10-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2016

or

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

For the transition period from                  to                 

Commission file number 1-4300

APACHE CORPORATION

(Exact name of registrant as specified in its charter)

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

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

(Address of principal executive offices)

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

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

Title of each class	Name of each exchange on which registered
Common Stock, $0.625 par value	New York Stock Exchange, Chicago Stock Exchange and NASDAQ Global Select Market
Apache Finance Canada Corporation 7.75% Notes Due 2029 Irrevocably and Unconditionally Guaranteed by Apache Corporation	New York Stock Exchange

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

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

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes [   ] No [X]

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

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. Large accelerated filer [X] Accelerated filer[   ] Non-accelerated filer[   ] Smaller reporting company [   ]

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

Aggregate market value of the voting and non-voting common equity held by non-affiliates of registrant as of June 30, 2016	$	21,118,858,691
Number of shares of registrant’s common stock outstanding as of January 31, 2017	379,687,129

Documents Incorporated By Reference

Portions of registrant’s proxy statement relating to registrant’s 2017 annual meeting of stockholders have been incorporated by reference in Part II and Part III of this annual report on Form 10-K.

TABLE OF CONTENTS

DESCRIPTION

Item		Page
	PART I
1.	BUSINESS	1
1A.	RISK FACTORS	14
1B.	UNRESOLVED STAFF COMMENTS	23
2.	PROPERTIES	1
3.	LEGAL PROCEEDINGS	23
4.	MINE SAFETY DISCLOSURES	23
	PART II
5.	MARKET FOR THE REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER  MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES	24
6.	SELECTED FINANCIAL DATA	26
7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	27
7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	47
8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	48
9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	48
9A.	CONTROLS AND PROCEDURES	48
9B.	OTHER INFORMATION	48
	PART III
10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	49
11.	EXECUTIVE COMPENSATION	49
12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	49
13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	49
14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	49
	PART IV
15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	50
16.	FORM 10-K SUMMARY	50

i

FORWARD-LOOKING STATEMENTS AND RISK

This Annual Report on Form 10-K 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, 2016, and other data in our possession or available from third parties. In addition, forward-looking statements generally can be identified by the use of forward-looking terminology such as “may,” “will,” “could,” “expect,” “intend,” “project,” “estimate,” “anticipate,” “plan,” “believe,” or “continue” or similar terminology. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to have been correct. Important factors that could cause actual results to differ materially from our expectations include, but are not limited to, our assumptions about:

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

• our commodity hedging arrangements;

• the 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, regulatory, or policy changes;

• terrorism or cyber attacks;

• occurrence of property acquisitions or divestitures;

• the integration of acquisitions;

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

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

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

ii

DEFINITIONS

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

“3-D” means three-dimensional.

“4-D” means four-dimensional.

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

“bbl” or “bbls” means barrel or barrels of oil or natural gas liquids.

“bcf” means billion cubic feet of natural gas.

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

“boe/d” means boe per day.

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

“Liquids” means oil and natural gas liquids.

“LNG” means liquefied natural gas.

“Mb/d” means Mbbls per day.

“Mbbls” means thousand barrels of oil or natural gas liquids.

“Mboe” means thousand boe.

“Mboe/d” means Mboe per day.

“Mcf” means thousand cubic feet of natural gas.

“Mcf/d” means Mcf per day.

“MMbbls” means million barrels of oil or natural gas liquids.

“MMboe” means million boe.

“MMBtu” means million Btu.

“MMBtu/d” means MMBtu per day.

“MMcf” means million cubic feet of natural gas.

“MMcf/d” means MMcf per day.

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

“NYMEX” means New York Mercantile Exchange.

“oil” includes crude oil and condensate.

“PUD” means proved undeveloped.

“SEC” means United States Securities and Exchange Commission.

“Tcf” means trillion cubic feet of natural gas.

“U.K.” means United Kingdom.

“U.S.” means United States.

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

iii

PART I

ITEMS 1 and 2. BUSINESS AND PROPERTIES

General

Apache Corporation, a Delaware corporation formed in 1954, is an independent energy company that explores for, develops, and produces natural gas, crude oil, and natural gas liquids. Apache currently has exploration and production operations in four geographic areas: the United States (U.S.), Canada, Egypt, and offshore the United Kingdom (U.K.) in the North Sea. Apache also has exploration interests in Suriname that may, over time, result in a reportable discovery and development opportunity.

Our common stock, par value $0.625 per share, has been listed on the New York Stock Exchange (NYSE) since 1969, on the Chicago Stock Exchange (CHX) since 1960, and on the NASDAQ Global Select Market (NASDAQ) since 2004. On May 31, 2016, we filed certifications of our compliance with the listing standards of the NYSE and the NASDAQ, including our principal executive officer’s certification of compliance with the NYSE standards. Through our website, www.apachecorp.com, you can access, free of charge, electronic copies of the charters of the committees of our Board of Directors, other documents related to our corporate governance (including our Code of Business Conduct and Governance Principles), and documents we file with the SEC, including our annual reports on Form 10-K, quarterly reports on Form 10-Q, and current reports on Form 8-K, as well as any amendments to these reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934. Included in our annual and quarterly reports are the certifications of our principal executive officer and our principal financial officer that are required by applicable laws and regulations. Access to these electronic filings is available as soon as reasonably practicable after we file such material with, or furnish it to, the SEC. You may also request printed copies of our corporate charter, bylaws, committee charters, or other governance documents free of charge by writing to our corporate secretary at the address on the cover of this report. Our reports filed with the SEC are made available to read and copy at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C., 20549. You may obtain information about the Public Reference Room by contacting the SEC at 1-800-SEC-0330. Reports filed with the SEC are also made available on its website at www.sec.gov. From time to time, we also post announcements, updates, and investor information on our website in addition to copies of all recent press releases. Information on our website or any other website is not incorporated by reference into, and does not constitute a part of, this Annual Report on Form 10-K.

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

During the second quarter of 2016, Apache changed its method of accounting for its oil and gas exploration and development activities from the full cost method to the successful efforts method of accounting. Financial information for all periods has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1—Summary of Significant Accounting Policies of the Notes to Consolidated Financial Statements under Part IV, Item 15 of this Form 10-K.

During 2015, Apache sold its Australia LNG business and oil and gas assets. During 2014, Apache sold its operations in Argentina. Results of operations and cash flows from operations for Argentina and Australia are reflected as discontinued operations in the Company’s financial statements for all periods presented. Certain historical information has been recast to reflect the results of operations for Argentina and Australia as discontinued operations.

Business Strategy

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

• rigorous portfolio management

• conservative capital structure

• optimization of returns

Rigorous management of the Company’s asset portfolio plays a key role in optimizing shareholder value over the long-term. The Company has monetized certain capital intensive projects that were not accretive to earnings in the near-term and other non-strategic assets. These divestitures over the past few years included selling Apache’s interest in LNG projects in Australia and Canada, all of its exploration and production operations in Australia and Argentina, mature assets offshore in the Gulf of Mexico, and various leasehold areas in North America onshore plays where the Company made strategic decisions to allocate resources to other, more impactful development opportunities.

1

Preserving financial flexibility is also key to the Company’s business philosophy. In response to the significant decline in commodity prices that began in 2014, Apache immediately took proactive measures to reduce activity levels and bring costs in alignment with activity levels, while taking concrete steps to cut overhead, operating, and drilling costs. The Company allocated a portion of its reduced overall capital spend in North America for strategic testing and completion optimization, which resulted in significant expansion of our economic drilling inventory and improved well performance. In addition, the Company completed confirmation testing and initiated a delineation program that confirmed a significant exploration discovery in the Delaware Basin, “Alpine High.”

For a more in-depth discussion of the Company’s Alpine High discovery, please refer to the Permian region discussion. For a more in-depth discussion of the Company’s divestitures, strategy, 2016 results, and its capital resources and liquidity, please see Part II, Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations of this Form 10-K.

Geographic Area Overviews

Apache has exploration and production interests in four geographic areas: the United States (U.S.), Canada, Egypt, and the United Kingdom (U.K.) North Sea. Apache also has exploration interests in Suriname that may, over time, result in a reportable discovery and development opportunity.

The following table sets out a brief comparative summary of certain key 2016 data for each of Apache’s operating areas. Additional data and discussion is provided in Part II, Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations of this Form 10-K.

	Production	Percentage of Total Production		Production Revenue		Year-End Estimated Proved Reserves	Percentage of Total Estimated Proved Reserves		Gross Wells Drilled	Gross Productive Wells Drilled
	(In MMboe)			(In millions)		(In MMboe)
United States	82.0	43	%	$	1,997	733	56	%	168	161
Canada	21.7	11		343		175	13		17	15
Total North America	103.7	54		2,340		908	69		185	176
Egypt(1)	62.3	33		2,057		280	21		61	54
North Sea(2)	25.0	13		970		123	10		14	10
Total International	87.3	46		3,027		403	31		75	64
Total	191.0	100	%	$	5,367	1,311	100	%	260	240

(1) Apache's operations in Egypt, excluding a one-third noncontrolling interest, contributed 24 percent of 2016 production and accounted for 15 percent of year-end estimated proved reserves and 28 percent of estimated discounted future net cash flows.

(2) Average sales volumes from the North Sea for 2016 were 24.5 MMboe. Sales volumes may vary from production volumes as a result of the timing of liftings in the Beryl field.

North America

In 2016, Apache’s North American operations contributed approximately 54 percent of production and 69 percent of estimated year-end proved reserves. Apache has access to significant liquid hydrocarbons across its 11.3 million gross acres in North America, 59 percent of which is undeveloped.

2

In North America Apache has three onshore regions:

• The Permian region located in West Texas and New Mexico includes the Permian sub-basins, the Midland Basin, Central Basin Platform/Northwest Shelf, and Delaware Basin. Examples of shale plays within this region include the Woodford, Barnett, Pennsylvanian, Cline, Wolfcamp, Bone Spring, and Spraberry.

• The Midcontinent/Gulf Coast region (formerly Gulf Coast and Central regions) includes the Granite Wash, Tonkawa, Canyon Lime, Marmaton, and Cleveland formations of the West Anadarko Basin, the Woodford-SCOOP and Stack plays located in Central Oklahoma, and the Eagle Ford shale in South East Texas.

• The Canada region has exploration and production operations in the provinces of British Columbia, Alberta, and Saskatchewan. Current drilling activities are primarily focused in the Duvernay and Montney shale plays.

Apache also has one offshore region in North America, the Gulf of Mexico region, which consists of both shallow and deep water exploration and production activities.

Permian Region The Permian region is one of Apache’s core growth areas. Highlights of the Company’s operations in the region include:

• Over 3.1 million gross acres with exposure to numerous plays focused primarily in the Midland Basin, the Central Basin Platform/Northwest Shelf, and the Delaware Basin.

• Estimated proved reserves of 611 MMboe at year-end 2016, representing 47 percent of the Company’s worldwide reserves.

• Annual production decline of only 4 percent, despite operating an average rig count of 5, down from 12 rigs in 2015 and 40 rigs in 2014. The reduced rig count reflected the Company’s decisive action to curtail capital spending in response to continued weakness in commodity prices until commodity prices and costs come into better equilibrium.

• In 2016, the Permian region drilled or participated in 132 wells, 96 of which were horizontal, with a 96 percent success rate.

In September 2016, after more than two years of extensive geological and geophysical work, methodical acreage accumulation, and strategic testing and delineation drilling, Apache announced the discovery of a significant new resource play, “Alpine High.” Apache’s Alpine High acreage lies in the southern portion of the Delaware Basin, primarily in Reeves County, Texas. The Company has established an acreage position of over 320,000 contiguous net acres, which it acquired at an attractive average cost of approximately $1,300 per acre. Since first announcing the Alpine High last September, the Company has made substantial progress further delineating the opportunity. The Company has confirmed an extensive play fairway which spans 55 miles and a 5,000-foot vertical column encompassing five geologic formations, with multiple target zones spanning the hydrocarbon phase window from dry gas to wet gas to oil. We have recently identified an additional landing zone in the Woodford formation, and confirmed production from the Pennsylvanian. Based on these results, Apache now believes the drilling locations at Alpine High will exceed the 2,000 to 3,000 previously announced. During 2017, we expect to average 4 to 6 drilling rigs at Alpine High. A second hydraulic fracturing crew was added at the start of the year to accelerate completions and data collection. Using data collected from strategic testing and delineation drilling, the Company is now beginning to optimize wells drilled in Alpine High using customized targeting, larger fracs, and longer laterals. Combined with multi-well pad drilling, the Company believes these measures contribute to the optimized development of the area to maximize economic value. The field is expected to have low levels of water production which will also have a positive impact on long-term economics. We are currently installing the infrastructure, which will allow gas sales from the field around mid-year 2017.

In addition to activity in Alpine High, the Permian region drilled or participated in over 110 wells in 2016, with a 100 percent success rate. In the Midland Basin, where Apache holds approximately 443,000 net acres, activity was focused on stratigraphic and development pad drilling of the Wolfcamp and Spraberry shale formations in the Wildfire, Powell, and Azalea areas. Activity in Midland Basin has been significantly increased in 2017: the region has increased the rig count to five, compared to an average of one in 2016. The additional rigs will be dedicated to long-term pad development drilling. The Company’s assets in the Central Basin Platform/Northwest Shelf span 739,000 net acres. The Yeso play was the primary focus of 2016 development activities in this area. In the Delaware Basin, Apache holds approximately 392,000 net acres. In addition to drilling and development activities at Alpine High, the Company targeted plays in the Bone Spring and Wolfcamp plays.

3

Apache plans to significantly increase activity in the Permian region during 2017, while continuing to balance capital investments between its larger development project at Alpine High and focused exploration and development programs on other core assets in its Permian region. During 2017, the Company expects to average 15 drilling rigs in the Permian Basin and drill approximately 250 wells, which includes a four to six rig delineation drilling program at Alpine High. The Company plans to allocate approximately two-thirds of its 2017 capital budget to the Permian region.

Midcontinent/Gulf Coast Region As part of Apache’s 2015 strategic efforts to reduce its operating cost structure, the Company combined the Midcontinent (formerly Central region) and Gulf Coast regions. Apache’s Midcontinent/Gulf Coast region includes 2.6 million gross acres and over 3,200 producing wells primarily in western Oklahoma, the Texas Panhandle and south Texas. In 2016, the region accounted for 11 percent of the Company’s production and approximately 9 percent of the Company’s year-end estimated proved reserves.

In 2016, Apache drilled or participated in drilling 35 wells with a 94 percent success rate. Activity was focused primarily in the Woodford-SCOOP and Canyon Lime formations. In 2017, Apache plans to run a targeted program, drilling four wells in the Woodford-SCOOP play. In addition, the region will continue its focus on high grading acreage and building its inventory of future drilling locations.

Canada Region Apache holds 3.5 million gross acres across the provinces of British Columbia, Alberta, and Saskatchewan. The region’s large acreage position provides significant drilling opportunities and portfolio diversification with exposure to oil, gas, and liquids rich fairways. The Canadian region provided approximately 11 percent of Apache’s 2016 worldwide production and 175 MMboe of estimated proved reserves at year-end.

In 2016, Apache drilled or participated in drilling 17 wells in the region with an 88 percent success rate. Drilling operations primarily focused on the Wapiti Montney, Ante Creek Montney, Duvernay, and Glauconite plays. In 2017, the Company expects to drill 10 wells: a six-well pad in the Duvernay play, three wells in the Wapiti Montney play, and one exploratory well in the East Shale Basin.

Gulf of Mexico Region The Gulf of Mexico region comprises assets in the offshore waters of the Gulf of Mexico and onshore Louisiana. In addition to its interest in several deepwater exploration and development offshore leases, when the Company sold substantially all of its offshore assets in water depths less than 1,000 feet, it retained a 50 percent ownership interest in all exploration blocks and in horizons below production in development blocks, and access to existing infrastructure. Apache’s offshore technical teams continue to focus on evaluating subsalt and other deeper exploration opportunities in water depths less than 1,000 feet, which have been relatively untested by the industry, where high-potential deep hydrocarbon plays may exist. During 2016, Apache’s Gulf of Mexico region contributed 7.7 Mboe/d to the Company’s total production. During 2017, the Company expects to participate in one non-operated exploration well.

North America Marketing In general, most of the Company’s North American gas is sold at either monthly or daily market prices. The Company also occasionally enters into fixed physical sales contracts for durations of up to one year. These physical sales volumes are typically sold at fixed prices over the term of the contract. Natural gas is sold primarily to local distribution companies (LDCs), utilities, end-users, marketers, and integrated major oil companies. Apache strives to maintain a diverse client portfolio, which is intended to reduce the concentration of credit risk.

Apache primarily markets its North American crude oil to integrated major oil companies, marketing and transportation companies, and refiners based on a West Texas Intermediate (WTI) price, adjusted for quality, transportation, and a market-reflective differential.

In the U.S., Apache’s objective is to maximize the value of crude oil sold by identifying the best markets and most economical transportation routes available to move the product. Sales contracts are generally 30-day evergreen contracts that renew automatically until canceled by either party. These contracts provide for sales that are priced daily at prevailing market prices. Also, from time to time, the Company will enter into physical term sales contracts for durations up to five years. These term contracts typically have a firm transport commitment and often provide for the higher of prevailing market prices from multiple market hubs.

In Canada, crude is transported by pipeline or truck within Western Canada to market hubs in Alberta and Manitoba where it is sold, allowing for a more diversified group of purchasers and a higher netback price. The Company evaluates its transport options monthly to maximize its netback prices.

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

4

International

In 2016, international assets contributed 46 percent of Apache’s production and 56 percent of oil and gas revenues. Approximately 31 percent of estimated proved reserves at year-end were located outside North America.

Apache has two international regions:

• The Egypt region includes onshore conventional assets in Egypt’s Western Desert.

• The North Sea region includes offshore assets based in the United Kingdom.

The Company also has an offshore exploration program in Suriname.

Egypt Apache’s Egypt operations are conducted pursuant to production sharing contracts (PSCs). Under the terms of the Company’s PSCs, the contractor partners (Contractor) bears the risk and cost of exploration, development, and production activities. In return, if exploration is successful, the Contractor receives entitlement to variable physical volumes of hydrocarbons, representing recovery of the costs incurred and a stipulated share of production after cost recovery. Additionally, the Contractor’s income taxes, which remain the liability of the Contractor under domestic law, are paid by Egyptian General Petroleum Corporation (EGPC) on behalf of the Contractor out of EGPC’s production entitlement. Income taxes paid to the Arab Republic of Egypt on behalf of the Contractor are recognized as oil and gas sales revenue and income tax expense and reflected as production and estimated reserves. Because Contractor cost recovery entitlement and income taxes paid on its behalf are determined as a monetary amount, the quantities of production entitlement and estimated reserves attributable to these monetary amounts will fluctuate with commodity prices. In addition, because the Contractor income taxes are paid by EGPC, the amount of the income tax has no economic impact on Apache’s Egypt operations despite impacting Apache’s production and reserves. Sinopec International Petroleum Exploration and Production Corporation (Sinopec) holds a one-third minority participation interest in Apache’s oil and gas operations in Egypt.

Apache has 21 years of exploration, development and operations experience in Egypt and is one of the largest acreage holders in Egypt’s Western Desert. At year-end 2016, the Company held 4.8 million gross acres in 23 separate concessions. Development leases within concessions currently have expiration dates ranging from 4 to 20 years, with extensions possible for additional commercial discoveries or on a negotiated basis. Approximately 63 percent of the Company’s acreage in Egypt is undeveloped, providing us with considerable exploration and development opportunities for the future. In December 2016, the Company was notified by the Egyptian Ministry that it was the successful bidder in two new concessions, which will add an additional 1.6 million gross undeveloped acres to its portfolio. Apache anticipates these concessions will be signed into law mid-2017.

The Company’s estimated proved reserves in Egypt are reported under the economic interest method and exclude the host country’s share of reserves. The Egypt region, including the one-third noncontrolling interest, contributed 33 percent of 2016 production, 21 percent of year-end estimated proved reserves, and 37 percent of estimated discounted future net cash flows. Excluding the noncontrolling interest, Egypt contributed 24 percent of 2016 production, 15 percent of year-end estimated proved reserves, and 28 percent of estimated discounted future net cash flows.

While Apache has historically been one of the most active drillers in the Western Desert, activity has been curtailed for the past several years in response to weak oil prices. In 2016, the region drilled 47 development and 14 exploration wells. Approximately 57 percent of the exploration wells were successful, further expanding Apache’s presence in the westernmost concessions and unlocking additional opportunities in existing plays. A key component of the region’s success has been the ability to acquire and evaluate 3-D seismic surveys that enable Apache’s technical teams to consistently high-grade existing prospects and identify new targets across multiple pay horizons in the Cretaceous, Jurassic, and deeper Paleozoic formations.

In 2017, Apache plans to operate 8 to 10 drilling rigs and drill approximately 90 to 100 wells. In addition, Apache will initiate a large, continuous 3-D seismic survey program to support development on its existing acreage and exploration on its new concessions. The program will provide newer vintage, higher resolution imaging of the substrata across Apache’s Western Desert position, allowing Apache to build and high-grade its drilling inventory.

Egypt Marketing  Apache’s gas production in Egypt is sold to EGPC primarily under an industry-pricing formula, a sliding scale based on Dated Brent crude oil with a minimum of $1.50 per MMBtu and a maximum of $2.65 per MMBtu, plus an upward adjustment for liquids content. The region averaged $2.71 per Mcf in 2016.

Oil production is sold to third parties in the export market or to EGPC when called upon to supply domestic demand. Oil production sold to third parties is exported from or sold at one of two terminals on the northern coast of Egypt. Oil production sold to EGPC is sold at prices equivalent to the export market.

5

North Sea Apache has interests in approximately 380,000 gross acres in the U.K. North Sea. The region contributed 13 percent of Apache’s 2016 production and approximately 10 percent of year-end estimated proved reserves.

Apache entered the North Sea in 2003 after acquiring an approximate 97 percent working interest in the Forties field (Forties). Since acquiring Forties, Apache has actively invested in the region and has established a large inventory of drilling prospects through successful exploration programs and the interpretation of acquired 3-D and 4-D seismic data. Building upon its success in Forties, in 2011 Apache acquired Mobil North Sea Limited, providing the region with additional exploration and development opportunities across numerous fields, including operated interests in the Beryl, Nevis, Nevis South, Skene, and Buckland fields and non-operated interests in the Maclure and Nelson field. The Beryl field, which is a geologically complex area with multiple fields and stacked pay potential, provides for significant exploration opportunity. The North Sea region plays a strategic role in Apache’s portfolio by providing competitive investment opportunities and potential reserve upside with high-impact exploration potential.

During the year, the region drilled 12 development wells with an 83 percent success rate: six at Forties, five at Beryl, and one at Aviat. In addition, it drilled or participated in three exploration wells with a 33 percent success rate. The Storr discovery, an exploration prospect targeting the Beryl and Nansen sands, encountered hydrocarbons in two separate fault blocks. The region is evaluating a development plan for the Storr discovery. Apache holds a 55 percent working interest in the prospect.

Apache progressed the development of the 2015 Callater (formerly K) exploration discovery in the Beryl area, with first production projected in the second half of 2017. Initial production is expected at 20,000 boe/d on a gross basis. Apache plans to drill two additional wells in the second half of the year. Apache holds a 55 percent working interest in Callater, and operates the field. The region also continued to assess development plans for two earlier exploration discoveries, Seagull and Corona, in which Apache holds 35 and 100 percent interests, respectively.

Also during the year, Apache completed the Aviat gas-for-power project at Forties. This project enables a switch from diesel to natural gas to power the Forties field. The use of natural gas to power the field will extend the economic life, lower operating costs, and reduce certain reliability and safety risks associated with bunkering diesel. Annual fuel and other savings are projected at $15 million.

In 2017, Apache currently plans to operate an average of three rigs in the North Sea region, two platform rigs (one at Forties and one at Beryl) and two semi-submersible rigs on rig-sharing agreements, and drill 15 to 16 wells.

North Sea Marketing  Apache has traditionally sold its North Sea crude oil under term contracts, with a market-based index price plus a premium, which reflects the higher market value for term arrangements.

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

Australia/Argentina During the second quarter of 2015, Apache completed the sale of its Australian LNG business and oil and gas assets. In March 2014, Apache completed the sale of all of its operations in Argentina. Results of operations and consolidated cash flows for the divested Australia assets and Argentina operations are reflected as discontinued operations in the Company’s financial statements for all periods presented in this Annual Report on Form 10-K.

Other Exploration

New Ventures Apache’s global New Ventures team provides exposure to new growth opportunities by looking outside of the Company’s traditional core areas and targeting higher-risk, higher-reward exploration opportunities located in frontier basins as well as new plays in more mature basins. Plans for 2017 include continued analysis and review of the Company’s deepwater prospects in offshore Suriname, including fully processing the data set from its 3-D seismic shoot completed in the third quarter of 2016. Apache will begin drilling an exploration well in the first quarter of 2017.

Major Customers

In 2016 and 2015, purchases by China Petroleum & Chemical Corporation and its subsidiaries accounted for 21 percent and 12 percent, respectively, of the Company’s worldwide oil and gas production revenues. In 2016 and 2015, purchases by Egyptian General Petroleum Company and its subsidiaries accounted for 12 percent and 11 percent, respectively, of the Company’s worldwide oil and gas production revenues. In 2015 and 2014, purchases by Royal Dutch Shell plc and its subsidiaries accounted for 11 percent and 19 percent, respectively, of the Company’s worldwide oil and gas production revenues.

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Drilling Statistics

Worldwide in 2016, Apache participated in drilling 260 gross wells, with 240 (92 percent) completed as producers. Historically, Apache’s drilling activities in the U.S. have generally concentrated on exploitation and extension of existing producing fields rather than exploration. As a general matter, Apache’s operations outside of North America focus on a mix of exploration and development wells. In addition to Apache’s completed wells, at year-end a number of wells had not yet reached completion: 70 gross (33.7 net) in the U.S., 14 gross (14 net) in Egypt, and 5 gross (3.1 net) in the North Sea.

