13,351	176,969	148,640
Purchase of minerals in-place		1,745
Revisions of previous estimates	(101)	101
Production	(81,553)	(78,329)	(67,554)
Ending balance	1,601,767	1,670,070	1,569,584
Natural Gas [Member] | North Sea [Member]
Reserve Quantities [Line Items]
Beginning balance	112,304	108,442	4,144
Proved developed reserves	88,177	93,319	105,028	4,144
Proved undeveloped reserves	18,988	18,985	3,414
Extensions, discoveries and other additions	2,750	16,397	475
Purchase of minerals in-place	10,680	8,494	104,658
Revisions of previous estimates	32
Production	(18,601)	(21,029)	(835)
Ending balance	107,165	112,304	108,442
Natural Gas [Member] | Argentina [Member]
Reserve Quantities [Line Items]
Beginning balance	462,550	537,559	532,671
Proved developed reserves	289,133	365,054	447,132	462,206
Proved undeveloped reserves	121,584	97,496	90,427	70,465
Extensions, discoveries and other additions	16,515	2,623	81,274
Revisions of previous estimates	49	496	1,107
Production	(68,397)	(78,128)	(77,493)
Ending balance	410,717	462,550	537,559

XML

Other Current Liabilities - Details of Other Current Liabilities (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Payables And Accruals [Abstract]
Accrued operating expenses	$ 190	$ 211
Accrued exploration and development	1,582	1,792
Accrued compensation and benefits	242	198
Accrued interest	161	160
Accrued income taxes	248	297
Accrued U.K. Petroleum Revenue Tax	9	53
Other	179	149
Total Other current liabilities	$ 2,611	$ 2,860

