8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

Date of Report (Date of earliest event reported): July 17, 2014

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

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):

¨ Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

¨ Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

¨ Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

¨ Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

ITEM 8.01 OTHER EVENTS

On March 12, 2014, Apache’s subsidiaries completed the sale of all of the Company’s 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 a result of the sale, the results of operations related to Argentina have been classified as discontinued operations.

Accordingly, we have recast certain information of our filing to reflect this transaction for all periods presented in the following sections of our Annual Report on Form 10-K for the year ended December 31, 2013 (the “Previously Filed Annual Report”) to reflect the Argentine business as discontinued operations for all periods presented:

• Part II, Item 6. Selected Financial Data,

• Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations,

• Part II, Item 7A. Quantitative and Qualitative Disclosures About Market Risk, and

• Part IV, Item 15. Exhibits and Financial Statement Schedules (sub-Item (a)(1) only excluding Report of Management on page F-1 and Report of Independent Registered Public Accounting Firm on page F-3 included in the Previously Filed Annual Report).

As this Current Report on Form 8-K is being filed only for the purpose described above, and only affects the Items specified above, the other information in the Previously Filed Annual Report remains unchanged. No attempt has been made in this Current Report on Form 8-K to modify or update disclosures in the Previously Filed Annual Report, except for the recast of certain financial information as described above. This Current Report on Form 8-K does not reflect events occurring after the filing of the Previously Filed Annual Report with the Securities Exchange Commission (SEC) on February 28, 2014. Accordingly, this Current Report on Form 8-K should be read in conjunction with the Previously Filed Annual Report and the Company’s filings made with the SEC subsequent to the filing of the Previously Filed Annual Report, including any amendments to those filings. In addition, on May 9, 2014, the Company filed a separate Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2014, reflecting the results of operations and assets and liabilities of the Argentine business as discontinued operations as of and for the three months ended March 31, 2014.

ITEM 9.01 FINANCIAL STATEMENTS AND EXHIBITS

*12.1	–	Statement of Computation of Ratios of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividends
*23.1	–	Consent of Ernst & Young LLP
*99.1	–	Updated Selected Financial Data, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Quantitative and Qualitative Disclosures About Market Risk, and Financial Statements and Supplementary Data of our Annual Report on Form 10-K for the year ended December 31, 2013.
*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.

SIGNATURES

Pursuant to the requirements 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/ ALFONSO LEON

Alfonso Leon

Executive Vice President and Chief Financial Officer

Dated: July 17, 2014

EXHIBIT INDEX

No.		Description
12.1	–	Statement of Computation of Ratios of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividends
23.1	–	Consent of Ernst & Young LLP
99.1	–	Updated Selected Financial Data, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Quantitative and Qualitative Disclosures About Market Risk, and Financial Statements and Supplementary Data of our Annual Report on Form 10-K for the year ended December 31, 2013.
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.

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	$	4,404	$	4,840	$	8,064	$	5,167	$	244
Add: Fixed charges excluding capitalized interest		286		255		246		306		286
Adjusted Earnings	$	4,690	$	5,095	$	8,310	$	5,473	$	530
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		56		—		—		—		—
Combined Fixed Charges and Preferred Stock Dividends (1)	$	798	$	774	$	643	$	482	$	358
Ratio of Earnings to Fixed Charges		7.10		8.65		16.33		12.82		1.53
Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends		5.88		6.58		12.92		11.35		1.48

⁽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-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 report dated February 28, 2014, except for the effects of discontinued operations as discussed in Note 1, as to which the date is July 17, 2014, with respect to the consolidated financial statements of Apache Corporation included in this Current Report on Form 8-K.

/s/ Ernst & Young LLP

Houston, Texas

July 17, 2014

EX-99.1

Exhibit 99.1

PART II

ITEM 6. SELECTED FINANCIAL DATA

As further discussed in Note 1 to our consolidated financial statements, in March 2014, we completed the sale of all of the Company’s 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 a result of this transaction, we have recast certain information included in our consolidated financial statements for all periods presented in this report to reflect Argentina’s discontinued operations.

The following table sets forth selected financial data of the Company and its consolidated subsidiaries as of December 31, 2013 and 2012, and for the years ended December 31, 2013, 2012 and 2011, which information has been derived from the Company’s audited financial statements included in Part IV, Item 15 of this report. The selected financial data of the Company and its consolidated subsidiaries as of December 31, 2011, 2010 and 2009 and for the years ended December 31, 2010 and 2009 have been derived from the Company’s accounting records as adjusted for the discontinued operations. 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 8-K. As discussed in more detail in Part IV, Item 15, the 2013 numbers in the following table reflect a total of $995 million ($541 million net of tax) in non-cash write-downs of the carrying value of the Company’s U.S. and North Sea 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	$	15,560	$	16,564	$	16,451	$	11,742	$	8,250
Net income (loss) from continuing operations attributable to common shareholders		2,380		1,911		4,496		2,968		(374	)
Net income (loss) from continuing operations per share:
Basic		6.02		4.91		11.72		8.44		(1.11	)
Diluted		5.97		4.89		11.44		8.37		(1.11	)
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 8-K.

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

As further discussed in Note 1 to our consolidated financial statements, in March 2014, we completed the sale of all of the Company’s 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 a result of this transaction, we have recast certain information included in our consolidated financial statements for all periods presented in this report to reflect Argentina’s discontinued 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 five countries: the U.S., Canada, Egypt, Australia, and the U.K. North Sea. Apache also pursues exploration interests in other countries that may over time result in reportable discoveries and development opportunities.

The following discussion should be read together with the Consolidated Financial Statements and the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 8-K, and the risk factors and related information set forth in Part I, Item 1A of the Previously Filed Annual Report, and Part II, Item 7A of this Form 8-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 56 percent of our production but provided 83 percent of our $15.9 billion of oil and gas production revenues. In addition, approximately 67 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.

2

Results for the year ended December 31, 2013 include:

• Apache reported annual daily production of oil, natural gas, and natural gas liquids averaging 718 Mboe/d. Excluding the impact of the divested Gulf of Mexico Shelf and Canadian assets, production for the year would have increased 3 percent from 2012.

• Liquids production for the year averaged 400 Mboe/d, an increase of 4 percent from 384 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 $15.9 billion, down $517 million from a record $16.4 billion in 2012, reflecting asset sales and lower realized prices compared to the prior year.

• Net cash provided by continuing operating activities totaled $9.6 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 in continuing operations totaling $541 million and $1.4 billion, respectively, and an additional after-tax write-down of $118 million in discontinued operations in 2013. 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 8-K.

• Apache’s adjusted earnings, which exclude certain items impacting the comparability of results, were $3.2 billion, or $7.89 per diluted common share, down from $3.7 billion, or $9.41 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 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.

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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 46 percent of Apache’s total worldwide continuing production, an increase from 42 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.

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.

4

Acquisition and Divestiture Activity

2014 Activity

Argentina Divestiture On March 12, 2014, Apache’s subsidiaries completed the sale of 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 results of operations related to Argentina have been classified as discontinued operations in all periods presented in this Form 8-K.

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.

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.

Canadian Divestitures In September, Apache completed sales of primarily dry gas assets 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.

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 8-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.

5

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		42	%	$	4,662		36	%	$	4,163		33	%
Canada		563		4	%		492		4	%		485		4	%
North America		5,825		46	%		5,154		40	%		4,648		37	%
Egypt (3)		3,528		28	%		4,050		31	%		4,169		34	%
Australia		779		6	%		1,218		9	%		1,552		12	%
North Sea		2,500		20	%		2,517		20	%		2,072		17	%
International (3)		6,807		54	%		7,785		60	%		7,793		63	%
Total(1)(3)	$	12,632		100	%	$	12,939		100	%	$	12,441		100	%
Total Gas Revenues:
United States	$	1,096		41	%	$	1,169		40	%	$	1,550		46	%
Canada		587		23	%		751		25	%		1,033		30	%
North America		1,683		64	%		1,920		65	%		2,583		76	%
Egypt (3)		389		15	%		504		17	%		621		18	%
Australia		361		14	%		357		12	%		182		5	%
North Sea		194		7	%		188		6	%		19		1	%
International (3)		944		36	%		1,049		35	%		822		24	%
Total(2)(3)	$	2,627		100	%	$	2,969		100	%	$	3,405		100	%
NGL Revenues:
United States	$	544		84	%	$	395		76	%	$	391		80	%
Canada		74		11	%		79		15	%		99		20	%
North America		618		95	%		474		91	%		490		100	%
Egypt (3)		—		—			—		—			1		0	%
North Sea		34		5	%		46		9	%		—		—
International (3)		34		5	%		46		9	%		1		0	%
Total (3)	$	652		100	%	$	520		100	%	$	491		100	%
Total Oil and Gas Revenues:
United States	$	6,902		43	%	$	6,226		38	%	$	6,104		37	%
Canada		1,224		8	%		1,322		8	%		1,617		10	%
North America		8,126		51	%		7,548		46	%		7,721		47	%
Egypt (3)		3,917		25	%		4,554		28	%		4,791		29	%
Australia		1,140		7	%		1,575		9	%		1,734		11	%
North Sea		2,728		17	%		2,751		17	%		2,091		13	%
International (3)		7,785		49	%		8,880		54	%		8,616		53	%
Total (3)	$	15,911		100	%	$	16,428		100	%	$	16,337		100	%
Discontinued Operations — Argentina
Oil Revenue		271					271					238
Gas Revenue		202					224					204
NGL Revenue		18					24					31
Total	$	491				$	519				$	473

⁽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.

6

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
International		172,611		(10	%)		192,332		(2	%)		196,681
Total		337,242		(1	%)		342,285		4	%		330,348
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
International		630,848		1	%		625,208		13	%		552,781
Total		1,909,698		(8	%)		2,079,987		1	%		2,050,073
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
International		1,272		(21	%)		1,618		NM			53
Total		62,541		51	%		41,403		47	%		28,122
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
International		279,025		(6	%)		298,152		3	%		288,863
Total		718,066		(2	%)		730,353		4	%		700,149
Discontinued Operations — Argentina
Oil (b/d)		9,375		(4	%)		9,741		2	%		9,597
Gas (Mcf/d)		187,390		(12	%)		213,464		1	%		212,311
NGL (b/d)		2,102		(30	%)		3,008		(0	%)		3,018
BOE/d		42,709		(12	%)		48,326		1	%		48,000

⁽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

7

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
International		108.04		(2	%)		110.59		2	%		108.55
Total(1)		102.62		(1	%)		103.29		0	%		103.18
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
International		4.10		(11	%)		4.59		13	%		4.07
Total(2)		3.77		(3	%)		3.90		(14	%)		4.55
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
International		73.06		(5	%)		77.11		16	%		66.30
Total		28.56		(17	%)		34.31		(28	%)		47.88
Discontinued Operations — Argentina
Oil price ($/Bbl)	$	79.05		4	%	$	75.89		12	%	$	68.02
Gas price ($/Mcf)		2.96		3	%		2.87		9	%		2.64
NGL price ($/Bbl)		23.64		10	%		21.55		(23	%)		27.90

⁽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. Price movements for all types and grades of crude oil generally move in the same direction. Crude oil prices realized in 2013 averaged $102.62 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 67 percent of our crude oil production. Our Egypt, Australia, and North Sea regions, which collectively comprised 51 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.

8

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, and the U.K. 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.

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 $12.6 billion, $307 million lower than the 2012 total of $12.9 billion, driven by a 1 percent decrease in worldwide production. Average daily production in 2013 was 337.2 Mb/d, with prices averaging $102.62 per barrel. Crude oil represented 79 percent of our 2013 oil and gas production revenues and 47 percent of our equivalent production, compared to 79 and 47 percent, respectively, in the prior year. Lower production volumes reduced revenues $224 million, while slightly lower realized prices reduced revenues an additional $83 million.

Worldwide oil production from continuing operations decreased 5.0 Mb/d, however, when excluding the Gulf of Mexico Shelf and Canadian assets that we sold during the year, oil production increased 4.0 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 Mb/d, respectively, as a result of drilling and recompletion activity. Production from our remaining property base in Canada increased 2.1 Mb/d, or 14 percent, as a result of our continued focus on liquids-rich drilling targets. These increases were partially offset by a 19.7 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 $12.9 billion, $498 million higher than the 2011 total of $12.4 billion, driven by a 4 percent increase in worldwide production. Average daily production in 2012 was 342.0 Mb/d, with prices averaging $103.29 per barrel. Crude oil represented 79 percent of our 2012 oil and gas production revenues and 47 percent of our equivalent production, compared to 76 and 47 percent, respectively, in the prior year. Higher realized prices contributed $13 million to the increase in full-year revenues, while higher production volumes added another $485 million.

Worldwide oil production from continuing operations increased 11.9 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.

9

Natural Gas Revenues

2013 vs. 2012 Natural gas revenues of $2.6 billion for 2013 were $342 million lower than 2012, the result of a 8 percent decrease in production volumes and a 3 percent decrease in realized prices. Worldwide production decreased 170.3 MMcf/d, lowering revenues by $242 million. Realized prices in 2013 averaged $3.77 per Mcf, a decrease of $0.13 per Mcf, which reduced revenues by an additional $100 million.

Worldwide gas production from continuing operations decreased 8 percent; however, excluding production from the Gulf of Mexico Shelf and Canadian assets sold during the year, gas production declined only 2 percent, or 34 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. 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 $3.0 billion were $436 million lower than 2011, the result of a 14 percent decrease in realized prices partially offset by a 1 percent increase in production volumes. Realized prices in 2012 averaged $3.90 per Mcf, a decrease of $0.65 per Mcf, which reduced revenues by $486 million. Worldwide production from continuing operations rose 29.9 MMcf/d, adding $50 million to revenues.

Worldwide gas production from continuing operations 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.

NGL Revenues

2013 vs. 2012 NGL revenues totaled $652 million in 2013, an increase of $132 million from 2012, the result of a 51 percent increase in production volumes partially offset by a 17 percent decrease in realized prices. Worldwide production from continuing operations rose 21.1 Mb/d, adding $219 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 $28.56 per Mcf barrel, a decrease of $5.75 per barrel, which reduced revenues by $87 million.

2012 vs. 2011 NGL revenues totaled $520 million in 2012, an increase of $29 million from 2011, the result of a 47 percent increase in production volumes partially offset by a 28 percent decrease in realized prices. Worldwide production rose 13.3 Mb/d, adding $168 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 $34.31 per Mcf barrel, a decrease of $13.57 per barrel, which reduced revenues by $139 million.

10

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. Operating expenses for all periods exclude discontinued operations in Argentina.