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

	Net Exploratory			Net Development			Total Net Wells
	Productive	Dry	Total	Productive	Dry	Total	Productive	Dry	Total
2016
United States	18.9	5.0	23.9	79.5	1.9	81.4	98.4	6.9	105.3
Canada	—	2.0	2.0	10.2	—	10.2	10.2	2.0	12.2
Egypt	7.3	5.1	12.4	40.5	1.0	41.5	47.8	6.1	53.9
North Sea	—	0.9	0.9	8.2	1.6	9.8	8.2	2.5	10.7
Total	26.2	13.0	39.2	138.4	4.5	142.9	164.6	17.5	182.1
2015
United States	14.7	8.0	22.7	289.0	5.3	294.3	303.7	13.3	317.0
Canada	4.0	—	4.0	16.7	—	16.7	20.7	—	20.7
Egypt	13.4	8.6	22.0	82.3	3.0	85.3	95.7	11.6	107.3
North Sea	1.6	0.7	2.3	15.9	3.5	19.4	17.5	4.2	21.7
Other International	—	0.5	0.5	—	—	—	—	0.5	0.5
Total	33.7	17.8	51.5	403.9	11.8	415.7	437.6	29.6	467.2
2014
United States	18.5	6.4	24.9	781.5	10.1	791.6	800.0	16.5	816.5
Canada	1.0	1.0	2.0	83.9	2.0	85.9	84.9	3.0	87.9
Egypt	18.6	22.8	41.4	143.3	9.9	153.2	161.9	32.7	194.6
Australia	1.6	1.7	3.3	2.9	—	2.9	4.5	1.7	6.2
North Sea	—	—	—	17.6	1.1	18.7	17.6	1.1	18.7
Argentina	—	—	—	1.0	—	1.0	1.0	—	1.0
Total	39.7	31.9	71.6	1,030.2	23.1	1,053.3	1,069.9	55.0	1,124.9

Productive Oil and Gas Wells

The number of productive oil and gas wells, operated and non-operated, in which the Company had an interest as of December 31, 2016, is set forth below:

	Oil		Gas		Total
	Gross	Net	Gross	Net	Gross	Net
United States	13,716	8,936	3,192	1,581	16,908	10,517
Canada	1,786	795	2,313	1,873	4,099	2,668
Egypt	1,135	1,072	120	116	1,255	1,188
North Sea	158	119	25	16	183	135
Total	16,795	10,922	5,650	3,586	22,445	14,508
Domestic	13,716	8,936	3,192	1,581	16,908	10,517
Foreign	3,079	1,986	2,458	2,005	5,537	3,991
Total	16,795	10,922	5,650	3,586	22,445	14,508

Gross natural gas and crude oil wells include 640 wells with multiple completions.

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Production, Pricing, and Lease Operating Cost Data

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

	Production			Average Lease Operating   Cost per Boe		Average Sales Price
	Oil	NGL	Gas			Oil		NGL		Gas
Year Ended December 31,	(MMbbls)	(MMbbls)	(Bcf)			(Per bbl)		(Per bbl)		(Per Mcf)
2016
United States	38.0	19.8	145.0	$	7.72	$	39.43	$	9.28	$	2.17
Canada	4.8	2.1	88.8	11.52		37.62		8.15		1.64
Egypt(1)	37.9	0.4	143.4	7.86		43.66		28.68		2.71
North Sea(2)	20.0	0.6	26.3	13.14		42.93		24.20		4.51
Total	100.7	22.9	403.5	8.90		41.63		9.92		2.40
2015
United States	45.1	19.7	160.6	$	8.81	$	45.71	$	9.72	$	2.38
Canada	5.8	2.2	100.3	13.46		42.33		5.52		2.41
Egypt(1)	33.1	0.4	134.8	10.11		50.97		30.97		2.91
North Sea	21.7	0.4	23.7	13.74		51.26		26.53		6.73
Total	105.7	22.7	419.4	10.40		48.31		9.98		2.80
2014
United States	48.7	21.5	215.8	$	9.55	$	87.33	$	25.57	$	4.33
Canada	6.4	2.3	117.8	17.90		83.57		33.61		4.07
Egypt(1)	33.0	0.2	146.5	9.37		97.06		51.60		2.96
North Sea	22.2	0.5	20.5	17.30		95.53		59.42		8.29
Total	110.3	24.5	500.6	11.51		91.66		27.28		4.03

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

(2) Average sales volumes from the North Sea for 2016 were 24.5 MMboe. Sales volumes may vary from production volumes as a result of the timing of liftings in the Beryl field.

Gross and Net Undeveloped and Developed Acreage

The following table sets out Apache’s gross and net acreage position as of December 31, 2016, in each country where the Company has operations:

	Undeveloped Acreage		Developed Acreage
	Gross Acres	Net Acres	Gross Acres	Net Acres
	(in thousands)
United States	5,739	2,697	2,057	1,134
Canada	948	740	2,554	1,857
Egypt	3,007	2,616	1,758	1,657
North Sea	230	139	150	115
Total	9,924	6,192	6,519	4,763

As of December 31, 2016, Apache had 1.2 million net undeveloped acres scheduled to expire by year-end 2017 if production is not established or Apache takes no other action to extend the terms. Additionally, Apache has 668,000 and 854,000 net undeveloped acres set to expire in 2018 and 2019, respectively. The Company strives to extend the terms of many of these licenses and concession areas through operational or administrative actions, but cannot assure that such extensions can be achieved on an economic basis or otherwise on terms agreeable to both the Company and third parties, including governments.

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Exploration concessions in Apache’s Egypt region comprise a significant portion of Apache’s net undeveloped acreage expiring over the next three years. Apache has 0.7 million, 0.4 million, and 0.6 million net undeveloped acres set to expire in 2017, 2018, and 2019, respectively. Apache will continue to pursue acreage extensions in areas in which it believes exploration opportunities exist. There were no reserves recorded on this undeveloped acreage. Separately, Apache was awarded the NW Razzak and South Alam El Shawish concession blocks in December 2016. The agreements are currently progressing and formal approval and signing of the agreements by Apache, EGPC, and the Ministry of Petroleum is expected to occur by the summer of 2017. Combined, the two concessions are expected to add approximately 1.6 million of undeveloped gross acres in Egypt in 2017.

As of December 31, 2016, 34 percent of U.S. net undeveloped acreage and 44 percent of Canadian net undeveloped acreage was held by production.

In addition, Apache has exploration interests in Suriname consisting of 1.8 million net undeveloped acreage in two blocks set to expire in 2017 and 2018. Apache will commence drilling operations on a commitment well in 2017, and will determine a course of action based on the results of drilling tests. No reserves have been booked on this undeveloped acreage.

Estimated Proved Reserves and Future Net Cash Flows

Proved oil and gas reserves are those quantities of natural gas, crude oil, condensate, and NGLs, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. Estimated proved developed oil and gas reserves can be expected to be recovered through existing wells with existing equipment and operating methods. The Company reports all estimated proved reserves held under production-sharing arrangements utilizing the “economic interest” method, which excludes the host country’s share of reserves.

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

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

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The following table shows proved oil, NGL, and gas reserves as of December 31, 2016, based on average commodity prices in effect on the first day of each month in 2016, held flat for the life of the production, except where future oil and gas sales are covered by physical contract terms. This table shows reserves on a boe basis in which natural gas is converted to an equivalent barrel of oil based on a ratio of 6 Mcf to 1 bbl. This ratio is not reflective of the current price ratio between the two products.

	Oil	NGL	Gas	Total
	(MMbbls)	(MMbbls)	(Bcf)	(MMboe)
Proved Developed:
United States	301	155	1,200	656
Canada	51	14	554	157
Egypt(1)	139	1	676	253
North Sea	91	2	87	108
Total Proved Developed	582	172	2,517	1,174
Proved Undeveloped:
United States	21	17	231	77
Canada	8	2	45	18
Egypt(1)	20	—	42	27
North Sea	11	1	24	15
Total Proved Undeveloped	60	20	342	137
TOTAL PROVED	642	192	2,859	1,311

(1) Includes total proved reserves of 93 MMboe attributable to a one-third noncontrolling interest in Egypt

As of December 31, 2016, Apache had total estimated proved reserves of 642 MMbbls of crude oil, 192 MMbbls of NGLs, and 2.9 Tcf of natural gas. Combined, these total estimated proved reserves are the volume equivalent of 1.3 billion barrels of oil or 7.9 Tcf of natural gas, of which oil represents 49 percent. As of December 31, 2016, the Company’s proved developed reserves totaled 1,174 MMboe and estimated PUD reserves totaled 137 MMboe, or approximately 10.5 percent of worldwide total proved reserves. Apache has elected not to disclose probable or possible reserves in this filing.

During 2016, Apache added 103 MMboe of proved reserves through exploration and development activity and 2 MMboe through purchases of minerals in-place. Apache sold a combined 7 MMboe through several divestiture transactions. During 2016, Apache also had combined downward revisions of previously estimated reserves of 159 MMboe. Changes in product prices accounted for 172 MMboe, lease ownership changes accounted for 6 MMboe, offset by engineering and performance upward revisions totaling 19 MMboe.

The Company’s estimates of proved reserves, proved developed reserves, and PUD reserves as of December 31, 2016, 2015, and 2014, changes in estimated proved reserves during the last three years, and estimates of future net cash flows from proved reserves are contained in Note 16—Supplemental Oil and Gas Disclosures in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K. Estimated future net cash flows were calculated using a discount rate of 10 percent per annum, end of period costs, and an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months, held flat for the life of the production, except where prices are defined by contractual arrangements.

Proved Undeveloped Reserves

The Company’s total estimated PUD reserves of 137 MMboe as of December 31, 2016, decreased by 95 MMboe from 232 MMboe of PUD reserves reported at the end of 2015. During the year, Apache converted 22 MMboe of PUD reserves to proved developed reserves through development drilling activity. In North America, Apache converted 15 MMboe, with the remaining 7 MMboe in Apache’s international areas. Apache sold 3 MMboe and acquired no PUD reserves during the year. Apache added 48 MMboe of new PUD reserves through extensions and discoveries. Apache recognized a 118 MMboe downward revision in proved undeveloped reserves during the year, of which 99 MMboe was associated with lower product prices, 5 MMboe was associated with interest revisions, and 14 MMboe was a result of changes in development plans.

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During the year, a total of approximately $357 million was spent on projects associated with reserves that were carried as PUD reserves at the end of 2015. A portion of Apache’s costs incurred each year relate to development projects that will be converted to proved developed reserves in future years. Apache spent approximately $289 million on PUD reserve development activity in North America and $68 million in the international areas. As of December 31, 2016, Apache had no material amounts of proved undeveloped reserves scheduled to be developed beyond five years from initial disclosure.

Preparation of Oil and Gas Reserve Information

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

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

Apache’s Executive Vice President of Corporate Reservoir Engineering is the person primarily responsible for overseeing the preparation of our internal reserve estimates and for coordinating any reserves audits conducted by a third-party engineering firm. He has a Bachelor of Science degree in Petroleum Engineering and over 36 years of industry experience with positions of increasing responsibility within Apache’s corporate reservoir engineering department. The Executive Vice President of Corporate Reservoir Engineering reports directly to our Chief Executive Officer.

The estimate of reserves disclosed in this Annual Report on Form 10-K is prepared by the Company’s internal staff, and the Company is responsible for the adequacy and accuracy of those estimates. However, the Company engages Ryder Scott Company, L.P. Petroleum Consultants (Ryder Scott) to review our processes and the reasonableness of our estimates of proved hydrocarbon liquid and gas reserves. The Company selects the properties for review by Ryder Scott based primarily on relative reserve value. The Company also considers other factors such as geographic location, new wells drilled during the year and reserves volume. During 2016, the properties selected for each country ranged from 87 to 100 percent of the total future net cash flows discounted at 10 percent. These properties also accounted for over 88 percent of the reserves value of our international proved reserves and 93 percent of the new wells drilled in each country. In addition, all fields containing five percent or more of the Company’s total proved reserves volume were included in Ryder Scott’s review. The review covered 83 percent of total proved reserves by volume.

During 2016, 2015, and 2014, Ryder Scott’s review covered 92, 90, and 91 percent, respectively, of the Company’s worldwide estimated proved reserves value and 83, 83, and 85 percent, respectively, of the Company’s total proved reserves volume. Ryder Scott’s review of 2016 covered 81 percent of U.S., 81 percent of Canada, 85 percent of Egypt, and 92 percent of the U.K.’s total proved reserves.

Ryder Scott’s review of 2015 covered 81 percent of U.S., 81 percent of Canada, 86 percent of Egypt, and 88 percent of the U.K.’s total proved reserves.

Ryder Scott’s review of 2014 covered 83 percent of U.S., 75 percent of Canada, 99.5 percent of Australia, 86 percent of Egypt, and 94 percent of the U.K.’s total proved reserves.

The Company has filed Ryder Scott’s independent report as an exhibit to this Form 10-K.

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

Employees

On December 31, 2016, the Company had 3,727 employees.

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Offices

Our principal executive offices are located at One Post Oak Central, 2000 Post Oak Boulevard, Suite 100, Houston, Texas 77056-4400. At year-end 2016, the Company maintained regional exploration and/or production offices in Midland, Texas; San Antonio, Texas; Houston, Texas; Calgary, Alberta; Cairo, Egypt; and Aberdeen, Scotland. Apache leases all of its primary office space. The current lease on our principal executive offices runs through December 31, 2019. The Company has two, five-year options to extend the lease through 2024 and 2029, which may be exercised in five or ten-year increments. For information regarding the Company’s obligations under its office leases, please see Part II, Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity—Contractual Obligations and Note 10—Commitments and Contingencies in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.

Title to Interests

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

Additional Information about Apache

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

Response Plans and Available Resources

Apache and its wholly owned subsidiary, Apache Deepwater LLC (ADW), developed Oil Spill Response Plans (the Plans) for their respective Gulf of Mexico operations and offshore operations in the North Sea and Suriname. These plans ensure rapid and effective responses to spill events that may occur on such entities’ operated properties. Annually, drills are conducted to measure and maintain the effectiveness of the Plans.

Apache is a member of Oil Spill Response Limited (OSRL), a large international oil spill response cooperative, which entitles any Apache entity worldwide to access OSRL’s services. Apache also has a contract in place for response resources and services with Polyeco Group, a large, privately owned, tier three Oil Spill Response Organization (OSRO), which has resources strategically staged at six bases worldwide.

In the event of a spill in the Gulf of Mexico, Clean Gulf Associates (CGA) is the primary oil spill response association available to Apache and ADW. Both Apache and ADW are members of CGA, a not-for-profit association of producing and pipeline companies operating in the Gulf of Mexico. CGA was created to provide a means of effectively staging response equipment and providing immediate spill response for its member companies’ operations in the Gulf of Mexico. In the event of a spill, CGA’s equipment, which is positioned at various staging points around the Gulf, is ready to be mobilized. In addition, ADW is a member of Marine Spill Response Corporation (MSRC), and their equipment and resources are also available to ADW for its deepwater Gulf of Mexico and new venture operations.

An Apache subsidiary is also a member of the Marine Well Containment Company (MWCC) to help the Company fulfill the government’s permit requirements for containment and oil spill response plans in deepwater Gulf of Mexico operations. MWCC is a not-for-profit, stand-alone organization whose goal is to improve capabilities for containing an underwater well control incident in the U.S. Gulf of Mexico. Members and their affiliates have access to MWCC’s extensive containment network and systems. As of December 31, 2016, Apache’s investment in MWCC totals $163 million and is reflected in “Deferred charges and other” in the Company’s consolidated balance sheet.

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Competitive Conditions

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

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

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

Environmental Compliance

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

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

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ITEM 1A. RISK FACTORS

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

Crude oil and natural gas price volatility, including the recent decline in prices for oil and natural gas, could adversely affect our operating results and the price of our common stock.

Our revenues, operating results, and future rate of growth depend highly upon the prices we receive for our crude oil and natural gas production. Historically, the markets for crude oil and natural gas have been volatile and are likely to continue to be volatile in the future. For example, the NYMEX daily settlement price for the prompt month oil contract in 2016 ranged from a high of $54.06 per barrel to a low of $26.21 per barrel. The NYMEX daily settlement price for the prompt month natural gas contract in 2016 ranged from a high of $3.93 per MMBtu to a low of $1.64 per MMBtu. The market prices for crude oil and natural gas depend on factors beyond our control. These factors include demand for crude oil and natural gas, which fluctuates with changes in market and economic conditions, and other factors, including:

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

• actions taken by foreign oil and gas producing nations, including the Organization of the Petroleum Exporting Countries (OPEC);

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

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

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

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

• the availability of pipeline capacity and infrastructure;

• the availability of crude oil transportation and refining capacity;

• weather conditions;

• domestic and foreign governmental regulations and taxes; and

• the overall economic environment.

Our results of operations, as well as the carrying value of our oil and gas properties, are substantially dependent upon the prices of oil and natural gas, which have declined significantly since June 2014. Despite slight increases in oil and natural gas prices in 2016, prices have remained significantly lower than levels seen in recent years, which has adversely affected our revenues, operating income, cash flow, and proved reserves. Continued low prices could have a material adverse impact on our operations and limit our ability to fund capital expenditures. Without the ability to fund capital expenditures, we would be unable to replace reserves and production. Sustained low prices of crude oil and natural gas may further adversely impact our business as follows:

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

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

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

• reducing our revenues, operating income, and cash flows;

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

• reducing the carrying value of our crude oil and natural gas properties, resulting in additional non-cash impairments;

• reducing the carrying value of our gathering, transmission, and processing facilities, resulting in additional impairments; or

• reducing the carrying value of goodwill.

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

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

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

Current global market conditions, and uncertainty, including economic instability in Europe and certain emerging markets, is likely to have significant long-term effects. Global economic growth drives demand for energy from all sources, including fossil fuels. A lower future economic growth rate could result in decreased demand growth for our crude oil and natural gas production as well as lower commodity prices, which would reduce our cash flows from operations and our profitability.

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

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

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

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

• well blowouts, explosions, and cratering;

• pipeline or other facility ruptures and spills;

• fires;

• formations with abnormal pressures;

• equipment malfunctions;

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

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

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

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

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

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

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

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

• our production falls short of the hedged volumes;

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

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

• an unexpected event materially impacts oil and natural gas prices.

The credit risk of financial institutions could adversely affect us.

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

We are exposed to a risk of financial loss if a counterparty fails to perform under a derivative contract. This risk of counterparty non-performance is of particular concern given the recent volatility of the financial markets and significant decline in oil and natural gas prices, which could lead to sudden changes in a counterparty’s liquidity and impair its ability to perform under the terms of the derivative contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions. Furthermore, the bankruptcy of one or more of our hedge providers, or some other similar proceeding or liquidity constraint, might make it unlikely that we would be able to collect all or a significant portion of amounts owed to us by the distressed entity or entities. During periods of falling commodity prices our hedge receivable positions increase, which increases our exposure. If the creditworthiness of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss.

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The distressed financial conditions of our purchasers and partners could have an adverse impact on us in the event they are unable to pay us for the products or services we provide or to reimburse us for their share of costs.

Concerns about global economic conditions and the volatility of oil and natural gas prices have had a significant adverse impact on the oil and gas industry. We are exposed to risk of financial loss from trade, joint venture, joint interest billing, and other receivables. We sell our crude oil, natural gas, and NGLs to a variety of purchasers. As operator, we pay expenses and bill our non-operating partners for their respective shares of costs. As a result of current economic conditions and the severe decline in oil and natural gas prices, some of our customers and non-operating partners may experience severe financial problems that may have a significant impact on their creditworthiness. We cannot provide assurance that one or more of our financially distressed customers or non-operating partners will not default on their obligations to us or that such a default or defaults will not have a material adverse effect on our business, financial position, future results of operations, or future cash flows. Furthermore, the bankruptcy of one or more of our customers or non-operating partners, or some other similar proceeding or liquidity constraint, might make it unlikely that we would be able to collect all or a significant portion of amounts owed by the distressed entity or entities. Nonperformance by a trade creditor or non-operating partner could result in significant financial losses.

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

We receive debt ratings from the major credit rating agencies in the United States. Factors that may impact our credit ratings include debt levels, planned asset purchases or sales, and near-term and long-term production growth opportunities. Liquidity, asset quality, cost structure, product mix, and commodity pricing levels and others are also considered by the rating agencies. A ratings downgrade could adversely impact our ability to access debt markets in the future, increase the cost of future debt, and potentially require us to post letters of credit or other forms of collateral for certain obligations. On February 2, 2016, our credit rating was downgraded by Standard and Poor’s to BBB/Stable, and on February 25, 2016, our credit rating was downgraded by Moody’s to Baa3/negative outlook, in each case as part of an industry-wide review and downgrade of U.S. exploration and production and oilfield services companies due to deteriorating commodity prices. Subsequently, on November 11, 2016, Moody’s changed our rating outlook to stable and affirmed our Baa3 rating. Any future downgrades could result in additional postings ranging from approximately $400 million to $1.0 billion, depending upon timing and availability of tax relief.

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

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

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

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

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

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

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

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

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

• unexpected drilling conditions;

• pressure or irregularities in formations;

• equipment failures or accidents;

• fires, explosions, blowouts, and surface cratering;

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

• other adverse weather conditions; and

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

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

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

We are involved in several large development projects and the completion of these projects may be delayed beyond our anticipated completion dates. Our projects may be delayed by project approvals from joint venture partners, timely issuances of permits and licenses by governmental agencies, weather conditions, manufacturing and delivery schedules of critical equipment, and other unforeseen events. Delays and differences between estimated and actual timing of critical events may adversely affect our large development projects and our ability to participate in large-scale development projects in the future. In addition, our estimates of future development costs are based on current expectation of prices and other costs of equipment and personnel we will need to implement such projects. Our actual future development costs may be significantly higher than we currently estimate. If costs become too high, our development projects may become uneconomic to us, and we may be forced to abandon such development projects.

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

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

Our liabilities could be adversely affected in the event one or more of our transaction counterparties become the subject of a bankruptcy case.

Over the last several years, we have taken action to enhance and streamline our North American portfolio through not only the acquisition of assets in key operating regions but also the divestitures of noncore domestic assets and the monetization of certain nonstrategic international assets. The agreements relating to these transactions contain provisions pursuant to which liabilities related to past and future operations have been allocated between the parties by means of liability assumptions, indemnities, escrows, trusts, and similar arrangements. One or more of the counterparties in these transactions could, either as a result of the severe decline in oil and natural gas prices or other factors related to the historical or future operations of their respective businesses, face financial problems that may have a significant impact on its ability to perform its obligations under these agreements and its solvency and ability to continue as a going concern. In the event that any such counterparty were to become unable financially to perform its liabilities or obligations assumed and as a result become the subject of a case or proceeding under Title 11 of the United States Code (the bankruptcy code) or any other relevant insolvency law or similar law (which we collectively refer to as Insolvency Laws) the counterparty may not perform its obligations under the agreements related to these transactions. In that case, our remedy would be a claim in the proceeding for damages for the breach of the contractual arrangement, which may be either a secured claim or an unsecured claim depending on whether or not we have collateral from the counterparty for the performance of the obligations. Resolution of our damage claim in such a proceeding may be delayed, and we may be forced to use available cash to cover the costs of the obligations assumed by the counterparties under such agreements should they arise.

Despite the provisions in our agreements requiring purchasers of our state or federal leasehold interests to assume certain liabilities and obligations related to such interests, if a purchaser of such interests becomes the subject of a case or proceeding under relevant Insolvency Laws and/or becomes unable financially to perform such liabilities or obligations, the relevant governmental authorities could require us to perform, and hold us responsible for, such liabilities and obligations, such as the decommissioning of such transferred assets. In such event, we may be forced to use available cash to cover the costs of such liabilities and obligations should they arise.

If a court or a governmental authority were to make any of the foregoing determinations or take any of the foregoing actions, or any similar determination or action, it could adversely impact our cash flows, operations, or financial condition.

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

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

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

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

• future operating costs and capital expenditures; and

• workover and remediation costs.

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

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

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

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

We may incur significant costs related to environmental matters.

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

Our North American operations are subject to governmental risks.

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

In response to the Deepwater Horizon incident in the U.S. Gulf of Mexico in April 2010, and as directed by the Secretary of the U.S. Department of the Interior, the Bureau of Ocean Energy Management (BOEM) and the Bureau of Safety and Environmental Enforcement (BSEE) issued new guidelines and regulations regarding safety, environmental matters, drilling equipment, and decommissioning applicable to drilling in the Gulf of Mexico. These regulations imposed additional requirements and caused delays with respect to development and production activities in the Gulf of Mexico.

With respect to oil and gas operations in the Gulf of Mexico, the BOEM has issued a new Notice to Lessees (NTL No. 2016-N01) significantly revising the obligations of companies operating in the Gulf of Mexico to provide supplemental assurances of performance with respect to plugging, abandonment, and decommissioning obligations associated with wells, platforms, structures, and facilities located upon or used in connection with such companies’ oil and gas leases. While requirements under the new NTL have not yet been fully implemented by BOEM, the new NTL may require that Apache provide additional security to BOEM with respect to plugging, abandonment, and decommissioning obligations relating to Apache’s current ownership interests in various Gulf of Mexico leases. We are working closely with BOEM to make arrangements for the provision of such additional required security, if such security becomes necessary under the new NTL. Additionally, we are not able to predict the effect that these changes might have on counterparties to which Apache has sold Gulf of Mexico assets or with whom Apache has joint ownership. Such changes could cause the bonding obligations of such parties to increase substantially, thereby causing a significant impact on the counterparties’ solvency and ability to continue as a going concern.

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New political developments, laws, and the enactment of new or stricter regulations in the Gulf of Mexico or otherwise impacting our North American operations, and increased liability for companies operating in this sector may adversely impact our results of operations.

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

Certain countries where we operate, including Canada and the United Kingdom, either tax or assess some form of greenhouse gas (GHG) related fees on our operations. Exposure has not been material to date, although a change in existing regulations could adversely affect our cash flows and results of operations.

In the event the predictions for rising temperatures and sea levels suggested by reports of the United Nations Intergovernmental Panel on Climate Change do transpire, we do not believe those events by themselves are likely to impact our assets or operations. However, any increase in severe weather could have a material adverse effect on our assets and operations.

The present U.S. federal and state income tax laws affecting oil and natural gas exploration, development, and extraction may be modified by administrative, legislative, or judicial interpretation at any time. Future legislation may result in the elimination of certain U.S. federal income tax deductions currently available with respect to oil and natural gas exploration and development.