XML

Supplemental Guarantor Information - Supplemental Condensed Consolidating Balance Sheet (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
CURRENT ASSETS:
Cash and cash equivalents	$ 1,906	$ 160	$ 295	$ 134
Receivables, net of allowance	2,952	3,086
Inventories	891	908
Drilling advances	371	584
Derivative instruments	1	31
Prepaid assets and other	245	193
Total Assets	6,366	4,962
PROPERTY AND EQUIPMENT, NET	52,421	53,280	45,448
OTHER ASSETS:
Goodwill, net	1,369	1,289
Deferred charges and other	1,481	1,206
Total assets	61,637	60,737	52,051
CURRENT LIABILITIES:
Accounts payable	1,616	1,092
Current debt	53	990
Asset retirement obligation	121	478
Derivative instruments	299	116
Other current liabilities	2,611	2,860
Total current liabilities	4,700	5,536
Long-term debt	9,672	11,355
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes	8,364	8,024
Asset retirement obligation	3,101	4,100
Other	407	391
Total deferred credits and other noncurrent liabilities	11,872	12,515
COMMITMENTS AND CONTINGENCIES
TOTAL EQUITY	35,393	31,331	28,993	24,377
Total liabilities and equity	61,637	60,737
Income taxes	8,364	8,024
Asset retirement obligation	3,101	4,100
Other	407	391
Total deferred credits and other noncurrent liabilities	11,872	12,515
COMMITMENTS AND CONTINGENCIES APACHE SHAREHOLDERS' EQUITY
Noncontrolling interest	1,997
TOTAL EQUITY	35,393	31,331	28,993	24,377
Total liabilities and shareholders' equity	61,637	60,737
Income taxes	8,364	8,024
Asset retirement obligation	3,101	4,100
Other	407	391
Total deferred credits and other noncurrent liabilities	11,872	12,515
COMMITMENTS AND CONTINGENCIES
TOTAL EQUITY	35,393	31,331	28,993	24,377
Total liabilities and equity	61,637	60,737
Apache Corporation [Member]
CURRENT ASSETS:
Cash and cash equivalents	155		41	6
Receivables, net of allowance	1,043	876
Inventories	48	95
Drilling advances	49	21
Derivative instruments	1	31
Prepaid assets and other	99	102
Intercompany receivable	5,357	3,766
Total Assets	6,752	4,891
PROPERTY AND EQUIPMENT, NET	16,092	18,517
OTHER ASSETS:
Intercompany receivable	1,572	4,628
Equity in affiliates	24,743	21,047
Goodwill, net	173	173
Deferred charges and other	166	152
Total assets	49,498	49,408
CURRENT LIABILITIES:
Accounts payable	956	639
Current debt		912
Asset retirement obligation	115	471
Derivative instruments	299	96
Other current liabilities	896	893
Total current liabilities	2,266	3,011
Long-term debt	9,374	10,706
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes	3,586	2,990
Asset retirement obligation	430	992
Other	446	378
Total deferred credits and other noncurrent liabilities	4,462	4,360
COMMITMENTS AND CONTINGENCIES	33,396
TOTAL EQUITY	33,396	31,331
Total liabilities and equity	49,498	49,408
Income taxes	3,586	2,990
Asset retirement obligation	430	992
Other	446	378
Total deferred credits and other noncurrent liabilities	4,462	4,360
COMMITMENTS AND CONTINGENCIES APACHE SHAREHOLDERS' EQUITY	33,396
TOTAL EQUITY	33,396	31,331
Total liabilities and shareholders' equity	49,498	49,408
Income taxes	3,586	2,990
Asset retirement obligation	430	992
Other	446	378
Total deferred credits and other noncurrent liabilities	4,462	4,360
COMMITMENTS AND CONTINGENCIES	33,396
TOTAL EQUITY	33,396	31,331
Total liabilities and equity	49,498	49,408
Apache Finance Canada [Member]
CURRENT ASSETS:
Cash and cash equivalents	3		5
Drilling advances		1
Total Assets	3	1
OTHER ASSETS:
Equity in affiliates	1,155	934
Deferred charges and other	1,006	1,002
Total assets	2,164	1,937
CURRENT LIABILITIES:
Accounts payable	2	1
Other current liabilities	10	3
Total current liabilities	12	4
Long-term debt	298	647
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes		5
Other	250	250
Total deferred credits and other noncurrent liabilities	250	255
COMMITMENTS AND CONTINGENCIES	1,604
TOTAL EQUITY	1,604	1,031
Total liabilities and equity	2,164	1,937
Income taxes		5
Other	250	250
Total deferred credits and other noncurrent liabilities	250	255
COMMITMENTS AND CONTINGENCIES APACHE SHAREHOLDERS' EQUITY	1,604
TOTAL EQUITY	1,604	1,031
Total liabilities and shareholders' equity	2,164	1,937
Income taxes		5
Other	250	250
Total deferred credits and other noncurrent liabilities	250	255
COMMITMENTS AND CONTINGENCIES	1,604
TOTAL EQUITY	1,604	1,031
Total liabilities and equity	2,164	1,937
All Other Subsidiaries of Apache Corporation [Member]
CURRENT ASSETS:
Cash and cash equivalents	1,748	160	249	128
Receivables, net of allowance	1,909	2,210
Inventories	843	813
Drilling advances	322	562
Prepaid assets and other	146	91
Total Assets	4,968	3,836
PROPERTY AND EQUIPMENT, NET	36,329	34,763
OTHER ASSETS:
Equity in affiliates	449	97
Goodwill, net	1,196	1,116
Deferred charges and other	1,309	1,052
Total assets	44,251	40,864
CURRENT LIABILITIES:
Accounts payable	658	452
Current debt	53	78
Asset retirement obligation	6	7
Derivative instruments		20
Other current liabilities	1,705	1,964
Intercompany payable	5,357	3,766
Total current liabilities	7,779	6,287
Long-term debt		2
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Intercompany payable	1,572	4,628
Income taxes	4,778	5,029
Asset retirement obligation	2,671	3,108
Other	711	763
Total deferred credits and other noncurrent liabilities	9,732	13,528
COMMITMENTS AND CONTINGENCIES	24,743
TOTAL EQUITY	26,740	21,047
Total liabilities and equity	44,251	40,864
Income taxes	4,778	5,029
Asset retirement obligation	2,671	3,108
Other	711	763
Total deferred credits and other noncurrent liabilities	9,732	13,528
COMMITMENTS AND CONTINGENCIES APACHE SHAREHOLDERS' EQUITY	24,743
Noncontrolling interest	1,997
TOTAL EQUITY	26,740	21,047
Total liabilities and shareholders' equity	44,251	40,864
Intercompany payable	1,572	4,628
Income taxes	4,778	5,029
Asset retirement obligation	2,671	3,108
Other	711	763
Total deferred credits and other noncurrent liabilities	9,732	13,528
COMMITMENTS AND CONTINGENCIES	24,743
TOTAL EQUITY	26,740	21,047
Total liabilities and equity	44,251	40,864
Reclassifications & Eliminations [Member]
CURRENT ASSETS:
Intercompany receivable	(5,357)	(3,766)
Total Assets	(5,357)	(3,766)
OTHER ASSETS:
Intercompany receivable	(1,572)	(4,628)
Equity in affiliates	(26,347)	(22,078)
Deferred charges and other	(1,000)	(1,000)
Total assets	(34,276)	(31,472)
CURRENT LIABILITIES:
Intercompany payable	(5,357)	(3,766)
Total current liabilities	(5,357)	(3,766)
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Intercompany payable	(1,572)	(4,628)
Other	(1,000)	(1,000)
Total deferred credits and other noncurrent liabilities	(2,572)	(5,628)
COMMITMENTS AND CONTINGENCIES	(26,347)
TOTAL EQUITY	(26,347)	(22,078)
Total liabilities and equity	(34,276)	(31,472)
Other	(1,000)	(1,000)
Total deferred credits and other noncurrent liabilities	(2,572)	(5,628)
COMMITMENTS AND CONTINGENCIES APACHE SHAREHOLDERS' EQUITY	(26,347)
TOTAL EQUITY	(26,347)	(22,078)
Total liabilities and shareholders' equity	(34,276)	(31,472)
Intercompany payable	(1,572)	(4,628)
Other	(1,000)	(1,000)
Total deferred credits and other noncurrent liabilities	(2,572)	(5,628)
COMMITMENTS AND CONTINGENCIES	(26,347)
TOTAL EQUITY	(26,347)	(22,078)
Total liabilities and equity	$ (34,276)	$ (31,472)