	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	$	4,894	$	4,593	$	3,624	$	18.67	$	17.18	$	14.18
Additional		995		1,926		109		3.80		7.21		0.43
Other assets		400		362		273		1.53		1.35		1.07
Asset retirement obligation accretion		238		228		150		0.91		0.85		0.59
Lease operating costs		2,864		2,784		2,440		10.93		10.41		9.55
Gathering and transportation costs		288		295		289		1.08		1.12		1.12
Taxes other than income		785		818		871		3.00		3.06		3.41
General and administrative expense		482		515		439		1.84		1.92		1.72
Acquisitions, divestitures & transition		33		31		20		0.12		0.12		0.08
Financing costs, net		177		172		172		0.68		0.64		0.67
Total	$	11,156	$	11,724	$	8,387	$	42.56	$	43.86	$	32.82

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	$	3,624
Volume change		229
DD&A Rate change		740
2012 DD&A	$	4,593
Volume change		(57	)
DD&A Rate change		358
2013 DD&A	$	4,894

2013 vs. 2012 Recurring full-cost depletion expense increased $301 million on an absolute dollar basis: $358 million on rate partially offset by a decrease of $57 million from lower volumes. Our full-cost depletion rate increased $1.49 to $18.67 per boe reflecting acquisition and drilling costs that exceed our historical levels.

2012 vs. 2011 Recurring full-cost depletion expense increased $969 million on an absolute dollar basis: $740 million on higher costs and $229 million from additional production. Our full-cost depletion rate increased $3.00 to $17.18 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.

11

In 2013 we recorded non-cash write-downs of the carrying value of the Company’s proved oil and gas properties totaling $995 million. The after-tax impact of these write-downs was $356 million in the U.S. and $139 million in the North Sea. 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.

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	$	9.55
Divestitures(1)		(0.11	)	Repairs and maintenance		0.42
Power and fuel costs		0.21		Labor and pumper costs		0.25
Labor and overhead costs		0.16		Non-operated property costs		0.11
Non-operated property costs		0.14		Workover costs		0.05
Transportation		0.14		Other		0.17
Workover costs		0.08		Other decreased production		0.01
Repairs and maintenance		0.08		Acquisitions(1)		(0.15	)
Other		0.08
Other increased production		(0.26	)
2013 LOE	$	10.93		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. and Canada 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.

12

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
Total Gathering and transportation	$	288	$	295	$	289

2013 vs. 2012 Gathering and transportation costs decreased $7 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.

2012 vs. 2011 Gathering and transportation costs increased $6 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. and Australia, 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		249		215		205
Ad valorem taxes		113		103		94
Other		41		49		34
Total Taxes other than income	$	785	$	818	$	871

2013 vs. 2012 Taxes other than income were $33 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 $10 million to severance and ad valorem tax expense, respectively.

2012 vs. 2011 Taxes other than income were $53 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 $10 million and $9 million to severance and ad valorem tax expense, respectively.

General and Administrative Expenses

2013 vs. 2012 General and administrative (G&A) expenses decreased $33 million, or 6 percent, from 2012. On a per-unit basis, G&A expenses were down $0.08 to $1.84 per boe, with the benefit of lower costs partially offset by the impact of lower production.

13

2012 vs. 2011 G&A expenses increased $76 million, or 17 percent, from 2011. On a per-unit basis, G&A expenses increased 12 percent, or $0.20 per boe: $0.14 per boe primarily relates to stock-based performance plan charges and $0.15 per boe relates to growth-related increases, less $0.09 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.

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	$	560		$	501		$	430
Amortization of deferred loan costs		8			7			5
Capitalized interest		(364	)		(323	)		(251	)
Gain on extinguishment of debt		(16	)		—			—
Interest income		(11	)		(13	)		(12	)
Total Financing costs, net	$	177		$	172		$	172

2013 vs. 2012 Net financing costs increased $5 million from 2012. The increase is primarily related to a $59 million increase in interest expense from debt issuances during 2012, partially offset by a $41 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 remained essentially flat from 2011 to 2012. A $71 million increase in interest expense from debt issuances during 2012 was primarily offset by a $72 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 43.7 percent. The 2013 effective rate reflects the tax benefit from the $995 million non-cash write-downs in the U.S., North Sea, 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 58.9 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 a valuation allowance in Canada. Excluding these items, the 2012 effective tax rate would have been 45 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 8-K.

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Capital Resources and Liquidity

Operating cash flows are the Company’s primary source of liquidity. We may also elect to utilize available committed borrowing capacity, access to both debt and equity capital markets, or proceeds from the occasional sale of nonstrategic assets for all other liquidity and capital resource needs.

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

Apache’s long-term operating cash flows are dependent on reserve replacement and the level of costs required for ongoing operations. 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 the Previously Filed Annual Report.

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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 continuing operating activities	$	9,603	$	8,281		$	9,707
Commercial paper and bank loan borrowings, net		—		511			—
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			—
Net cash provided by Argentina operations		18		—			—
Other		21		—			68
		16,995		13,797			10,197
Uses of Cash and Cash Equivalents:
Capital expenditures(1)	$	11,006	$	9,212		$	6,701
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		509		—			927
Dividends paid		360		332			306
Shares repurchased		997		—			—
Payments on fixed-rate debt		2,072		400			—
Net cash used by Argentina operations		—		66			127
Other		90		565			162
		15,249		13,932			10,036
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 Continuing 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 continuing operating activities for 2013 totaled $9.6 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 8-K.

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 8-K.

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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(2)		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.

⁽²⁾ Capitalized interest includes Argentina discontinued operations of $10 million, $11 million, and $12 million for the years ended 2013, 2012 and 2011, respectively.

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.

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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 discontinued operations’ E&D expenditure was 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 8-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.

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 through the date of the filing of the Previously Filed Annual Report 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.

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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 at year-end consisted of $2 million borrowed under uncommitted money market and overdraft lines of credit in Canada and $51 million in Argentina, which was repaid in conjunction with the divestiture of our Argentine operations. 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 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.

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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 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.

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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 8-K.

	Note Reference									2019 & Beyond
Contractual Obligations(1)		Total		2014		2015-2016		2017-2018
	(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 8-K.

⁽²⁾  This represents minimum future expenditures for drilling rig services. Apache’s expenditures for drilling rig services will exceed such minimum amounts to the extent Apache utilizes the drilling rigs subject to a particular contractual commitment for a period greater than the period set forth in the governing contract.

⁽³⁾  Purchase obligations represent agreements to purchase goods or services that are enforceable, are legally binding, and specify all significant terms, including fixed and minimum quantities to be purchased; fixed, minimum or variable price provisions; and the appropriate timing of the transaction. These include minimum commitments associated with take-or-pay contracts, hydraulic fracturing service agreements, obtaining and processing seismic data, and contractual obligations to buy or build oil and gas plants and facilities, including LNG facilities.

⁽⁴⁾  Other operating lease obligations pertain to other long-term exploration, development, and production activities. The Company has work-related commitments for oil and gas operations equipment, acreage maintenance commitments, FPSOs, and aircraft, among other things.

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 8-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.

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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.

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.

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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 Attributable to Common Stock (GAAP)	$	2,188		$	1,925		$	4,508
Adjustments:
Oil & gas property write-downs, net of tax(1)		541			1,427			60
Deferred tax on distributed foreign earnings		225			—			—
Argentina discontinued operations, net of tax		192			(14	)		(12	)
Commodity derivative mark-to-market, net of tax(2)		142			51			—
Acquisitions, divestitures, and transition, net of tax(3)		21			19			13
U.K. income tax adjustments		—			118			218
Deferred tax adjustments		(28	)		211			(75	)
Unrealized foreign currency fluctuation impact on deferred tax expense		(123	)		1			(73	)
Adjusted Earnings (Non-GAAP)	$	3,158		$	3,738		$	4,639
Net Income per Common Share – Diluted (GAAP)	$	5.50		$	4.92		$	11.47
Adjustments:
Oil & gas property write-downs, net of tax(1)		1.34			3.53			0.15
Deferred tax on distributed foreign earnings		0.55			—			—
Argentina discontinued operations, net of tax		0.47			(0.03	)		(0.03	)
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
U.K. income tax adjustments		—			0.30			0.55
Deferred tax adjustments		(0.07	)		0.52			(0.19	)
Unrealized foreign currency fluctuation impact on deferred tax expense		(0.30	)		—			(0.18	)
Adjusted Earnings Per Share – Diluted (Non-GAAP)	$	7.89		$	9.41		$	11.80

⁽¹⁾  Write-downs of our U.S. and North Sea proved oil and gas property balances of $552 million and $368 million, respectively, were recorded in 2013, for which tax benefits of $196 million and $229 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.

23

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.

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.

24

Purchase Price Allocation

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

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

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

25

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 $102.62 per barrel compared to $103.29 per barrel in 2012. Our average natural gas price realizations decreased 3 percent in 2013 to $3.77 per Mcf from $3.90 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 9 percent of our natural gas production from continuing operations and approximately 43 percent of our crude oil production from continuing operations was subject to financial derivative hedges, compared with 15 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 8-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 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. Revenue and disbursement transactions denominated in Australian dollars, Canadian dollars, and British pounds 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, and British pound against the U.S. dollar as of December 31, 2013, would result in a foreign currency net loss or gain, respectively, of approximately $181 million.

26

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;

• 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 the Previously Filed Annual Report.

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.

27

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) Documents included in this report:

1. Financial Statements

Report of independent registered public accounting firm	F-1
Statement of consolidated operations for each of the three years in the period ended December 31, 2013	F-2
Statement of consolidated comprehensive income for each of the three years in the period ended December 31, 2013	F-3
Statement of consolidated cash flows for each of the three years in the period ended December 31, 2013	F-4
Consolidated balance sheet as of December 31, 2013 and 2012	F-5
Statement of consolidated changes in equity for each of the three years in the period ended December 31, 2013	F-6
Notes to consolidated financial statements	F-7

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, except for the effects of discontinued operations as discussed in Note 1, as to which the date is July 17, 2014

F-1

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	$	12,632		$	12,939		$	12,441
Gas revenues		2,627			2,969			3,405
Natural gas liquids revenues		652			520			491
		15,911			16,428			16,337
Derivative instrument gains (losses), net		(399	)		(79	)		—
Other		48			215			114
		15,560			16,564			16,451
OPERATING EXPENSES:
Depreciation, depletion, and amortization:
Oil and gas property and equipment
Recurring		4,894			4,593			3,624
Additional		995			1,926			109
Other assets		400			362			273
Asset retirement obligation accretion		238			228			150
Lease operating expenses		2,864			2,784			2,440
Gathering and transportation		288			295			289
Taxes other than income		785			818			871
General and administrative		482			515			439
Acquisitions, divestitures and transition		33			31			20
Financing costs, net		177			172			172
		11,156			11,724			8,387
NET INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		4,404			4,840			8,064
Current income tax provision		1,663			2,199			2,248
Deferred income tax provision		261			654			1,244
NET INCOME FROM CONTINUING OPERATIONS
INCLUDING NONCONTROLLING INTEREST		2,480			1,987			4,572
Net income (loss) from discontinued operations, net of tax		(192	)		14			12
NET INCOME INCLUDING NONCONTROLLING INTEREST		2,288			2,001			4,584
Preferred stock dividends		44			76			76
Net income attributable to noncontrolling interest		56			—			—
NET INCOME ATTRIBUTABLE TO COMMON STOCK	$	2,188		$	1,925		$	4,508
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS:
Net income from continuing operations attributable to common shareholders	$	2,380		$	1,911		$	4,496
Net income (loss) from discontinued operations		(192	)		14			12
Net income attributable to common shareholders	$	2,188		$	1,925		$	4,508
BASIC NET INCOME PER COMMON SHARE:
Basic net income from continuing operations per share	$	6.02		$	4.91		$	11.72
Basic net income (loss) from discontinued operations per share		(0.49	)		0.04			0.03
Basic net income per share	$	5.53		$	4.95		$	11.75
DILUTED NET INCOME PER COMMON SHARE:
Diluted net income from continuing operations per share	$	5.97		$	4.89		$	11.44
Diluted net income (loss) from discontinued operations per share		(0.47	)		0.03			0.03
Diluted net income per share	$	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-2

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
Preferred stock dividends		44			76			76
Comprehensive income attributable to noncontrolling interest		56			—			—
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-3

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:
Loss (income) from discontinued operations		192			(14	)		(12	)
Depreciation, depletion, and amortization		6,289			6,881			4,006
Asset retirement obligation accretion		238			228			150
Provision for deferred income taxes		261			654			1,244
Other		268			223			42
Changes in operating assets and liabilities:
Receivables		112			28			(736	)
Inventories		(71	)		(60	)		(35	)
Drilling advances		234			(343	)		24
Deferred charges and other		(148	)		41			31
Accounts payable		491			(84	)		179
Accrued expenses		(566	)		(1,133	)		85
Deferred credits and noncurrent liabilities		15			(141	)		145
NET CASH PROVIDED BY CONTINUING OPERATING ACTIVITIES		9,603			8,281			9,707
NET CASH PROVIDED BY DISCONTINUED OPERATIONS		232			223			246
NET CASH PROVIDED BY OPERATING ACTIVITIES		9,835			8,504			9,953
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property		(9,816	)		(8,479	)		(6,049	)
Additions to gas gathering, transmission, and processing facilities		(1,190	)		(733	)		(652	)
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		(90	)		(555	)		(162	)
NET CASH USED IN CONTINUING INVESTING ACTIVITIES		(6,906	)		(13,097	)		(8,254	)
NET CASH USED IN DISCONTINUED OPERATIONS		(210	)		(327	)		(391	)
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		(509	)		511			(927	)
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	)		68
NET CASH PROVIDED BY (USED IN) CONTINUING FINANCING ACTIVITIES		(969	)		4,747			(1,165	)
NET CASH PROVIDED BY (USED IN) DISCONTINUED OPERATIONS		(4	)		38			18
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-4

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-5

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-6

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 five countries: the United States (U.S.), Canada, Egypt, Australia, and the United Kingdom (U.K.) North Sea (North Sea). 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.

Recast of Financial Information for Discontinued Operations

In March 2014, Apache completed the sale of all of its operations in Argentina. Results of operations and cash flows for Argentina operations are reflected as discontinued operations in the Company’s financial statements for all periods presented. As a result of this transaction, the Company has recast certain historical information to reflect the results of operations of Argentina as discontinued operations for all periods presented, including the Statement of Consolidated Operations, Statement of Consolidated Cash Flows, and related information in Notes 1, 2, 5, 6, 7, 8, 10, 13, 14, 15, and 16.

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.

F-7

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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

F-8

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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 for its continuing operations totaling $920 million. The after-tax impact of these write-downs was $356 million in the U.S. and $139 million in the North Sea. In addition, the Company recorded a non-cash write-down of $118 million, net of tax, in Argentina, which is reflected as discontinued operations in the Company’s consolidated financial statements. 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.

F-9

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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

F-10

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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.

F-11

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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. 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. In March 2014, Apache’s subsidiaries closed the sale of Argentina, and as a result, Apache classified the results of operations related to Argentina as discontinued operations.

F-12

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The carrying amounts of the major classes of assets and liabilities associated with the disposition were as follows:

	December 31,
	2013		2012
	(In millions)
ASSETS
Current assets	$	150	$	174
Net property and equipment		1,416		1,621
Other assets		12		40
Total assets	$	1,578	$	1,835
LIABILITIES
Current debt	$	51	$	69
Other current liabilities		95		105
Asset retirement obligations		91		83
Other long-term liabilities		21		39
Total liabilities	$	258	$	296

Sales and other operating revenues and loss from discontinued operations related to the Argentina disposition were as follows:

	For the Year Ended December 31,
	2013			2012		2011
	(In millions)
Revenues and other from discontinued operations	$	494		$	514	$	437
Income (loss) from discontinued operations, net of tax	$	(192	)	$	14	$	12

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.