The present U.S. federal and state income tax laws affecting oil and natural gas exploration, development, and extraction may be modified by administrative, legislative, or judicial interpretation at any time. Previous legislative proposals, if enacted into law, could make significant changes to such laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain U.S. production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures. The President and Congress could include some or all of these previously proposed changes in conjunction with lower tax rates as part of fundamental tax reform legislation. The passage or adoption of these changes, or similar changes, could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development. Further, the President and Congress may propose and implement more general tax reform changes including changes to cost recovery rules, the deductibility of interest expense, the taxation of foreign dividends, and a border adjustability provision that would impact the taxation of oil and gas companies. We are unable to predict whether any of these changes or other proposals will be enacted. Any such changes could adversely affect our business, financial condition, and results of operations.

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

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

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

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

Our operations outside North America are based primarily in Egypt and the United Kingdom. On a barrel equivalent basis, approximately 46 percent of our 2016 production was outside North America, and approximately 31 percent of our estimated proved oil and gas reserves on December 31, 2016, were located outside North America. As a result, a significant portion of our production and resources are subject to the increased political and economic risks and other factors associated with international operations including, but not limited to:

• general strikes and civil unrest;

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

• import and export regulations;

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

• price control;

• transportation regulations and tariffs;

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

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

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

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

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

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

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

The impact that future terrorist attacks or regional hostilities as have occurred in Egypt and Libya may have on the oil and gas industry in general, and on our operations in particular, is not known at this time. Uncertainty surrounding military strikes or a sustained military campaign may affect operations in unpredictable ways, including disruptions of fuel supplies and markets, particularly oil, and the possibility that infrastructure facilities, including pipelines, production facilities, processing plants, and refineries, could be direct targets of, or indirect casualties of, an act of terror or war. We may be required to incur significant costs in the future to safeguard our assets against terrorist activities.

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

Deterioration in the political, economic, and social conditions or other relevant policies of the Egyptian government, such as changes in laws or regulations, export restrictions, expropriation of our assets or resource nationalization, and/or forced renegotiation or modification of our existing contracts with EGPC, or threats or acts of terrorism, could materially and adversely affect our business, financial condition, and results of operations. Our operations in Egypt, excluding a one-third noncontrolling interest, contributed 24 percent of our 2016 production and accounted for 15 percent of our year-end estimated proved reserves and 28 percent of our estimated discounted future net cash flows.

Our operations are sensitive to currency rate fluctuations.

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

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We do not always control decisions made under joint operating agreements and the parties under such agreements may fail to meet their obligations.

We conduct many of our E&P operations through joint operating agreements with other parties under which we may not control decisions, either because we do not have a controlling interest or are not operator under the agreement. There is risk that these parties may at any time have economic, business, or legal interests or goals that are inconsistent with ours, and therefore decisions may be made which are not what we believe is in our best interest. Moreover, parties to these agreements may be unable to meet their economic or other obligations and we may be required to fulfill those obligations alone. In either case, the value of our investment may be adversely affected.

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

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

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

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

ITEM 1B. UNRESOLVED STAFF COMMENTS

As of December 31, 2016, we did not have any unresolved comments from the SEC staff that were received 180 or more days prior to year-end.

ITEM 3. LEGAL PROCEEDINGS

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

ITEM 4. MINE SAFETY DISCLOSURES

None.

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APACHE CORPORATION

PART II

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

During 2016, Apache common stock, par value $0.625 per share, was traded on the New York and Chicago Stock Exchanges and the NASDAQ Global Select Market under the symbol “APA.” The table below provides certain information regarding our common stock for 2016 and 2015. Prices were obtained from The New York Stock Exchange, Inc. Composite Transactions Reporting System. Per-share prices and quarterly dividends shown below have been rounded to the indicated decimal place.

	2016								2015
	Price Range				Dividends Per Share				Price Range				Dividends Per Share
	High		Low		Declared		Paid		High		Low		Declared		Paid
First Quarter	$	51.02	$	34.38	$	0.25	$	0.25	$	68.37	$	58.46	$	0.25	$	0.25
Second Quarter	58.29		46.82		0.25		0.25		71.40		56.54		0.25		0.25
Third Quarter	63.87		48.78		0.25		0.25		56.78		36.20		0.25		0.25
Fourth Quarter	67.35		55.52		0.25		0.25		53.94		39.72		0.25		0.25

The closing price of our common stock, as reported on the New York Stock Exchange Composite Transactions Reporting System for January 31, 2017 (last trading day of the month), was $59.82 per share. As of January 31, 2017, there were 379,687,129 shares of our common stock outstanding held by approximately 4,300 stockholders of record and 263,000 beneficial owners.

We have paid cash dividends on our common stock for 52 consecutive years through December 31, 2016. When, and if, declared by our Board of Directors, future dividend payments will depend upon our level of earnings, financial requirements, and other relevant factors.

Information concerning securities authorized for issuance under equity compensation plans is set forth under the caption “Equity Compensation Plan Information” in the proxy statement relating to the Company’s 2017 annual meeting of stockholders, which is incorporated herein by reference.

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The following stock price performance graph is intended to allow review of stockholder returns, expressed in terms of the appreciation of the Company’s common stock relative to two broad-based stock performance indices. The information is included for historical comparative purposes only and should not be considered indicative of future stock performance. The graph compares the yearly percentage change in the cumulative total stockholder return on the Company’s common stock with the cumulative total return of the Standard & Poor’s Composite 500 Stock Index and of the Dow Jones U.S. Exploration & Production Index (formerly Dow Jones Secondary Oil Stock Index) from December 31, 2011, through December 31, 2016. The stock performance graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall information be incorporated by reference into any future filing under the Securities Act of 1933 or Securities Exchange Act of 1934, each as amended, except to the extent that the Company specifically incorporates it by reference into such filing.

COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN*

Among Apache Corporation, S&P 500 Index,

and the Dow Jones US Exploration & Production Index

* $100 invested on 12/31/11 in stock including reinvestment of dividends.

Fiscal year ending December 31.

	2011		2012		2013		2014		2015		2016
Apache Corporation	$	100.00	$	87.29	$	96.48	$	71.15	$	51.42	$	74.88
S & P’s Composite 500 Stock Index	100.00		116.00		153.57		174.60		177.01		198.18
DJ US Expl & Prod Index	100.00		105.82		139.52		124.48		94.94		118.19

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ITEM 6. SELECTED FINANCIAL DATA

The following table sets forth selected financial data of the Company and its consolidated subsidiaries over the five-year period ended December 31, 2016. This information should be read in connection with, and is qualified in its entirety by, the more detailed information in the Company’s financial statements set forth in Part IV, Item 15 of this Form 10-K. Financial information for prior periods have been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1 – Summary of Significant Accounting Policies of the Notes to Consolidated Financial Statements under Part IV, Item 15 of this Form 10-K. Certain amounts for prior years have been reclassified to conform to the current presentation. Factors that materially affect the comparability of this information are disclosed in Management’s Discussion and Analysis under Item 7 of this Form 10-K.

	As of or for the Year Ended December 31,
	2016			2015			2014			2013			2012
	(In millions, except per share amounts)
Income Statement Data
Oil and gas production revenues	$	5,367		$	6,510		$	12,795		$	14,825		$	14,965
Net income (loss) from continuing operations attributable to common shareholders	(1,372		)	(10,844		)	(6,653		)	(94		)	484
Net income (loss) from continuing operations per share:
Basic	(3.62		)	(28.70		)	(17.32		)	(0.24		)	1.00
Diluted	(3.62		)	(28.70		)	(17.32		)	(0.24		)	1.00
Cash dividends declared per common share	1.00			1.00			1.00			0.80			0.68
Balance Sheet Data
Total assets	$	22,519		$	25,500		$	44,264		$	54,828		$	56,775
Long-term debt	8,544			8,716			11,178			9,600			11,270
Total equity	7,679			9,490			20,541			30,756			28,538
Common shares outstanding	379			378			377			396			392

For a discussion of significant acquisitions and divestitures, see Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.

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

Apache Corporation, a Delaware corporation formed in 1954, is an independent energy company that explores for, develops, and produces natural gas, crude oil, and natural gas liquids. Apache currently has exploration and production interests in four geographic areas: the U.S., Canada, Egypt, and the U.K. (North Sea). Apache also has exploration interests in Suriname that may, over time, result in a reportable discovery and development opportunity.

During the second quarter of 2016, Apache changed its method of accounting for its oil and gas exploration and development activities from the full cost method to the successful efforts method of accounting. Financial information for all periods has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1—Summary of Significant Accounting Policies of the Notes to Consolidated Financial Statements under Part IV, Item 15 of this Form 10-K.

During 2015, Apache sold its Australia LNG business and oil and gas assets. During 2014, Apache sold its operations in Argentina. Results of operations and cash flows from operations for Argentina and Australia are reflected as discontinued operations in the Company’s financial statements for all periods presented. Certain historical information has been recast to reflect the results of operations for Argentina and Australia as discontinued operations.

The following discussion should be read together with the Consolidated Financial Statements and the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K, and the risk factors and related information set forth in Part I, Item 1A and Part II, Item 7A of this Form 10-K.

Overview of 2016 Results

The Company took decisive action at the start of the significant decline in commodity prices that began in 2014 in order to preserve its financial position, improve its operational capabilities, and to position Apache for a lower-for-longer commodity price environment. The cornerstone of its approach has been capital discipline and cost structure rationalization. We accomplished these objectives through a rigorous and more centralized process for capital allocations, more detailed, long-term planning, and relentless pursuit of cost reductions in our operations and overhead structure. Apache remained focused on its mission to grow the Company for the long-term benefit of its shareholders, allocating a significant portion of its reduced capital spending program to well completion optimization, strategic testing, and strategic acreage acquisitions as opposed to investing its entire capital budget on more near-term production growth.

In September 2016, after more than two years of extensive geological and geophysical work, methodical acreage accumulation, and strategic testing and delineation drilling, Apache announced the discovery of a significant new resource play, “Alpine High.” Apache’s Alpine High acreage lies in the southern portion of the Delaware Basin, primarily in Reeves County, Texas. The Company has established an acreage position of over 320,000 contiguous net acres, which it acquired at an attractive average cost of approximately $1,300 per acre. Since first announcing the Alpine High last September, the Company has made substantial progress further delineating the opportunity. The Company has confirmed an extensive play fairway which spans 55 miles and a 5,000-foot vertical column encompassing five geologic formations, with multiple target zones spanning the hydrocarbon phase window from dry gas to wet gas to oil. We have recently identified an additional landing zone in the Woodford formation, and confirmed production from the Pennsylvanian. Based on these results, Apache now believes the drilling locations at Alpine High will exceed the 2,000 to 3,000 previously announced. During 2017, we expect to average 4 to 6 drilling rigs at Alpine High. A second hydraulic fracturing crew was added at the start of the year to accelerate completions and data collection. Using data collected from strategic testing and delineation drilling, the Company is now beginning to optimize wells drilled in Alpine High using customized targeting, larger fracs, and longer laterals. Combined with multi-well pad drilling, the Company believes these measures contribute to the optimized development of the area to maximize economic value. The field is expected to have low levels of water production which will also have a positive impact on long-term economics. We are currently installing the infrastructure, which will allow gas sales from the field around mid-year 2017.

Daily production of 522 Mboe/d decreased only four percent from 2015, despite investing a significant portion of curtailed capital spending on acreage, delineation wells, and infrastructure at Alpine High rather than drilling development wells with a focus on maintaining production levels in the shorter-term. The Company’s ability to maintain production levels is the result of several successful initiatives during the downturn: reduction of Apache’s cost structure; implementation of a more rigorous and integrated capital allocation and planning process; upgrades to, and expansion of, drilling inventory; and improvements in its capital efficiency, including reduction in service costs. Lease operating expenses were 19 percent lower than 2015 and 33 percent lower than 2014. General and administrative expenses decreased 9 percent over the past two years.

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During 2016, Apache reported a $1.4 billion loss attributable to common stock, or $3.71 per diluted common share, compared to a loss of $10.4 billion, or $27.40 per share in 2015. Results for both periods were directly impacted by asset impairments primarily resulting from the significant drop in crude oil prices beginning in late 2014. Apache generated $2.5 billion in cash from continuing operating activities in 2016, a decrease of 4 percent from the prior year, as a result of falling commodity prices and lower production following curtailment of exploration and development activity. Apache has reduced debt by 24 percent from year-end 2014 levels, while increasing cash by $698 million during the same period. At the end of 2016, in addition to $1.4 billion of cash on hand, Apache has $3.5 billion in available committed borrowing capacity.

2017 Outlook

The Company currently plans to increase 2017 capital investments by more than 60 percent over 2016 spending, to approximately $3.1 billion, excluding capital associated with the one-third noncontrolling interest in Egypt. The Company’s 2017 plan assumes $50 per barrel for WTI, $51 per barrel for Brent indexed crude, $3.15 per Mcf for NYMEX natural gas, and $5.25 per Mcf for UK-indexed gas. At these price levels, our capital program will exceed anticipated operating cash flows. Based on current strip pricing, the remaining outspend will be funded primarily by proceeds from non-core asset sales, approximately $400 million of which has already occurred. In early 2017, the Company entered into put option contracts which will mitigate the downside risk of price volatility while providing full exposure to upside price potential. The put contracts provide an average floor of $50.47 per barrel and cover most of the Company’s second-half 2017 oil production.

Nearly two-thirds, or approximately $2 billion, of Apache’s capital spending in 2017 will be allocated to the Permian Basin, primarily in the Midland and Delaware Basins. This allocation includes approximately $500 million for construction of infrastructure at Alpine High. The infrastructure at Alpine High will include multiple pipeline connections along with compression, gathering, centralized processing facilities and tank batteries designed to accommodate expected volume increases as the play is developed. Internationally, Apache’s capital plan is intended to sustain longer-term free cash flow generation in Egypt and the North Sea. International spending will account for approximately 30 percent of Apache’s total 2017 budget, split nearly evenly between Egypt and the North Sea. Apache’s 2017 opportunity set in these regions is primarily centered on development drilling and lower-risk, step-out exploration wells, where the Company has a long-standing track record of success. Apache’s remaining capital budget is allocated between its remaining North American regions and an exploration well in Suriname expected to commence drilling in the first quarter.

The Company anticipates that production volumes will decline through the second quarter of 2017, before showing consistent quarterly growth beginning in the second half of the year. For the full year, the Company projects reported production in the range of 486 to 506 Mboe/d. Production excluding the noncontrolling interest and tax volumes in Egypt is expected to be in the range of 398 to 415 Mboe/d.

Operational Highlights

Apache’s deliberate focus on strategic testing and targeted development drilling during the price downturn, in addition to the Alpine High discovery, significantly impacted results in its Permian Basin plays, Egypt, and the North Sea.

Other operational highlights for the year include:

North America

• North America onshore liquids averaged 171,691 barrels per day, with crude oil representing 65 percent of this liquids production. North America onshore liquids production represented 51 percent of worldwide liquids production and 33 percent of overall production, contributing $1.8 billion of liquids revenues in 2016. Onshore equivalent production was down 11 percent relative to 2015 as a result of a significant reduction in exploration and development capital spending during 2015 and 2016.

• The Permian region averaged 5 operated rigs during the year, drilling 132 gross wells, 93 net wells. Over half of the region’s production is crude oil and 23 percent is NGLs. Combined, this represents more than a third of Apache’s total liquids production for 2016. The region averaged 161 Mboe/d during 2016 and contributed $1.5 billion of revenues during 2016.

• The Midcontinent/Gulf Coast region drilled or participated in drilling 35 gross wells, with a 94 percent success rate. The region focused its drilling activities in the Woodford-SCOOP and Canyon Lime formations during 2016. The region averaged 55 Mboe/d during 2016, contributing $378 million of revenues for the year.

• The Canada region drilled or participated in drilling 17 gross wells, with an 88 percent success rate. Drilling operations were primarily focused on the region’s Wapiti Montney, Ante Creek Montney, Duvernay, and Glauconite plays, with a goal of reducing drilling and completion costs. The region averaged 59 Mboe/d and contributed $343 million of revenues during 2016.

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International and Offshore

• The Egypt region continued to reduce its drilling program throughout 2016, averaging 6 rigs and drilling 61 gross wells. As a result of the reduced investment in drilling activity over the past several years, gross production decreased one percent. Egypt’s net production increased 11 percent from 2015, a function of the mechanics of its production-sharing contracts. In December 2016, Apache was notified by the Egyptian Ministry that it was the successful bidder in two new concessions, which will add 1.6 million gross undeveloped acres to its portfolio. Apache anticipates these concessions will be signed into law mid-2017. The region averaged 170 net Mboe/d and contributed $2.1 billion of revenues during 2016.

• The North Sea region averaged 4 rigs during 2016, drilling 14 gross wells, 11 net wells. During the year, the region averaged production of 68 Mboe/d and contributed $970 million of revenues. Apache was able to minimize production decline to 4 percent year over year despite a significant reduction in capital expenditures. Apache continues to progress the development of its 2015 Callater (formerly K) exploration discovery in the Beryl area, with first production projected in the second half of 2017. The Company continues appraisal activities on two additional 2015 exploration discoveries: the Corona discovery, which logged 225 feet total vertical depth net pay in excellent reservoir-quality sandstone, and the Seagull discovery, which confirmed 672 feet of net oil pay over a 1,092-foot column in Triassic-age sands. 

For a more detailed discussion related to Apache’s various geographic regions, please refer to the “Geographic Area Overviews” section set forth in Part I, Item 1 and 2 of this Form 10-K.

Acquisition and Divestiture Activity

Over Apache’s 60-year history, it has repeatedly demonstrated its ability to capitalize quickly and decisively on changes in its industry and economic conditions. A key component of this strategy is to continuously review and optimize Apache’s portfolio of assets in response to changes. Most recently, Apache has completed a series of divestitures designed to monetize nonstrategic assets and enhance Apache’s portfolio in order to strategically allocate resources to more impactful development opportunities. These divestments comprised primarily capital intensive projects and assets that were not accretive to earnings in the near-term, and included all of Apache’s operations in Australia and Argentina. These divestments include:

• Australia Operations On June 5, 2015, Apache’s subsidiaries completed the sale of the Company’s Australian subsidiary Apache Energy Limited to a consortium of private equity funds managed by Macquarie Capital Group Limited and Brookfield Asset Management Inc. for total proceeds of $1.9 billion. Additionally, in October 2015, Apache’s subsidiaries completed the sale of its 49 percent interest in Yara Pilbara Holdings Pty Ltd (YPHPL), to Yara International for total proceeds of $391 million. The effective date of the transaction was January 1, 2015.

• LNG Projects On April 2, 2015 and April 10, 2015, Apache subsidiaries completed the sale of its interest in the Wheatstone LNG and Kitimat LNG projects, respectively, along with accompanying upstream oil and gas reserves to Woodside Petroleum Limited (Woodside) for a total cash consideration of $3.7 billion.

• Nonstrategic Assets in the Anadarko Basin and in Southern Louisiana On December 31, 2014, Apache completed the sale of certain Anadarko basin and southern Louisiana oil and gas assets for approximately $1.3 billion in two separate transactions. In the Anadarko basin, Apache sold approximately 115,000 net acres in Wheeler County, Texas, and western Oklahoma. In southern Louisiana, the Company sold working interests in approximately 90,000 net acres. The effective date of both of these transactions was October 1, 2014.

• Certain Gulf of Mexico Deepwater Assets On June 30, 2014, Apache completed the sale of non-operated interests in the Lucius and Heidelberg development projects and 11 primary term deepwater exploration blocks in the Gulf of Mexico for $1.4 billion. The effective date of the transaction was May 1, 2014.

• Nonstrategic Canadian Assets On April 30, 2014, Apache completed the sale of primarily dry gas producing hydrocarbon assets in the Deep Basin area of western Alberta and British Columbia, Canada, for $374 million. The assets comprise 328,400 net acres in the Ojay, Noel, and Wapiti areas. Apache retained 100 percent of its working interest in horizons below the Cretaceous in the Wapiti area, including rights to the liquids-rich Montney and other deeper horizons. The effective date of the transaction was January 1, 2014.

• Argentina Operations On March 12, 2014, Apache’s subsidiaries completed the sale of all of the Company’s operations in Argentina to YPF Sociedad Anónima for $800 million (subject to customary closing adjustments) plus the assumption of $52 million of bank debt as of June 30, 2013.

For detailed information regarding Apache’s acquisitions and divestitures, please refer to Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.

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Results of Operations

Oil and Gas Revenues

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

	For the Year Ended December 31,
	2016				2015				2014
	$ Value		% Contribution		$ Value		% Contribution		$ Value		% Contribution
	($ in millions)
Total Oil Revenues:
United States	$	1,499	36	%	$	2,063	40	%	$	4,260	42	%
Canada	180		4	%	244		5	%	537		5	%
North America	1,679		40	%	2,307		45	%	4,797		47	%
Egypt (1)	1,657		40	%	1,690		33	%	3,196		32	%
North Sea	836		20	%	1,110		22	%	2,117		21	%
International (1)	2,493		60	%	2,800		55	%	5,313		53	%
Total(1)	$	4,172	100	%	$	5,107	100	%	$	10,110	100	%
Total Natural Gas Revenues:
United States	$	314	33	%	$	382	32	%	$	935	46	%
Canada	146		15	%	242		21	%	479		24	%
North America	460		48	%	624		53	%	1,414		70	%
Egypt (1)	389		40	%	393		33	%	434		22	%
North Sea	118		12	%	159		14	%	169		8	%
International (1)	507		52	%	552		47	%	603		30	%
Total(1)	$	967	100	%	$	1,176	100	%	$	2,017	100	%
Total NGL Revenues:
United States	$	184	81	%	$	191	84	%	$	549	82	%
Canada	17		7	%	12		5	%	76		12	%
North America	201		88	%	203		89	%	625		94	%
Egypt (1)	11		5	%	13		6	%	13		2	%
North Sea	16		7	%	11		5	%	30		4	%
International (1)	27		12	%	24		11	%	43		6	%
Total (1)	$	228	100	%	$	227	100	%	$	668	100	%
Total Oil and Gas Revenues:
United States	$	1,997	37	%	$	2,636	40	%	$	5,744	45	%
Canada	343		7	%	498		8	%	1,092		8	%
North America	2,340		44	%	3,134		48	%	6,836		53	%
Egypt (1)	2,057		38	%	2,096		32	%	3,643		29	%
North Sea	970		18	%	1,280		20	%	2,316		18	%
International (1)	3,027		56	%	3,376		52	%	5,959		47	%
Total (1)	$	5,367	100	%	$	6,510	100	%	$	12,795	100	%
Discontinued Operations:
Oil Revenue	$	—			$	138			$	757
Natural Gas Revenue	—				140				385
NGL Revenue	—				—				3
Total	$	—			$	278			$	1,145

(1) Amounts include revenue attributable to a noncontrolling interest in Egypt.

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Production

The following table presents production volumes by region:

	For the Year Ended December 31,
	2016	Increase (Decrease)	2015	Increase (Decrease)	2014
Oil Volume – b/d:
United States	103,827	(16)%	123,666	(7)%	133,667
Canada	13,081	(17)%	15,768	(10)%	17,593
North America	116,908	(16)%	139,434	(8)%	151,260
Egypt(1)(2)	103,719	14%	90,857	1%	90,230
North Sea	54,630	(8)%	59,334	(2)%	60,699
International	158,349	5%	150,191	—	150,929
Total	275,257	(5)%	289,625	(4)%	302,189
Natural Gas Volume – Mcf/d:
United States	396,227	(10)%	440,037	(26)%	591,312
Canada	242,602	(12)%	274,764	(15)%	322,783
North America	638,829	(11)%	714,801	(22)%	914,095
Egypt(1)(2)	391,968	6%	369,507	(8)%	401,431
North Sea	71,751	11%	64,787	16%	55,964
International	463,719	7%	434,294	(5)%	457,395
Total	1,102,548	(4)%	1,149,095	(16)%	1,371,490
NGL Volume – b/d:
United States	54,165	—	53,928	(8)%	58,807
Canada	5,731	(6)%	6,126	(1)%	6,180
North America	59,896	—	60,054	(8)%	64,987
Egypt(1)(2)	1,084	2%	1,064	55%	687
North Sea	1,703	51%	1,131	(19)%	1,392
International	2,787	27%	2,195	6%	2,079
Total	62,683	1%	62,249	(7)%	67,066
BOE per day:(3)
United States	224,029	(11)%	250,934	(14)%	291,027
Canada	59,246	(12)%	67,688	(13)%	77,569
North America	283,275	(11)%	318,622	(14)%	368,596
Egypt(1)(2)	170,131	11%	153,506	(3)%	157,822
North Sea(4)	68,292	(4)%	71,262	—	71,419
International	238,423	6%	224,768	(2)%	229,241
Total	521,698	(4)%	543,390	(9)%	597,837
Discontinued Operations:
Oil (b/d)	—		7,610		22,227
Natural Gas (Mcf/d)	—		94,114		248,837
NGL (b/d)	—		—		317
BOE/d	—		23,296		64,017

(1) Gross oil, natural gas, and NGL production in Egypt were as follows:

	2016	2015	2014
Oil (b/d)	209,659	206,501	197,366
Natural Gas (Mcf/d)	827,202	856,950	894,802
NGL (b/d)	1,861	2,459	1,901

(2) Includes net production volumes per day attributable to a noncontrolling interest in Egypt of:

Oil (b/d)	34,530	30,224	30,063
Natural Gas (Mcf/d)	130,856	122,985	133,901
NGL (b/d)	361	363	229

(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 ratio of 6 Mcf to 1 bbl. This ratio is not reflective of the price ratio between the two products.

(4) Average sales volumes from the North Sea for 2016 were 66,872 boe/d. Sales volumes may vary from production volumes as a result of the timing of liftings in the Beryl field.