XML

Acquisitions and Divestitures - Additional Information (Detail) (USD $)	0 Months Ended	1 Months Ended	12 Months Ended								0 Months Ended		1 Months Ended				1 Months Ended		1 Months Ended
	Nov. 14, 2013	Apr. 30, 2012 acre	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013 Argentina [Member]	Dec. 31, 2012 Argentina [Member]	Dec. 31, 2011 Argentina [Member]	Dec. 31, 2013 Sinopec [Member]	Jun. 30, 2013 YPF Sociedad Anonima [Member]	Sep. 30, 2013 Fieldwood Energy Llc [Member]	Feb. 12, 2014 Subsequent Event [Member] YPF Sociedad Anonima [Member]	Nov. 14, 2013 Egypt Oil And Gas [Member] Sinopec [Member]	Feb. 28, 2013 Kitimat LNG [Member]	Sep. 30, 2013 Kitimat LNG [Member]	Feb. 28, 2013 Kitimat LNG [Member] Horn River and Liard Basins [Member] acre	Feb. 28, 2013 Kitimat LNG [Member] Chevron Canada and Apache Canada [Member]	Sep. 30, 2013 Kitimat LNG [Member] Fieldwood Energy Llc [Member]	Jan. 31, 2012 Yara International [Member]
Business Acquisition [Line Items]
Net assets						$ 1,300,000,000
Proceeds from sale of Operations	2,950,000,000										3,700,000,000	800,000,000	2,950,000,000
Effective date of the transaction											Jul. 01, 2013		Jan. 01, 2013
Liabilities assumed										52,000,000	1,500,000,000
Net income attributable to noncontrolling interest			56,000,000						56,000,000
Proceeds as noncontrolling interest			1,997,000,000						1,900,000,000
Percentage of ownership interest in assets																		50.00%
Proved properties			83,390,000,000	78,383,000,000		2,933,000,000	2,706,000,000								4,600,000,000
Unproved properties			8,363,000,000	8,754,000,000		349,000,000	382,000,000								473,000,000
Percentage of ownership																	50.00%		49.00%
Business properties held																644,000
Proceeds from transaction			396,000,000											396,000,000
Proceeds from limited partnership																	0
Proceeds from sale of other oil and gas properties			307,000,000	27,000,000	422,000,000
Acquisitions of oil and gas property			215,000,000	13,831,000,000	10,792,000,000	195,000,000	318,000,000	358,000,000
Cordillera's properties		312,000
Shares of common stock issued seller		6,272,667
Cash paid to seller		2,700,000,000
Amount paid for acquisition																			439,000,000
Ownership percentage by other party																			51.00%
Expenses in connection with Apache's merger, transition and acquisition activity			33,000,000	31,000,000	20,000,000
Investment banking fees and other costs			33,000,000
Business combination separation and other costs				$ 20,000,000