F-13

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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.

F-14

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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.

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-15

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.

F-16

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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

F-17

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-18

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,
	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.

Accretion expense includes Argentina discontinued operations of $5 million and $4 million, respectively, for the years ended 2013 and 2012 and is included in Net income (loss) from discontinued operations, net of tax.

Additionally, accretion expense for the year ended 2011 included Argentina discontinued operations of $4 million, which is included in Net income (loss) from discontinued operations, net of tax.

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-19

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-20

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.

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

F-21

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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		Fair		Carrying		Fair
	Amount		Value		Amount		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 $2 million was drawn on facilities in Canada and $51 million in Argentina, which was repaid in conjunction with the divestiture of our Argentine operations. As of December 31, 2012, a total of $22 million was drawn on facilities in the U.S. and Canada, and $69 million in Argentina.

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.

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.

F-22

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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.

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	$	560		$	501		$	430
Amortization of deferred loan costs		8			7			5
Capitalized interest		(364	)		(323	)		(251	)
Gain on extinguishment of debt		(16	)		—			—
Interest income		(11	)		(13	)		(12	)
Financing costs, net	$	177		$	172		$	172

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.

F-23

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

7. INCOME TAXES

Income from continuing operations 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		3,213		3,235		5,691
Total	$	4,404	$	4,840	$	8,064

The total provision for income taxes from continuing operations consists of the following:

	For the Year Ended December 31,
	2013			2012			2011
	(In millions)
Current taxes:
Federal	$	(29	)	$	(150	)	$	64
State		—			—			2
Foreign		1,692			2,349			2,182
		1,663			2,199			2,248
Deferred taxes:
Federal		509			596			656
State		44			10			17
Foreign		(292	)		48			571
		261			654			1,244
Total	$	1,924		$	2,853		$	3,492

A reconciliation of the tax on the Company’s income from continuing operations 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	$	1,541		$	1,694		$	2,823
State income tax, less federal benefit		29			6			12
Taxes related to foreign operations		200			767			563
Tax credits		6			(4	)		(14	)
Deferred tax on distributed foreign earnings		225			—			—
Current and deferred taxes related to currency fluctuations		(144	)		26			(67	)
Change in U.K. tax rate		—			118			218
Net change in tax contingencies		(10	)		(115	)		(6	)
Valuation allowances		132			341			8
All other, net		(55	)		20			(45	)
	$	1,924		$	2,853		$	3,492

F-24

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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, of which $69 million, $14 million, and none related to discontinued operations and is included in Net income (loss) from discontinued operations, net of tax.

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.

F-25

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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. On March 12, 2014, Apache completed the sale of its Argentina operations to YPF Sociedad Anónima. YPF Sociedad Anónima acquired all of Apache Argentina’s tax attributes, including $299 million of Argentina net operating losses.

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.

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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(1)	2006

⁽¹⁾  On March 12, 2014, Apache divested of its Argentina operations.

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 and Argentine Tariff

On March 12, 2014, the Company and its subsidiaries completed the sale of all of the Company’s subsidiaries’ operations and properties in Argentina to YPF Sociedad Anonima (YPF). As part of that sale, YPF assumed responsibility for all of the past, present, and future litigation in Argentina involving Company subsidiaries, except that Company subsidiaries have agreed to indemnify YPF for certain environmental, tax, and royalty obligations capped at an aggregate of $100 million. The indemnity is subject to specific agreed conditions precedent, thresholds, contingencies, limitations, claim deadlines, loss sharing, and other terms and conditions. On April 11, 2014, YPF provided its first notice of claims pursuant to the indemnity. Company subsidiaries have not paid any amounts under the indemnity but will continue to review and consider claims presented by YPF. Further, Company subsidiaries retain the right to enforce certain Argentina-related indemnification obligations against Pioneer Natural Resources Company (Pioneer) up to $67.5 million pursuant to the terms and conditions of stock purchase agreements entered in 2006 between Company subsidiaries and Pioneer subsidiaries.

The litigation that YPF assumed responsibility for, as explained above, includes the previously-reported ASSUPA and Enargas matters:

In connection with the acquisition from 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, 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

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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. 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 YPF may incur liabilities related to the environmental claims and then seek indemnity from Company subsidiaries as described above, no reasonable prediction can be made as the exposure related to these lawsuits is not currently determinable. Company subsidiaries reserve all rights.

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 the YPF-acquired Company affiliates in Argentina, totaled approximately $39.5 million at the time of the sale to YPF, of which $11 million had been paid. The YPF-acquired Company affiliates initiated legal proceedings in the Provinces of Neuquén and Tierra del Fuego challenging the Enargas tariff charge and obtained temporary injunctive relief that prohibits the collection of the charges pending final rulings on the merits of the legal challenges. It is possible YPF may incur liabilities related to the Enargas tariffs and then seek indemnity from Company subsidiaries as described above. Company subsidiaries reserve all rights.

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

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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 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 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.

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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.

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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.

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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

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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:

Net Minimum Commitments	Total		2014		2015-2016		2017-2018		2019 & 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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

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

The table above includes leases for buildings, facilities, and related equipment with varying expiration dates through 2035. Net rental expense was $81 million, $76 million, and $64 million for 2013, 2012, and 2011, respectively.

9. RETIREMENT AND DEFERRED COMPENSATION PLANS

Apache Corporation provides retirement benefits to its U.S. employees through the use of multiple plans: a 401(k) savings plan, a money purchase retirement plan, a non-qualified retirement/savings plan, and a non-qualified restorative retirement savings plan. The 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 Benefits			Postretirement Benefits			Pension Benefits			Postretirement Benefits			Pension Benefits			Postretirement 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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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.

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The following tables set forth the components of the net periodic cost and the underlying weighted average actuarial assumptions used for the pension and postretirement benefit plans as of December 31, 2013, 2012, and 2011:

	2013						2012						2011
	Pension Benefits			Postretirement Benefits			Pension Benefits			Postretirement Benefits			Pension Benefits			Postretirement Benefits
	(In millions)
Component of Net Periodic Benefit Costs
Service cost	$	5		$	4		$	5		$	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 Benefits		Postretirement 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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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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:
Income from continuing operations	$	2,380			395	$	6.02		$	1,911		389	$	4.91	$	4,496		384	$	11.72
Income (loss) from discontinued operations		(192	)		395		(0.49	)		14		389		0.04		12		384		0.03
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:
Income from continuing operations	$	2,424			406	$	5.97		$	1,911		391	$	4.89	$	4,572		400	$	11.44
Income (loss) from discontinued operations		(192	)		406		(0.47	)		14		391		0.03		12		400		0.03
Income attributable to common stock	$	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

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

price of $90.08. An additional 2,393,917 shares were purchased subsequent to December 31, 2013 through the date of the filing of the Previously Filed Annual Report 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.

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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.

F-42

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

	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		—			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 when fully executed 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-43

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.

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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 five countries: the United States, Canada, Egypt, Australia, and the U.K. North Sea. 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		Other International			Total(1)
	(In millions)
2013
Oil and gas production revenues(2)	$	6,902	$	1,224		$	3,917	$	1,140	$	2,728	$	—		$	15,911
Operating Expenses:
Depreciation, depletion, and amortization
Recurring		2,338		505			1,005		423		1,022		1			5,294
Additional		552		—			—		—		367		76			995
Asset retirement obligation accretion		94		49			—		27		68		—			238
Lease operating expenses		1,320		459			471		214		400		—			2,864
Gathering and transportation		84		155			42		—		7		—			288
Taxes other than income		335		45			8		13		384		—			785
Operating Income (Loss)(2)	$	2,179	$	11		$	2,391	$	463	$	480	$	(77	)		5,447
Other Income (Expense):
Derivative instrument gains (losses), net																(399	)
Other																48
General and administrative																(482	)
Acquisitions, divestitures, and transition																(33	)
Financing costs, net																(177	)
Net Income From Continuing Operations
Before Income Taxes(2)															$	4,404
Net Property and Equipment(2)	$	27,010	$	6,058		$	5,454	$	6,838	$	5,622	$	23		$	51,005
Total Assets(2)	$	29,940	$	6,952		$	8,121	$	8,094	$	6,902	$	51		$	60,060
Additions to Net Property and Equipment(2)	$	6,404	$	1,082		$	1,309	$	1,954	$	1,084	$	24		$	11,857
2012
Oil and gas production revenues(2)	$	6,226	$	1,322		$	4,554	$	1,575	$	2,751	$	—		$	16,428
Operating Expenses:
Depreciation, depletion, and amortization
Recurring		2,056		594			925		466		914		—			4,955
Additional		—		1,883			—		—		—		43			1,926
Asset retirement obligation accretion		112		41			—		17		58		—			228
Lease operating expenses		1,386		458			410		215		315		—			2,784
Gathering and transportation		69		163			39		—		24		—			295
Taxes other than income		292		50			14		11		451		—			818
Operating Income (Loss)(2)	$	2,311	$	(1,867	)	$	3,166	$	866	$	989	$	(43	)		5,422
Other Income (Expense):
Derivative instrument gains (losses), net																(79	)
Other																215
General and administrative																(515	)
Acquisitions, divestitures, and transition																(31	)
Financing costs, net																(172	)
Net Income From Continuing Operations
Before Income Taxes(2)															$	4,840
Net Property and Equipment(2)	$	28,552	$	6,640		$	5,151	$	5,312	$	5,927	$	77		$	51,659
Total Assets(2)	$	31,175	$	7,142		$	7,311	$	6,280	$	6,874	$	120		$	58,902
Additions to Net Property and Equipment(2)	$	9,586	$	1,096		$	1,153	$	1,581	$	1,104	$	98		$	14,618

F-45

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

	United States		Canada		Egypt		Australia		North Sea		Other International			Total
	(In millions)
2011
Oil and gas production revenues(2)	$	6,104	$	1,617	$	4,791	$	1,734	$	2,091	$	—		$	16,337
Operating Expenses:
Depreciation, depletion, and amortization
Recurring		1,684		546		818		440		409		—			3,897
Additional		—		—		—		—		—		109			109
Asset retirement obligation accretion		97		26		—		10		17		—			150
Lease operating expenses		1,167		470		398		197		208		—			2,440
Gathering and transportation		64		165		35		—		25		—			289
Taxes other than income		259		51		13		9		539		—			871
Operating Income (Loss)(2)	$	2,833	$	359	$	3,527	$	1,078	$	893	$	(109	)		8,581
Other Expense:
Other															114
General and administrative															(439	)
Acquisitions, divestitures, and transition															(20	)
Financing costs, net															(172	)
Net Income From Continuing Operations
Before Income Taxes(2)														$	8,064
Net Property and Equipment(2)	$	21,038	$	8,022	$	4,923	$	4,194	$	5,737	$	22		$	43,936
Total Assets(2)	$	23,499	$	8,816	$	6,656	$	4,681	$	6,600	$	33		$	50,285
Additions to Net Property and Equipment(2)	$	3,854	$	1,288	$	1,015	$	1,140	$	4,175	$	73		$	11,545

⁽¹⁾  2013 includes a noncontrolling interest in Egypt.

⁽²⁾  Amounts have been recast to exclude discontinued operations.

F-46

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.

On March 12, 2014, Apache’s subsidiaries completed the sale of all of the Company’s operations in Argentina and as such the results of Argentina have been classified as discontinued operations.

	United States		Canada			Egypt(3)		Australia		North Sea		Other International			Total(3)(4)
	(In millions, except per boe)
2013
Oil and gas production revenues	$	6,902	$	1,224		$	3,917	$	1,140	$	2,728	$	—		$	15,911
Operating cost:
Depreciation, depletion, and amortization
Recurring(1)		2,227		426			881		361		999		—			4,894
Additional		552		—			—		—		367		76			995
Asset retirement obligation accretion		94		49			—		27		68		—			238
Lease operating expenses		1,320		459			471		214		400		—			2,864
Gathering and transportation		84		155			42		—		7		—			288
Production taxes(2)		324		40			—		14		382		—			760
Income tax		817		24			1,161		157		313		—			2,472
		5,418		1,153			2,555		773		2,536		76			12,511
Results of operation	$	1,484	$	71		$	1,362	$	367	$	192	$	(76	)	$	3,400
Amortization rate per boe	$	18.39	$	10.89		$	16.21	$	17.47	$	37.25	$	—		$	18.67
2012
Oil and gas production revenues	$	6,226	$	1,322		$	4,554	$	1,575	$	2,751	$	—		$	16,428
Operating cost:
Depreciation, depletion, and amortization
Recurring(1)		1,984		580			924		460		912		—			4,860
Additional		—		1,883			—		—		—		43			1,926
Asset retirement obligation accretion		112		41			—		17		58		—			228
Lease operating expenses		1,386		458			410		215		315		—			2,784
Gathering and transportation		69		163			39		—		24		—			295
Production taxes(2)		279		42			—		11		451		—			783
Income tax		851		(466	)		1,527		262		614		—			2,788
		4,681		2,701			2,900		965		2,374		43			13,664
Results of operation	$	1,545	$	(1,379	)	$	1,654	$	610	$	377	$	(43	)	$	2,764
Amortization rate per boe	$	17.24	$	11.66		$	13.81	$	17.67	$	32.65	$	—		$	17.18
2011
Oil and gas production revenues	$	6,104	$	1,617		$	4,791	$	1,734	$	2,091	$	—		$	16,337
Operating cost:
Depreciation, depletion, and amortization
Recurring(1)		1,634		537			818		435		405		—			3,829
Additional		—		—			—		—		—		109			109
Asset retirement obligation accretion		97		26			—		10		17		—			150
Lease operating expenses		1,167		470			398		197		208		—			2,440
Gathering and transportation		64		165			35		—		25		—			289
Production taxes(2)		255		44			—		9		538		—			846
Income tax		1,025		95			1,699		325		557		—			3,701
		4,242		1,337			2,950		976		1,750		109			11,364
Results of operation	$	1,862	$	280		$	1,841	$	758	$	341	$	(109	)	$	4,973
Amortization rate per boe	$	15.55	$	10.44		$	11.63	$	16.59	$	20.21	$	—		$	14.18

⁽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.

⁽⁴⁾  Amounts have been recast to exclude discontinued operations.

F-47

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-48

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.

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-49

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-50

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-51

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-52

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-53

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.

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	)		(50,544	)
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.