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Pricing

The following table presents pricing information by region:

	For the Year Ended December 31,
	2016		Increase (Decrease)	2015		Increase (Decrease)	2014
Average Oil Price - Per barrel:
United States	$	39.43	(14)%	$	45.71	(48)%	$	87.33
Canada	37.62		(11)%	42.33		(49)%	83.57
North America	39.23		(13)%	45.33		(48)%	86.89
Egypt	43.66		(14)%	50.97		(47)%	97.06
North Sea	42.93		(16)%	51.26		(46)%	95.53
International	43.41		(15)%	51.09		(47)%	96.44
Total	41.63		(14)%	48.31		(47)%	91.66
Average Natural Gas Price - Per Mcf:
United States	$	2.17	(9)%	$	2.38	(45)%	$	4.33
Canada	1.64		(32)%	2.41		(41)%	4.07
North America	1.97		(18)%	2.39		(44)%	4.24
Egypt	2.71		(7)%	2.91		(2)%	2.96
North Sea	4.51		(33)%	6.73		(19)%	8.29
International	2.99		(14)%	3.48		(4)%	3.61
Total	2.40		(14)%	2.80		(31)%	4.03
Average NGL Price - Per barrel:
United States	$	9.28	(5)%	$	9.72	(62)%	$	25.57
Canada	8.15		48%	5.52		(84)%	33.61
North America	9.17		(1)%	9.29		(65)%	26.33
Egypt	28.68		(7)%	30.97		(40)%	51.60
North Sea	24.20		(9)%	26.53		(55)%	59.42
International	25.94		(10)%	28.68		(50)%	56.83
Total	9.92		(1)%	9.98		(63)%	27.28
Discontinued Operations:
Oil price ($/Bbl)	$	—		$	49.76		$	93.28
Natural Gas price ($/Mcf)	—			4.07			4.24
NGL price ($/Bbl)	—			—			24.57

Crude Oil Prices

A substantial portion of our crude 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 2016 were down14 percent compared to 2015, a direct result of the sharply lower benchmark oil prices over the past year. Crude oil prices realized in 2016 averaged $41.63 per barrel.

Continued volatility in the commodity price environment reinforces the importance of our asset portfolio. While the market price received for natural gas varies among geographic areas, crude oil tends to trade within a global market. Price movements for all types and grades of crude oil generally move in the same direction.

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. Our primary markets include North America, Egypt, 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 $1.97 per Mcf in 2016, down from $2.39 per Mcf in 2015.

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• In Egypt, our gas is sold to EGPC, primarily under an industry pricing formula indexed to Dated Brent crude oil with a minimum gas price of $1.50 per MMBtu and a maximum gas price of $2.65 per MMBtu, plus an upward adjustment for liquids content. Overall, the region averaged $2.71 per Mcf in 2016, down 7 percent from the prior year.

• 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 $4.51 per Mcf in 2016, a 33 percentdecrease from an average of $6.73 per Mcf in 2015.

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

2016 vs. 2015   Crude oil revenues for 2016 totaled $4.2 billion, a $935 milliondecrease from the 2015 total of $5.1 billion. A 5 percentdecrease in average daily production reduced2016 revenues by $228 million compared to 2015, while 14 percentlower average realized prices decreased revenues by $707 million. Average daily production in 2016 was 275.3 Mb/d, with prices averaging $41.63 per barrel. Crude oil accounted for 78 percent of our 2016 oil and gas production revenues and 53 percent of our worldwide production.

Worldwide crude oil production from continuing operations decreased 14.4 Mb/d compared to 2015, primarily the result of reduced drilling activity in response to lower commodity prices and natural decline.

2015 vs. 2014   During 2015, crude oil revenues totaled $5.1 billion, approximately 49 percent lower than the 2014 total of $10.1 billion, driven by a 47 percent decrease in average crude oil prices and a 4 percent decrease in worldwide production. Average daily production in 2015 was 289.6 Mb/d, with prices averaging $48.31 per barrel. Crude oil represented 78 percent of our 2015 oil and gas production revenues and 53 percent of our equivalent production, compared to 79 and 51 percent, respectively, in the prior year. Lower realized prices reduced revenues $4.8 billion, while lower production volumes reduced revenues an additional $222 million.

Worldwide crude oil production from continuing operations decreased 12.6 Mb/d. When excluding production from asset divestitures during 2015 and 2014, crude oil production remained essentially flat as drilling and recompletion activity in our North American onshore regions offset natural decline in all regions.

Natural Gas Revenues

2016 vs. 2015   Natural gas revenues for 2016 totaled $1.0 billion, a $209 milliondecrease from the 2015 total of $1.2 billion. A 4 percentdecrease in average production reduced2016 revenues by $38 million compared to 2015, while 14 percentlower average realized prices decreased revenues by $171 million. Average daily production in 2016 was 1,103 MMcf/d, with prices averaging $2.40 per Mcf. Natural gas accounted for 18 percent of our 2016 oil and gas production revenues and 35 percent of our worldwide production.

Worldwide gas production from continuing operations decreased 46.5 MMcf/d compared to 2015, primarily the result of reduced drilling activity in response to lower commodity prices and natural decline.

2015 vs. 2014   Natural gas revenues of $1.2 billion for 2015 were $841 million lower than 2014, the result of a 31 percent decrease in realized prices and a 16 percent decrease in production volumes. Worldwide production decreased 222.4 MMcf/d, lowering revenues by $228 million. Realized prices in 2015 averaged $2.80 per Mcf, a decrease of $1.23 per Mcf compared to 2014, which decreased revenues by $613 million.

Worldwide gas production from continuing operations decreased 16 percent. Excluding production from asset divestitures during 2015 and 2014, gas production decreased only 2 percent. This decrease was driven primarily by natural decline and well shut-ins in Egypt and Canada. This decrease was primarily offset by drilling and recompletion activity in North America onshore regions.

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NGL Revenues

2016 vs. 2015   NGL revenues for 2016 totaled $228 million, essentially unchanged from 2015. A 1 percentincrease in average production was offset by 1 percentlower average realized prices. Average daily production in 2016 was 62.7 Mb/d, with prices averaging $9.92 per barrel. NGLs accounted for nearly 4 percent of our 2016 oil and gas production revenues and 12 percent of our worldwide production.

2015 vs. 2014   NGL revenues totaled $227 million in 2015, a decrease of $441 million from 2014, the result of a 7 percent decrease in production volumes and a 63 percent decrease in realized prices. Worldwide production from continuing operations decreased 4.8 Mb/d, reducing revenues by $17 million. Realized prices in 2015 averaged $9.98 per barrel, a decrease of $17.30 per barrel, which reduced revenues by $424 million.

Operating Expenses

The table below presents a comparison of our expenses on an absolute dollar basis and an equivalent unit of production (boe) basis. Our discussion may reference expenses on a boe basis, on an absolute dollar basis or both, depending on context. All operating expenses include costs attributable to a noncontrolling interest in Egypt. Operating expenses for all periods exclude discontinued operations in Argentina and Australia.

	For the Year Ended December 31,
	2016		2015		2014		2016		2015		2014
	(In millions)						(Per boe)
Lease operating expenses(1)	$	1,494	$	1,854	$	2,238	$	7.85	$	9.35	$	10.26
Gathering and transportation(1)	200		211		273		1.05		1.05		1.25
Taxes other than income	126		282		577		0.66		1.42		2.65
Exploration	473		2,771		2,499		2.48		13.97		11.45
General and administrative	410		380		453		2.15		1.92		2.07
Depreciation, depletion and amortization:
Oil and gas property and equipment(1)	2,460		2,976		4,195		12.92		15.01		19.22
Other assets	158		324		331		0.83		1.63		1.52
Asset retirement obligation accretion	156		145		154		0.82		0.73		0.71
Impairments	1,103		9,472		7,102		5.78		47.75		32.55
Transaction, reorganization, and separation	39		132		67		0.20		0.67		0.31
Financing costs, net	417		511		413		2.18		2.58		1.89

(1) For expenses impacted by the timing of 2016 liftings in the North Sea, per-boe calculations are based on sales volumes rather than production volumes.

Lease Operating Expenses (LOE)

LOE includes 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 more than half of our 2016 production, is inherently more expensive to produce than natural gas. Repair and maintenance costs are typically higher on offshore properties.

During 2016, LOE decreased$360 million, or 19 percent, on an absolute dollar basis compared to 2015. On a per-unit basis, LOE decreased$1.50, or 16 percent compared to 2015. During 2015, LOE decreased$384 million, or 17 percent, on an absolute dollar basis compared to 2014. On a per-unit basis, LOE decreased$0.91, or 9 percent, compared to 2014. These reductions reflect our continued focus on cost reductions consistent with the current price environment.

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Gathering and Transportation

Apache generally sells 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 Egypt, our oil and natural gas production that is sold to EGPC is primarily under netback arrangements. The Egypt crude oil that is exported is sold under both types of arrangements.

2016 vs. 2015  Gathering and transportation costs decreased$11 million from 2015. The decrease was driven primarily by a decrease in volumes and rate changes in Canada, partially offset by rate changes in the Permian Basin.

2015 vs. 2014  Gathering and transportation costs decreased $62 million from 2014. The decrease was driven primarily by North American onshore divestitures.

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 waters off the coast of the U.S., 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 and various Canadian taxes, including the Freehold Mineral tax and Saskatchewan Resource surcharge.

2016 vs. 2015  Taxes other than income in 2016 were $156 million lower than 2015. In the third quarter of this year, the rate of U.K. PRT, historically assessed on qualifying fields in the U.K. North Sea, was reduced to zero percent effective January 1, 2016.  As a result, U.K. PRT decreased $92 million over the comparable 2015 period. Severance tax decreased $25 million as a result of the decline in oil and gas production and lower prices. Ad valorem taxes decreased $21 million as a result of a decrease in property values in 2016.

2015 vs. 2014  Taxes other than income in 2015 were $295 million lower than 2014. U.K. PRT decreased $118 million over the comparable 2014 period as the result of decreased production revenues in the North Sea from qualifying fields during the year. Severance tax decreased $138 million as the result of lower revenues and the divestiture of properties in Louisiana and Oklahoma. Ad valorem taxes decreased $27 million as a result of property divestitures.

Exploration Expense

Exploration expense includes unproved leasehold impairments, exploration dry hole expense, geological and geophysical expense, and the costs of maintaining and retaining unproved leasehold properties. The following table presents a summary of these expenses:

	For the Year Ended December 31,
	2016		2015		2014
	(In millions)
Unproved leasehold impairments	$	272	$	2,462	$	1,976
Dry hole expense	81		133		318
Geological and geophysical expense	44		89		122
Exploration overhead and other	76		87		83
	$	473	$	2,771	$	2,499

2016 vs. 2015  Exploration expenses in 2016decreased$2.3 billion, or 83 percent, compared to 2015, primarily a result of stabilizing commodity and leasehold prices reducing unproved leasehold impairments during 2016 in all key geographic areas. Dry hole expense decreased $52 million primarily as a result of reduced capital spending during 2016. Geological and geophysical expense decreased by $45 million during 2016 compared to 2015 as a result of reduced capital spending.

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2015 vs. 2014  Exploration expenses in 2015 increased$272 million, or 11 percent, compared to 2014 as lower commodity prices impacted exploration activity and resulted in unproved leasehold impairments increasing in all key geographic areas. This increase was partially offset by reduced exploration dry hole costs in 2015. Dry hole expense was $185 million higher in 2014 as a result of unsuccessful drilling activities expensed in that period associated with wells primarily in the Gulf of Mexico and Egypt. Geological and geophysical expense decreased $33 million as a result of fewer seismic purchases in Canada during 2015.

General and Administrative (G&A) Expenses

2016 vs. 2015  G&A expenses increased$30 million, or 8 percent, from 2015. On a per-unit basis, G&A expenses increased$0.23 to $2.15 per boe. The increase in G&A expense was primarily related to non-cash stock-based compensation expense.

2015 vs. 2014  G&A expenses decreased$73 million, or 16 percent, from 2014. On a per-unit basis, G&A expenses decreased$0.15 to $1.92 per boe. These reductions reflect Apache’s intense focus on driving internal efficiencies and bringing overhead in line with the current commodity price environment. In 2015, we rationalized our entire organizational structure, eliminating layers of management, consolidating office locations, and reducing corporate and regional staffing to more closely align with activity levels expected in the future.

Depreciation, Depletion and Amortization (DD&A)

2016 vs. 2015  Oil and gas property DD&A expense of $2.5 billion in 2016decreased$516 million compared to 2015. The Company’s oil and gas property DD&A rate decreased$2.09 per boe in 2016 compared to 2015. The primary factor driving both lower absolute dollar expense and lower DD&A per boe rates was the reduction in the Company’s oil and gas properties as a result of impairments to proved properties in 2015 and 2016. Other asset depreciation decreased$166 million compared to 2015primarily related to a reduction in the Company’s gas gathering, transmission, and processing (GTP) assets as a result of impairments to GTP assets during 2015.

2015 vs. 2014  Oil and gas property DD&A expense decreased $1.2 billion compared to 2014. The Company’s oil and gas property DD&A rate decreased $4.21 to $15.01 per boe in 2015 compared to 2014. The primary factor driving both lower absolute dollar expense and lower DD&A per boe rates was the reduction in the Company’s oil and gas properties as a result of impairments to proved properties in 2014 and 2015. Other asset depreciation remained relatively flat.

Impairments

During 2016, the Company recorded asset impairments totaling $1.1 billion in connection with fair value assessments, including $486 million for a PRT decommissioning asset that is no longer expected to be realizable from future abandonment activities in the North Sea, $427 million impairments of oil and gas proved properties in the U.S. and Canada, $135 million impairments of certain GTP facilities in the North Sea, and $55 million for inventory write-downs.

During 2015, the Company recorded asset impairments totaling $9.5 billion, including $7.4 billion impairments of oil and gas proved properties, $1.7 billion impairments of GTP facilities, a $148 million impairment of our YPHPL equity method investment sold in the fourth quarter, $163 million impairment of goodwill in our North Sea reporting unit, and $55 million for inventory write-downs. Oil and gas proved property impairments resulted from lower commodity prices and downward revisions of reserves resulting from changes to the Company's development plans in certain areas. GTP impairments included $555 million for facilities in Canada, $102 million in the U.S., and $1.1 billion in Egypt. The Egyptian impairments resulted in net losses for the year in the applicable concessions, significantly reducing tax expense recorded under our production-sharing contracts.

During 2014, the Company recorded asset impairments totaling $7.1 billion, including $6.1 billion impairments of oil and gas proved properties, $655 million impairment of assets held for sale, $347 million impairments of goodwill in our U.S. and Canadian reporting units, and $32 million for inventory write-downs.

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The following table presents a summary of asset impairments recorded for 2016, 2015, and 2014:

	For the Year Ended December 31,
	2016		2015		2014
	(In millions)
Oil and gas proved property	$	427	$	7,389	$	6,068
GTP facilities	135		1,717		—
Equity method investment	—		148		—
Assets held for sale	—		—		655
Goodwill	—		163		347
PRT decommissioning asset	486		—		—
Inventory	55		55		32
Total impairments	$	1,103	$	9,472	$	7,102

Transaction, Reorganization, and Separation Costs

Apache recorded $39 million, $132 million and $67 million of expenses during 2016, 2015, and 2014, respectively, primarily related to company reorganization, including separation costs, investment banking fees and other associated costs. The charges for 2016 include $33 million for employee separation and $6 million for consolidation of office space and other reorganization efforts.

Financing Costs, Net

Financing costs incurred during the period comprised the following:

	For the Year Ended December 31,
	2016			2015			2014
	(In millions)
Interest expense	$	464		$	486		$	499
Amortization of deferred loan costs	8			11			6
Capitalized interest	(48		)	(15		)	(85		)
Loss on extinguishment of debt	1			39			—
Interest income	(8		)	(10		)	(7		)
Total Financing costs, net	$	417		$	511		$	413

2016 vs. 2015  Net financing costs decreased$94 million from 2015. The decrease is primarily related to an increase of $33 million in capitalized interest, a decrease of $22 million in interest expense, and a $39 million loss on the early extinguishment of debt incurred in 2015.

2015 vs. 2014  Net financing costs increased$98 million from 2014. The increase is primarily related to a decrease of $70 million in capitalized interest from lower asset balances qualifying for capitalized interest and a $39 million loss on the early extinguishment of debt during 2015, partially offset by a decrease of $13 million in interest expense resulting from lower average debt balances.

Provision for Income Taxes

The 2016 income tax benefit from continuing operations totaled $442 million. During 2016, Apache’s effective tax rate was impacted primarily by non-cash impairments of the carrying value of the Company’s oil and gas properties, non-cash impairments of the Company’s PRT decommissioning asset, the impact of the change in U.K. statutory income tax rate, and an increase in the amount of valuation allowances on U.S. and Canadian deferred tax assets.

In 2016, the U.K. government enacted Finance Bill 2016 which provides income tax relief to Exploration and Production (E&P) companies operating in the North Sea through a reduction of Supplementary Charge from 20 percent to 10 percent, effective January 1, 2016. As a result of the enacted legislation in the third quarter of 2016, the Company recorded a deferred tax benefit of $238 million related to the remeasurement of the Company’s December 31, 2015 U.K. deferred income tax liability.

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In 2015, Apache repatriated the sales proceeds from the divestment of its interest in LNG projects and Australian upstream assets. Upon the repatriation of these proceeds, Apache recognized a U.S. current income tax liability of $560 million. Pursuant to its plan of divestiture of these assets, Apache recorded a deferred income tax liability of $560 million on undistributed foreign earnings in 2014.

The 2015 income tax benefit from continuing operations totaled $1.0 billion. The 2015 effective tax rate reflects the tax benefit from $11.9 billion of asset impairments, the recognition of $2.1 billion of deferred tax assets related to foreign tax credit carryforwards, and an increase in valuation allowance against the Canadian region’s net deferred tax assets. Separately, the U.K. government enacted Finance Bill 2015 which provided income tax relief to E&P companies operating in the North Sea through a reduction of Supplementary Charge from 32 percent to 20 percent, effective January 1, 2015. As a result of the enacted legislation, in 2015, Apache recorded a deferred tax benefit of $414 million related to the remeasurement of the Company’s December 31, 2014 U.K. deferred income tax liability.

For additional information regarding income taxes, please refer to Note 9—Income Taxes in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.

Capital Resources and Liquidity

Operating cash flows are the Company’s primary source of liquidity. We may also elect to utilize available cash on hand, committed borrowing capacity, access to both debt and equity capital markets, or proceeds from the 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, as well as costs and sales volumes. Significant changes in commodity prices impact our revenues, earnings and cash flows. These changes potentially impact our liquidity if costs do not trend with changes in commodity prices. Historically, costs have trended with commodity prices, albeit on a lag. Sales volumes also impact cash flows; however, they have a less volatile impact 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 drilling program and our ability to add reserves economically. Deterioration in commodity prices also impacts estimated quantities of proved reserves. During 2016, we recognized negative reserve revisions of approximately 11 percent of our year-end 2015 estimated proved reserves as a result of lower prices. If realized prices for the remainder of 2017 approximate commodity futures prices as of December 31, 2016, the Company does not expect additional negative revisions for the year.

The Company currently plans to increase 2017 capital investments by more than 60 percent from 2016 spending, to approximately $3.1 billion, excluding capital associated with the one-third noncontrolling interest in Egypt. The Company’s 2017 plan assumes $50 per barrel for WTI, $51 per barrel for Brent indexed crude, $3.15 per Mcf for NYMEX natural gas, and $5.25 per Mcf for UK-indexed gas. At these price levels, our capital program will exceed anticipated operating cash flows. Based on current strip pricing, the remaining outspend will be funded primarily by proceeds from non-core asset sales, approximately $400 million of which has already occurred. In early 2017, the Company entered into put option contracts which will mitigate the downside risk of price volatility while providing full exposure to upside price potential. Nearly two-thirds, or approximately $2 billion, of Apache’s capital spending in 2017 will be allocated to the Permian Basin, primarily in the Midland and Delaware Basins. This allocation includes approximately $500 million for construction of infrastructure at Alpine High. International spending will account for approximately 30 percent of Apache’s total 2017 budget, split nearly evenly between Egypt and the North Sea. Apache’s remaining capital budget is allocated between its remaining North American regions and an exploration well in Suriname expected to commence drilling in the first quarter.

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

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

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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,
	2016			2015		2014
	(In millions)
Sources of Cash and Cash Equivalents:
Net cash provided by continuing operating activities	$	2,453		$	2,554	$	7,013
Proceeds from Australian divestitures	—			4,693		—
Net cash provided by Argentina discontinued operations	—			—		788
Proceeds from asset divestitures	134			1,513		3,092
Commercial paper and bank loan borrowings, net	—			—		1,568
Other	148			59		—
	2,735			8,819		12,461
Uses of Cash and Cash Equivalents:
Capital expenditures	$	1,768		$	4,441	$	9,489
Leasehold and property acquisitions	181			367		1,475
Net cash used by Australia discontinued operations	23			208		105
Commercial paper, credit facility and bank loan repayments, net	—			1,570		—
Payments on fixed-rate debt	181			939		—
Shares repurchased	—			—		1,864
Dividends paid	379			377		365
Distributions to noncontrolling interest	293			129		140
Other	—			—		250
	2,825			8,031		13,688
Increase (decrease) in cash and cash equivalents	$	(90	)	$	788	$	(1,227	)

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, exploratory dry hole expense, asset impairments, and deferred income tax expense.

Net cash provided by continuing operating activities for 2016 totaled $2.5 billion, down $101 million from 2015. The decrease primarily reflects lower commodity prices.

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

Australia Discontinued Operations

During 2015, Apache completed the sale of its Wheatstone LNG project and associated upstream assets to Woodside for total proceeds of $2.8 billion. During 2015, Apache also completed the sale of its Australian subsidiary Apache Energy Limited (AEL) to a consortium of private equity funds managed by Macquarie Capital Group Limited and Brookfield Asset Management Inc. for total proceeds of $1.9 billion. The results of operations for the divested Australian assets, asset impairments, and losses on disposal are classified as discontinued operations in all periods presented in this Annual Report on Form 10-K.

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Argentina Discontinued Operations

During 2014, Apache completed the sale of our Argentina operations and properties to YPF Sociedad Anónima for cash proceeds of $800 million (subject to customary closing adjustments). The results of operations related to Argentina have been classified as discontinued operations in all periods presented in this Annual Report on Form 10-K. Net cash provided by Argentina discontinued operations for the first quarter of 2014 was $2 million.

Asset Divestitures

During 2016, 2015, and 2014, Apache recorded proceeds from divestitures totaling $134 million, $1.5 billion, and $3.1 billion, respectively. For information regarding our acquisitions and divestitures, please see Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.

Egypt Noncontrolling Interest

Sinopec International Petroleum Exploration and Production Corporation (Sinopec) holds a one-third minority participation interest in Apache’s oil and gas business in Egypt. Apache made cash distributions totaling $293 million, $129 million, and $140 million to Sinopec in 2016, 2015, and 2014, respectively.

Capital Expenditures

During 2016, 2015, and 2014, capital spending for exploration and development (E&D) activities totaled $1.6 billion, $4.2 billion, and $8.6 billion, respectively. This reduction is a direct result of our proactive measures to adjust our capital budget to reflect lower commodity prices and operating cash flows during 2016. Apache’s E&D capital spending was evenly distributed between our North American onshore and international regions. Apache’s investment in gas gathering, transmission, and processing facilities totaled $158 million, $233 million, and $881 million during 2016, 2015, and 2014, respectively. GTP expenditures in 2016 primarily comprise investments in infrastructure for the Alpine High play.

Apache also completed leasehold and property acquisitions totaling $181 million, $367 million, and $1.5 billion in 2016, 2015, and 2014, respectively. Our acquisition investments continued to focus on adding new leasehold positions to our North American onshore portfolio.

Shares Repurchased

Apache’s Board of Directors has authorized the purchase of up to 40 million shares of the Company’s common stock. 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, and through December 31, 2014, had repurchased a total of 32.2 million shares at an average price of $88.96 per share. The Company has not purchased any additional shares during 2016 or 2015 and is not obligated to acquire any specific number of shares.

Dividends

The Company has paid cash dividends on its common stock for 52 consecutive years through 2016. Future dividend payments will depend on the Company’s level of earnings, financial requirements, and other relevant factors. Common stock dividends paid during 2016 totaled $379 million, compared with $377 million in 2015 and $365 million in 2014.

Liquidity

	At December 31,
	2016		2015
	(In millions)
Cash and cash equivalents	$	1,377	$	1,467
Total debt	8,544		8,717
Equity	7,679		9,490
Available committed borrowing capacity	3,500		3,500

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Cash and Cash Equivalents

At December 31, 2016, we had $1.4 billion in cash and cash equivalents, of which $1 billion of cash was held by foreign subsidiaries, and approximately $347 million was held by Apache Corporation and U.S. subsidiaries. The cash held by foreign subsidiaries should not be subject to additional U.S. income taxes if repatriated. The majority of the cash is invested in highly liquid, investment-grade instruments with maturities of three months or less at the time of purchase.

Debt

At December 31, 2016, outstanding debt, which consisted of notes and debentures, totaled $8.5 billion. We have $550 million maturing in 2018, $150 million maturing in 2019, $493 million maturing in 2021, and the remaining maturing in years 2022 through 2096. At December 31, 2016, we had $483,000 of notes due March 2017 classified as current debt on the consolidated balance sheet.

In November 2016, the Company initiated a program to purchase in the open market up to $250 million in aggregate principal amount of senior notes issued under its indentures. In the fourth quarter of 2016, Apache purchased and canceled $181 million aggregate principal amount of its senior notes through open market repurchases for $182 million in cash, including accrued interest and $0.5 million of premium. These repurchases resulted in a $1 million net loss on extinguishment of debt, which is included in “Financing costs, net” in our statement of consolidated operations. The net loss includes an acceleration of related discount and deferred financing costs.

In January 2017, we purchased and canceled an additional $69 million aggregate principal amount of senior notes for $71 million in cash, including accrued interest and $1 million of premium, which completed the open market repurchase program.

Available Credit Facilities

In June 2015, the Company entered into a five-year revolving credit facility which matures in June 2020, subject to Apache’s two, one-year extension options. The facility provides for aggregate commitments of $3.5 billion (including a $750 million letter of credit subfacility), with rights to increase commitments up to an aggregate $4.5 billion. Proceeds from borrowings may be used for general corporate purposes. Apache’s available borrowing capacity under this facility supports its commercial paper program. In connection with entry into the $3.5 billion facility, Apache terminated $5.3 billion in commitments under existing credit facilities. As of December 31, 2016, there were no borrowings under this credit facility, leaving aggregate available borrowing capacity at $3.5 billion.

At the Company’s option, the interest rate per annum for borrowings under the 2015 facility is either a base rate, as defined, plus a margin, or the London Inter-bank Offered Rate (LIBOR), plus a margin. The Company also pays quarterly a facility fee at a per annum rate on total commitments. The margins and the facility fee vary based upon the Company’s senior long-term debt rating. At December 31, 2016, the base rate margin was 0.075 percent, the LIBOR margin was 1.075 percent, and the facility fee was 0.175 percent.