XML

CONSOLIDATED BALANCE SHEET (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
CURRENT ASSETS:
Cash and cash equivalents	$ 1,906	$ 160
Receivables, net of allowance	2,952	3,086
Inventories	891	908
Drilling advances	371	584
Derivative instruments	1	31
Prepaid assets and other	245	193
Total Assets	6,366	4,962
Oil and gas, on the basis of full-cost accounting:
Proved properties	83,390	78,383
Unproved properties and properties under development, not being amortized	8,363	8,754
Gathering, transmission, and processing facilities	6,995	5,955
Other	1,071	1,055
Property and equipment, gross	99,819	94,147
Less: Accumulated depreciation, depletion, and amortization	(47,398)	(40,867)
Property and equipment, net	52,421	53,280
OTHER ASSETS:
Goodwill	1,369	1,289
Deferred charges and other	1,481	1,206
Total assets	61,637	60,737
CURRENT LIABILITIES:
Accounts payable	1,616	1,092
Current debt	53	990
Current asset retirement obligation	121	478
Derivative instruments	299	116
Other current liabilities	2,611	2,860
Total current liabilities	4,700	5,536
Long-term debt	9,672	11,355
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes	8,364	8,024
Asset retirement obligation	3,101	4,100
Other	407	391
Total deferred credits and other noncurrent liabilities	11,872	12,515
COMMITMENTS AND CONTINGENCIES (Note 8)
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 converted in 2013, 1,265,000 shares issued and outstanding in 2012		1,227
Common stock, $0.625 par, 860,000,000 shares authorized, 0 and 392,712,245 shares issued, respectively	255	245
Paid-in capital	12,251	9,859
Retained earnings	22,032	20,161
Treasury stock, at cost, 0 and 1,071,475 shares, respectively	(1,027)	(30)
Accumulated other comprehensive (loss)	(115)	(131)
APACHE SHAREHOLDERS' EQUITY	33,396	31,331
Noncontrolling interest	1,997
TOTAL EQUITY	35,393	31,331
Total liabilities and shareholders' equity	$ 61,637	$ 60,737

XML

Business Segment Information - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2013 Country
Segment Reporting [Abstract]
Production in number of countries	6

XML

ACQUISITIONS AND DIVESTITURES

12 Months Ended

Dec. 31, 2013

Business Combinations [Abstract]

ACQUISITIONS AND DIVESTITURES

2.     ACQUISITIONS AND DIVESTITURES

2014 Activity

Argentina Divestiture

On February 12, 2014, Apache Corporation and its subsidiaries announced an agreement to sell all of its operations in Argentina to YPF Sociedad Anónima for cash consideration of $800 million plus the assumption of $52 million of bank debt as of June 30, 2013. As of December 31, 2013, Apache’s net assets in Argentina totaled approximately $1.3 billion, and the Company expects to recognize a loss associated with this transaction upon closing. The transaction is expected to close in the first quarter of 2014.