F-54

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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-55

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	$	3,946		$	4,268		$	3,900		$	3,446		$	15,560
Expenses(2)		3,168			3,231			3,464			3,217			13,080
Net income from continuing operations including noncontrolling interest		778			1,037			436			229			2,480
Net income (loss) from discontinued operations, net of tax		(61	)		(2	)		(130	)		1			(192	)
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
Basic net income per common share(1):
Net income from continuing operations	$	1.94		$	2.60		$	1.08		$	0.40		$	6.02
Net income (loss) from discontinued operations		(0.16	)		(0.01	)		(0.33	)		0.01			(0.49	)
Net income per share	$	1.78		$	2.59		$	0.75		$	0.41		$	5.53
Diluted net income per common share(1):
Net income from continuing operations	$	1.91		$	2.54		$	1.07		$	0.45		$	5.97
Net income (loss) from discontinued operations		(0.15	)		—			(0.32	)		—			(0.47	)
Net income per share	$	1.76		$	2.54		$	0.75		$	0.45		$	5.50
2012
Revenues and other	$	4,400		$	3,850		$	4,055		$	4,259		$	16,564
Expenses(2)		3,626			3,502			3,875			3,574			14,577
Net income from continuing operations including noncontrolling interest		774			348			180			685			1,987
Net income (loss) from discontinued operations, net of tax		23			8			—			(17	)		14
Net income including noncontrolling interest	$	797		$	356		$	180		$	668		$	2,001
Net income attributable to common stock	$	778		$	337		$	161		$	649		$	1,925
Basic net income per common share(1):
Net income from continuing operations	$	1.96		$	0.84		$	0.41		$	1.70		$	4.91
Net income (loss) from discontinued operations		0.06			0.03			—			(0.05	)		0.04
Net income per share	$	2.02		$	0.87		$	0.41		$	1.65		$	4.95
Diluted net income per common share(1):
Net income from continuing operations	$	1.94		$	0.84		$	0.41		$	1.70		$	4.89
Net income (loss) from discontinued operations		0.06			0.02			—			(0.05	)		0.03
Net income per share	$	2.00		$	0.86		$	0.41		$	1.65		$	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 $541 million, net of tax, in the U.S. and North Sea 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.

F-56

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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-57

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		$	—	$	11,326		$	—		$	15,911
Equity in net income (loss) of affiliates		2,313			17		36			(2,366	)		—
Derivative instrument losses, net		(399	)		—		—			—			(399	)
Other		—			61		(9	)		(4	)		48
		6,499			78		11,353			(2,370	)		15,560
OPERATING EXPENSES:
Depreciation, depletion, and amortization		2,250			—		4,039			—			6,289
Asset retirement obligation accretion		67			—		171			—			238
Lease operating expenses		939			—		1,925			—			2,864
Gathering and transportation		61			—		227			—			288
Taxes other than income		190			—		595			—			785
General and administrative		408			—		78			(4	)		482
Acquisitions, divestitures, and transition		33			—		—			—			33
Financing costs, net		97			5		75			—			177
		4,045			5		7,110			(4	)		11,156
NET INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		2,454			73		4,243			(2,366	)		4,404
Provision for income taxes		222			20		1,682			—			1,924
NET INCOME (LOSS) FROM CONTINUING OPERATIONS INCLUDING NONCONTROLLING INTEREST		2,232			53		2,561			(2,366	)		2,480
Net loss from discontinued operations, net of tax		—			—		(192	)		—			(192	)
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTEREST		2,232			53		2,369			(2,366	)		2,288
Preferred stock dividends		44			—		—			—			44
Net income attributable to noncontrolling interest		—			—		56			—			56
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-58

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		$	—		$	12,191	$	—		$	16,428
Equity in net income (loss) of affiliates		1,523			(737	)		248		(1,034	)		—
Other		(80	)		69			151		(4	)		136
		5,680			(668	)		12,590		(1,038	)		16,564
OPERATING EXPENSES:
Depreciation, depletion, and amortization		1,391			—			5,490		—			6,881
Asset retirement obligation accretion		76			—			152		—			228
Lease operating expenses		957			—			1,827		—			2,784
Gathering and transportation		51			—			244		—			295
Taxes other than income		185			—			633		—			818
General and administrative		425			—			94		(4	)		515
Acquisitions, divestitures, and transition		25			—			6		—			31
Financing costs, net		94			(20	)		98		—			172
		3,204			(20	)		8,544		(4	)		11,724
NET INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		2,476			(648	)		4,046		(1,034	)		4,840
Provision (benefit) for income taxes		475			(159	)		2,537		—			2,853
NET INCOME (LOSS) FROM CONTINUING OPERATIONS INCLUDING NONCONTROLLING INTEREST		2,001			(489	)		1,509		(1,034	)		1,987
Net income from discontinued operations, net of tax		—			—			14		—			14
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTEREST		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-59

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	$	—		$	11,957		$	—		$	16,337
Equity in net income (loss) of affiliates		3,590		234			46			(3,870	)		—
Other		9		125			(16	)		(4	)		114
		7,979		359			11,987			(3,874	)		16,451
OPERATING EXPENSES:
Depreciation, depletion, and amortization		1,257		—			2,749			—			4,006
Asset retirement obligation accretion		70		—			80			—			150
Lease operating expenses		794		—			1,646			—			2,440
Gathering and transportation		51		—			238			—			289
Taxes other than income		170		—			701			—			871
General and administrative		365		—			78			(4	)		439
Acquisitions, divestitures, and transition		14		—			6			—			20
Financing costs, net		149		(18	)		41			—			172
		2,870		(18	)		5,539			(4	)		8,387
NET INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		5,109		377			6,448			(3,870	)		8,064
Provision for income taxes		525		97			2,870			—			3,492
NET INCOME (LOSS) FROM CONTINUING OPERATIONS INCLUDING NONCONTROLLING INTEREST		4,584		280			3,578			(3,870	)		4,572
Net income from discontinued operations, net of tax		—		—			12			—			12
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTEREST		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-60

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 CONTINUING OPERATING ACTIVITIES	$	1,421		$	315		$	7,867		$	—	$	9,603
CASH USED IN DISCONTINUED OPERATIONS		—			—			232			—		232
CASH PROVIDED BY OPERATING ACTIVITIES		1,421			315			8,099			—		9,835
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property		(4,291	)		—			(5,525	)		—		(9,816	)
Additions to gas gathering, transmission, and processing facilities		(124	)		—			(1,066	)		—		(1,190	)
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	)		—			(32	)		—		(90	)
NET CASH USED IN CONTINUING INVESTING ACTIVITIES		(771	)		—			(6,135	)		—		(6,906	)
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES		—			—			(210	)		—		(210	)
NET CASH USED IN INVESTING ACTIVITIES		(771	)		—			(6,345	)		—		(7,116	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Commercial paper, credit facility, and bank notes, net		(501	)		—			(8	)		—		(509	)
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 USED IN CONTINUING FINANCING ACTIVITIES		(495	)		(312	)		(162	)		—		(969	)
NET CASH USED IN DISCONTINUED OPERATIONS		—			—			(4	)		—		(4	)
NET CASH 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-61

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

For the Year Ended December 31, 2012

	Apache Corporation			Apache Finance Canada			All Other Subsidiaries of Apache Corporation			Reclassifications & Eliminations			Consolidated
	(In millions)
CASH PROVIDED BY (USED IN) CONTINUING OPERATING ACTIVITIES	$	2,357		$	(40	)	$	5,964		$	—		$	8,281
CASH PROVIDED BY DISCONTINUED OPERATIONS		—			—			223			—			223
CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES		2,357			(40	)		6,187			—			8,504
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property		(3,313	)		—			(5,166	)		—			(8,479	)
Additions to gas gathering, transmission, and processing facilities		(48	)		—			(685	)		—			(733	)
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	)		—			(105	)		—			(555	)
NET CASH PROVIDED BY (USED IN) CONTINUING INVESTING ACTIVITIES		(7,175	)		—			(6,579	)		657			(13,097	)
NET CASH USED IN DISCONTINUED OPERATIONS		—			—			(327	)		—			(327	)
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			—			9			—			511
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) CONTINUING FINANCING ACTIVITIES		4,777			35			592			(657	)		4,747
NET CASH PROVIDED BY DISCONTINUED OPERATIONS		—			—			38			—			38
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-62

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 CONTINUING OPERATING ACTIVITIES	$	2,191		$	13		$	7,503		$	—		$	9,707
CASH PROVIDED BY DISCONTINUED OPERATIONS		—			—			246			—			246
CASH PROVIDED BY OPERATING ACTIVITIES		2,191			13			7,749			—			9,953
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property		(1,478	)		—			(4,571	)		—			(6,049	)
Additions to gas gathering, transmission, and processing facilities		—			—			(652	)		—			(652	)
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	)		—			(81	)		—			(162	)
NET CASH USED IN CONTINUING INVESTING ACTIVITIES		(1,031	)		—			(6,451	)		(772	)		(8,254	)
NET CASH USED IN DISCONTINUED OPERATIONS		—			—			(391	)		—			(391	)
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	)		—			—			—			(927	)
Intercompany borrowings		—			(1	)		(763	)		764			—
Dividends paid		(306	)		—			—			—			(306	)
Other		108			(7	)		(41	)		8			68
NET CASH PROVIDED BY (USED IN) CONTINUING FINANCING ACTIVITIES		(1,125	)		(8	)		(804	)		772			(1,165	)
NET CASH PROVIDED BY DISCONTINUED OPERATIONS		—			—			18			—			18
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-63

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-64

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		(1,000	)		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-65

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		$	—	$	11,326		$	—		$	15,911
Equity in net income (loss) of affiliates		2,313			17		36			(2,366	)		—
Derivative instrument losses, net		(399	)		—		—			—			(399	)
Other		—			61		(9	)		(4	)		48
		6,499			78		11,353			(2,370	)		15,560
OPERATING EXPENSES:
Depreciation, depletion, and amortization		2,250			—		4,039			—			6,289
Asset retirement obligation accretion		67			—		171			—			238
Lease operating expenses		939			—		1,925			—			2,864
Gathering and transportation		61			—		227			—			288
Taxes other than income		190			—		595			—			785
General and administrative		408			—		78			(4	)		482
Acquisitions, divestitures, and transition		33			—		—			—			33
Financing costs, net		97			5		75			—			177
		4,045			5		7,110			(4	)		11,156
NET INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		2,454			73		4,243			(2,366	)		4,404
Provision for income taxes		222			20		1,682			—			1,924
NET INCOME (LOSS) FROM CONTINUING OPERATIONS INCLUDING NONCONTROLLING INTEREST		2,232			53		2,561			(2,366	)		2,480
Net loss from discontinued operations, net of tax		—			—		(192	)		—			(192	)
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTEREST		2,232			53		2,369			(2,366	)		2,288
Preferred stock dividends		44			—		—			—			44
Net income attributable to noncontrolling interest		—			—		56			—			56
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		$	—		$	12,191	$	—		$	16,428
Equity in net income (loss) of affiliates		1,523			(737	)		248		(1,034	)		—
Other		(80	)		69			151		(4	)		136
		5,680			(668	)		12,590		(1,038	)		16,564
OPERATING EXPENSES:
Depreciation, depletion, and amortization		1,391			—			5,490		—			6,881
Asset retirement obligation accretion		76			—			152		—			228
Lease operating expenses		957			—			1,827		—			2,784
Gathering and transportation		51			—			244		—			295
Taxes other than income		185			—			633		—			818
General and administrative		425			—			94		(4	)		515
Acquisitions, divestitures, and transition		25			—			6		—			31
Financing costs, net		94			(20	)		98		—			172
		3,204			(20	)		8,544		(4	)		11,724
NET INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		2,476			(648	)		4,046		(1,034	)		4,840
Provision (benefit) for income taxes		475			(159	)		2,537		—			2,853
NET INCOME (LOSS) FROM CONTINUING OPERATIONS INCLUDING NONCONTROLLING INTEREST		2,001			(489	)		1,509		(1,034	)		1,987
Net income from discontinued operations, net of tax		—			—			14		—			14
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTEREST		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	$	—		$	11,957		$	—		$	16,337
Equity in net income (loss) of affiliates		3,590		234			46			(3,870	)		—
Other		9		125			(16	)		(4	)		114
		7,979		359			11,987			(3,874	)		16,451
OPERATING EXPENSES:
Depreciation, depletion, and amortization		1,257		—			2,749			—			4,006
Asset retirement obligation accretion		70		—			80			—			150
Lease operating expenses		794		—			1,646			—			2,440
Gathering and transportation		51		—			238			—			289
Taxes other than income		170		—			701			—			871
General and administrative		365		—			78			(4	)		439
Acquisitions, divestitures, and transition		14		—			6			—			20
Financing costs, net		149		(18	)		41			—			172
		2,870		(18	)		5,539			(4	)		8,387
NET INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		5,109		377			6,448			(3,870	)		8,064
Provision for income taxes		525		97			2,870			—			3,492
NET INCOME (LOSS) FROM CONTINUING OPERATIONS INCLUDING NONCONTROLLING INTEREST		4,584		280			3,578			(3,870	)		4,572
Net income from discontinued operations, net of tax		—		—			12			—			12
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTEREST		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 CONTINUING OPERATING ACTIVITIES	$	1,421		$	315		$	7,867		$	—	$	9,603
CASH USED IN DISCONTINUED OPERATIONS		—			—			232			—		232
CASH PROVIDED BY OPERATING ACTIVITIES		1,421			315			8,099			—		9,835
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property		(4,291	)		—			(5,525	)		—		(9,816	)
Additions to gas gathering, transmission, and processing facilities		(124	)		—			(1,066	)		—		(1,190	)
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	)		—			(32	)		—		(90	)
NET CASH USED IN CONTINUING INVESTING ACTIVITIES		(771	)		—			(6,135	)		—		(6,906	)
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES		—			—			(210	)		—		(210	)
NET CASH USED IN INVESTING ACTIVITIES		(771	)		—			(6,345	)		—		(7,116	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Commercial paper, credit facility, and bank notes, net		(501	)		—			(8	)		—		(509	)
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 USED IN CONTINUING FINANCING ACTIVITIES		(495	)		(312	)		(162	)		—		(969	)
NET CASH USED IN DISCONTINUED OPERATIONS		—			—			(4	)		—		(4	)
NET CASH 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 (USED IN) CONTINUING OPERATING ACTIVITIES	$	2,357		$	(40	)	$	5,964		$	—		$	8,281
CASH PROVIDED BY DISCONTINUED OPERATIONS		—			—			223			—			223
CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES		2,357			(40	)		6,187			—			8,504
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property		(3,313	)		—			(5,166	)		—			(8,479	)
Additions to gas gathering, transmission, and processing facilities		(48	)		—			(685	)		—			(733	)
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	)		—			(105	)		—			(555	)
NET CASH PROVIDED BY (USED IN) CONTINUING INVESTING ACTIVITIES		(7,175	)		—			(6,579	)		657			(13,097	)
NET CASH USED IN DISCONTINUED OPERATIONS		—			—			(327	)		—			(327	)
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			—			9			—			511
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) CONTINUING FINANCING ACTIVITIES		4,777			35			592			(657	)		4,747
NET CASH PROVIDED BY DISCONTINUED OPERATIONS		—			—			38			—			38
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 CONTINUING OPERATING ACTIVITIES	$	2,191		$	13		$	7,503		$	—		$	9,707
CASH PROVIDED BY DISCONTINUED OPERATIONS		—			—			246			—			246
CASH PROVIDED BY OPERATING ACTIVITIES		2,191			13			7,749			—			9,953
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property		(1,478	)		—			(4,571	)		—			(6,049	)
Additions to gas gathering, transmission, and processing facilities		—			—			(652	)		—			(652	)
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	)		—			(81	)		—			(162	)
NET CASH USED IN CONTINUING INVESTING ACTIVITIES		(1,031	)		—			(6,451	)		(772	)		(8,254	)
NET CASH USED IN DISCONTINUED OPERATIONS		—			—			(391	)		—			(391	)
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	)		—			—			—			(927	)
Intercompany borrowings		—			(1	)		(763	)		764			—
Dividends paid		(306	)		—			—			—			(306	)
Other		108			(7	)		(41	)		8			68
NET CASH PROVIDED BY (USED IN) CONTINUING FINANCING ACTIVITIES		(1,125	)		(8	)		(804	)		772			(1,165	)
NET CASH PROVIDED BY DISCONTINUED OPERATIONS		—			—			18			—			18
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		(1,000	)		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