The financial covenants of the 2015 credit facility require the Company to maintain an adjusted debt-to-capital ratio of not greater than 60 percent at the end of any fiscal quarter. For purposes of this calculation, capital excludes the effects of non-cash write-downs, impairments, and related charges occurring after June 30, 2015. At December 31, 2016, the Company’s debt-to-capital ratio as calculated under the credit facility was 33 percent.

The 2015 facility's negative covenants restrict the ability of the Company and its subsidiaries to create liens securing debt on its hydrocarbon-related assets, with exceptions for liens typically arising in the oil and gas industry, purchase money liens, liens on subsidiary assets located outside of the United States and Canada, and liens arising as a matter of law, such as tax and mechanics’ liens. The Company also may incur liens on assets if debt secured thereby does not exceed 5 percent of the Company’s consolidated assets, or approximately $1.1 billion as of December 31, 2016. Negative covenants also restrict Apache’s ability to merge with another entity unless it is the surviving entity, dispose of substantially all of its assets, and guarantee debt of non-consolidated entities in excess of the stated threshold.

In February 2016, Apache entered into a three-year letter of credit facility providing £900 million in commitments, with options to increase commitments to £1.075 billion and extend the term by one year. The facility is available for letters of credit denominated in pounds sterling, U.S. dollars, Canadian dollars, and any other foreign currency consented to by an issuing bank. The facility also is available for loans in pounds sterling, U.S. dollars, and Canadian dollars to cash collateralize letters of credit or obligations to provide letters of credit, in each case, to the extent letters of credit are unavailable under the facility. The facility’s representations and warranties, covenants, and events of default are substantially similar to those in Apache’s 2015 $3.5 billion revolving credit facility.

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Commissions are payable on letters of credit outstanding under the 2016 facility at a per annum rate equal to a LIBOR margin. Borrowings bear interest per annum at a base rate or LIBOR, plus a margin. A facility fee at a per annum rate on aggregate commitments also is payable. Letter of credit commissions, the interest margin, and the facility fee vary depending on Apache’s senior unsecured long-term debt rating. At December 31, 2016, the LIBOR margin was 1.075 percent, the base rate margin was 0.075 percent, and the facility fee was 0.175 percent.

The 2016 facility is available for the Company’s letter of credit needs, particularly those which may arise in respect of abandonment obligations assumed in various North Sea acquisitions. As of December 31, 2016, three letters of credit aggregating approximately £147.5 million and no borrowings were outstanding under this facility.

There are no clauses in the 2015 $3.5 billion or 2016 £900 million credit facilities that permit the lenders to accelerate payments or refuse to lend based on unspecified material adverse changes. The agreements for these facilities 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 payment maturity and terminate lending and issuance commitments for nonpayment and other breaches, and if the Company or any of its U.S. or Canadian subsidiaries defaults on other indebtedness in excess of the stated threshold, is insolvent, or has any unpaid, non-appealable judgment against it for payment of money in excess of the stated threshold. Lenders may also accelerate payment maturity and terminate lending and issuance commitments if the Company undergoes a specified change in control or any borrower has specified pension plan liabilities in excess of the stated threshold. The Company was in compliance with the terms of these credit facilities as of December 31, 2016.

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

Commercial Paper Program

As of December 31, 2016, the Company has available a $3.5 billion commercial paper program. The commercial paper program 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 the Company’s 2015 $3.5 billion committed credit facility. If the Company is unable to issue commercial paper following a significant credit downgrade or dislocation in the market, the Company’s 2015 committed credit facility, which expires in 2020, is available as a 100 percent backstop. As of December 31, 2016, the Company had no borrowings under its commercial paper program.

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.

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Contractual Obligations

The following table summarizes the Company’s contractual obligations as of December 31, 2016. For additional information regarding these obligations, please see Note 8—Debt and Note 10—Commitments and Contingencies in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.

Contractual Obligations(1)	Note Reference	Total		2017		2018-2019		2020-2021		2022 & Beyond
	(In millions)
On-Balance Sheet:
Debt, at face value	Note 8	$	8,650	$	—	$	700	$	493	$	7,457
Interest payments	Note 8	8,622		440		836		772		6,574
Capital lease(2)		43		1		3		3		36
Off-Balance Sheet:
Drilling rigs		244		177		67		—		—
Purchase obligations(3)	Note 10	680		119		287		250		24
Operating lease obligations(4)	Note 10	258		56		95		37		70
Total Contractual Obligations		$	18,497	$	793	$	1,988	$	1,555	$	14,161

(1) This table does not include the Company’s liability for dismantlement, abandonment, and restoration costs of oil and gas properties or pension or postretirement benefit obligations. For additional information regarding these liabilities, please see Notes 7 and 11, respectively, in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.

(2) This represents our capital lease obligation discounted at 4.4 percent for a Midland office building.

(3) Amounts represent any agreements to purchase goods or services that are enforceable and legally binding and that specify all significant terms. These include minimum commitments associated with long-term take-or-pay contracts, NGL processing agreements, drilling work program commitments, and agreements to secure capacity rights on third-party pipelines. Amounts exclude certain product purchase obligations related to marketing and trading activities for which there are no minimum purchase requirements or the amounts are not fixed or determinable.

(4) Amounts include long-term lease payments for office space, aircraft, supply and standby vessels, gas pipeline and land leases, and equipment related to exploration, development, and production activities, such as compressors. The Company expects to receive $10 million in sublease income associated with these leases.

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 believes that it has adequately reserved for its contingent obligations, including approximately $51 million for environmental remediation and approximately $15 million for various contingent legal liabilities. For a detailed discussion of the Company’s environmental and legal contingencies, please see Note 10—Commitments and Contingencies in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.

In addition to our recorded environmental and legal liabilities, we have potential exposure to future obligations related to divested properties. Apache has divested various leases, wells, and facilities located in the Gulf of Mexico where the purchasers typically assume all obligations to plug, abandon, and decommission the associated wells, structures, and facilities acquired. One or more of the counterparties in these transactions could, either as a result of the severe decline in oil and natural gas prices or other factors related to the historical or future operations of their respective businesses, face financial problems that may have a significant impact on their solvency and ability to continue as a going concern. If a purchaser of our Gulf of Mexico assets becomes the subject of a case or proceeding under relevant insolvency laws or otherwise fails to perform required abandonment obligations, Apache could be required to perform such actions under applicable federal laws and regulations. In such event, we may be forced to use available cash to cover the costs of such liabilities and obligations should they arise.

With respect to our retained oil and gas operations in the Gulf of Mexico, the Bureau of Ocean Energy Management (BOEM) has issued Notice to Lessees (NTL) No. 2016-N01 pertaining to the obligations of companies to provide supplemental assurances for performance with respect to plugging, abandonment, decommissioning, and site clearance obligations associated with wells, platforms, structures, and facilities located upon or used in connection with such companies’ oil and gas leases. Under this NTL, the Company will likely be required to provide additional security to BOEM with respect to plugging, abandonment, and decommissioning obligations relating to the Company’s current ownership interests in various Gulf of Mexico leases. We are working closely with the BOEM to make arrangements for the provision of such additional required security, if such security becomes necessary under the new NTL. Additionally, we are not able to predict the effect that these changes might have on counterparties to which Apache has sold Gulf of Mexico assets. Such changes could cause the bonding obligations of such parties to increase substantially, thereby causing a significant impact on the counterparties’ solvency and ability to continue as a going concern.

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Insurance Program

We maintain insurance policies that include coverage for physical damage to our assets, general liabilities, workers’ compensation, employers’ liability, sudden and accidental pollution, and other risks. Our insurance coverage is subject to deductibles or retentions that we must satisfy prior to recovering on insurance. Additionally, our insurance is subject to policy exclusions and limitations. There is no assurance that our insurance will adequately protect us against liability from all potential consequences and damages.

Our current insurance policies covering physical damage to our assets provide up to $1 billion in coverage per occurrence. These policies also provide sudden and accidental pollution coverage. Coverage for Gulf of Mexico named windstorms is excluded from this coverage.

Our current insurance policies covering general liabilities provide approximately $500 million in coverage, scaled to Apache’s interest. 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.

Apache purchases multi-year political risk insurance from the Overseas Private Investment Corporation (OPIC) and highly-rated insurers covering a portion of its investments in Egypt for losses arising from confiscation, nationalization, and expropriation risks. The Islamic Corporation for the Insurance of Investment and Export Credit (ICIEC, an agency of the Islamic Development Bank) reinsures OPIC. In the aggregate, these insurance policies provide up to $750 million of coverage to Apache, subject to policy terms and conditions and a retention of approximately $1 billion.

Apache has an additional insurance policy with OPIC, which, subject to policy terms and conditions, provides up to $300 million of coverage through 2024 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. The Multilateral Investment Guarantee Agency (MIGA), a member of the World Bank Group, provides $150 million in reinsurance to OPIC.

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.

Critical Accounting Policies and Estimates

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

Reserves Estimates

Proved oil and gas reserves are the estimated quantities of natural gas, crude oil, condensate, and NGLs that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing conditions, operating conditions, and government regulations.

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

Despite the inherent imprecision in these engineering estimates, our reserves are used throughout our financial statements. For example, since we use the units-of-production method to amortize our oil and gas properties, the quantity of reserves could significantly impact our DD&A expense. A material adverse change in the estimated volumes of reserves could result in property impairments. Finally, these reserves are the basis for our supplemental oil and gas disclosures.

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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. Operating costs, production and ad valorem taxes and future development costs are based on current costs with no escalation.

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

Oil and Gas Exploration Costs

Apache accounts for its exploration and production activities using the successful efforts method of accounting. Costs of acquiring unproved and proved oil and gas leasehold acreage are capitalized. Costs of drilling and equipping productive wells, including development dry holes, and related production facilities are also capitalized. Oil and gas exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. Costs associated with drilling an exploratory well are initially capitalized, or suspended, pending a determination as to whether proved reserves have been found. On a quarterly basis, management reviews the status of all suspended exploratory drilling costs in light of ongoing exploration activities and determines whether the Company is making sufficient progress in its ongoing exploration and appraisal efforts. If management determines that future appraisal drilling or development activities are unlikely to occur, associated suspended exploratory well costs are recorded as dry hole expense and reported in exploration expense in the statement of consolidated operations. Otherwise, the costs of exploratory wells remain capitalized.

Long-Lived Assets

Long-lived assets used in operations, including proved oil and gas properties, are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in future cash flows expected to be generated by an asset group. Individual assets are grouped for impairment purposes based on a judgmental assessment of the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. If there is an indication the carrying amount of an asset may not be recovered, the asset is assessed by management through an established process in which changes to significant assumptions such as prices, volumes, and future development plans are reviewed. If, upon review, the sum of the undiscounted pre-tax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value. Because there usually is a lack of quoted market prices for long-lived assets, the fair value of impaired assets is typically determined based on the present values of expected future cash flows using discount rates believed to be consistent with those used by principal market participants. The expected future cash flows used for impairment reviews and related fair value calculations are typically based on judgmental assessments of future production volumes, commodity prices, operating costs, and capital investment plans, considering all available information at the date of review.

During the past two years, there was a substantial decline in commodity prices. The resulting change in future commodity price assumptions and impact to our future development plan was a triggering event which required us to reassess our long-lived assets for impairment. Based on the results of this assessment, we recorded impairments of certain proved oil and gas properties and gathering, transmission, and processing facilities. For discussion of these impairments, see “Fair Value Measurements” of Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements.

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 in the North Sea and Gulf of Mexico. 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. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value.

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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 ability to realize our deferred tax assets. If we conclude that it is more likely than not that some portion or all of the deferred tax assets will not be realized under accounting standards, the tax asset would be reduced by a valuation allowance. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and gas prices).

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

Purchase Price Allocation

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

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

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

Goodwill

As of December 31, 2016, the Company’s consolidated balance sheet included $87 million of goodwill, all of which has been assigned to the Egypt reporting unit. Goodwill is assessed at least annually for impairment at the reporting unit level. We conduct a qualitative goodwill impairment assessment as of July 1 of each year, and whenever impairment indicators arise, by examining relevant events and circumstances which could have a negative impact on our goodwill such as macroeconomic conditions, industry and market conditions, cost factors that have a negative effect on earnings and cash flows, overall financial performance, acquisitions and divestitures, and other relevant entity-specific events.

The first step of the impairment test requires management to make estimates regarding the fair value of each reporting unit to which goodwill has been assigned. If it is necessary to determine the fair value of the reporting unit, we use a combination of the income approach and the market approach.

Under the income approach, the fair value of each reporting unit is estimated based on the present value of expected future cash flows. The income approach is dependent on a number of factors including estimates of forecasted revenue and operating costs, proved reserves, the success of future exploration for and development of unproved reserves, discount rates, and other variables. Negative revisions of estimated reserves quantities, increases in future cost estimates, divestiture of a significant component of the reporting unit, or sustained decreases in crude oil or natural gas prices could lead to a reduction in expected future cash flows and possibly an impairment of all or a portion of goodwill in future periods.

Key assumptions used in the discounted cash flow model described above include estimated quantities of crude oil and natural gas reserves, including both proved reserves and risk-adjusted unproved reserves; estimates of market prices considering forward commodity price curves as of the measurement date; and estimates of operating, administrative, and capital costs adjusted for inflation. We discount the resulting future cash flows using discount rates similar to those used by the Company in the valuation of acquisitions and divestitures.

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To assess the reasonableness of our fair value estimate, we use a market approach to compare the fair value to similar businesses whose securities are actively traded in the public market. This requires management to make certain judgments about the selection of comparable companies, recent comparable asset transactions, and transaction premiums. Associated market multiples are applied to various financial metrics of the reporting unit to estimate fair value.

Although we base the fair value estimate of each reporting unit on assumptions we believe to be reasonable, those assumptions are inherently unpredictable and uncertain, and actual results could differ from the estimate. In the event of a prolonged global recession, commodity prices may stay depressed or decline further, thereby causing the fair value of the reporting unit to decline, which could result in an impairment of goodwill.

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 2016, our average crude oil realizations decreased to $41.63 per barrel compared to $48.31 per barrel in 2015. Our average natural gas price realizations decreased 14 percent in 2016 to $2.40 per Mcf from $2.80 per Mcf in 2015. Based on average daily production for 2016, a $1.00 per barrel change in the weighted average realized oil price would have increased or decreased revenues for the year by approximately $101 million, and a $0.10 per Mcf change in the weighted average realized price of natural gas would have increased or decreased revenues for the year by approximately $40 million.

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. During 2016 and 2015, the Company did not have any derivative positions.

Subsequent to December 31, 2016, the Company entered into put option derivative contracts not designated as cash flow hedges for 2017 crude oil production of 175,000 barrels per day. These contracts will be settled against either NYMEX WTI or Dated Brent between July 1, 2017 and December 31, 2017, with a weighted average strike price of $50.47 per barrel. Apache paid a total premium of $100 million for these contracts, averaging $3.09 per barrel.

See Note 5—Derivative Instruments and Hedging Activities in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.

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 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, substantially 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 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 Canadian dollar and British pound against the U.S. dollar as of December 31, 2016, would result in a foreign currency net loss or gain, respectively, of approximately $99 million.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The financial statements and supplementary financial information required to be filed under this Item 8 are presented on pages F-1 through F-70 in Part IV, Item 15 of this Form 10-K and are incorporated herein by reference.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

The financial statements for the fiscal years ended December 31, 2016, 2015, and 2014, included in this report, have been audited by Ernst & Young LLP, independent registered public accounting firm, as stated in their audit report appearing herein. There have been no changes in or disagreements with the accountants during the periods presented.

ITEM 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

John J. Christmann IV, the Company’s Chief Executive Officer and President, in his capacity as principal executive officer, and Stephen J. Riney, the Company’s Executive Vice President and Chief Financial Officer, in his capacity as principal financial officer, evaluated the effectiveness of our disclosure controls and procedures as of December 31, 2016, the end of the period covered by this report. Based on that evaluation and as of the date of that evaluation, these officers concluded that the Company’s disclosure controls and procedures were effective, providing effective means to ensure that the information we are required to disclose under applicable laws and regulations is recorded, processed, summarized, and reported within the time periods specified in the Commission’s rules and forms and accumulated and communicated to our management, including our principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure. We made no changes in internal controls over financial reporting during the quarter ending December 31, 2016, that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

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

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

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

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

Changes in Internal Control over Financial Reporting

There was no change in our internal controls over financial reporting during the quarter ending December 31, 2016, that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

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PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The information set forth under the captions “Nominees for Election as Directors,” “Continuing Directors,” “Executive Officers of the Company,” and “Securities Ownership and Principal Holders” in the proxy statement relating to the Company’s 2017 annual meeting of shareholders (the Proxy Statement) is incorporated herein by reference.

Code of Business Conduct

Pursuant to Rule 303A.10 of the NYSE and Rule 4350(n) of the NASDAQ, we are required to adopt a code of business conduct and ethics for our directors, officers, and employees. In February 2004, the Board of Directors adopted the Code of Business Conduct (Code of Conduct), and revised it in July 2016. The revised Code of Conduct also meets the requirements of a code of ethics under Item 406 of Regulation S-K. You can access the Company’s Code of Conduct on the Governance page of the Company’s website at www.apachecorp.com. Any shareholder who so requests may obtain a printed copy of the Code of Conduct by submitting a request to the Company’s corporate secretary at the address on the cover of this Form 10-K. Changes in and waivers to the Code of Conduct for the Company’s directors, chief executive officer and certain senior financial officers will be posted on the Company’s website within five business days and maintained for at least 12 months. Information on our website or any other website is not incorporated by reference into, and does not constitute a part of, this Annual Report on Form 10-K.

ITEM 11. EXECUTIVE COMPENSATION

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

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

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

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

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

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

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

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PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a) Documents included in this report:

1. Financial Statements

Report of management on internal control over financial reporting	F-1
Report of independent registered public accounting firm	F-2
Report of independent registered public accounting firm	F-3
Statement of consolidated operations for each of the three years in the period ended December 31,  2016	F-4
Statement of consolidated comprehensive income (loss) for each of the three years in the period ended December 31, 2016	F-5
Statement of consolidated cash flows for each of the three years in the period ended December 31,  2016	F-6
Consolidated balance sheet as of December 31, 2016 and 2015	F-7
Statement of consolidated changes in equity for each of the three years in the period ended December  31, 2016	F-8
Notes to consolidated financial statements	F-9

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

3. Exhibits

See Index to Exhibits of this report.

ITEM 16. FORM 10-K SUMMARY

None

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SIGNATURES

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

APACHE CORPORATION

/s/ John J. Christmann IV                    

John J. Christmann IV

Chief Executive Officer and President

Dated: February 24, 2017

POWER OF ATTORNEY

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

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

Name	Title	Date
/s/ John J. Christmann IV John J. Christmann IV	Chief Executive Officer and President (principal executive officer)	February 24, 2017
/s/ Stephen J. Riney Stephen J. Riney	Executive Vice President and Chief Financial Officer (principal financial officer)	February 24, 2017
/s/ Rebecca A. Hoyt Rebecca A. Hoyt	Senior Vice President, Chief Accounting Officer, and Controller (principal accounting officer)	February 24, 2017
/s/ ANNELL R. BAY Annell R. Bay	Director	February 24, 2017
/s/ CHANSOO JOUNG Chansoo Joung	Director	February 24, 2017
/s/ GEORGE D. LAWRENCE George D. Lawrence	Director	February 24, 2017
/s/ JOHN E. LOWE John E. Lowe	Director	February 24, 2017
/s/ WILLIAM C. MONTGOMERY William C. Montgomery	Director	February 24, 2017
/s/ AMY H. NELSON Amy H. Nelson	Director	February 24, 2017
/s/ RODMAN D. PATTON Rodman D. Patton	Director	February 24, 2017
/s/ CHARLES J. PITMAN Charles J. Pitman	Director	February 24, 2017
/s/ DANIEL W. RABUN Daniel W. Rabun	Director	February 24, 2017
/s/ PETER A. RAGAUSS Peter A. Ragauss	Director	February 24, 2017

51

REPORT OF MANAGEMENT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

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

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

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

Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2016. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control – Integrated Framework (2013). Based on our assessment, management believes that the Company maintained effective internal control over financial reporting as of December 31, 2016.

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

/s/  John J. Christmann IV

Chief Executive Officer and President

(principal executive officer)

/s/  Stephen J. Riney

Executive Vice President and Chief Financial Officer

(principal financial officer)

/s/  Rebecca A. Hoyt

Senior Vice President, Chief Accounting Officer and Controller

(principal accounting officer)

Houston, Texas

February 24, 2017

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Shareholders of Apache Corporation:

We have audited the accompanying consolidated balance sheet of Apache Corporation and subsidiaries as of December 31, 2016 and 2015, and the related statements of consolidated operations, comprehensive income (loss), cash flows, and changes in equity for each of the three years in the period ended December 31, 2016. 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, 2016 and 2015, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2016, in conformity with U.S. generally accepted accounting principles.

As discussed in Note 1 to the consolidated financial statements, the Company has elected to change its method of accounting for oil and gas exploration and development activities from the full-cost method of accounting to the successful-efforts method of accounting in 2016.

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, 2016, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 24, 2017, expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Houston, Texas

February 24, 2017

F-2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Shareholders of Apache Corporation:

We have audited Apache Corporation and subsidiaries’ internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). Apache Corporation and subsidiaries’ management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Report of Management on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.

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

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

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

In our opinion, Apache Corporation and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Apache Corporation and subsidiaries as of December 31, 2016 and 2015, and the related statements of consolidated operations, comprehensive income (loss), cash flows, and changes in equity for each of the three years in the period ended December 31, 2016 of Apache Corporation and subsidiaries, and our report dated February 24, 2017, expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Houston, Texas

February 24, 2017

F-3

APACHE CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED OPERATIONS

	For the Year Ended December 31,
	2016			2015*			2014*
	(In millions, except per common share data)
REVENUES AND OTHER:
Oil and gas production revenues:
Oil revenues	$	4,172		$	5,107		$	10,110
Natural gas revenues	967			1,176			2,017
Natural gas liquids revenues	228			227			668
	5,367			6,510			12,795
Other	(34		)	98			285
Gain (loss) on divestiture	21			281			(1,608		)
	5,354			6,889			11,472
OPERATING EXPENSES:
Lease operating expenses	1,494			1,854			2,238
Gathering and transportation	200			211			273
Taxes other than income	126			282			577
Exploration	473			2,771			2,499
General and administrative	410			380			453
Depreciation, depletion, and amortization:
Oil and gas property and equipment	2,460			2,976			4,195
Other assets	158			324			331
Asset retirement obligation accretion	156			145			154
Impairments	1,103			9,472			7,102
Transaction, reorganization, and separation	39			132			67
Financing costs, net	417			511			413
	7,036			19,058			18,302
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(1,682		)	(12,169		)	(6,830		)
Current income tax provision	391			435			1,281
Deferred income tax benefit	(833		)	(1,445		)	(1,799		)
NET LOSS FROM CONTINUING OPERATIONS
INCLUDING NONCONTROLLING INTEREST	(1,240		)	(11,159		)	(6,312		)
Net income (loss) from discontinued operations, net of tax	(33		)	492			(1,707		)
NET LOSS INCLUDING NONCONTROLLING INTEREST	(1,273		)	(10,667		)	(8,019		)
Net income (loss) attributable to noncontrolling interest	132			(315		)	341
NET LOSS ATTRIBUTABLE TO COMMON STOCK	$	(1,405	)	$	(10,352	)	$	(8,360	)
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS:
Net loss from continuing operations attributable to common shareholders	$	(1,372	)	$	(10,844	)	$	(6,653	)
Net income (loss) from discontinued operations	(33		)	492			(1,707		)
Net loss attributable to common shareholders	$	(1,405	)	$	(10,352	)	$	(8,360	)
BASIC AND DILUTED NET INCOME (LOSS) PER COMMON SHARE:
Basic and diluted net loss from continuing operations per share	$	(3.62	)	$	(28.70	)	$	(17.32	)
Basic and diluted net income (loss) from discontinued operations per share	(0.09		)	1.30			(4.44		)
Basic and diluted net loss per share	$	(3.71	)	$	(27.40	)	$	(21.76	)
WEIGHTED-AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
Basic	379			378			384
Diluted	379			378			384
DIVIDENDS DECLARED PER COMMON SHARE	$	1.00		$	1.00		$	1.00

*Financial information for 2015 and 2014 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

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

F-4

APACHE CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS)

	For the Year Ended December 31,
	2016			2015*			2014*
	(In millions)
NET LOSS INCLUDING NONCONTROLLING INTEREST	$	(1,273	)	$	(10,667	)	$	(8,019	)
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and postretirement benefit plan, net of tax	7			(3		)	—
Commodity cash flow hedge activity, net of tax:
Change in fair value of derivative instruments	—			—			(1		)
	7			(3		)	(1		)
COMPREHENSIVE LOSS INCLUDING NONCONTROLLING INTEREST	(1,266		)	(10,670		)	(8,020		)
Comprehensive income (loss) attributable to noncontrolling interest	132			(315		)	341
COMPREHENSIVE LOSS ATTRIBUTABLE TO COMMON STOCK	$	(1,398	)	$	(10,355	)	$	(8,361	)

*Financial information for 2015 and 2014 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