2013 Activity

Egypt Partnership

On November 14, 2013, Apache completed the sale of a one-third minority participation in its Egypt oil and gas business to a subsidiary of Sinopec International Petroleum Exploration and Production Corporation (Sinopec). Apache received cash consideration of $2.95 billion after customary closing adjustments. Apache continues to operate its Egypt upstream oil and gas business. The effective date of the agreement is January 1, 2013.

Apache recorded $1.9 billion of the proceeds as a non-controlling interest, which is reflected as a separate component of equity in the Company’s consolidated balance sheet. This represents one-third of Apache’s net book value of its Egypt holdings at the time of the transaction. The remaining proceeds were recorded as additional paid-in capital. Included in “Net income including noncontrolling interest” for the year ended December 31, 2013, is net income attributable to Sinopec’s interest totaling $56 million.

Gulf of Mexico Shelf Divestiture

On September 30, 2013, Apache completed the sale of its Gulf of Mexico Shelf operations and properties to Fieldwood Energy LLC (Fieldwood), an affiliate of Riverstone Holdings. Under the terms of the agreement, Apache received cash consideration of $3.7 billion, and Fieldwood assumed $1.5 billion of discounted asset abandonment liabilities. Additionally, Apache retained 50 percent of its ownership interest in all exploration blocks and in horizons below production in developed blocks. The effective date of the agreement is July 1, 2013. Apache’s net book value of oil and gas properties was reduced by approximately $4.6 billion of proved property costs and $473 million of unproved property costs as a result of the transaction.

Canada LNG Project

In February 2013, Apache completed a transaction with Chevron Canada Limited (Chevron Canada) under which each company became a 50 percent owner of the Kitimat LNG plant, the Pacific Trail Pipelines Limited Partnership (PTP), and 644,000 gross undeveloped acres in the Horn River and Liard basins. Chevron Canada will operate the LNG plant and pipeline while Apache Canada will continue to operate the upstream assets. Apache’s net proceeds from the transaction were $396 million after post-closing adjustments, and no gain or loss was recorded.

Other Activity

During 2013 Apache completed $307 million of other oil and gas property sales and $215 million of oil and gas property acquisitions.

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 included approximately 312,000 net acres in the Granite Wash, Tonkawa, Cleveland, and Marmaton plays in western Oklahoma and the Texas Panhandle.

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 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. Yara Australia Pty Ltd (Yara) owns the remaining 51 percent of YPHPL and operates the plant. 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.

Acquisitions, Divestitures, and Transition Expenses

In 2013, Apache recorded $33 million of investment banking fees and other costs associated with divestitures during the year. In 2012, the Company recorded $31 million of expenses reflecting costs related to our 2011 acquisition of Mobil North Sea and our 2012 acquisition of Cordillera. In 2011, Apache recorded $20 million of expenses primarily for separation and other costs related to the merger with Mariner Energy, Inc. (Mariner) and the acquisition of Mobil North Sea.

XML

Income Taxes - Income Before Income Taxes (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Tax Disclosure [Abstract]
United States	$ 1,191	$ 1,605	$ 2,373
Foreign	3,025	3,272	5,720
INCOME BEFORE INCOME TAXES	$ 4,216	$ 4,877	$ 8,093

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Capital Stock - Risk-Free Rate Based on U S Treasury Yield Curve (Detail)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Equity [Abstract]
Expected volatility	33.60%	34.94%	34.47%
Expected dividend yields	0.99%	0.82%	0.47%
Expected term (in years)	5 years 6 months	5 years 6 months	5 years 6 months
Risk-free rate	0.79%	0.78%	1.95%