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	2,000,000	22,000,000
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%
Argentina Divestiture [Member] | Money Market Lines of Credit [Member]
Debt Instrument [Line Items]
Outstanding balance under the facility secured revolving syndicated	51,000,000	69,000,000
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

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

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

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

XML

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

XML

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

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

XML

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

XML

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]
Income from continuing operations									$ 2,380	$ 1,911	$ 4,496
Income (loss) from discontinued operations									(192)	14	12
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
Income from continuing operations									2,424	1,911	4,572
Income (loss) from discontinued operations									(192)	14	12
Income attributable to common stock									$ 2,232	$ 1,925	$ 4,584
Income from continuing operations, shares									395	389	384
Income (loss)from discontinued operations, shares									395	389	384
Income attributable to common stock, shares									395	389	384
Mandatory Convertible Preferred Stock									9		14
Stock options and other									2	2	2
Income from continuing operations, shares									406	391	400
Income (loss)from discontinued operations, shares									406	391	400
Income attributable to common stock, shares									406	391	400
Basic income from continuing operations per share	$ 0.40	$ 1.08	$ 2.60	$ 1.94	$ 1.70	$ 0.41	$ 0.84	$ 1.96	$ 6.02	$ 4.91	$ 11.72	$ 4.91
Basic income (loss) from discontinued operations per share	$ 0.01	$ (0.33)	$ (0.01)	$ (0.16)	$ (0.05)		$ 0.03	$ 0.06	$ (0.49)	$ 0.04	$ 0.03	$ 0.04
Income attributable to common stock, per share	$ 0.41	$ 0.75	$ 2.59	$ 1.78	$ 1.65	$ 0.41	$ 0.87	$ 2.02	$ 5.53	$ 4.95	$ 11.75	$ 4.95
Diluted income from continuing operations per share	$ 0.45	$ 1.08	$ 2.54	$ 1.91	$ 1.70	$ 0.41	$ 0.84	$ 1.94	$ 5.97	$ 4.89	$ 11.44	$ 4.89
Diluted income (loss) from discontinued operations per share		$ (0.33)		$ (0.15)	$ (0.05)		$ 0.02	$ 0.06	$ (0.47)	$ 0.03	$ 0.03	$ 0.03
Income attributable to common stock, per share	$ 0.45	$ 0.75	$ 2.54	$ 1.76	$ 1.65	$ 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

XML

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%

XML

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

XML

Retirement and Deferred Compensation Plans - Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates (Detail) (Postretirement Benefits [Member], USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 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)

XML

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

XML

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

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
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

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

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%

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

12 Months Ended

Dec. 31, 2013

Accounting Policies [Abstract]

Recast of Financial Information for Discontinued Operations

Recast of Financial Information for Discontinued Operations

In March 2014, Apache completed the sale of all of its operations in Argentina. Results of operations and cash flows for Argentina operations are reflected as discontinued operations in the Company’s financial statements for all periods presented. As a result of this transaction, the Company has recast certain historical information to reflect the results of operations of Argentina as discontinued operations for all periods presented, including the Statement of Consolidated Operations, Statement of Consolidated Cash Flows, and related information in Notes 1, 2, 5, 6, 7, 8, 10, 13, 14, 15, and 16.

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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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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Acquisitions and Divestitures - Summary of Carrying Amount of Major Assets and Liabilities Associated with Disposition (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
ASSETS
Current assets	$ 6,366	$ 4,962
Net Property and Equipment	52,421	53,280	43,936
LIABILITIES
Current debt	53	990
Other current liabilities	2,611	2,860
Asset retirement obligations	3,101	4,100
Argentina Divestiture [Member]
ASSETS
Current assets	150	174
Net Property and Equipment	1,416	1,621
Other assets	12	40
Total assets	1,578	1,835
LIABILITIES
Current debt	51	69
Other current liabilities	95	105
Asset retirement obligations	91	83
Other long-term liabilities	21	39
Total liabilities	$ 258	$ 296

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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%

XML

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

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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.

On March 12, 2014, Apache’s subsidiaries completed the sale of all of the Company’s operations in Argentina and as such the results of Argentina have been classified as discontinued operations.

	United States		Canada			Egypt(3)		Australia		North Sea		Other International			Total(3)(4)
	(In millions, except per boe)
2013
Oil and gas production revenues	$	6,902	$	1,224		$	3,917	$	1,140	$	2,728	$	—		$	15,911
Operating cost:
Depreciation, depletion, and amortization
Recurring(1)		2,227		426			881		361		999		—			4,894
Additional		552		—			—		—		367		76			995
Asset retirement obligation accretion		94		49			—		27		68		—			238
Lease operating expenses		1,320		459			471		214		400		—			2,864
Gathering and transportation		84		155			42		—		7		—			288
Production taxes(2)		324		40			—		14		382		—			760
Income tax		817		24			1,161		157		313		—			2,472
		5,418		1,153			2,555		773		2,536		76			12,511
Results of operation	$	1,484	$	71		$	1,362	$	367	$	192	$	(76	)	$	3,400
Amortization rate per boe	$	18.39	$	10.89		$	16.21	$	17.47	$	37.25	$	—		$	18.67
2012
Oil and gas production revenues	$	6,226	$	1,322		$	4,554	$	1,575	$	2,751	$	—		$	16,428
Operating cost:
Depreciation, depletion, and amortization
Recurring(1)		1,984		580			924		460		912		—			4,860
Additional		—		1,883			—		—		—		43			1,926
Asset retirement obligation accretion		112		41			—		17		58		—			228
Lease operating expenses		1,386		458			410		215		315		—			2,784
Gathering and transportation		69		163			39		—		24		—			295
Production taxes(2)		279		42			—		11		451		—			783
Income tax		851		(466	)		1,527		262		614		—			2,788
		4,681		2,701			2,900		965		2,374		43			13,664
Results of operation	$	1,545	$	(1,379	)	$	1,654	$	610	$	377	$	(43	)	$	2,764
Amortization rate per boe	$	17.24	$	11.66		$	13.81	$	17.67	$	32.65	$	—		$	17.18
2011
Oil and gas production revenues	$	6,104	$	1,617		$	4,791	$	1,734	$	2,091	$	—		$	16,337
Operating cost:
Depreciation, depletion, and amortization
Recurring(1)		1,634		537			818		435		405		—			3,829
Additional		—		—			—		—		—		109			109
Asset retirement obligation accretion		97		26			—		10		17		—			150
Lease operating expenses		1,167		470			398		197		208		—			2,440
Gathering and transportation		64		165			35		—		25		—			289
Production taxes(2)		255		44			—		9		538		—			846
Income tax		1,025		95			1,699		325		557		—			3,701
		4,242		1,337			2,950		976		1,750		109			11,364
Results of operation	$	1,862	$	280		$	1,841	$	758	$	341	$	(109	)	$	4,973
Amortization rate per boe	$	15.55	$	10.44		$	11.63	$	16.59	$	20.21	$	—		$	14.18

⁽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.

⁽⁴⁾  Amounts have been recast to exclude discontinued operations.

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	)		(50,544	)
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

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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	238	228	150
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

XML

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

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	1,692	2,349	2,182
Current tax, net	1,663	2,199	2,248
Deferred taxes:
Federal	509	596	656
State	44	10	17
Foreign	(292)	48	571
Deferred taxes, net	261	654	1,244
Total	$ 1,924	$ 2,853	$ 3,492

XML

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

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.

Recast of Financial Information for Discontinued Operations

In March 2014, Apache completed the sale of all of its operations in Argentina. Results of operations and cash flows for Argentina operations are reflected as discontinued operations in the Company’s financial statements for all periods presented. As a result of this transaction, the Company has recast certain historical information to reflect the results of operations of Argentina as discontinued operations for all periods presented, including the Statement of Consolidated Operations, Statement of Consolidated Cash Flows, and related information in Notes 1, 2, 5, 6, 7, 8, 10, 13, 14, 15, and 16.

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 for its continuing operations totaling $920 million. The after-tax impact of these write-downs was $356 million in the U.S. and $139 million in the North Sea. In addition, the Company recorded a non-cash write-down of $118 million, net of tax, in Argentina, which is reflected as discontinued operations in the Company’s consolidated financial statements. 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.

XML

Income Taxes - Reconciliation of Tax of Income Before Income Taxes and Total Tax Expense (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Tax Disclosure [Abstract]
Income tax expense at U.S. statutory rate	$ 1,541	$ 1,694	$ 2,823
State income tax, less federal benefit	29	6	12
Taxes related to foreign operations	200	767	563
Tax credits	6	(4)	(14)
Deferred tax on distributed foreign earnings	225
Current and deferred taxes related to currency fluctuations	(144)	26	(67)
Change in U.K. tax rate		118	218
Net change in tax contingencies	(10)	(115)	(6)
Valuation allowances	132	341	8
All other, net	(55)	20	(45)
Total	$ 1,924	$ 2,853	$ 3,492

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Acquisitions and Divestitures - Summary of Sales and Other Operating Revenue and Loss From Discontinued Operation Related to Disposition (Detail) (Argentina Divestiture [Member], USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Argentina Divestiture [Member]
Discontinued Operations [Line Items]
Revenues and other from discontinued operations	$ 494	$ 514	$ 437
Discontinued Operation, Amount of Other Income (Loss) from Disposition of Discontinued Operation, Net of Tax	$ (192)	$ 14	$ 12

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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		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 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

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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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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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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	$	560		$	501		$	430
Amortization of deferred loan costs		8			7			5
Capitalized interest		(364	)		(323	)		(251	)
Gain on extinguishment of debt		(16	)		—			—
Interest income		(11	)		(13	)		(12	)
Financing costs, net	$	177		$	172		$	172

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INCOME TAXES (Tables)

12 Months Ended

Dec. 31, 2013

Income Tax Disclosure [Abstract]

Income Before Income Taxes

Income from continuing operations 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		3,213		3,235		5,691
Total	$	4,404	$	4,840	$	8,064

Total Provision for Income Taxes

The total provision for income taxes from continuing operations consists of the following:

	For the Year Ended December 31,
	2013			2012			2011
	(In millions)
Current taxes:
Federal	$	(29	)	$	(150	)	$	64
State		—			—			2
Foreign		1,692			2,349			2,182
		1,663			2,199			2,248
Deferred taxes:
Federal		509			596			656
State		44			10			17
Foreign		(292	)		48			571
		261			654			1,244
Total	$	1,924		$	2,853		$	3,492

Reconciliation of Tax of Income Before Income Taxes and Total Tax Expense

A reconciliation of the tax on the Company’s income from continuing operations 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	$	1,541		$	1,694		$	2,823
State income tax, less federal benefit		29			6			12
Taxes related to foreign operations		200			767			563
Tax credits		6			(4	)		(14	)
Deferred tax on distributed foreign earnings		225			—			—
Current and deferred taxes related to currency fluctuations		(144	)		26			(67	)
Change in U.K. tax rate		—			118			218
Net change in tax contingencies		(10	)		(115	)		(6	)
Valuation allowances		132			341			8
All other, net		(55	)		20			(45	)
	$	1,924		$	2,853		$	3,492

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(1)	2006

⁽¹⁾  On March 12, 2014, Apache divested of its Argentina operations.

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STATEMENT OF CONSOLIDATED SHAREHOLDERS EQUITY (Unaudited) (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:

Net Minimum Commitments	Total		2014		2015-2016		2017-2018		2019 & 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 - 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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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	995,000,000	1,926,000,000	109,000,000
Seismic costs		15,000,000	49,000,000
Write-down of the carrying value of Oil and Gas properties	1,100,000,000
Write-down of the carrying value of Oil and Gas properties, net of tax	541,000,000
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		920,000,000
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
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

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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	Dec. 31, 2011
Asset Retirement Obligation [Line Items]
Asset retirement obligation accretion	$ 238	$ 228	$ 150
Additional abandonment liabilities associated with its drilling and development program	481	592
Argentina Divestiture [Member]
Asset Retirement Obligation [Line Items]
Asset retirement obligation accretion	$ 5	$ 4	$ 4

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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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STATEMENT OF CONSOLIDATED OPERATIONS (Unaudited) (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	$ 15,911	$ 16,428	$ 16,337
Derivative instrument gains (losses), net	(399)	(79)
Other	48	215	114
Total revenues and other	15,560	16,564	16,451
Oil and gas property and equipment
Recurring	4,894	4,593	3,624
Additional	995	1,926	109
Other assets	400	362	273
Asset retirement obligation accretion	238	228	150
Lease operating expenses	2,864	2,784	2,440
Gathering and transportation	288	295	289
Taxes other than income	785	818	871
General and administrative	482	515	439
Acquisitions, divestitures and transition	33	31	20
Financing costs, net	177	172	172
Total operating expenses	11,156	11,724	8,387
INCOME BEFORE INCOME TAXES	4,404	4,840	8,064
Current income tax provision	1,663	2,199	2,248
Deferred income tax provision	261	654	1,244
NET INCOME (LOSS) FROM CONTINUING OPERATIONS INCLUDING NONCONTROLLING INTEREST	2,480	1,987	4,572
Net income (loss) from discontinued operations, net of tax	(192)	14	12
NET INCOME INCLUDING NONCONTROLLING INTEREST	2,288	2,001	4,584
Preferred stock dividends	44	76	76
Net income attributable to noncontrolling interest	56
Net income attributable to common shareholders	2,188	1,925	4,508
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS:
Net income from continuing operations attributable to common shareholders	2,380	1,911	4,496
Net income (loss) from discontinued operations	(192)	14	12
Net income attributable to common shareholders	2,188	1,925	4,508
BASIC NET INCOME PER COMMON SHARE:
Basic net income from continuing operations per share	$ 6.02	$ 4.91	$ 11.72
Basic net income (loss) from discontinued operations per share	$ (0.49)	$ 0.04	$ 0.03
Basic net income per share	$ 5.53	$ 4.95	$ 11.75
Diluted net income per common share:
Diluted net income from continuing operations per share	$ 5.97	$ 4.89	$ 11.44
Diluted net income (loss) from discontinued operations per share	$ (0.47)	$ 0.03	$ 0.03
Diluted net income per share	$ 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	12,632	12,939	12,441
Natural Gas [Member]
Oil and gas production revenues:
Revenues	2,627	2,969	3,405
Natural Gas Liquids Revenues [Member]
Oil and gas production revenues:
Revenues	$ 652	$ 520	$ 491

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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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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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CONSOLIDATED BALANCE SHEET (Unaudited) (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

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Supplemental Oil and Gas Disclosures - Costs Incurred in Oil and Gas Property Acquisitions, Exploration and Development Activities (Parenthetical) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 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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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	$ 560	$ 501	$ 430
Amortization of deferred loan costs	8	7	5
Capitalized interest	(364)	(323)	(251)
Gain on extinguishment of debt	(16)
Interest income	(11)	(13)	(12)
Financing costs, net	$ 177	$ 172	$ 172

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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	(50,544)	(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

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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 - 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

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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.