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

F-5

APACHE CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED CASH FLOWS

	For the Year Ended December 31,
	2016			2015*			2014*
	(In millions)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss including noncontrolling interest	$	(1,273	)	$	(10,667	)	$	(8,019	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Loss (income) from discontinued operations	33			(492		)	1,707
Loss (gain) on divestitures	(21		)	(281		)	1,608
Exploratory dry hole expense and unproved leasehold impairments	353			2,595			2,294
Depreciation, depletion, and amortization	2,618			3,300			4,526
Asset retirement obligation accretion	156			145			154
Impairments	1,103			9,472			7,102
Benefit from deferred income taxes	(833		)	(1,445		)	(1,799		)
Other	164			7			(231		)
Changes in operating assets and liabilities:
Receivables	126			663			757
Inventories	(27		)	21			(31		)
Drilling advances	91			138			107
Deferred charges and other	115			(345		)	(301		)
Accounts payable	(63		)	(489		)	(216		)
Accrued expenses	(9		)	(156		)	(572		)
Deferred credits and noncurrent liabilities	(80		)	88			(73		)
NET CASH PROVIDED BY CONTINUING OPERATING ACTIVITIES	2,453			2,554			7,013
NET CASH PROVIDED BY (USED IN) DISCONTINUED OPERATIONS	(23		)	113			944
NET CASH PROVIDED BY OPERATING ACTIVITIES	2,430			2,667			7,957
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property	(1,610		)	(4,208		)	(8,608		)
Additions to gas gathering, transmission, and processing facilities	(158		)	(233		)	(881		)
Leasehold and property acquisitions	(181		)	(367		)	(1,475		)
Proceeds from sale of Kitimat LNG	—			854			—
Proceeds from sale of Yara Pilbara	—			391			—
Proceeds from sale of Deepwater Gulf of Mexico assets	—			—			1,360
Proceeds from sale of Anadarko basin and southern Louisiana assets	—			—			1,262
Proceeds from sale of oil and gas properties, other	134			268			470
Other, net	155			6			(299		)
NET CASH USED IN CONTINUING INVESTING ACTIVITIES	(1,660		)	(3,289		)	(8,171		)
NET CASH PROVIDED BY (USED IN) DISCONTINUED OPERATIONS	—			4,372			(219		)
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES	(1,660		)	1,083			(8,390		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Commercial paper, credit facilities and bank notes, net	—			(1,570		)	1,568
Payments on fixed rate debt	(181		)	(939		)	—
Distributions to noncontrolling interest	(293		)	(129		)	(140		)
Dividends paid	(379		)	(377		)	(365		)
Treasury stock activity, net	—			—			(1,864		)
Other	(7		)	53			49
NET CASH USED IN CONTINUING FINANCING ACTIVITIES	(860		)	(2,962		)	(752		)
NET CASH USED IN DISCONTINUED OPERATIONS	—			—			(42		)
NET CASH USED IN FINANCING ACTIVITIES	(860		)	(2,962		)	(794		)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(90		)	788			(1,227		)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	1,467			679			1,906
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	1,377		$	1,467		$	679
SUPPLEMENTARY CASH FLOW DATA:
Interest paid, net of capitalized interest	$	413		$	461		$	260
Income taxes paid, net of refunds	305			573			1,357

*Financial information for 2015 and 2014 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

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

F-6

APACHE CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET

	December 31,
	2016			2015*
	(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	1,377		$	1,467
Receivables, net of allowance	1,128			1,253
Inventories	476			570
Drilling advances	81			172
Prepaid assets and other	179			290
	3,241			3,752
PROPERTY AND EQUIPMENT:
Oil and gas, on the basis of successful efforts accounting:
Proved properties	42,693			41,728
Unproved properties and properties under development	1,969			2,277
Gathering, transmission, and processing facilities	976			1,052
Other	1,111			1,093
	46,749			46,150
Less: Accumulated depreciation, depletion, and amortization	(27,882		)	(25,312		)
	18,867			20,838
OTHER ASSETS:
Deferred charges and other	411			910
	$	22,519		$	25,500
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable	$	585		$	618
Other current liabilities	1,258			1,223
	1,843			1,841
LONG-TERM DEBT	8,544			8,716
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes	1,710			2,529
Asset retirement obligation	2,432			2,562
Other	311			362
	4,453			5,453
COMMITMENTS AND CONTINGENCIES (Note 10)
EQUITY:
Common stock, $0.625 par, 860,000,000 shares authorized, 412,612,102 and 411,218,105 shares issued, respectively	258			257
Paid-in capital	12,364			12,619
Accumulated deficit	(3,385		)	(1,980		)
Treasury stock, at cost, 33,172,426 and 33,183,930 shares, respectively	(2,887		)	(2,889		)
Accumulated other comprehensive loss	(112		)	(119		)
APACHE SHAREHOLDERS’ EQUITY	6,238			7,888
Noncontrolling interest	1,441			1,602
TOTAL EQUITY	7,679			9,490
	$	22,519		$	25,500

*Financial information for 2015 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

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

F-7

APACHE CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED CHANGES IN EQUITY

	Common Stock		Paid-In Capital			Retained Earnings (Accumulated Deficit)			Treasury Stock			Accumulated Other Comprehensive (Loss)			APACHE SHAREHOLDERS’ EQUITY			Non- Controlling Interest			TOTAL EQUITY
	(In millions)
BALANCE AT DECEMBER 31, 2013*	$	255	$	12,403		$	17,395		$	(1,027	)	$	(115	)	$	28,911		$	1,845		$	30,756
Net income (loss)	—		—			(8,360		)	—			—			(8,360		)	341			(8,019		)
Distributions to noncontrolling interest	—		—			—			—			—			—			(140		)	(140		)
Commodity hedges, net of tax	—		—			—			—			(1		)	(1		)	—			(1		)
Common dividends ($1.00 per share)	—		—			(380		)	—			—			(380		)	—			(380		)
Common stock activity, net	1		(11		)	—			—			—			(10		)	—			(10		)
Treasury stock activity, net	—		(1		)	—			(1,863		)	—			(1,864		)	—			(1,864		)
Compensation expense	—		202			—			—			—			202			—			202
Other	—		(3		)	—			—			—			(3		)	—			(3		)
BALANCE AT DECEMBER 31, 2014*	$	256	$	12,590		$	8,655		$	(2,890	)	$	(116	)	$	18,495		$	2,046		$	20,541
Net loss	—		—			(10,352		)	—			—			(10,352		)	(315		)	(10,667		)
Distributions to noncontrolling interest	—		—			—			—			—			—			(129		)	(129		)
Postretirement benefit plans, net of tax	—		—			—			—			(3		)	(3		)	—			(3		)
Common dividends ($1.00 per share)	—		(95		)	(283		)	—			—			(378		)	—			(378		)
Common stock activity, net	1		(15		)	—			—			—			(14		)	—			(14		)
Treasury stock activity, net	—		(1		)	—			1			—			—			—			—
Compensation expense	—		140			—			—			—			140			—			140
BALANCE AT DECEMBER 31, 2015*	$	257	$	12,619		$	(1,980	)	$	(2,889	)	$	(119	)	$	7,888		$	1,602		$	9,490
Net income (loss)	—		—			(1,405		)	—			—			(1,405		)	132			(1,273		)
Distributions to noncontrolling interest	—		—			—			—			—			—			(293		)	(293		)
Postretirement benefit plans, net of tax	—		—			—			—			7			7			—			7
Common dividends ($1.00 per share)	—		(379		)	—			—			—			(379		)	—			(379		)
Common stock activity, net	1		(39		)	—			—			—			(38		)	—			(38		)
Treasury stock activity, net	—		(1		)	—			2			—			1			—			1
Compensation expense	—		164			—			—			—			164			—			164
BALANCE AT DECEMBER 31, 2016	$	258	$	12,364		$	(3,385	)	$	(2,887	)	$	(112	)	$	6,238		$	1,441		$	7,679

*Financial information for 2015, 2014, and 2013 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

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

F-8

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Nature of Operations

Apache Corporation (Apache or the Company) is an independent energy company that explores for, develops, and produces natural gas, crude oil, and natural gas liquids. The Company has exploration and production interests in four geographic areas: the United States (U.S.), Canada, Egypt, and the United Kingdom (U.K.) North Sea (North Sea). Apache also has exploration interests in Suriname that may, over time, result in a reportable discovery and development opportunity.

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 include reclassifications that were made to conform to the current-year presentation. During the second quarter of 2015, Apache completed the sale of its Australian LNG business and oil and gas assets. In March 2014, Apache completed the sale of all of its operations in Argentina. Results of operations and cash flows for the divested Australia assets and Argentina operations are reflected as discontinued operations in the Company’s financial statements for all periods presented. Significant policies are discussed below.

Recast Financial Information for Change in Accounting Principle

In the second quarter of 2016, Apache voluntarily changed its method of accounting for its oil and gas exploration and development activities from the full cost method to the successful efforts method of accounting. The financial information for prior periods has been recast to reflect retrospective application of the successful efforts method, as prescribed by the Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 932 “Extractive Activities—Oil and Gas.” Although the full cost method of accounting for oil and gas exploration and development activities continues to be an accepted alternative, the successful efforts method of accounting is the generally preferred method of the U.S. Securities and Exchange Commission (SEC) and is more widely used in the industry such that the change improves comparability of the Company’s financial statements to its peers. The Company believes the successful efforts method provides a more representational depiction of assets and operating results. The successful efforts method also provides for the Company’s investments in oil and gas properties to be assessed for impairment in accordance with ASC 360 “Property, Plant, and Equipment” rather than valuations based on prices and costs prescribed under the full cost method as of the balance sheet date. For more detailed information regarding the effects of the change to the successful efforts method, please refer to Note 2—Change in Accounting Principle. The Company has recast certain historical information for the years ended 2015 and 2014, including the Statement of Consolidated Operations, Statement of Consolidated Comprehensive Income (Loss), Statement of Consolidated Cash Flows, Consolidated Balance Sheet, Statement of Consolidated Changes in Equity, and related information in Notes 1, 2, 3, 4, 6, 7, 8, 9, 12, 13, 15, 16, 17, and 18.

In addition, in the first quarter of 2016, the Company retrospectively adopted a new accounting standard update for all periods presented which requires debt issuance costs to be presented as a direct deduction from the carrying value of the associated debt liability, consistent with debt discounts. For more information regarding this update, please refer to Note 8—Debt and Financing Costs.

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. Sinopec International Petroleum Exploration and Production Corporation (Sinopec) owns a one-third minority participation in Apache’s Egypt oil and gas business as a noncontrolling interest, which is reflected as a separate component of equity in Apache’s consolidated balance sheet. 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.

F-9

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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 and assets held for sale at year-end (see Note 3—Acquisitions and Divestitures), the estimate of proved oil and gas reserves and related present value estimates of future net cash flows therefrom (see Note 16—Supplemental Oil and Gas Disclosures), the assessment of asset retirement obligations (see Note 7—Asset Retirement Obligation), the estimates of fair value for long-lived assets and goodwill (see “Fair Value Measurements,” “Property and Equipment,” and “Goodwill” sections in this Note 1 below), and the estimate of income taxes (see Note 9—Income Taxes).

Fair Value Measurements

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

Recurring fair value measurements are presented in further detail in Note 8—Debt and Note 11—Retirement and Deferred Compensation Plans.

Apache also uses fair value measurements on a nonrecurring basis when certain qualitative assessments of its assets indicate a potential impairment. For the year ended December 31, 2016, the Company recorded asset impairments totaling $1.1 billion in connection with fair value assessments in the current low commodity price environment. Impairments totaling $427 million and $135 million were recorded for proved properties and gathering, transmission, and processing (GTP) facilities, respectively, which were written down to their fair values. These impairments are discussed in further detail below in “Property and Equipment.” Also in 2016, the Company recorded $486 million for a U.K. Petroleum Revenue Tax (PRT) decommissioning asset that is no longer expected to be realizable from future abandonment activities in the North Sea and $55 million for inventory write-downs.

In 2016, the U.K. government enacted Finance Bill 2016, providing tax relief to exploration and production (E&P) companies operating in the U.K. North Sea. Under the enacted legislation, the U.K. PRT rate was reduced to zero from the previously enacted 35 percent rate in effect from January 1, 2016. PRT expense ceased prospectively from that date. As a further result of this change, the Company reduced the recoverable PRT decommissioning asset that would have been realized from future abandonment activities by $486 million ($292 million net of tax). This recoverable PRT decommissioning asset had an aggregate remaining value of $8 million as of December 31, 2016, which is recorded in “Deferred charges and other” on the consolidated balance sheet. The recoverable value of the PRT decommissioning asset was estimated using the income approach. The expected future cash flows used in the determination were based on anticipated spending and timing of planned future abandonment activities for applicable fields, considering all available information at the date of review. Apache has classified this fair value measurement as Level 3 in the fair value hierarchy.

For the year ended December 31, 2015, the Company recorded asset impairments totaling $9.5 billion in connection with fair value assessments. Impairments totaling $7.4 billion and $1.7 billion were recorded for proved properties and GTP facilities, respectively, which were written down to their fair values. These impairments are discussed in further detail below in “Property and Equipment.” Also in 2015, the Company recorded $163 million for the impairment of goodwill, $148 million for the impairment of an equity method investment sold in the fourth quarter, and $55 million for inventory write-downs. For a discussion of the equity method investment impairment, see Note 3—Acquisitions and Divestitures.

F-10

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

For the year ended December 31, 2014, the Company recorded asset impairments totaling $7.1 billion in connection with fair value assessments, including $6.1 billion for proved properties, $347 million for the impairment of goodwill, $655 million for the impairment of assets held for sale, and $32 million for inventory write-downs. The Company also recorded $833 million in impairments related to the sale of the Company’s Australian assets and an additional $271 million in impairment of proved properties and inventory in Australia. These impairments are classified as discontinued operations in 2014. For discussion of these impairments, see “Property and Equipment” and “Goodwill” below and Note 3—Acquisitions and Divestitures.

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, 2016 and 2015, Apache had $1.4 billion and $1.5 billion, 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 doubtful 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, 2016, 2015, and 2014, the Company had an allowance for doubtful accounts of $93 million, $103 million, and $98 million, respectively.

The following table describes changes to the Company’s allowance for doubtful accounts for 2016, 2015, and 2014:

	2016			2015			2014
	(In millions)
Allowance for doubtful accounts at beginning of year	$	103		$	98		$	78
Additional provisions for the year	14			40			4
Uncollectible accounts written off net of recoveries	(24		)	(35		)	16
Allowance for doubtful accounts at end of year	$	93		$	103		$	98

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, net of any impairments. 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 successful efforts method of accounting for its oil and gas property. Under this method of accounting, exploration costs such as exploratory geological and geophysical costs, delay rentals, and exploration overhead are expensed as incurred. All costs related to production, general corporate overhead, and similar activities are expensed as incurred. If an exploratory well provides evidence to justify potential development of reserves, drilling costs associated with the well are initially capitalized, or suspended, pending a determination as to whether a commercially sufficient quantity of proved reserves can be attributed to the area as a result of drilling. This determination may take longer than one year in certain areas depending on, among other things, the amount of hydrocarbons discovered, the outcome of planned geological and engineering studies, the need for additional appraisal drilling activities to determine whether the discovery is sufficient to support an economic development plan, and government sanctioning of development activities in certain international locations. At the end of each quarter, management reviews the status of all suspended exploratory well costs in light of ongoing exploration activities; in particular, whether the Company is making sufficient progress in its ongoing exploration and appraisal efforts or, in the case of discoveries requiring government sanctioning, whether development negotiations are underway and proceeding as planned. If management determines that future appraisal drilling or development activities are unlikely to occur, associated suspended exploratory well costs are expensed.

F-11

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Acquisition costs of unproved properties are assessed for impairment at least annually and are transferred to proved oil and gas properties to the extent the costs are associated with successful exploration activities. Significant undeveloped leases are assessed individually for impairment based on the Company’s current exploration plans. Unproved oil and gas properties with individually insignificant lease acquisition costs are amortized on a group basis over the average lease term at rates that provide for full amortization of unsuccessful leases upon lease expiration or abandonment. Costs of expired or abandoned leases are charged to exploration expense, while costs of productive leases are transferred to proved oil and gas properties. Costs of maintaining and retaining unproved properties, as well as amortization of individually insignificant leases and impairment of unsuccessful leases, are included in exploration costs in the statement of consolidated operations.

Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of crude oil and natural gas, are capitalized. Depreciation of the cost of proved oil and gas properties is calculated using the unit-of-production (UOP) method. The UOP calculation multiplies the percentage of estimated proved reserves produced each quarter by the carrying value of those reserves. The reserve base used to calculate depreciation for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. With respect to lease and well equipment costs, which include development costs and successful exploration drilling costs, the reserve base includes only proved developed reserves. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are included in the depreciable cost.

Oil and gas properties are grouped for depreciation in accordance with ASC 932 “Extractive Activities - Oil and Gas.” The basis for grouping is a reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field.

When circumstances indicate that proved oil and gas properties may be impaired, the Company compares unamortized capitalized costs to the expected undiscounted pre-tax future cash flows for the associated assets grouped at the lowest level for which identifiable cash flows are independent of cash flows of other assets. If the expected undiscounted pre-tax future cash flows, based on Apache’s estimate of future crude oil and natural gas prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally estimated using the income approach described in the ASC 820 “Fair Value Measurement.” If applicable, the Company utilizes accepted bids as the basis for determining fair value. The expected future cash flows used for impairment reviews and related fair value calculations are typically based on judgmental assessments of future production volumes, commodity prices, operating costs, and capital investment plans, considering all available information at the date of review. These assumptions are applied to develop future cash flow projections that are then discounted to estimated fair value, using a discount rate believed to be consistent with those applied by market participants. Apache has classified these fair value measurements as Level 3 in the fair value hierarchy.

The following table represents non-cash impairments of the carrying value of the Company’s proved and unproved property and equipment for 2016, 2015, and 2014:

	For the Year Ended December 31,
	2016		2015		2014
	(In millions)
Oil and Gas Property:
Proved	$	427	$	7,389	$	6,068
Unproved	272		2,462		1,976

The fair values of the impaired proved properties as of the most recent date of impairment were $306 million, $3.9 billion, and $4.8 billion for 2016, 2015, and 2014, respectively.

In the statement of consolidated operations, unproved property impairments are recorded in exploration expense, and proved property impairments are recorded in impairments.

Gains and losses on significant divestitures are recognized in the statement of consolidated operations. See Note 3—Acquisitions and Divestitures for more detail.

F-12

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Gathering, Transmission, and Processing Facilities

GTP facilities totaled $976 million and $1.1 billion at December 31, 2016 and 2015, respectively, with accumulated depreciation for these assets totaling $130 million and $160 million for the respective periods. GTP facilities are depreciated on a straight-line basis over the estimated useful lives of the assets. The estimation of useful life takes into consideration anticipated production lives from the fields serviced by the GTP assets, whether Apache-operated or third party, as well as potential development plans by Apache for undeveloped acreage within or in close proximity to those fields.

The Company assesses the carrying amount of its GTP facilities whenever events or changes in circumstances indicate that their carrying amount may not be recoverable. If the carrying amount of these facilities is more than the sum of the undiscounted cash flows, an impairment loss is recognized for the excess of the carrying value over its fair value. During 2016, the Company recorded impairments of $135 million on certain GTP assets in the North Sea, which were written down to their fair values of $142 million. The fair values of the impaired assets were determined using a combination of the income approach and the market approach. The income approach considers internal estimates of future throughput volumes, processing rates, and costs. These assumptions were applied to develop future cash flow projections that were then discounted to estimated fair value, using a discount rate believed to be consistent with those applied by market participants. Apache has classified these non-recurring fair value measurements as Level 3 in the fair value hierarchy. During 2015, the Company recorded impairments of $1.7 billion on certain GTP assets, including $1.1 billion in Egypt, $555 million in Canada, and $103 million in the U.S., which were written down to their fair values of $306 million in aggregate. During 2014, the Company recorded impairments of $1.1 billion of its GTP assets related to the sale of Apache’s Wheatstone and Kitimat LNG projects, and the remaining carrying value of those assets was reclassified to “Assets held for sale” on the Company’s consolidated balance sheet as of December 31, 2014. The $430 million impairment of GTP assets related to Apache's Wheatstone LNG project is reflected in discontinued operations in the Company's statement of consolidated operations.

The costs of GTP facilities retired or otherwise disposed of and associated accumulated depreciation are removed from Apache’s consolidated financial statements, and the resulting gain or loss is reflected in “Gain (loss) on divestitures” under “Revenues and Other” in the Company’s statement of consolidated operations. No gain or loss on the sales of GTP facilities was recognized during 2016. During 2015, Apache recorded a gain on the sale of GTP facilities totaling $59 million associated with the Company’s divestitures of certain Permian Basin assets. During 2014, the Company recorded a loss totaling $180 million associated with divestitures of certain Anadarko basin and southern Louisiana assets.

Other Property and Equipment

Other property and equipment includes computer software and equipment, buildings, vehicles, furniture and fixtures, land, and other equipment. These assets are depreciated on a straight-line basis over the estimated useful lives of the assets, which range from 3 to 20 years. Accumulated depreciation for these assets totaled $780 million and $693 million at December 31, 2016 and 2015, 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. 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.

CapitalizedInterest

For significant projects, interest is capitalized as part of the historical cost of developing and constructing assets. Significant oil and gas investments in unproved properties actively being explored, significant exploration and development projects that have not commenced production, significant midstream development activities that are in progress, and investments in equity method affiliates that are undergoing the construction of assets that have not commenced principal operations qualify for interest capitalization. Interest is capitalized until the asset is ready for service. Capitalized interest is determined by multiplying the Company’s weighted-average borrowing cost on debt by the average amount of qualifying costs incurred. Once an asset subject to interest capitalization is completed and placed in service, the associated capitalized interest is expensed through depreciation or impairment.

F-13

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Goodwill

Goodwill represents the excess of the purchase price of an entity over the estimated fair value of the assets acquired and liabilities assumed, and it is recorded in “Deferred charges and other” in the Company's consolidated balance sheet. The Company assesses the carrying amount of goodwill by testing for impairment annually and when impairment indicators arise. The impairment test requires allocating goodwill and all other assets and liabilities to assigned reporting units. As of December 31, 2016, Apache assesses each country as a reporting unit. The fair value of each unit is determined and compared to the book value of the reporting unit. If the fair value of the reporting unit is less than the book value, including goodwill, then goodwill is written down to the implied fair value of the goodwill through a charge to expense.

In order to determine the fair value of each reporting unit, the Company uses a combination of the income approach and the market approach. The income approach considers management views on current operating measures as well as assumptions pertaining to market forces in the oil and gas industry, such as future production, future commodity prices, and costs. These assumptions are applied to develop future cash flow projections that are then discounted to estimate fair value, using a discount rate similar to those used by the Company in the valuation of acquisitions and divestitures. To assess the reasonableness of its fair value estimate, the Company uses a market approach to compare the fair value to similar businesses whose securities are actively traded in the public market. This requires management to make certain judgments about the selection of comparable companies, recent comparable asset transactions, and transaction premiums. Associated market multiples are applied to various financial metrics of the reporting unit to estimate fair value. Apache has classified this reporting unit estimation as a non-recurring Level 3 fair value measurement.

When there is a disposal of a reporting unit or a portion of a reporting unit that constitutes a business, goodwill associated with that business is included in the carrying amount to determine the gain or loss on disposal. The amount of goodwill allocated to the carrying amount of a business can significantly impact the amount of gain or loss recognized on the sale of that business. The amount of goodwill to be included in that carrying amount is based on the relative fair value of the business to be disposed of and the portion of the reporting unit that will be retained.

The following presents the changes to goodwill for the years ended 2016, 2015, and 2014:

	United States			Canada			Egypt		North Sea			Total
	(In millions)
Goodwill at December 31, 2013	$	384		$	103		$	87	$	163		$	737
Divested	(140		)	—			—		—			(140		)
Impairments	(244		)	(103		)	—		—			(347		)
Goodwill at December 31, 2014	—			—			87		163			250
Impairments	—			—			—		(163		)	(163		)
Goodwill at December 31, 2015	—			—			87		—			87
Impairments	—			—			—		—			—
Goodwill at December 31, 2016	$	—		$	—		$	87	$	—		$	87

Reductions in estimated net present value of expected future cash flows from oil and gas properties resulted in implied fair values below the carrying values of Apache’s U.S., North Sea, and Canada reporting units. These goodwill impairments have been recorded in “Impairments” in the Company’s statement of consolidated operations.

Accounts Payable

Included in accounts payable at December 31, 2016 and 2015, are liabilities of approximately $86 million and $129 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.

F-14

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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 North American natural gas production. Since the Company’s production fluctuates because of operational issues, it is occasionally necessary to purchase third-party oil and gas to fulfill sales obligations and commitments. The costs of third-party oil and gas purchases totaled $159 million, $105 million, and $70 million, for 2016, 2015, and 2014, respectively, which offset the related sales proceeds recorded as “Other” under “Revenues and Other” in the statement of consolidated operations.

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. As of December 31, 2016, Apache had no open derivative positions.

When applicable, 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 “Other” 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 2014 oil and gas cash flow hedges, including terminated contracts, were recognized in oil and gas production revenues when the forecasted transaction occurred. For more information, please refer to Note 5—Derivative Instruments and Hedging Activities.

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 ability to realize 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 record U.S. deferred income taxes on foreign subsidiaries that are deemed to be permanently reinvested. When such earnings are no longer deemed permanently reinvested, Apache will recognize the appropriate U.S. current or deferred income tax liabilities. For more information, please refer to Note 9—Income Taxes.

F-15

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Foreign Currency Transaction Gains and Losses

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

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. For further discussion, please refer to Note 9—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 2016 of $25 million, a loss in 2015 of $11 million, and a gain in 2014 of $8 million.

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 potential dilution, using the treasury stock method, which assumes that options were exercised and restricted stock was fully vested.

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 12—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 $2 million, $1 million, and $35,000 as financing cash inflows in 2016, 2015, and 2014, 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 January 2017, the FASB issued Accounting Standards Update (ASU) 2017-04, “Simplifying the Test for Goodwill Impairment.” ASU 2017-04 seeks to simplify the accounting for goodwill by eliminating the second step in the goodwill impairment test which requires an entity to determine the implied fair value of the reporting unit’s goodwill. Under the new guidance, an entity will recognize an impairment loss if the carrying value of the net assets assigned to the reporting unit exceeds the fair value of the reporting unit, with the impairment loss not to exceed the amount of goodwill allocated to the reporting unit. This update will be applied prospectively and is effective for annual and interim goodwill impairment tests conducted in fiscal years beginning after December 15, 2019. Early adoption is permitted for annual and interim goodwill impairment testing dates after January 1, 2017. The Company plans to early adopt this ASU, and does not expect the adoption to have a material impact on its consolidated financial statements.

F-16

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

In August 2016, the FASB issued Accounting Standards Update (ASU) 2016-15, Statement of Cash Flows (Topic 230).  ASU 2016-15 seeks to reduce the existing diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows. This update is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years, with early adoption permitted. The Company is currently evaluating the provisions of ASU 2016-15 and assessing the impact, if any, it may have on its statement of consolidated cash flows.

In June 2016, the FASB issued ASU 2016-13, “Financial Instruments - Credit Losses.”  The standard changes the impairment model for most financial assets and certain other instruments, including trade and other receivables, held-to-maturity debt securities and loans, and requires entities to use a new forward-looking expected loss model that will result in the earlier recognition of allowance for losses. This update is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. Early adoption is permitted for a fiscal year beginning after December 15, 2018, including interim periods within that fiscal year.  The Company does not expect to adopt the guidance early. Entities will apply the standard’s provisions as a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is adopted. The Company is evaluating the new guidance and does not believe this standard will have a material impact on its consolidated financial statements.