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, 2013	Dec. 31, 2012	Dec. 31, 2011
Change in Plan Assets
Fair value of plan assets at end of year	$ 191	$ 170
Pension Benefits [Member]
Change in Projected Benefit Obligation
Projected benefit obligation beginning of year	177	150	136
Service cost	5	5	5
Interest cost	7	7	7
Foreign currency exchange rate changes	4	7	(1)
Actuarial losses (gains)		14	6
Effect of curtailment and settlements
Benefits paid	(4)	(6)	(3)
Retiree contributions
Projected benefit obligation at end of year	189	177	150
Change in Plan Assets
Fair value of plan assets at beginning of year	170	145	135
Actual return on plan assets	15	14	4
Foreign currency exchange rates	4	6	(1)
Employer contributions	6	11	10
Benefits paid	(4)	(6)	(3)
Retiree contributions
Fair value of plan assets at end of year	191	170	145
Funded status at end of year	2	(7)	(5)
Amounts recognized in Consolidated Balance Sheet
Current liability
Non-current asset (liability)	2	(7)	(5)
Defined Benefit Plans, Liabilities, Total	2	(7)	(5)
Pre-tax Amounts Recognized in Accumulated Other Comprehensive Income (Loss)
Accumulated gain (loss)	(22)	(32)	(25)
Pretax Amounts Recognized in Accumulated Other Comprehensive Income, Total	(22)	(32)	(25)
Weighted Average Assumptions used as of December 31
Discount rate	4.60%	4.30%	4.70%
Salary increases	4.90%	4.60%	4.60%
Expected return on assets	5.60%	4.70%	4.85%
Healthcare cost trend
Initial
Ultimate in 2022
Postretirement Benefits [Member]
Change in Projected Benefit Obligation
Projected benefit obligation beginning of year	35	30	29
Service cost	4	4	3
Interest cost	1	1	1
Foreign currency exchange rate changes
Actuarial losses (gains)	(8)	1	(2)
Effect of curtailment and settlements	(3)
Benefits paid	(2)	(1)	(1)
Retiree contributions	1
Projected benefit obligation at end of year	28	35	30
Change in Plan Assets
Fair value of plan assets at beginning of year
Actual return on plan assets
Foreign currency exchange rates
Employer contributions	1	1	1
Benefits paid	(2)	(1)	(1)
Retiree contributions	1
Fair value of plan assets at end of year
Funded status at end of year	(28)	(35)	(30)
Amounts recognized in Consolidated Balance Sheet
Current liability	(1)	(1)	(1)
Non-current asset (liability)	(27)	(34)	(29)
Defined Benefit Plans, Liabilities, Total	(28)	(35)	(30)
Pre-tax Amounts Recognized in Accumulated Other Comprehensive Income (Loss)
Accumulated gain (loss)	1	(7)	(6)
Pretax Amounts Recognized in Accumulated Other Comprehensive Income, Total	$ 1	$ (7)	$ (6)
Weighted Average Assumptions used as of December 31
Discount rate	4.33%	3.43%	4.04%
Salary increases
Expected return on assets
Healthcare cost trend
Initial	7.00%	7.25%	7.50%
Ultimate in 2022	5.00%	5.00%	5.00%

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DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES (Tables)

12 Months Ended

Dec. 31, 2013

Derivative Instruments And Hedging Activities Disclosure [Abstract]

Open Crude Oil and Natural Gas Derivative Instruments

As of December 31, 2013, Apache had the following open crude oil derivative positions which have not been designated as cash flow hedges:

		Fixed-Price Swaps
Production Period	Settlement Index	Mbbls		Weighted Average Fixed Price
2014	NYMEX WTI		22,889	$	90.77
2014	Dated Brent		22,812		100.05

As of December 31, 2013, Apache had the following open natural gas derivative positions which have been designated as cash flow hedges:

		Fixed-Price Swaps
				Weighted
Production Period	Settlement Index	MMBtu (in 000’s)		Average Fixed Price
2014	NYMEX Henry Hub		1,295	$	6.72

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, 2013
Assets:
Derivatives designated as cash flow hedges	$	—	$	3	$	—	$	3	$	(2	)	$	1
Liabilities:
Derivatives designated as cash flow hedges	$	—	$	1	$	—	$	1
Derivatives not designated as cash flow hedges		—		300		—		300
Total Derivative liabilities	$	—	$	301	$	—	$	301	$	(2	)	$	299
December 31, 2012
Assets:
Derivatives designated as cash flow hedges	$	—	$	48	$	—	$	48	$	(15	)	$	33
Liabilities:
Derivatives designated as cash flow hedges	$	—	$	51	$	—	$	51
Derivatives not designated as cash flow hedges		—		80		—		80
Total Derivative liabilities	$	—	$	131	$	—	$	131	$	(15	)	$	116