On March 12, 2014, Apache’s subsidiaries completed the sale of all of the Company’s operations in Argentina and as such the results of Argentina have been classified as discontinued operations.

	United States		Canada			Egypt(3)		Australia		North Sea		Other International			Total(3)(4)
	(In millions, except per boe)
2013
Oil and gas production revenues	$	6,902	$	1,224		$	3,917	$	1,140	$	2,728	$	—		$	15,911
Operating cost:
Depreciation, depletion, and amortization
Recurring(1)		2,227		426			881		361		999		—			4,894
Additional		552		—			—		—		367		76			995
Asset retirement obligation accretion		94		49			—		27		68		—			238
Lease operating expenses		1,320		459			471		214		400		—			2,864
Gathering and transportation		84		155			42		—		7		—			288
Production taxes(2)		324		40			—		14		382		—			760
Income tax		817		24			1,161		157		313		—			2,472
		5,418		1,153			2,555		773		2,536		76			12,511
Results of operation	$	1,484	$	71		$	1,362	$	367	$	192	$	(76	)	$	3,400
Amortization rate per boe	$	18.39	$	10.89		$	16.21	$	17.47	$	37.25	$	—		$	18.67
2012
Oil and gas production revenues	$	6,226	$	1,322		$	4,554	$	1,575	$	2,751	$	—		$	16,428
Operating cost:
Depreciation, depletion, and amortization
Recurring(1)		1,984		580			924		460		912		—			4,860
Additional		—		1,883			—		—		—		43			1,926
Asset retirement obligation accretion		112		41			—		17		58		—			228
Lease operating expenses		1,386		458			410		215		315		—			2,784
Gathering and transportation		69		163			39		—		24		—			295
Production taxes(2)		279		42			—		11		451		—			783
Income tax		851		(466	)		1,527		262		614		—			2,788
		4,681		2,701			2,900		965		2,374		43			13,664
Results of operation	$	1,545	$	(1,379	)	$	1,654	$	610	$	377	$	(43	)	$	2,764
Amortization rate per boe	$	17.24	$	11.66		$	13.81	$	17.67	$	32.65	$	—		$	17.18
2011
Oil and gas production revenues	$	6,104	$	1,617		$	4,791	$	1,734	$	2,091	$	—		$	16,337
Operating cost:
Depreciation, depletion, and amortization
Recurring(1)		1,634		537			818		435		405		—			3,829
Additional		—		—			—		—		—		109			109
Asset retirement obligation accretion		97		26			—		10		17		—			150
Lease operating expenses		1,167		470			398		197		208		—			2,440
Gathering and transportation		64		165			35		—		25		—			289
Production taxes(2)		255		44			—		9		538		—			846
Income tax		1,025		95			1,699		325		557		—			3,701
		4,242		1,337			2,950		976		1,750		109			11,364
Results of operation	$	1,862	$	280		$	1,841	$	758	$	341	$	(109	)	$	4,973
Amortization rate per boe	$	15.55	$	10.44		$	11.63	$	16.59	$	20.21	$	—		$	14.18

⁽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.

⁽⁴⁾  Amounts have been recast to exclude discontinued operations.

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	)		(50,544	)
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		Other International			Total(1)
	(In millions)
2013
Oil and gas production revenues(2)	$	6,902	$	1,224		$	3,917	$	1,140	$	2,728	$	—		$	15,911
Operating Expenses:
Depreciation, depletion, and amortization
Recurring		2,338		505			1,005		423		1,022		1			5,294
Additional		552		—			—		—		367		76			995
Asset retirement obligation accretion		94		49			—		27		68		—			238
Lease operating expenses		1,320		459			471		214		400		—			2,864
Gathering and transportation		84		155			42		—		7		—			288
Taxes other than income		335		45			8		13		384		—			785
Operating Income (Loss)(2)	$	2,179	$	11		$	2,391	$	463	$	480	$	(77	)		5,447
Other Income (Expense):
Derivative instrument gains (losses), net																(399	)
Other																48
General and administrative																(482	)
Acquisitions, divestitures, and transition																(33	)
Financing costs, net																(177	)
Net Income From Continuing Operations
Before Income Taxes(2)															$	4,404
Net Property and Equipment(2)	$	27,010	$	6,058		$	5,454	$	6,838	$	5,622	$	23		$	51,005
Total Assets(2)	$	29,940	$	6,952		$	8,121	$	8,094	$	6,902	$	51		$	60,060
Additions to Net Property and Equipment(2)	$	6,404	$	1,082		$	1,309	$	1,954	$	1,084	$	24		$	11,857
2012
Oil and gas production revenues(2)	$	6,226	$	1,322		$	4,554	$	1,575	$	2,751	$	—		$	16,428
Operating Expenses:
Depreciation, depletion, and amortization
Recurring		2,056		594			925		466		914		—			4,955
Additional		—		1,883			—		—		—		43			1,926
Asset retirement obligation accretion		112		41			—		17		58		—			228
Lease operating expenses		1,386		458			410		215		315		—			2,784
Gathering and transportation		69		163			39		—		24		—			295
Taxes other than income		292		50			14		11		451		—			818
Operating Income (Loss)(2)	$	2,311	$	(1,867	)	$	3,166	$	866	$	989	$	(43	)		5,422
Other Income (Expense):
Derivative instrument gains (losses), net																(79	)
Other																215
General and administrative																(515	)
Acquisitions, divestitures, and transition																(31	)
Financing costs, net																(172	)
Net Income From Continuing Operations
Before Income Taxes(2)															$	4,840
Net Property and Equipment(2)	$	28,552	$	6,640		$	5,151	$	5,312	$	5,927	$	77		$	51,659
Total Assets(2)	$	31,175	$	7,142		$	7,311	$	6,280	$	6,874	$	120		$	58,902
Additions to Net Property and Equipment(2)	$	9,586	$	1,096		$	1,153	$	1,581	$	1,104	$	98		$	14,618

	United States		Canada		Egypt		Australia		North Sea		Other International			Total
	(In millions)
2011
Oil and gas production revenues(2)	$	6,104	$	1,617	$	4,791	$	1,734	$	2,091	$	—		$	16,337
Operating Expenses:
Depreciation, depletion, and amortization
Recurring		1,684		546		818		440		409		—			3,897
Additional		—		—		—		—		—		109			109
Asset retirement obligation accretion		97		26		—		10		17		—			150
Lease operating expenses		1,167		470		398		197		208		—			2,440
Gathering and transportation		64		165		35		—		25		—			289
Taxes other than income		259		51		13		9		539		—			871
Operating Income (Loss)(2)	$	2,833	$	359	$	3,527	$	1,078	$	893	$	(109	)		8,581
Other Expense:
Other															114
General and administrative															(439	)
Acquisitions, divestitures, and transition															(20	)
Financing costs, net															(172	)
Net Income From Continuing Operations
Before Income Taxes(2)														$	8,064
Net Property and Equipment(2)	$	21,038	$	8,022	$	4,923	$	4,194	$	5,737	$	22		$	43,936
Total Assets(2)	$	23,499	$	8,816	$	6,656	$	4,681	$	6,600	$	33		$	50,285
Additions to Net Property and Equipment(2)	$	3,854	$	1,288	$	1,015	$	1,140	$	4,175	$	73		$	11,545

⁽¹⁾  2013 includes a noncontrolling interest in Egypt.

⁽²⁾  Amounts have been recast to exclude discontinued operations.

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

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		$	—	$	11,326		$	—		$	15,911
Equity in net income (loss) of affiliates		2,313			17		36			(2,366	)		—
Derivative instrument losses, net		(399	)		—		—			—			(399	)
Other		—			61		(9	)		(4	)		48
		6,499			78		11,353			(2,370	)		15,560
OPERATING EXPENSES:
Depreciation, depletion, and amortization		2,250			—		4,039			—			6,289
Asset retirement obligation accretion		67			—		171			—			238
Lease operating expenses		939			—		1,925			—			2,864
Gathering and transportation		61			—		227			—			288
Taxes other than income		190			—		595			—			785
General and administrative		408			—		78			(4	)		482
Acquisitions, divestitures, and transition		33			—		—			—			33
Financing costs, net		97			5		75			—			177
		4,045			5		7,110			(4	)		11,156
NET INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		2,454			73		4,243			(2,366	)		4,404
Provision for income taxes		222			20		1,682			—			1,924
NET INCOME (LOSS) FROM CONTINUING OPERATIONS INCLUDING NONCONTROLLING INTEREST		2,232			53		2,561			(2,366	)		2,480
Net loss from discontinued operations, net of tax		—			—		(192	)		—			(192	)
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTEREST		2,232			53		2,369			(2,366	)		2,288
Preferred stock dividends		44			—		—			—			44
Net income attributable to noncontrolling interest		—			—		56			—			56
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		$	—		$	12,191	$	—		$	16,428
Equity in net income (loss) of affiliates		1,523			(737	)		248		(1,034	)		—
Other		(80	)		69			151		(4	)		136
		5,680			(668	)		12,590		(1,038	)		16,564
OPERATING EXPENSES:
Depreciation, depletion, and amortization		1,391			—			5,490		—			6,881
Asset retirement obligation accretion		76			—			152		—			228
Lease operating expenses		957			—			1,827		—			2,784
Gathering and transportation		51			—			244		—			295
Taxes other than income		185			—			633		—			818
General and administrative		425			—			94		(4	)		515
Acquisitions, divestitures, and transition		25			—			6		—			31
Financing costs, net		94			(20	)		98		—			172
		3,204			(20	)		8,544		(4	)		11,724
NET INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		2,476			(648	)		4,046		(1,034	)		4,840
Provision (benefit) for income taxes		475			(159	)		2,537		—			2,853
NET INCOME (LOSS) FROM CONTINUING OPERATIONS INCLUDING NONCONTROLLING INTEREST		2,001			(489	)		1,509		(1,034	)		1,987
Net income from discontinued operations, net of tax		—			—			14		—			14
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTEREST		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	$	—		$	11,957		$	—		$	16,337
Equity in net income (loss) of affiliates		3,590		234			46			(3,870	)		—
Other		9		125			(16	)		(4	)		114
		7,979		359			11,987			(3,874	)		16,451
OPERATING EXPENSES:
Depreciation, depletion, and amortization		1,257		—			2,749			—			4,006
Asset retirement obligation accretion		70		—			80			—			150
Lease operating expenses		794		—			1,646			—			2,440
Gathering and transportation		51		—			238			—			289
Taxes other than income		170		—			701			—			871
General and administrative		365		—			78			(4	)		439
Acquisitions, divestitures, and transition		14		—			6			—			20
Financing costs, net		149		(18	)		41			—			172
		2,870		(18	)		5,539			(4	)		8,387
NET INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		5,109		377			6,448			(3,870	)		8,064
Provision for income taxes		525		97			2,870			—			3,492
NET INCOME (LOSS) FROM CONTINUING OPERATIONS INCLUDING NONCONTROLLING INTEREST		4,584		280			3,578			(3,870	)		4,572
Net income from discontinued operations, net of tax		—		—			12			—			12
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTEREST		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 CONTINUING OPERATING ACTIVITIES	$	1,421		$	315		$	7,867		$	—	$	9,603
CASH USED IN DISCONTINUED OPERATIONS		—			—			232			—		232
CASH PROVIDED BY OPERATING ACTIVITIES		1,421			315			8,099			—		9,835
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property		(4,291	)		—			(5,525	)		—		(9,816	)
Additions to gas gathering, transmission, and processing facilities		(124	)		—			(1,066	)		—		(1,190	)
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	)		—			(32	)		—		(90	)
NET CASH USED IN CONTINUING INVESTING ACTIVITIES		(771	)		—			(6,135	)		—		(6,906	)
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES		—			—			(210	)		—		(210	)
NET CASH USED IN INVESTING ACTIVITIES		(771	)		—			(6,345	)		—		(7,116	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Commercial paper, credit facility, and bank notes, net		(501	)		—			(8	)		—		(509	)
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 USED IN CONTINUING FINANCING ACTIVITIES		(495	)		(312	)		(162	)		—		(969	)
NET CASH USED IN DISCONTINUED OPERATIONS		—			—			(4	)		—		(4	)
NET CASH 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 (USED IN) CONTINUING OPERATING ACTIVITIES	$	2,357		$	(40	)	$	5,964		$	—		$	8,281
CASH PROVIDED BY DISCONTINUED OPERATIONS		—			—			223			—			223
CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES		2,357			(40	)		6,187			—			8,504
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property		(3,313	)		—			(5,166	)		—			(8,479	)
Additions to gas gathering, transmission, and processing facilities		(48	)		—			(685	)		—			(733	)
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	)		—			(105	)		—			(555	)
NET CASH PROVIDED BY (USED IN) CONTINUING INVESTING ACTIVITIES		(7,175	)		—			(6,579	)		657			(13,097	)
NET CASH USED IN DISCONTINUED OPERATIONS		—			—			(327	)		—			(327	)
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			—			9			—			511
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) CONTINUING FINANCING ACTIVITIES		4,777			35			592			(657	)		4,747
NET CASH PROVIDED BY DISCONTINUED OPERATIONS		—			—			38			—			38
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 CONTINUING OPERATING ACTIVITIES	$	2,191		$	13		$	7,503		$	—		$	9,707
CASH PROVIDED BY DISCONTINUED OPERATIONS		—			—			246			—			246
CASH PROVIDED BY OPERATING ACTIVITIES		2,191			13			7,749			—			9,953
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property		(1,478	)		—			(4,571	)		—			(6,049	)
Additions to gas gathering, transmission, and processing facilities		—			—			(652	)		—			(652	)
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	)		—			(81	)		—			(162	)
NET CASH USED IN CONTINUING INVESTING ACTIVITIES		(1,031	)		—			(6,451	)		(772	)		(8,254	)
NET CASH USED IN DISCONTINUED OPERATIONS		—			—			(391	)		—			(391	)
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	)		—			—			—			(927	)
Intercompany borrowings		—			(1	)		(763	)		764			—
Dividends paid		(306	)		—			—			—			(306	)
Other		108			(7	)		(41	)		8			68
NET CASH PROVIDED BY (USED IN) CONTINUING FINANCING ACTIVITIES		(1,125	)		(8	)		(804	)		772			(1,165	)
NET CASH PROVIDED BY DISCONTINUED OPERATIONS		—			—			18			—			18
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		(1,000	)		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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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
Environmental tax and royalty obligations		100,000,000				100,000,000
Retain right of obligations		67,500,000				67,500,000
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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STATEMENT OF CONSOLIDATED SHAREHOLDERS EQUITY (Unaudited) (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

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STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME (Unaudited) (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
Preferred stock dividends	44	76	76
Comprehensive income attributable to noncontrolling interest	56
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON STOCK	$ 2,204	$ 1,803	$ 4,640

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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 Benefits			Postretirement Benefits			Pension Benefits			Postretirement Benefits			Pension Benefits			Postretirement 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, outperformance relative to gilts is assumed to be 3.5 percent per year.