In March 2016, the FASB issued ASU 2016-09, which seeks to simplify accounting for share-based payment transactions including income tax consequences, classification of awards as either equity or liabilities, and the classification on the statement of cash flows. The new standard requires the Company to recognize the income tax effects of awards in the income statement when the awards vest or are settled. The guidance is effective for fiscal years beginning after December 15, 2016. The Company has evaluated the new guidance and recorded a cumulative-effect adjustment of $11 million as of January 1, 2017 representing an increase in accumulated deficit with the offset to paid-in capital to reflect actual forfeitures versus the previously-estimated forfeiture rate.

In February 2016, the FASB issued ASU 2016-02, a new lease standard requiring lessees to recognize lease assets and lease liabilities for most leases classified as operating leases under previous U.S. GAAP. The guidance is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The Company will be required to use a modified retrospective approach for leases that exist or are entered into after the beginning of the earliest comparative period in the financial statements. The Company is currently evaluating the impact of adopting this standard on its consolidated financial statements.

In May 2014, the FASB and the International Accounting Standards Board (IASB) issued a joint revenue recognition standard, ASU 2014-09. The new standard removes inconsistencies in existing standards, changes the way companies recognize revenue from contracts with customers, and increases disclosure requirements. The codification was amended through additional ASUs and, as amended, requires companies to recognize revenue to depict the transfer of goods or services to customers in amounts that reflect the consideration to which the company expects to be entitled in exchange for those goods or services. The guidance is effective for annual and interim periods beginning after December 15, 2017. The standard is required to be adopted using either the full retrospective approach, with all prior periods presented adjusted, or the modified retrospective approach, with a cumulative adjustment to retained earnings on the opening balance sheet. The Company will adopt the new standard utilizing the modified retrospective approach. Upon preliminary evaluation, the Company does not expect the adoption of this ASU to have a material impact on its consolidated financial statements. The Company is continuing to evaluate the disclosure requirements of this ASU and does not plan on early adopting the standard.

F-17

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

2.   CHANGE IN ACCOUNTING PRINCIPLE

During the second quarter of 2016, the Company voluntarily changed its method of accounting for oil and gas exploration and development activities from the full cost method to the successful efforts method. Accordingly, financial information for prior periods has been recast to reflect retrospective application of the successful efforts method. In general, under successful efforts, exploration expenditures such as exploratory dry holes, exploratory geological and geophysical costs, delay rentals, unproved impairments, and exploration overhead are charged against earnings as incurred, versus being capitalized under the full cost method of accounting. Successful efforts also provides for the assessment of potential property impairments under ASC 360 by comparing the net carrying value of oil and gas properties with associated projected undiscounted pre-tax future net cash flows. If the expected undiscounted pre-tax future net cash flows are lower than the unamortized capitalized costs, the capitalized cost is reduced to fair value. Under the full cost method of accounting, a write-down would be required if the net carrying value of oil and gas properties exceeds a full cost “ceiling,” using an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months. In addition, gains or losses, if applicable, are generally recognized on the dispositions of oil and gas property and equipment under the successful efforts method, as opposed to an adjustment to the net carrying value of the remaining assets under the full cost method. Apache’s consolidated financial statements have been recast to reflect these differences.

The following tables present the effects of the change to the successful efforts method in the statement of consolidated operations:

	Changes to the Statement of Consolidated Operations and Statement of Consolidated Comprehensive Income (Loss)
For the Year Ended December 31, 2016	Under Full Cost			Changes*			As Reported Under Successful Efforts
	(In millions, except per share data)
Oil revenues	$	3,983		$	189		$	4,172
Natural gas revenues	997			(30		)	967
NGL revenues	228			—			228
Oil and gas production revenues	5,208			159			5,367
Other	(38		)	4			(34		)
Gain on divestiture	17			4			21
Exploration	—			473			473
Depreciation, depletion, and amortization:
Oil and gas property and equipment
Recurring	1,974			486			2,460
Additional	1,438			(1,438		)	—
Impairments	677			426			1,103
Financing costs, net	365			52			417
Current income tax provision	232			159			391
Deferred income tax benefit	(721		)	(112		)	(833		)
NET LOSS FROM CONTINUING OPERATIONS INCLUDING NONCONTROLLING INTEREST	(1,361		)	121			(1,240		)
Net income (loss) attributable to noncontrolling interest	(26		)	158			132
NET LOSS FROM CONTINUING OPERATIONS ATTRIBUTABLE TO COMMON SHAREHOLDERS	(1,335		)	(37		)	(1,372		)
Net loss from discontinued operations, net of tax	(33		)	—			(33		)
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS	(1,368		)	(37		)	(1,405		)
Per Common Share
Basic and diluted net loss from continuing operations per share	$	(3.52	)	$	(0.10	)	$	(3.62	)
Basic and diluted net loss from discontinued operations per share	(0.09		)	—			(0.09		)
Basic and diluted net loss per share	$	(3.61	)	$	(0.10	)	$	(3.71	)
Other Comprehensive Income
COMPREHENSIVE LOSS ATTRIBUTABLE TO COMMON STOCK	(1,361		)	(37		)	(1,398		)

F-18

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

	Changes to the Statement of Consolidated Operations and Statement of Consolidated Comprehensive Income (Loss)
For the Year Ended December 31, 2015	Under Full Cost			Changes*			As Reported Under Successful Efforts
	(In millions, except per share data)
Oil revenues	$	4,999		$	108		$	5,107
Natural gas revenues	1,157			19			1,176
NGL revenues	227			—			227
Oil and gas production revenues	6,383			127			6,510
Other	(76		)	174			98
Gain on divestiture	59			222			281
Exploration	—			2,771			2,771
General and administrative	377			3			380
Depreciation, depletion, and amortization:
Oil and gas property and equipment
Recurring	3,531			(555		)	2,976
Additional	25,517			(25,517		)	—
Impairments	1,920			7,552			9,472
Financing costs, net	299			212			511
Current income tax provision	309			126			435
Deferred income tax benefit	(5,778		)	4,333			(1,445		)
NET LOSS FROM CONTINUING OPERATIONS INCLUDING NONCONTROLLING INTEREST	(22,757		)	11,598			(11,159		)
Net loss attributable to noncontrolling interest	(409		)	94			(315		)
NET LOSS FROM CONTINUING OPERATIONS ATTRIBUTABLE TO COMMON SHAREHOLDERS	(22,348		)	11,504			(10,844		)
Net income (loss) from discontinued operations, net of tax	(771		)	1,263			492
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS	(23,119		)	12,767			(10,352		)
Per Common Share
Basic and diluted net loss from continuing operations per share	$	(59.16	)	$	30.46		$	(28.70	)
Basic and diluted net income (loss) from discontinued operations per share	(2.04		)	3.34			1.30
Basic and diluted net loss per share	$	(61.20	)	$	33.80		$	(27.40	)
Other Comprehensive Income
Pension and postretirement benefit plan, net of tax	$	—		$	(3	)	$	(3	)
COMPREHENSIVE LOSS ATTRIBUTABLE TO COMMON STOCK	(23,119		)	12,764			(10,355		)

F-19

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

	Changes to the Statement of Consolidated Operations and Statement of Consolidated Comprehensive Income (Loss)
For the Year Ended December 31, 2014	Under Full Cost			Changes*			As Reported Under Successful Efforts
	(In millions, except per share data)
Oil revenues	$	10,040		$	70		$	10,110
Natural gas revenues	1,983			34			2,017
NGL revenues	668			—			668
Oil and gas production revenues	12,691			104			12,795
Other	290			(5		)	285
Loss on divestiture	(180		)	(1,428		)	(1,608		)
Exploration	—			2,499			2,499
General and administrative	451			2			453
Depreciation, depletion, and amortization:
Oil and gas property and equipment
Recurring	4,388			(193		)	4,195
Additional	5,001			(5,001		)	—
Impairments	1,919			5,183			7,102
Financing costs, net	211			202			413
Current income tax provision	1,177			104			1,281
Deferred income tax benefit	(514		)	(1,285		)	(1,799		)
NET LOSS FROM CONTINUING OPERATIONS INCLUDING NONCONTROLLING INTEREST	(3,472		)	(2,840		)	(6,312		)
Net income attributable to noncontrolling interest	343			(2		)	341
NET LOSS FROM CONTINUING OPERATIONS ATTRIBUTABLE TO COMMON SHAREHOLDERS	(3,815		)	(2,838		)	(6,653		)
Net loss from discontinued operations, net of tax	(1,588		)	(119		)	(1,707		)
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS	(5,403		)	(2,957		)	(8,360		)
Per Common Share
Basic and diluted net loss from continuing operations per share	$	(9.93	)	$	(7.39	)	$	(17.32	)
Basic and diluted net loss from discontinued operations per share	(4.13		)	(0.31		)	(4.44		)
Basic and diluted net loss per share	$	(14.06	)	$	(7.70	)	$	(21.76	)
Other Comprehensive Income
COMPREHENSIVE LOSS ATTRIBUTABLE TO COMMON STOCK	$	(5,404	)	$	(2,957	)	$	(8,361	)

The following tables present the effects of the change to the successful efforts method in the statement of consolidated cash flows:

	Changes to the Statement of Consolidated Cash Flows
For the Year Ended December 31, 2016	Under Full Cost			Changes*			As Reported Under Successful Efforts
	(In millions)
Net loss including noncontrolling interest	$	(1,394	)	$	121		$	(1,273	)
Gain on divestitures, net	(17		)	(4		)	(21		)
Exploratory dry hole expense and unproved leasehold impairments	—			353			353
Depreciation, depletion, and amortization	3,570			(952		)	2,618
Impairments	677			426			1,103
Benefit from deferred income taxes	(721		)	(112		)	(833		)
Changes in operating assets and liabilities	138			15			153
Net cash provided by continuing operating activities	2,606			(153		)	2,453
Additions to oil and gas property	(1,776		)	166			(1,610		)
Net cash used in investing activities	(1,826		)	166			(1,660		)
Other	6			(13		)	(7		)
Net cash used in financing activities	(847		)	(13		)	(860		)
NET DECREASE IN CASH	(90		)	—			(90		)
BEGINNING CASH BALANCE	1,467			—			1,467
ENDING CASH BALANCE	1,377			—			1,377

F-20

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

	Changes to the Statement of Consolidated Cash Flows
For the Year Ended December 31, 2015	Under Full Cost			Changes*			As Reported Under Successful Efforts
	(In millions)
Net loss including noncontrolling interest	$	(23,528	)	$	12,861		$	(10,667	)
Loss (income) from discontinued operations	771			(1,263		)	(492		)
Gain on divestitures, net	(59		)	(222		)	(281		)
Exploratory dry hole expense and unproved leasehold impairments	—			2,595			2,595
Depreciation, depletion, and amortization	29,372			(26,072		)	3,300
Impairments	1,920			7,552			9,472
Other noncash items, net	161			(154		)	7
Benefit from deferred income taxes	(5,778		)	4,333			(1,445		)
Changes in operating assets and liabilities	(170		)	90			(80		)
Net cash provided by operating activities - continuing operations	2,834			(280		)	2,554
Net cash provided by operating activities - discontinued operations	150			(37		)	113
Additions to oil and gas property	(4,578		)	370			(4,208		)
Net cash used in investing activities - continuing operations	(3,659		)	370			(3,289		)
Net cash provided by investing activities - discontinued operations	4,335			37			4,372
NET INCREASE IN CASH	698			90			788
BEGINNING CASH BALANCE	769			(90		)	679
ENDING CASH BALANCE	1,467			—			1,467

	Changes to the Statement of Consolidated Cash Flows
For the Year Ended December 31, 2014	Under Full Cost			Changes*			As Reported Under Successful Efforts
	(In millions)
Net loss including noncontrolling interest	$	(5,060	)	$	(2,959	)	$	(8,019	)
Income from discontinued operations	1,588			119			1,707
Loss on divestitures, net	180			1,428			1,608
Exploratory dry hole expense and unproved leasehold impairments	—			2,294			2,294
Depreciation, depletion, and amortization	9,720			(5,194		)	4,526
Impairments	1,919			5,183			7,102
Benefit from deferred income taxes	(514		)	(1,285		)	(1,799		)
Changes in operating assets and liabilities	(239		)	(90		)	(329		)
Net cash provided by operating activities - continuing operations	7,517			(504		)	7,013
Net cash provided by operating activities - discontinued operations	944			—			944
Additions to oil and gas property	(9,022		)	414			(8,608		)
Net cash used in investing activities - continuing operations	(8,585		)	414			(8,171		)
Net cash used in investing activities - discontinued operations	(219		)	—			(219		)
NET DECREASE IN CASH	(1,137		)	(90		)	(1,227		)
BEGINNING CASH BALANCE	1,906			—			1,906
ENDING CASH BALANCE	769			(90		)	679

F-21

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The following tables present the effects of the change to the successful efforts method in the consolidated balance sheet:

	Changes to the Consolidated Balance Sheet
December 31, 2016	Under Full Cost			Changes*			As Reported Under Successful Efforts
	(In millions)
PROPERTY AND EQUIPMENT:
Property and equipment - cost	$	95,371		$	(48,622	)	$	46,749
Less: Accumulated depreciation, depletion, and amortization	(83,230		)	55,348			(27,882		)
PROPERTY AND EQUIPMENT, NET	12,141			6,726			18,867
TOTAL ASSETS	15,793			6,726			22,519
Income taxes	353			1,357			1,710
Paid-in capital	12,225			139			12,364
Accumulated deficit	(8,521		)	5,136			(3,385		)
Accumulated other comprehensive loss	(109		)	(3		)	(112		)
Noncontrolling interest	1,344			97			1,441
TOTAL EQUITY	2,310			5,369			7,679

	Changes to the Consolidated Balance Sheet
December 31, 2015	Under Full Cost			Changes*			As Reported Under Successful Efforts
	(In millions)
PROPERTY AND EQUIPMENT:
Property and equipment - cost	$	93,825		$	(47,675	)	$	46,150
Less: Accumulated depreciation, depletion, and amortization	(79,706		)	54,394			(25,312		)
PROPERTY AND EQUIPMENT, NET	14,119			6,719			20,838
TOTAL ASSETS	18,781			6,719			25,500
Income taxes	1,072			1,457			2,529
Paid-in capital	12,467			152			12,619
Accumulated deficit	(7,153		)	5,173			(1,980		)
Accumulated other comprehensive loss	(116		)	(3		)	(119		)
Noncontrolling interest	1,662			(60		)	1,602
TOTAL EQUITY	4,228			5,262			9,490

*In conjunction with recasting the financial information for the adoption of the successful efforts method of accounting, the Company corrected certain immaterial errors in the North Sea pertaining to the improper calculation of deferred tax liabilities associated with capitalized interest under the full cost method.

F-22

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

3.   ACQUISITIONS AND DIVESTITURES

2016 Activity

During the fourth quarter of 2016, Apache entered into multiple transactions to sell certain non-core assets in our Permian region, primarily leasehold acreage, for cash proceeds of $440 million, subject to customary closing adjustments. The Company expects to recognize a gain of approximately $300 million during the first quarter of 2017 upon closing of the transaction.

Also during the fourth quarter of 2016, Apache entered into an agreement to sell its 30.28 percent interest in the Scottish Area Gas Evacuation system (SAGE) and its 60.56 percent interest in the Beryl pipeline in the North Sea to Ancala Midstream Acquisitions Limited (Ancala). The transaction is subject to regulatory and third party approvals.

The Company received refundable deposits of $174 million in connection with the transactions, which are recorded in “Other current liabilities” on the consolidated balance sheet.

Leasehold and Property Acquisitions

Apache completed $181 million of leasehold and property acquisitions during 2016, primarily in our North America onshore regions.

Divestiture of Other Oil and Gas Properties

Apache recorded $134 million of proceeds from the divestiture of other oil and gas properties during 2016. An associated $21 million of gain was recorded in 2016.

2015 Activity

Yara Pilbara Holdings Pty Limited Sale

In October 2015, Apache sold its 49 percent interest in Yara Pilbara Holdings Pty Limited (YPHPL) for total cash proceeds of $391 million. The investment in YPHPL was 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 the results of operations recorded as a component of “Other” under “Revenue and other” in the Company’s statement of consolidated operations. As of September 30, 2015, Apache recognized an impairment of $148 million on the YPHPL equity investment based on negotiated sales proceeds. No additional gain or loss was recorded upon completion of the sale.

Canada Divestiture

In April 2015, Apache completed the sale of its 50 percent interest in the Kitimat LNG project and upstream acreage in the Horn River and Liard natural gas basins to Woodside Petroleum Limited (Woodside). Proceeds at closing were $854 million, of which approximately $344 million was associated with LNG assets and $510 million was associated with upstream assets. For additional details related to post-closing adjustments, please see Note 10—Commitments and Contingencies.

The Kitimat LNG assets were classified as held for sale and impaired $655 million in the fourth quarter of 2014. In 2015, Apache recognized a $146 million gain on the sale of the upstream assets upon completion of the sale.

Australia Divestitures

Woodside Sale In April 2015, Apache completed the sale of the Wheatstone LNG project and associated upstream oil and gas assets to Woodside. Proceeds at closing were $2.8 billion, of which approximately $1.4 billion was associated with LNG assets and $1.4 billion was associated with the upstream assets.

The Wheatstone LNG assets and associated upstream assets were classified as held for sale and impaired $833 million in the fourth quarter of 2014. An additional impairment of approximately $49 million was recognized in the first quarter of 2015. During the third quarter of 2016, Apache recognized an additional $23 million loss on the sale related to post-closing adjustments.

Consortium Sale In June 2015, Apache completed the sale of its Australian subsidiary Apache Energy Limited (AEL) to a consortium of private equity funds managed by Macquarie Capital Group Limited and Brookfield Asset Management Inc. Total proceeds of $1.9 billion include customary, post-closing adjustments for the period between the effective date, October 1, 2014, and closing. A loss of approximately $139 million was recognized for the sale of AEL.

F-23

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Upon closing of the sale of substantially all Australian operations, the associated results of operations for the divested Australian assets and the losses on disposal were classified as discontinued operations in the Company’s financial statements for all periods presented.

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

	For the Year Ended December 31,
	2016			2015			2014
	(In millions)
Revenues and other from discontinued operations	$	—		$	288		$	1,050
Impairment on Woodside sale	$	—		$	(49	)	$	(833	)
Loss on Woodside sale	(23		)	—			—
Loss on Consortium sale	—			(139		)	—
Income (loss) from divested Australian operations	—			28			(12		)
Income tax benefit (expense)	—			652			(231		)
Income (loss) from Australian discontinued operations, net of tax	$	(23	)	$	492		$	(1,076	)

Leasehold and Property Acquisitions

Apache completed $367 million of leasehold and property acquisitions during 2015, primarily in our North America onshore regions.

Divestiture of Other Oil and Gas Properties

Apache recorded $268 million of proceeds from the divestiture of other oil and gas properties during 2015. An associated $135 million of gain was recorded in 2015.

2014 Activity

Anadarko Basin and Southern Louisiana Divestitures

In December 2014, Apache completed the sale of certain Anadarko basin and non-core southern Louisiana oil and gas assets for approximately $1.3 billion in two separate transactions. In the Anadarko basin, Apache sold approximately 115,000 net acres in Wheeler County, Texas, and western Oklahoma. In southern Louisiana, Apache sold its working interest in approximately 90,000 net acres. The effective date of both of these transactions is October 1, 2014. Apache recognized a net $823 million loss on these transactions, of which approximately $10 million was associated with goodwill and approximately $180 million was associated with GTP facilities.

Gulf of Mexico Deepwater Divestiture

On June 30, 2014, Apache completed the sale of non-operated interests in the Lucius and Heidelberg development projects and 11 primary-term deepwater exploration blocks in the Gulf of Mexico for $1.4 billion. The effective date of the transaction was May 1, 2014. Apache recognized a $332 million loss as a result of the transaction, of which approximately $130 million was associated with goodwill.

Canada Divestiture

On April 30, 2014, Apache completed the sale of primarily dry gas producing hydrocarbon assets in the Deep Basin area of western Alberta and British Columbia, Canada, for $374 million. The assets comprise 328,400 net acres in the Ojay, Noel, and Wapiti areas. Apache retained 100 percent of its working interest in horizons below the Cretaceous in the Wapiti area, including rights to the liquids-rich Montney and other deeper horizons. The effective date of the transaction was January 1, 2014. Apache recognized a $237 million loss related to the sale of the assets.

F-24

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Argentina Divestiture

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 (subject to customary closing adjustments) 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.

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

	For the Year Ended December 31,
	2016			2015		2014
	(In millions)
Revenues and other from discontinued operations	$	—		$	—	$	87
Loss from Argentina divestiture	$	(10	)	$	—	$	(654	)
Loss from operations in Argentina	—			—		(1		)
Income tax benefit	—			—		23
Loss from discontinued operations, net of tax	$	(10	)	$	—	$	(632	)

Leasehold and Property Acquisitions

Apache completed $1.5 billion of leasehold and property acquisitions during 2014, primarily in our North America onshore regions.

Divestiture of Other Oil and Gas Properties

Apache recorded $96 million of proceeds from the divestiture of other oil and gas properties during 2014. An associated $216 million of loss was recorded in 2014.

Transaction, Reorganization, and Separation

Apache recorded $39 million, $132 million, and $67 million of expenses during 2016, 2015, and 2014, respectively, primarily related to various transactions, company reorganization, and employee separation.

F-25

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

4.   CAPITALIZED EXPLORATORY WELL COSTS

The following summarizes the changes in capitalized exploratory well costs for each of the last three years ended December 31, 2016, 2015, and 2014. Additions pending the determination of proved reserves excludes amounts capitalized and subsequently charged to expense within the same year.

	2016			2015			2014
	(In millions)
Balance at January 1	$	245		$	849		$	630
Additions pending determination of proved reserves	249			382			622
Divestitures and other	—			(557		)	(54		)
Reclassifications to proved properties	(211		)	(369		)	(207		)
Charged to exploration expense	(19		)	(60		)	(142		)
Balance at December 31(1)	$	264		$	245		$	849

⁽¹⁾ Includes $49 million of assets that were held for sale in Australia at December 31, 2014.

The following provides an aging of capitalized exploratory well costs and the number of projects for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling:

	2016		2015		2014
	(In millions)
Exploratory well costs capitalized for a period of one year or less	$	119	$	184	$	504
Exploratory well costs capitalized for a period greater than one year	145		61		345
Balance at December 31(1)	$	264	$	245	$	849
Number of projects with exploratory well costs capitalized for a period greater than one year	3		2		18

⁽¹⁾ Includes $49 million of assets that were held for sale in Australia at December 31, 2014.

The following summarizes a further aging by geographic area of those exploratory well costs that have been capitalized for a period greater than one year since the completion of drilling at December 31, 2016:

							2013 and
	Total		2015		2014		Prior
North Sea	$	113	$	53	$	58	$	2
Other International	32		28		3		1
	$	145	$	81	$	61	$	3

Projects with suspended exploratory well costs capitalized for a period greater than one year since the completion of drilling are those identified by management as exhibiting sufficient quantities of hydrocarbons to justify potential development. Management is actively pursuing efforts to assess whether reserves can be attributed to these projects.

Suspended exploratory well costs capitalized for a period greater than one year since the completion of drilling at December 31, 2016 primarily relate to the Seagull and Corona discoveries in the North Sea. In Seagull, appraisal work continues as the Company interprets the multi-azimuth 3-D survey acquired in late 2015. The survey will be used to create a development plan to be submitted to the Oil and Gas Authority in the U.K. in 2017. The suspended exploratory well costs related to the Corona discovery are pending development plan approval. In December 2016, the Company submitted the full field development plan to the Oil and Gas Authority in the U.K. Remaining activities required to classify the associated reserves as proved include approval of development plans and project sanctioning.

The remaining capitalized well costs in excess of one year relate to exploratory drilling in Suriname. The suspended exploratory well costs for the Block 53 Popokai well are pending the results of the Block 53 Kolibrie exploratory well. The Company plans to drill Kolibrie in 2017.

F-26

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

5.    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. When appropriate, 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. As of December 31, 2016, Apache had no open commodity derivative positions.

Subsequent to December 31, 2016, the Company entered into put option derivative contracts not designated as cash flow hedges for 2017 crude oil production of 175,000 barrels per day. These contracts will be settled against either NYMEX WTI or Dated Brent between July 1, 2017 and December 31, 2017, with a weighted average strike price of $50.47 per barrel. Apache paid a total premium of $100 million for these contracts, averaging $3.09 per barrel.

Derivative Activity Recorded in the Statement of Consolidated Operations

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

	Gain (Loss) on Derivatives Recognized in Income	For the Year Ended December 31,
		2016		2015		2014
		(In millions)
Derivatives not designated as cash flow hedges:
Realized loss		$	—	$	—	$	(16	)
Unrealized gain (loss)		—		—		300
Gain (loss) on derivatives not designated as cash flow hedges	Revenues and Other: Other	$	—	$	—	$	284

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 (loss) to net cash provided by operating activities.”

6.    OTHER CURRENT LIABILITIES

The following table provides detail of the Company’s other current liabilities at December 31, 2016 and 2015:

	December 31,
	2016		2015
	(In millions)
Accrued operating expenses	$	110	$	139
Accrued exploration and development	463		637
Accrued compensation and benefits	201		166
Accrued interest	145		144
Accrued income taxes	22		47
Current asset retirement obligation	66		36
Current debt	—		1
Refundable deposits	174		—
Other	77		53
Total Other current liabilities	$	1,258	$	1,223

F-27

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

7.    ASSET RETIREMENT OBLIGATION

The following table describes changes to the Company’s asset retirement obligation (ARO) liability for the years ended December 31, 2016 and 2015:

	2016			2015
	(In millions)
Asset retirement obligation at beginning of year	$	2,598		$	2,952
Liabilities incurred	41			68
Liabilities divested	(7		)	(490		)
Liabilities settled	(57		)	(90		)
Accretion expense	156			158
Revisions in estimated liabilities	(233		)	—
Asset retirement obligation at end of year	2,498			2,598
Less current portion	(66		)	(36		)
Asset retirement obligation, long-term	$	2,432		$	2,562

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 for 2015 includes discontinued operations of $13 million, which are included in “Net income (loss) from discontinued operations, net of tax” in the statement of consolidated operations.