(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, 2013		December 31, 2012
	(In millions)
Current Assets: Derivative instruments	$	1	$	31
Other Assets: Deferred charges and other		—		2
Total Assets	$	1	$	33
Current Liabilities: Derivative instruments	$	299	$	116
Total Liabilities	$	299	$	116

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	For the Year Ended December 31,
	Recognized in Income	2013			2012			2011
		(In millions)
Gain (loss) on cash flow hedges reclassified from accumulated other comprehensive loss	Oil and Gas Production Revenues	$	(16	)	$	268		$	(13	)
Gain (loss) for ineffectiveness on cash flow hedges	Revenues and Other: Other	$	(1	)	$	—		$	2
Loss on derivatives not designated as cash flow hedges	Derivative instrument gains (losses), net	$	(399	)	$	(79	)	$	—

Commodity Derivative Activity in Accumulated Other Comprehensive Loss

A reconciliation of the components of accumulated other comprehensive income (loss) in the statement of consolidated changes in equity related to Apache’s cash flow hedges is presented in the table below:

	For the Year Ended December 31,
	2013						2012						2011
	Before tax			After tax			Before tax			After tax			Before tax			After tax
	(In millions)
Unrealized gain (loss) on derivatives at beginning of year	$	(10	)	$	(6	)	$	145		$	114		$	(54	)	$	(19	)
Realized amounts reclassified into earnings		16			11			(268	)		(199	)		13			19
Net change in derivative fair value		(6	)		(5	)		113			79			188			115
Ineffectiveness reclassified into earnings		1			1			—			—			(2	)		(1	)
Unrealized gain (loss) on derivatives at end of period	$	1		$	1		$	(10	)	$	(6	)	$	145		$	114

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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, 2013
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	6
Effect on service and interest cost components, 1% Decrease	(1)
Effect on postretirement benefit obligation, 1% Decrease	$ (4)

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SUPPLEMENTAL QUARTERLY FINANCIAL DATA (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2013

Quarterly Financial Information Disclosure [Abstract]

Supplemental Quarterly Financial Data

	First		Second		Third		Fourth		Total
	(In millions, except per share amounts)
2013
Revenues and other	$	4,076	$	4,383	$	4,019	$	3,576	$	16,054
Expenses(2)		3,359		3,348		3,713		3,346		13,766
Net income including noncontrolling interest	$	717	$	1,035	$	306	$	230	$	2,288
Net income attributable to common stock	$	698	$	1,016	$	300	$	174	$	2,188
Net income per common share(1):
Basic	$	1.78	$	2.59	$	0.75	$	0.44	$	5.53
Diluted	$	1.76	$	2.54	$	0.75	$	0.43	$	5.50
2012
Revenues and other	$	4,536	$	3,972	$	4,179	$	4,391	$	17,078
Expenses(2)		3,739		3,616		3,999		3,723		15,077
Net income including noncontrolling interest	$	797	$	356	$	180	$	668	$	2,001
Net 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

(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.

(2) In 2013, operating expenses include non-cash write-downs of the Company’s oil and gas properties totaling $659 million, net of tax, in the U.S., North Sea, and Argentina regions and also the Company’s exit of operations in Kenya. In 2012, the Company recorded a $1.4 billion, net of tax, non-cash write-down of the carrying value of the Company’s Canadian proved oil and gas properties.

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MAJOR CUSTOMERS

12 Months Ended

Dec. 31, 2013

Text Block [Abstract]

MAJOR CUSTOMERS

12. MAJOR CUSTOMERS

In 2013, 2012, and 2011, purchases by Royal Dutch Shell plc and its subsidiaries accounted for 24 percent, 20 percent, and 11 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 Quarterly Financial Data - Supplemental Quarterly Financial Data (Parenthetical) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012 Canada [Member]
Schedule Of Quarterly Financial Data [Line Items]
Write-down of the carrying value of Oil and Gas properties, net of tax	$ 659	$ 1,400