The following tables set forth the components of the net periodic cost and the underlying weighted average actuarial assumptions used for the pension and postretirement benefit plans as of December 31, 2013, 2012, and 2011:

	2013						2012						2011
	Pension Benefits			Postretirement Benefits			Pension Benefits			Postretirement Benefits			Pension Benefits			Postretirement Benefits
	(In millions)
Component of Net Periodic Benefit Costs
Service cost	$	5		$	4		$	5		$	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 Benefits		Postretirement 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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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	$ 541	$ 1,400

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Supplemental Oil and Gas Disclosures - Costs Incurred in Oil and Gas Property Acquisitions, Exploration and Development Activities (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 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

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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	$ 15,911	$ 16,428	$ 16,337
Depreciation, depletion, and amortization
Recurring	5,294	4,955	3,897
Additional	995	1,926	109
Asset retirement obligation accretion	238	228	150
Lease operating expenses	2,864	2,784	2,440
Gathering and transportation	288	295	289
Taxes other than income	785	818	871
Operating Income (Loss)	5,447	5,422	8,581
Other Expense:
Derivative instrument gains (losses), net	(399)	(79)
Other	48	215	114
General and administrative	(482)	(515)	(439)
Acquisitions, divestitures, and transition	(33)	(31)	(20)
Financing costs, net	(177)	(172)	(172)
INCOME BEFORE INCOME TAXES	4,404	4,840	8,064
Net Property and Equipment	52,421	53,280	43,936
Total Assets	61,637	60,737	50,285
Additions to Net Property and Equipment	11,857	14,618	11,545
United States [Member]
Segment Reporting Information [Line Items]
Oil and gas production revenues	6,902	6,226	6,104
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	2,833
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
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

XML

Document and Entity Information	12 Months Ended
	Dec. 31, 2013
Document And Entity Information [Abstract]
Document Type	8-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2013
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	FY
Entity Registrant Name	APACHE CORP
Entity Central Index Key	0000006769

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:
Income from continuing operations	$	2,380			395	$	6.02		$	1,911		389	$	4.91	$	4,496		384	$	11.72
Income (loss) from discontinued operations		(192	)		395		(0.49	)		14		389		0.04		12		384		0.03
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:
Income from continuing operations	$	2,424			406	$	5.97		$	1,911		391	$	4.89	$	4,572		400	$	11.44
Income (loss) from discontinued operations		(192	)		406		(0.47	)		14		391		0.03		12		400		0.03
Income attributable to common stock	$	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 through the date of the filing of the Previously Filed Annual Report 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		—			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 when fully executed 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 - 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

XML

Business Segment Information - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2013 Country
Segment Reporting [Abstract]
Production in number of countries	5

XML

STATEMENT OF CONSOLIDATED CASH FLOWS (Unaudited) (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:
Loss (income) from discontinued operations	192	(14)	(12)
Depreciation, depletion, and amortization	6,289	6,881	4,006
Asset retirement obligation accretion	238	228	150
Provision for deferred income taxes	261	654	1,244
Other	268	223	42
Changes in operating assets and liabilities:
Receivables	112	28	(736)
Inventories	(71)	(60)	(35)
Drilling advances	234	(343)	24
Deferred charges and other	(148)	41	31
Accounts payable	491	(84)	179
Accrued expenses	(566)	(1,133)	85
Deferred credits and noncurrent liabilities	15	(141)	145
NET CASH PROVIDED BY CONTINUING OPERATING ACTIVITIES	9,603	8,281	9,707
NET CASH PROVIDED BY DISCONTINUED OPERATIONS	232	223	246
NET CASH PROVIDED BY OPERATING ACTIVITIES	9,835	8,504	9,953
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property	(9,816)	(8,479)	(6,049)
Additions to gas gathering, transmission, and processing facilities	(1,190)	(733)	(652)
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	(90)	(555)	(162)
NET CASH PROVIDED BY (USED IN) CONTINUING INVESTING ACTIVITIES	(6,906)	(13,097)	(8,254)
NET CASH USED IN DISCONTINUED OPERATIONS	(210)	(327)	(391)
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	(509)	511	(927)
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)	68
NET CASH PROVIDED BY (USED IN) CONTINUING FINANCING ACTIVITIES	(969)	4,747	(1,165)
NET CASH PROVIDED BY (USED IN) DISCONTINUED OPERATIONS	(4)	38	18
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

XML

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		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

XML

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.

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.

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	$	3,946		$	4,268		$	3,900		$	3,446		$	15,560
Expenses(2)		3,168			3,231			3,464			3,217			13,080
Net income from continuing operations including noncontrolling interest		778			1,037			436			229			2,480
Net income (loss) from discontinued operations, net of tax		(61	)		(2	)		(130	)		1			(192	)
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
Basic net income per common share(1):
Net income from continuing operations	$	1.94		$	2.60		$	1.08		$	0.40		$	6.02
Net income (loss) from discontinued operations		(0.16	)		(0.01	)		(0.33	)		0.01			(0.49	)
Net income per share	$	1.78		$	2.59		$	0.75		$	0.41		$	5.53
Diluted net income per common share(1):
Net income from continuing operations	$	1.91		$	2.54		$	1.07		$	0.45		$	5.97
Net income (loss) from discontinued operations		(0.15	)		—			(0.32	)		—			(0.47	)
Net income per share	$	1.76		$	2.54		$	0.75		$	0.45		$	5.50
2012
Revenues and other	$	4,400		$	3,850		$	4,055		$	4,259		$	16,564
Expenses(2)		3,626			3,502			3,875			3,574			14,577
Net income from continuing operations including noncontrolling interest		774			348			180			685			1,987
Net income (loss) from discontinued operations, net of tax		23			8			—			(17	)		14
Net income including noncontrolling interest	$	797		$	356		$	180		$	668		$	2,001
Net income attributable to common stock	$	778		$	337		$	161		$	649		$	1,925
Basic net income per common share(1):
Net income from continuing operations	$	1.96		$	0.84		$	0.41		$	1.70		$	4.91
Net income (loss) from discontinued operations		0.06			0.03			—			(0.05	)		0.04
Net income per share	$	2.02		$	0.87		$	0.41		$	1.65		$	4.95
Diluted net income per common share(1):
Net income from continuing operations	$	1.94		$	0.84		$	0.41		$	1.70		$	4.89
Net income (loss) from discontinued operations		0.06			0.02			—			(0.05	)		0.03
Net income per share	$	2.00		$	0.86		$	0.41		$	1.65		$	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 $541 million, net of tax, in the U.S. and North Sea 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 - 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%

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INCOME TAXES

12 Months Ended

Dec. 31, 2013

Income Tax Disclosure [Abstract]

INCOME TAXES

7. INCOME TAXES

Income from continuing operations 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		3,213		3,235		5,691
Total	$	4,404	$	4,840	$	8,064

The total provision for income taxes from continuing operations consists of the following:

	For the Year Ended December 31,
	2013			2012			2011
	(In millions)
Current taxes:
Federal	$	(29	)	$	(150	)	$	64
State		—			—			2
Foreign		1,692			2,349			2,182
		1,663			2,199			2,248
Deferred taxes:
Federal		509			596			656
State		44			10			17
Foreign		(292	)		48			571
		261			654			1,244
Total	$	1,924		$	2,853		$	3,492

A reconciliation of the tax on the Company’s income from continuing operations 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	$	1,541		$	1,694		$	2,823
State income tax, less federal benefit		29			6			12
Taxes related to foreign operations		200			767			563
Tax credits		6			(4	)		(14	)
Deferred tax on distributed foreign earnings		225			—			—
Current and deferred taxes related to currency fluctuations		(144	)		26			(67	)
Change in U.K. tax rate		—			118			218
Net change in tax contingencies		(10	)		(115	)		(6	)
Valuation allowances		132			341			8
All other, net		(55	)		20			(45	)
	$	1,924		$	2,853		$	3,492

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, of which $69 million, $14 million, and none related to discontinued operations and is included in Net income (loss) from discontinued operations, net of tax.

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. On March 12, 2014, Apache completed the sale of its Argentina operations to YPF Sociedad Anónima. YPF Sociedad Anónima acquired all of Apache Argentina’s tax attributes, including $299 million of Argentina net operating losses.

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(1)	2006

⁽¹⁾  On March 12, 2014, Apache divested of its Argentina operations.

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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	3,213	3,235	5,691
INCOME BEFORE INCOME TAXES	$ 4,404	$ 4,840	$ 8,064

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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.

Accretion expense includes Argentina discontinued operations of $5 million and $4 million, respectively, for the years ended 2013 and 2012 and is included in Net income (loss) from discontinued operations, net of tax.

Additionally, accretion expense for the year ended 2011 included Argentina discontinued operations of $4 million, which is included in Net income (loss) from discontinued operations, net of tax.

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 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.

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		Fair		Carrying		Fair
	Amount		Value		Amount		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 $2 million was drawn on facilities in Canada and $51 million in Argentina, which was repaid in conjunction with the divestiture of our Argentine operations. As of December 31, 2012, a total of $22 million was drawn on facilities in the U.S. and Canada, and $69 million in Argentina.

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.

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.

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	$	560		$	501		$	430
Amortization of deferred loan costs		8			7			5
Capitalized interest		(364	)		(323	)		(251	)
Gain on extinguishment of debt		(16	)		—			—
Interest income		(11	)		(13	)		(12	)
Financing costs, net	$	177		$	172		$	172

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.

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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 and Argentine Tariff

On March 12, 2014, the Company and its subsidiaries completed the sale of all of the Company’s subsidiaries’ operations and properties in Argentina to YPF Sociedad Anonima (YPF). As part of that sale, YPF assumed responsibility for all of the past, present, and future litigation in Argentina involving Company subsidiaries, except that Company subsidiaries have agreed to indemnify YPF for certain environmental, tax, and royalty obligations capped at an aggregate of $100 million. The indemnity is subject to specific agreed conditions precedent, thresholds, contingencies, limitations, claim deadlines, loss sharing, and other terms and conditions. On April 11, 2014, YPF provided its first notice of claims pursuant to the indemnity. Company subsidiaries have not paid any amounts under the indemnity but will continue to review and consider claims presented by YPF. Further, Company subsidiaries retain the right to enforce certain Argentina-related indemnification obligations against Pioneer Natural Resources Company (Pioneer) up to $67.5 million pursuant to the terms and conditions of stock purchase agreements entered in 2006 between Company subsidiaries and Pioneer subsidiaries.

The litigation that YPF assumed responsibility for, as explained above, includes the previously-reported ASSUPA and Enargas matters:

In connection with the acquisition from 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, 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. 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 YPF may incur liabilities related to the environmental claims and then seek indemnity from Company subsidiaries as described above, no reasonable prediction can be made as the exposure related to these lawsuits is not currently determinable. Company subsidiaries reserve all rights.

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 the YPF-acquired Company affiliates in Argentina, totaled approximately $39.5 million at the time of the sale to YPF, of which $11 million had been paid. The YPF-acquired Company affiliates initiated legal proceedings in the Provinces of Neuquén and Tierra del Fuego challenging the Enargas tariff charge and obtained temporary injunctive relief that prohibits the collection of the charges pending final rulings on the merits of the legal challenges. It is possible YPF may incur liabilities related to the Enargas tariffs and then seek indemnity from Company subsidiaries as described above. Company subsidiaries reserve all rights.

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:

Net Minimum Commitments	Total		2014		2015-2016		2017-2018		2019 & 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 - 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
Discontinued Operations [Member]
Income Tax Contingency [Line Items]
Increase in valuation allowances		69,000,000	14,000,000
United States [Member]
Income Tax Contingency [Line Items]
Net operating losses		1,558,000,000
Mariner Energy Inc [Member]
Income Tax Contingency [Line Items]
Net operating losses		520,000,000
Cordillera Energy Partners [Member]
Income Tax Contingency [Line Items]
Net operating losses		183,000,000
Canada [Member]
Income Tax Contingency [Line Items]
Net operating losses		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
Argentina [Member]
Income Tax Contingency [Line Items]
Net operating losses		$ 299,000,000

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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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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

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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	$ 3,446	$ 3,900	$ 4,268	$ 3,946	$ 4,259	$ 4,055	$ 3,850	$ 4,400	$ 15,560	$ 16,564	$ 16,451	$ 16,564
Expenses	3,217	3,464	3,231	3,168	3,574	3,875	3,502	3,626	11,156	11,724	8,387	14,577
Net income from continuing operations including noncontrolling interest	229	436	1,037	778	685	180	348	774	2,480	1,987	4,572	1,987
Net income (loss) from discontinued operations, net of tax	1	(130)	(2)	(61)	(17)	0	8	23	(192)	14	12	14
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 net income per common share:
Net income from continuing operations	$ 0.40	$ 1.08	$ 2.60	$ 1.94	$ 1.70	$ 0.41	$ 0.84	$ 1.96	$ 6.02	$ 4.91	$ 11.72	$ 4.91
Net income (loss) from discontinued operations	$ 0.01	$ (0.33)	$ (0.01)	$ (0.16)	$ (0.05)		$ 0.03	$ 0.06	$ (0.49)	$ 0.04	$ 0.03	$ 0.04
Net income per share	$ 0.41	$ 0.75	$ 2.59	$ 1.78	$ 1.65	$ 0.41	$ 0.87	$ 2.02	$ 5.53	$ 4.95	$ 11.75	$ 4.95
Diluted net income per common share:
Net income from continuing operations	$ 0.45	$ 1.08	$ 2.54	$ 1.91	$ 1.70	$ 0.41	$ 0.84	$ 1.94	$ 5.97	$ 4.89	$ 11.44	$ 4.89
Net income (loss) from discontinued operations		$ (0.33)		$ (0.15)	$ (0.05)		$ 0.02	$ 0.06	$ (0.47)	$ 0.03	$ 0.03	$ 0.03
Net income per share	$ 0.45	$ 0.75	$ 2.54	$ 1.76	$ 1.65	$ 0.41	$ 0.86	$ 2.00	$ 5.50	$ 4.92	$ 11.47	$ 4.92

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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

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Supplemental Oil and Gas Disclosures - Revenue and Direct Cost Information Relating to Company's Oil and Gas Exploration and Production Activities (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 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	$ 15,911	$ 16,428	$ 16,337
Depreciation, depletion, and amortization
Recurring	4,894	4,860	3,829
Additional	995	1,926	109
Asset retirement obligation accretion	238	228	150
Lease operating expenses	2,864	2,784	2,440
Gathering and transportation	288	295	289
Production taxes	760	783	846
Income tax	2,472	2,788	3,701
Oil and gas properties production expense	12,511	13,664	11,364
Results of operation	3,400	2,764	4,973
Amortization rate per boe	18.67	17.18	14.18
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	6,104
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	1,862
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
Other International [Member]
Depreciation, depletion, and amortization
Additional	76	43	109
Oil and gas properties production expense	76	43	109
Results of operation	$ (76)	$ (43)	$ (109)

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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:
Income from continuing operations	$	2,380			395	$	6.02		$	1,911		389	$	4.91	$	4,496		384	$	11.72
Income (loss) from discontinued operations		(192	)		395		(0.49	)		14		389		0.04		12		384		0.03
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:
Income from continuing operations	$	2,424			406	$	5.97		$	1,911		391	$	4.89	$	4,572		400	$	11.44
Income (loss) from discontinued operations		(192	)		406		(0.47	)		14		391		0.03		12		400		0.03
Income attributable to common stock	$	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		—			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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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

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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 five countries: the United States, Canada, Egypt, Australia, and the U.K. North Sea. 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		Other International			Total(1)
	(In millions)
2013
Oil and gas production revenues(2)	$	6,902	$	1,224		$	3,917	$	1,140	$	2,728	$	—		$	15,911
Operating Expenses:
Depreciation, depletion, and amortization
Recurring		2,338		505			1,005		423		1,022		1			5,294
Additional		552		—			—		—		367		76			995
Asset retirement obligation accretion		94		49			—		27		68		—			238
Lease operating expenses		1,320		459			471		214		400		—			2,864
Gathering and transportation		84		155			42		—		7		—			288
Taxes other than income		335		45			8		13		384		—			785
Operating Income (Loss)(2)	$	2,179	$	11		$	2,391	$	463	$	480	$	(77	)		5,447
Other Income (Expense):
Derivative instrument gains (losses), net																(399	)
Other																48
General and administrative																(482	)
Acquisitions, divestitures, and transition																(33	)
Financing costs, net																(177	)
Net Income From Continuing Operations
Before Income Taxes(2)															$	4,404
Net Property and Equipment(2)	$	27,010	$	6,058		$	5,454	$	6,838	$	5,622	$	23		$	51,005
Total Assets(2)	$	29,940	$	6,952		$	8,121	$	8,094	$	6,902	$	51		$	60,060
Additions to Net Property and Equipment(2)	$	6,404	$	1,082		$	1,309	$	1,954	$	1,084	$	24		$	11,857
2012
Oil and gas production revenues(2)	$	6,226	$	1,322		$	4,554	$	1,575	$	2,751	$	—		$	16,428
Operating Expenses:
Depreciation, depletion, and amortization
Recurring		2,056		594			925		466		914		—			4,955
Additional		—		1,883			—		—		—		43			1,926
Asset retirement obligation accretion		112		41			—		17		58		—			228
Lease operating expenses		1,386		458			410		215		315		—			2,784
Gathering and transportation		69		163			39		—		24		—			295
Taxes other than income		292		50			14		11		451		—			818
Operating Income (Loss)(2)	$	2,311	$	(1,867	)	$	3,166	$	866	$	989	$	(43	)		5,422
Other Income (Expense):
Derivative instrument gains (losses), net																(79	)
Other																215
General and administrative																(515	)
Acquisitions, divestitures, and transition																(31	)
Financing costs, net																(172	)
Net Income From Continuing Operations
Before Income Taxes(2)															$	4,840
Net Property and Equipment(2)	$	28,552	$	6,640		$	5,151	$	5,312	$	5,927	$	77		$	51,659
Total Assets(2)	$	31,175	$	7,142		$	7,311	$	6,280	$	6,874	$	120		$	58,902
Additions to Net Property and Equipment(2)	$	9,586	$	1,096		$	1,153	$	1,581	$	1,104	$	98		$	14,618

	United States		Canada		Egypt		Australia		North Sea		Other International			Total
	(In millions)
2011
Oil and gas production revenues(2)	$	6,104	$	1,617	$	4,791	$	1,734	$	2,091	$	—		$	16,337
Operating Expenses:
Depreciation, depletion, and amortization
Recurring		1,684		546		818		440		409		—			3,897
Additional		—		—		—		—		—		109			109
Asset retirement obligation accretion		97		26		—		10		17		—			150
Lease operating expenses		1,167		470		398		197		208		—			2,440
Gathering and transportation		64		165		35		—		25		—			289
Taxes other than income		259		51		13		9		539		—			871
Operating Income (Loss)(2)	$	2,833	$	359	$	3,527	$	1,078	$	893	$	(109	)		8,581
Other Expense:
Other															114
General and administrative															(439	)
Acquisitions, divestitures, and transition															(20	)
Financing costs, net															(172	)
Net Income From Continuing Operations
Before Income Taxes(2)														$	8,064
Net Property and Equipment(2)	$	21,038	$	8,022	$	4,923	$	4,194	$	5,737	$	22		$	43,936
Total Assets(2)	$	23,499	$	8,816	$	6,656	$	4,681	$	6,600	$	33		$	50,285
Additions to Net Property and Equipment(2)	$	3,854	$	1,288	$	1,015	$	1,140	$	4,175	$	73		$	11,545

⁽¹⁾  2013 includes a noncontrolling interest in Egypt.

⁽²⁾  Amounts have been recast to exclude discontinued operations.

XML

ACQUISITIONS AND DIVESTITURES (Tables)

12 Months Ended

Dec. 31, 2013

Summary of Carrying Amount of Major Assets and Liabilities Associated with Disposition

The carrying amounts of the major classes of assets and liabilities associated with the disposition were as follows:

	December 31,
	2013		2012
	(In millions)
ASSETS
Current assets	$	150	$	174
Net property and equipment		1,416		1,621
Other assets		12		40
Total assets	$	1,578	$	1,835
LIABILITIES
Current debt	$	51	$	69
Other current liabilities		95		105
Asset retirement obligations		91		83
Other long-term liabilities		21		39
Total liabilities	$	258	$	296

Summary of Sales and Other Operating Revenue and Loss from Discontinued Operation Related to Disposition

Sales and other operating revenues and loss from discontinued operations related to the Argentina disposition were as follows:

	For the Year Ended December 31,
	2013			2012		2011
	(In millions)
Revenues and other from discontinued operations	$	494		$	514	$	437
Income (loss) from discontinued operations, net of tax	$	(192	)	$	14	$	12

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.

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

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

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									$ 15,911	$ 16,428	$ 16,337
Derivative instrument losses, net									(399)	(79)
Other									48	215	114
Total revenues and other	3,446	3,900	4,268	3,946	4,259	4,055	3,850	4,400	15,560	16,564	16,451	16,564
OPERATING EXPENSES:
Depreciation, depletion, and amortization									6,289	6,881	4,006
Asset retirement obligation accretion									238	228	150
Lease operating expenses									2,864	2,784	2,440
Gathering and transportation									288	295	289
Taxes other than income									785	818	871
General and administrative									482	515	439
Acquisitions, divestitures, and transition									33	31	20
Financing costs, net									177	172	172
Total operating expenses	3,217	3,464	3,231	3,168	3,574	3,875	3,502	3,626	11,156	11,724	8,387	14,577
NET INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES									4,404	4,840	8,064
Provision (benefit) for income taxes									1,924	2,853	3,492
NET INCOME (LOSS) FROM CONTINUING OPERATIONS INCLUDING NONCONTROLLING INTEREST	229	436	1,037	778	685	180	348	774	2,480	1,987	4,572	1,987
Net income from discontinued operations, net of tax	1	(130)	(2)	(61)	(17)	0	8	23	(192)	14	12	14
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTEREST	230	306	1,035	717	668	180	356	797	2,288	2,001	4,584	2,001
Preferred stock dividends									44	76	76
Net income attributable to non controlling interest									56
Income 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 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
NET INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES									2,454	2,476	5,109
Provision (benefit) for income taxes									222	475	525
NET INCOME (LOSS) FROM CONTINUING OPERATIONS INCLUDING NONCONTROLLING INTEREST									2,232	2,001	4,584
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTEREST									2,232	2,001	4,584
Preferred stock dividends									44	76	76
Income 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)
NET INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES									73	(648)	377
Provision (benefit) for income taxes									20	(159)	97
NET INCOME (LOSS) FROM CONTINUING OPERATIONS INCLUDING NONCONTROLLING INTEREST									53	(489)	280
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTEREST									53	(489)	280
Income 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									11,326	12,191	11,957
Equity in net income (loss) of affiliates									36	248	46
Other									(9)	151	(16)
Total revenues and other									11,353	12,590	11,987
OPERATING EXPENSES:
Depreciation, depletion, and amortization									4,039	5,490	2,749
Asset retirement obligation accretion									171	152	80
Lease operating expenses									1,925	1,827	1,646
Gathering and transportation									227	244	238
Taxes other than income									595	633	701
General and administrative									78	94	78
Acquisitions, divestitures, and transition										6	6
Financing costs, net									75	98	41
Total operating expenses									7,110	8,544	5,539
NET INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES									4,243	4,046	6,448
Provision (benefit) for income taxes									1,682	2,537	2,870
NET INCOME (LOSS) FROM CONTINUING OPERATIONS INCLUDING NONCONTROLLING INTEREST									2,561	1,509	3,578
Net income from discontinued operations, net of tax									(192)	14	12
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTEREST									2,369	1,523	3,590
Net income attributable to non controlling interest									56
Income 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)
NET INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES									(2,366)	(1,034)	(3,870)
NET INCOME (LOSS) FROM CONTINUING OPERATIONS INCLUDING NONCONTROLLING INTEREST									(2,366)	(1,034)	(3,870)
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTEREST									(2,366)	(1,034)	(3,870)
Income attributable to common stock									(2,366)	(1,034)	(3,870)
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK									$ (2,366)	$ (1,034)	$ (3,870)

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

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 current assets	6,366	4,962
PROPERTY AND EQUIPMENT, NET	52,421	53,280	43,936
OTHER ASSETS:
Goodwill, net	1,369	1,289
Deferred charges and other	1,481	1,206
Total assets	61,637	60,737	50,285
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 current 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 current 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 current 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 current 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

CONSOLIDATED BALANCE SHEET (Unaudited) (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 current 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

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)

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. 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. In March 2014, Apache’s subsidiaries closed the sale of Argentina, and as a result, Apache classified the results of operations related to Argentina as discontinued operations.

The carrying amounts of the major classes of assets and liabilities associated with the disposition were as follows:

	December 31,
	2013		2012
	(In millions)
ASSETS
Current assets	$	150	$	174
Net property and equipment		1,416		1,621
Other assets		12		40
Total assets	$	1,578	$	1,835
LIABILITIES
Current debt	$	51	$	69
Other current liabilities		95		105
Asset retirement obligations		91		83
Other long-term liabilities		21		39
Total liabilities	$	258	$	296

Sales and other operating revenues and loss from discontinued operations related to the Argentina disposition were as follows:

	For the Year Ended December 31,
	2013			2012		2011
	(In millions)
Revenues and other from discontinued operations	$	494		$	514	$	437
Income (loss) from discontinued operations, net of tax	$	(192	)	$	14	$	12

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

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

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 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) CONTINUING OPERATING ACTIVITIES	$ 9,603	$ 8,281	$ 9,707
CASH PROVIDED BY DISCONTINUED OPERATIONS	232	223	246
CASH PROVIDED BY OPERATING ACTIVITIES	9,835	8,504	9,953
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property	(9,816)	(8,479)	(6,049)
Additions to gas gathering, transmission, and processing facilities	(1,190)	(733)	(652)
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	(90)	(555)	(162)
NET CASH PROVIDED BY (USED IN) CONTINUING INVESTING ACTIVITIES	(6,906)	(13,097)	(8,254)
NET CASH USED IN DISCONTINUED OPERATIONS	(210)	(327)	(391)
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	(509)	511	(927)
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)	68
NET CASH PROVIDED BY (USED IN) CONTINUING FINANCING ACTIVITIES	(969)	4,747	(1,165)
NET CASH PROVIDED BY DISCONTINUED OPERATIONS	(4)	38	18
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) CONTINUING OPERATING ACTIVITIES	1,421	2,357	2,191
CASH PROVIDED BY 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) CONTINUING INVESTING ACTIVITIES	(771)	(7,175)	(1,031)
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) CONTINUING FINANCING ACTIVITIES	(495)	4,777	(1,125)
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) CONTINUING OPERATING ACTIVITIES	315	(40)	13
CASH PROVIDED BY 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) CONTINUING FINANCING ACTIVITIES	(312)	35	(8)
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) CONTINUING OPERATING ACTIVITIES	7,867	5,964	7,503
CASH PROVIDED BY DISCONTINUED OPERATIONS	232	223	246
CASH PROVIDED BY OPERATING ACTIVITIES	8,099	6,187	7,749
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property	(5,525)	(5,166)	(4,571)
Additions to gas gathering, transmission, and processing facilities	(1,066)	(685)	(652)
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	(32)	(105)	(81)
NET CASH PROVIDED BY (USED IN) CONTINUING INVESTING ACTIVITIES	(6,135)	(6,579)	(6,451)
NET CASH USED IN DISCONTINUED OPERATIONS	(210)	(327)	(391)
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	(8)	9
Intercompany borrowings	(3,057)	697	(763)
Proceeds from sale of noncontrolling interest	2,948
Other	(45)	(114)	(41)
NET CASH PROVIDED BY (USED IN) CONTINUING FINANCING ACTIVITIES	(162)	592	(804)
NET CASH PROVIDED BY DISCONTINUED OPERATIONS	(4)	38	18
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) CONTINUING INVESTING ACTIVITIES		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) CONTINUING FINANCING ACTIVITIES		(657)	(772)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		$ (657)	$ 772

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

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 - 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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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	$	3,946		$	4,268		$	3,900		$	3,446		$	15,560
Expenses(2)		3,168			3,231			3,464			3,217			13,080
Net income from continuing operations including noncontrolling interest		778			1,037			436			229			2,480
Net income (loss) from discontinued operations, net of tax		(61	)		(2	)		(130	)		1			(192	)
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
Basic net income per common share(1):
Net income from continuing operations	$	1.94		$	2.60		$	1.08		$	0.40		$	6.02
Net income (loss) from discontinued operations		(0.16	)		(0.01	)		(0.33	)		0.01			(0.49	)
Net income per share	$	1.78		$	2.59		$	0.75		$	0.41		$	5.53
Diluted net income per common share(1):
Net income from continuing operations	$	1.91		$	2.54		$	1.07		$	0.45		$	5.97
Net income (loss) from discontinued operations		(0.15	)		—			(0.32	)		—			(0.47	)
Net income per share	$	1.76		$	2.54		$	0.75		$	0.45		$	5.50
2012
Revenues and other	$	4,400		$	3,850		$	4,055		$	4,259		$	16,564
Expenses(2)		3,626			3,502			3,875			3,574			14,577
Net income from continuing operations including noncontrolling interest		774			348			180			685			1,987
Net income (loss) from discontinued operations, net of tax		23			8			—			(17	)		14
Net income including noncontrolling interest	$	797		$	356		$	180		$	668		$	2,001
Net income attributable to common stock	$	778		$	337		$	161		$	649		$	1,925
Basic net income per common share(1):
Net income from continuing operations	$	1.96		$	0.84		$	0.41		$	1.70		$	4.91
Net income (loss) from discontinued operations		0.06			0.03			—			(0.05	)		0.04
Net income per share	$	2.02		$	0.87		$	0.41		$	1.65		$	4.95
Diluted net income per common share(1):
Net income from continuing operations	$	1.94		$	0.84		$	0.41		$	1.70		$	4.89
Net income (loss) from discontinued operations		0.06			0.02			—			(0.05	)		0.03
Net income per share	$	2.00		$	0.86		$	0.41		$	1.65		$	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 $541 million, net of tax, in the U.S. and North Sea 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 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