During 2016 and 2015, the Company recorded $41 million and $68 million, respectively, in abandonment liabilities resulting from Apache’s exploration and development capital program. Liabilities settled primarily relate to individual properties, platforms, and facilities plugged and abandoned during the period. Approximately $233 million of abandonment costs were revised downward to reflect changes in estimates of timing and costs, primarily in the North Sea.

8.    DEBT

Overview

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

In November 2016, the Company initiated a program to purchase in the open market up to $250 million in aggregate principal amount of senior notes issued under its indentures. In the fourth quarter of 2016, Apache purchased and canceled $181 million aggregate principal amount of its senior notes through open market repurchases for $182 million in cash, including accrued interest and $0.5 million of premium. These repurchases resulted in a $1 million net loss on extinguishment of debt, which is included in “Financing costs, net” in Apache's consolidated statement of operations. The net loss includes an acceleration of related discount and deferred financing costs.

In January 2017, Apache purchased and canceled an additional $69 million aggregate principal amount of senior notes for $71 million in cash, including accrued interest and $1 million of premium, which completed the open market repurchase program.

F-28

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, 2016 and 2015:

	December 31,
	2016			2015
	(In millions)
Commercial paper	$	—		$	—
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)	493			500
3.25% notes due 2022(1)	857			919
2.625% notes due 2023(1)	528			531
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)	1,499			1,500
5.25% notes due 2042(1)	500			500
4.75% notes due 2043(1)	1,413			1,500
4.25% notes due 2044(1)	780			800
7.375% debentures due 2047	150			150
7.625% debentures due 2096	150			150
	8,350			8,530
Subsidiary and other obligations:
Notes due in 2017	—			1
Apache Finance Canada 7.75% notes due 2029	300			300
	300			301
Debt before unamortized discount and debt issuance costs	8,650			8,831
Unamortized discount	(50		)	(53		)
Debt issuance costs	(56		)	(61		)
Total debt	8,544			8,717
Current maturities	—			(1		)
Long-term debt	$	8,544		$	8,716

(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, 2016, excluding discounts and debt issuance costs, are as follows:

	(In millions)
2017	$	—
2018	550
2019	150
2020	—
2021	493
Thereafter(1)	7,457
Total Debt(1), excluding discounts and debt issuance costs	$	8,650

(1) In January 2017, Apache purchased and canceled $69 million aggregate principal amount of senior notes (see overview above), which reduces “Thereafter” and “Total Debt” maturities to $7.4 billion and $8.6 billion, respectively, as of January 31, 2017.

F-29

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

In April 2015, the FASB issued ASU 2015-03 “Simplifying the Presentation of Debt Issuance Costs,” which requires debt issuance costs to be presented as a direct deduction from the carrying value of the associated debt liability. The Company adopted this update in the first quarter of 2016 and applied the changes retrospectively for all periods presented. At December 31, 2015, the Company had debt issuance costs of $61 million classified as a long-term asset as a component of “Deferred charges and other” on the balance sheet that have been netted against “Long-term debt” in these financial statements. As of December 31, 2016, long-term debt is presented net of debt issuance costs of $56 million.

Fair Value

The Company’s debt is recorded at the carrying amount, net of unamortized discount and debt issuance costs, 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, 2016				December 31, 2015
	Carrying     Amount		Fair     Value		Carrying     Amount		Fair     Value
	(In millions)
Commercial paper	$	—	$	—	$	—	$	—
Notes and debentures	8,544		9,183		8,717		8,330
Total Debt	$	8,544	$	9,183	$	8,717	$	8,330

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, 2016 and 2015, there was no outstanding balance on Apache’s lines of credit.

Unsecured Committed Bank Credit Facilities

In June 2015, the Company entered into a five-year revolving credit facility which matures in June 2020, subject to Apache’s two, one-year extension options. The facility provides for aggregate commitments of $3.5 billion (including a $750 million letter of credit subfacility), with rights to increase commitments up to an aggregate $4.5 billion. Proceeds from borrowings may be used for general corporate purposes. Apache’s available borrowing capacity under this facility supports its commercial paper program. In connection with entry into the $3.5 billion facility, Apache terminated $5.3 billion in commitments under existing credit facilities. As of December 31, 2016, there were no borrowings under this credit facility, leaving aggregate available borrowing capacity at $3.5 billion.

At the Company’s option, the interest rate per annum for borrowings under the 2015 facility is either a base rate, as defined, plus a margin or the London Inter-bank Offered Rate (LIBOR), plus a margin. The Company also pays quarterly a facility fee at per annum rate on total commitments. The margins and the facility fee vary based upon the Company’s senior long-term debt rating. At December 31, 2016, the base rate margin was 0.075 percent, the LIBOR margin was 1.075 percent, and the facility fee was 0.175 percent.

The financial covenants of the 2015 credit facility require the Company to maintain an adjusted debt-to-capital ratio of not greater than 60 percent at the end of any fiscal quarter. For purposes of this calculation, capital excludes the effects of non-cash write-downs, impairments, and related charges occurring after June 30, 2015.

The 2015 facility’s negative covenants restrict the ability of the Company and its subsidiaries to create liens securing debt on its hydrocarbon-related assets, with exceptions for liens typically arising in the oil and gas industry, purchase money liens, liens on subsidiary assets located outside of the United States and Canada, and liens arising as a matter of law, such as tax and mechanics’ liens. The Company also may incur liens on assets if debt secured thereby does not exceed 5 percent of the Company’s consolidated assets, or approximately $1.1 billion as of December 31, 2016. Negative covenants also restrict Apache’s ability to merge with another entity unless it is the surviving entity, dispose of substantially all of its assets, and guarantee debt of non-consolidated entities in excess of the stated threshold.

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

In February 2016, Apache entered into a three-year letter of credit facility providing £900 million in commitments, with options to increase commitments to £1.075 billion and extend the term by one year. The facility is available for letters of credit denominated in pounds sterling, U.S. Dollars, Canadian Dollars, and any other foreign currency consented to by an issuing bank. The facility also is available for loans in pounds sterling, U.S. Dollars, and Canadian Dollars to cash collateralize letters of credit or obligations to provide letters of credit, in each case, to the extent letters of credit are unavailable under the facility. The facility’s representations and warranties, covenants, and events of default are substantially similar to those in Apache’s 2015 $3.5 billion revolving credit facility.

Commissions are payable on letters of credit outstanding under the 2016 facility at a per annum rate equal to a LIBOR margin. Borrowings bear interest per annum at a base rate or LIBOR, plus a margin. A facility fee at a per annum rate on aggregate commitments also is payable. Letter of credit commissions, the interest margin, and the facility fee vary depending on Apache’s senior unsecured long-term debt rating. At December 31, 2016, the LIBOR margin was 1.075 percent, the base rate margin was 0.075 percent, and the facility fee was 0.175 percent.

The 2016 facility is available for the Company’s letter of credit needs, particularly those which may arise in respect of abandonment obligations assumed in various North Sea acquisitions. As of December 31, 2016, three letters of credit aggregating approximately £147.5 million and no borrowings were outstanding under this facility.

There are no clauses in the 2015 $3.5 billion or 2016 £900 million credit facilities that permit the lenders to accelerate payments or refuse to lend based on unspecified material adverse changes. The agreements for these facilities 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 payment maturity and terminate lending and issuance commitments for nonpayment and other breaches, and if the Company or any of its U.S. or Canadian subsidiaries defaults on other indebtedness in excess of the stated threshold, is insolvent, or has any unpaid, non-appealable judgment against it for payment of money in excess of the stated threshold. Lenders may also accelerate payment maturity and terminate lending and issuance commitments if the Company undergoes a specified change in control or any borrower has specified pension plan liabilities in excess of the stated threshold. The Company was in compliance with the terms of these credit facilities as of December 31, 2016.

Commercial Paper Program

The Company has available a $3.5 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 the Company’s 2015 committed credit facility. At December 31, 2016 and 2015, the Company had no 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 18—Supplemental Guarantor Information.

Financing Costs, Net

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

	For the Year Ended December 31,
	2016			2015			2014
	(In millions)
Interest expense	$	464		$	486		$	499
Amortization of deferred loan costs	8			11			6
Capitalized interest	(48		)	(15		)	(85		)
Loss on extinguishment of debt	1			39			—
Interest income	(8		)	(10		)	(7		)
Financing costs, net	$	417		$	511		$	413

As of December 31, 2016, the Company has $50 million of debt discounts, which will be charged to interest expense over the life of the related debt issuances. Discount amortization of $3 million was recorded as interest expense in each of 2016, 2015, and 2014.

F-31

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

9. INCOME TAXES

Loss from continuing operations before income taxes is composed of the following:

	For the Year Ended December 31,
	2016			2015			2014
	(In millions)
U.S.	$	(997	)	$	(9,386	)	$	(4,807	)
Foreign	(685		)	(2,783		)	(2,023		)
Total	$	(1,682	)	$	(12,169	)	$	(6,830	)

The total income tax provision (benefit) from continuing operations consists of the following:

	For the Year Ended December 31,
	2016			2015			2014
	(In millions)
Current income taxes:
Federal	$	(14	)	$	363		$	(10	)
State	(30		)	41			1
Foreign	435			31			1,290
	391			435			1,281
Deferred income taxes:
Federal	(257		)	(1,123		)	(671		)
State	—			(51		)	(45		)
Foreign	(576		)	(271		)	(1,083		)
	(833		)	(1,445		)	(1,799		)
Total	$	(442	)	$	(1,010	)	$	(518	)

The total income tax provision (benefit) differs from the amounts computed by applying the U.S. statutory income tax rate to loss before income taxes. A reconciliation of the tax on the Company’s loss from continuing operations before income taxes and total tax expense is shown below:

	For the Year Ended December 31,
	2016			2015			2014
	(In millions)
Income tax expense (benefit) at U.S. statutory rate	$	(589	)	$	(4,259	)	$	(2,391	)
State income tax, less federal effect(1)	(19		)	(7		)	(28		)
Taxes related to foreign operations	303			(662		)	(147		)
Tax credits	(1		)	(6		)	—
Tax on distributed foreign earnings	80			726			311
Foreign tax credits	(136		)	(2,090		)	—
Deferred tax on undistributed foreign earnings	(31		)	1,903			560
Tax impact of goodwill adjustments	—			82			161
Change in U.K. tax rate	(238		)	(414		)	—
Net change in tax contingencies	(19		)	20			(3		)
Canadian USD functional currency election	158			—			—
Valuation allowances(1)	10			3,746			1,021
All other, net	40			(49		)	(2		)
	$	(442	)	$	(1,010	)	$	(518	)

(1) The change in state valuation allowance is included as a component of state income tax.

F-32

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The net deferred income tax liability reflects the net tax impact of temporary differences between the asset and liability amounts carried on the balance sheet under the U.S. GAAP method of accounting and amounts utilized for income tax purposes. The net deferred income tax liability consists of the following:

	December 31,
	2016			2015
	(In millions)
Deferred tax assets:
Deferred income	$	105		$	20
U.S. and state net operating losses	1,095			329
Foreign net operating losses	1,424			1,507
Tax credits and other tax incentives	62			82
Foreign tax credits	2,226			2,090
Accrued expenses and liabilities	153			136
Asset retirement obligation	875			1,037
Property and equipment	1,189			1,534
Total deferred tax assets	7,129			6,735
Valuation allowance	(5,401		)	(5,434		)
Net deferred tax assets	1,728			1,301
Deferred tax liabilities:
Deferred income	—			140
Investment in foreign subsidiaries	1,872			1,903
Equity investments	23			5
Property and equipment	1,533			1,773
Other	5			4
Total deferred tax liabilities	3,433			3,825
Net deferred income tax liability	$	1,705		$	2,524

Net deferred tax assets and liabilities are included in the consolidated balance sheet as follows:

	December 31,
	2016		2015
	(In millions)
Assets:
Deferred charges and other	$	5	$	5
Liabilities:
Deferred income taxes	1,710		2,529
Net deferred income tax liability	$	1,705	$	2,524

In 2016, the U.K. government enacted Finance Bill 2016, which provides tax relief to E&P companies operating in the North Sea through a reduction of Supplementary Charge from 20 percent to 10 percent, effective January 1, 2016. As a result of the enacted legislation, in 2016, Apache recorded a deferred tax benefit of $238 million related to the remeasurement of the Company’s December 31, 2015 U.K. deferred income tax liability.

In 2015, Apache repatriated the sales proceeds from the divestment of its interest in LNG projects and Australian upstream assets. Upon the repatriation of these proceeds, Apache recognized a U.S. current income tax liability of $560 million. Also in 2015, the U.K. government enacted Finance Bill 2015, which provided a reduction of Supplementary Charge from 32 percent to 20 percent, effective January 1, 2015. As a result of the enacted legislation, in 2015, Apache recorded a deferred tax benefit of $414 million related to the remeasurement of the Company’s December 31, 2014 U.K. deferred income tax liability.

F-33

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

In 2014, Apache evaluated its permanent reinvestment position and determined that undistributed earnings from certain foreign subsidiaries located in Apache’s Australia, Egypt, and North Sea regions will no longer be permanently reinvested. As a result of this change in position, the Company recorded $560 million of U.S. deferred income tax expense on undistributed earnings that were previously considered permanently reinvested as a component of continuing operations. In addition, the Company recorded $311 million of U.S. deferred income tax expense on foreign earnings that were distributed to the U.S. in 2014. The Company’s Canadian subsidiaries do not currently have undistributed earnings.

The Company has recorded an increase in valuation allowance against certain deferred tax assets, primarily driven by asset impairments. The Company has assessed the future potential to realize 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 and expectations for the future.

In 2016, 2015, and 2014, the Company's valuation allowance decreased by $33 million, increased by $3.9 billion, and increased by $966 million, respectively, as detailed in the table below:

	2016			2015		2014
	(In millions)
Balance at beginning of year	$	5,434		$	1,564	$	598
State(1)	(43		)	151		62
U.S.	139			2,159		—
Foreign(2)	(129		)	1,560		1,021
Discontinued operations(3)	—			—		(117		)
Balance at end of year	$	5,401		$	5,434	$	1,564

(1) Reported as a component of state income taxes.

(2) In 2015, Apache’s subsidiaries completed the sale of its interest in the Kitimat LNG project. As such, the deferred tax assets, liabilities, and valuation allowance related to the project were removed for 2015.

(3) In 2014, Apache’s subsidiaries completed the sale of all of the Company’s operations in Argentina. As such, the deferred tax assets, liabilities, and valuation allowance related to Argentina were removed for 2014.

On December 31, 2016, the Company had net operating losses as follows:

	Amount		Expiration
	(In millions)
Net operating losses:
U.S.	$	2,452	2018 - 2037
State	4,774		Various
Canada	125		2028 - 2035

The Company has a U.S. net operating loss carryforward of $2.5 billion, which includes $197 million of net operating loss subject to annual limitation under Section 382 of the Internal Revenue Code. The Company also has $829 million of capital loss carryforwards in Canada, which have an indefinite carryover period. The Company has recorded a valuation allowance against the U.S. net operating loss subject to Section 382 limitation, the state net operating loss, the Canadian net operating loss, and the Canadian capital loss because it is probable that these attributes will expire unutilized.

On December 31, 2016, the Company had foreign tax credits as follows:

	Amount		Expiration
	(In millions)
Foreign tax credits	$	2,226	2025-2026

The Company has a $2.2 billion U.S. foreign tax credit carryforward. The Company has recorded a valuation allowance against the U.S. foreign tax credits listed above because it is probable that these attributes will expire unutilized.

F-34

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The Company accounts for income taxes in accordance with ASC Topic 740, “Income Taxes,” which prescribes a minimum recognition threshold a tax position must meet before being recognized in the financial statements. Tax positions generally refer to a position taken in a previously filed income tax return or expected to be included in a tax return to be filed in the future that is reflected in the measurement of current and deferred income tax assets and liabilities. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:

	2016			2015		2014
	(In millions)
Balance at beginning of year	$	19		$	—	$	3
Additions based on tax positions related to the current year	15			19		—
Reductions for tax positions of prior years	(19		)	—		(3		)
Balance at end of year	$	15		$	19	$	—

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, 2016, 2015, and 2014 the Company recorded tax expense of nil, tax expense of $1 million, and tax benefit of $1 million, respectively, for interest and penalties. At December 31, 2016, 2015, and 2014 the Company had an accrued liability for interest and penalties of nil, $1 million, and nil, respectively.

In 2016 and 2015, the Company recorded a $4 million net reduction and a $19 million increase in its reserve for uncertain tax positions, respectively. In 2014, the Internal Revenue Service concluded its audit of the 2011 and 2012 tax years, and the Company reduced its unrecognized tax benefit by $3 million as a result of the conclusion of this audit.

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.	2012
Canada	2012
Egypt	1998
U.K.	2014

F-35

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

10.    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 $15 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 Claims

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) in an amount up to $67.5 million pursuant to the terms and conditions of stock purchase agreements entered in 2006 between Company subsidiaries and subsidiaries of Pioneer.

Louisiana Restoration

Louisiana surface owners often file lawsuits or assert claims against oil and gas companies, including Apache, claiming that operators and working interest owners in the chain of title are liable for environmental damages on the leased premises, including damages measured by the cost of restoration of the leased premises to their original condition, regardless of the value of the underlying property. 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 as noted. Further, 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 these lawsuits and claims.

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. Plaintiff seeks unspecified 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 many defendants in the lawsuit. In 2014 the Louisiana state government passed a law (SB 469) clarifying that only entities authorized under the Coastal Zone Management Act may bring litigation to assert claims arising out of the permitted activities. Plaintiff is not one of those authorized entities. On February 13, 2015, the federal court entered judgment in favor of defendants dismissing all of plaintiff’s claims with prejudice on various grounds, and plaintiff appealed the case to the 5^th Circuit Court of Appeals. The appeal is still pending. The overall exposure related to this lawsuit is not currently determinable. While an adverse judgment against Apache might be possible, Apache intends to continue to vigorously oppose the claims, including by defending against plaintiff’s appeal of the federal court’s judgment.

F-36

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

On November 8, 2013, Plaquemines Parish, Louisiana, filed three lawsuits against Apache and other oil and gas producers in the Parish’s 25th Judicial District Court, captioned Parish of Plaquemines v. Rozel Operating Company et al., Docket No. 60-996; Parish of Plaquemines v. Apache Oil Corporation et al., Docket No. 610; and Parish of Plaquemines v. HHE Energy Company et al., Docket No. 60-983. On or about February 4, 2016, Cameron Parish, Louisiana, filed six new lawsuits against Apache and other oil and gas producers in the Parish’s 38th Judicial District Court, captioned Parish of Cameron v. BEPCO, L.P., et al., Docket No. 10-19572; Parish of Cameron v. BP America Production Company et al., Docket No. 10-19576; Parish of Cameron v. Apache Corporation (of Delaware) et al., Docket No. 10-19579; Parish of Cameron v. Atlantic Richfield Company et al., Docket No. 10-19577; Parish of Cameron v. Alpine Exploration Companies, Inc., et al., Docket No. 19580; and Parish of Cameron v. Auster Oil and Gas, Inc., et al, Docket No. 10-19582. On July 28, 2016, Vermillion Parish, Louisiana, filed an amended petition against Apache and other oil and gas producers in the 15^th Judicial District Court, captioned Keith Stutes, District Attorneyfor the 15^th Judicial District of the State of Louisiana v. Gulfport Energy, et al., Docket No.102156. On September 30, 2016, St. Bernard Parish, Louisiana, filed an Amended Petition against Apache and other oil and gas producers in the 34^th Judicial District Court, captioned The Parish of St. Bernard v. Atlantic Richfield et al., Docket No. 16-1228. Many similar lawsuits have been filed against other oil and gas producers in Parishes across south Louisiana. In these cases, the Parishes, as plaintiffs, allege 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 Parish or the State of Louisiana. Plaintiffs allege that defendants caused substantial damage to land and water bodies located in the coastal zone of Louisiana. Plaintiffs seek, 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. While an adverse judgment against Apache might be possible, Apache intends to vigorously oppose these claims.

Apollo Exploration Lawsuit

In a case captioned Apollo Exploration, LLC, Cogent Exploration, Ltd. Co. & SellmoCo, LLC v. Apache Corporation, Cause No. CV50538 in the 385th Judicial District Court, Midland County, Texas, in a Fourth Amended Petition filed on March 21, 2016, plaintiffs allege damages in excess of $500 million (having previously claimed in excess of $1.1 billion) relating to purchase and sale agreements, mineral leases, and areas of mutual interest agreements concerning properties located in Hartley, Moore, Potter, and Oldham Counties, Texas. Apache believes that plaintiffs’ claims lack merit, and further that plaintiffs’ alleged damages are grossly inflated. Apache will vigorously oppose the claims.

Escheat Audits

In September 2010, the State of Delaware, Department of Finance, Division of Revenue (Unclaimed Property) (Delaware), notified Apache Corporation that Delaware’s consultant, Kelmar Associates (Kelmar), would examine Apache’s books and records and those of its subsidiaries and related entities to determine compliance with Delaware Escheat Laws.

Delaware completed its audit of the Company's accounts payable, payroll, and royalty payments, on which the Company expects an assessment of less than $200,000. However, Delaware suspended its audit before completing its examination of the Company’s accounts receivable, following the June 2016 Temple-Inland v. Cook court decision, in which the Delaware federal court determined thatDelaware’s current method and technique for estimating a company’s unclaimed property liability violates the due process requirements of the U.S. Constitution.  In response to that decision, the Delaware Legislature is considering changes to its unclaimed property statute.  The timing and extent of any legislative modifications is currently unknown.

Burrup-Related Gas Supply Lawsuits

In the cases captioned Radhika Oswal v. Australia and New Zealand Banking Group Limited (ANZ) et al., No. SCI 2011 4653 and Pankaj Oswal v. Australia and New Zealand Banking Group Limited (ANZ) et al., No. SCI 2012 01995, in the Supreme Court of Victoria, Australia, trial commenced on May 30, 2016. In August 2016, the cases settled on confidential terms including an exchange of consideration that did not have a material effect on the Company’s financial position.

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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, 2016, the Company had an undiscounted reserve for environmental remediation of approximately $51 million. Apache is not aware of any environmental claims existing as of December 31, 2016 that have not been provided for or would otherwise have a material impact on its financial position or results of operations. There can be no assurance however, that current regulatory requirements will not change or past non-compliance with environmental laws will not be discovered on the Company’s properties.

Apache Canada Ltd. (ACL) reported a produced water release from a water injection pipeline in a remote area of the Belloy Field that occurred on or about May 4, 2016, and an H2S leak at the Zama 10-33-115-06 on or about September 19, 2016. The causes of these incidents remain under investigation. With respect to previous releases of produced water that occurred in the Zama area on or between October 3 and October 25, 2013, and in the Belloy Field on or about January 20, 2014, the Company resolved all of the charges associated with these releases with the Crown. The Company does not expect the economic impact of any of these incidents to have a material effect on the Company’s financial position, results of operations, or liquidity.

LNG Divestiture Dispute

Each of Woodside and the Company asserted claims against the other resulting in court proceedings in the Supreme Court of Western Australia and the Court of Queen’s Bench of Alberta, Calgary. Woodside also initiated third party expert determination proceedings at the ICC International Centre for ADR concerning certain aspects of its purchase price adjustment claims. Each of these proceedings has now been dismissed by agreement in November 2016. The parties have resolved the central matters in dispute on mutually agreeable terms and there was no significant impact on the Company’s financial position, results of operations, or liquidity.

Australian Operations Divestiture Dispute

By a Sale and Purchase Agreement dated April 9, 2015 (SPA), the Company and its subsidiaries divested their remaining Australian operations to Quadrant Energy Pty Ltd (Quadrant). Closing occurred on June 5, 2015. By letter dated June 6, 2016, Quadrant provided the Company with a notice of claim under the SPA claiming approximately $200 million in the aggregate. The Company believes that these claims lack merit and will not have a material adverse effect on the Company’s financial position, results of operation, or liquidity.

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Contractual Obligations

At December 31, 2016, contractual obligations for long-term operating leases, capital leases, and purchase obligations are as follows:

Net Minimum Commitments	Total		2017		2018-2019		2020-2021		2022 & Beyond
	(In millions)
Drilling rigs	$	244	$	177	$	67	$	—	$	—
Purchase obligations(1)	680		119		287		250		24
Operating lease obligations(2)	258		56		95		37		70
Capital lease obligations	$	43	$	1	$	3	$	3	$	36
Total Net Minimum Commitments	$	1,225	$	353	$	452	$	290	$	130

(1) Includes minimum commitments associated with long-term take-or-pay contracts, NGL processing agreements, drilling work program commitments, and agreements to secure capacity rights on third-party pipelines.

(2) Amounts include long-term lease payments for office space, aircraft, supply and standby vessels, gas pipeline and land leases, and equipment related to exploration, development, and production activities, such as compressors. The Company expects to receive $10 million in sublease income associated with these leases.

The table above includes leases for buildings, facilities, and related equipment with varying expiration dates through 2042. Net rental expense for continuing operations was $59 million, $57 million, and $45 million for 2016, 2015, and 2014, respectively. Costs incurred under take-or-pay and throughput obligations were $86 million, $92 million, and $89 million for 2016, 2015, and 2014, respectively.

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

11.    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, at its discretion, 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 Canada Ltd. and Apache North Sea Limited maintain separate retirement plans, as required under the laws of Canada and the U.K., respectively.

The aggregate annual cost to Apache of all U.S. plans, the money purchase retirement plan, non-qualified retirement/savings plan, and non-qualified restorative retirement savings plan was $82 million, $77 million, and $107 million for 2016, 2015, and 2014, 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 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 or at the date they become eligible for Medicare, 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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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The following tables set forth the benefit obligation, fair value of plan assets and funded status as of December 31, 2016, 2015, and 2014, 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.

	2016						2015						2014
	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	$	202		$	26		$	216		$	22		$	189		$	28
Service cost	4			2			5			2			5			3
Interest cost	7			1			8			1			9			1
Foreign currency exchange rate changes	(39		)	—			(10		)	—			(13		)	—
Actuarial losses (gains)	32			(2		)	(10		)	—			31			(9		)
Effect of curtailment and settlements	—			—			—			2			—			—
Benefits paid	(4		)	(3		)	(7		)	(2		)	(5		)	(2		)
Retiree contributions	—			2			—			1			—			1
Projected benefit obligation at end of year	202			26			202			26			216			22
Change in Plan Assets
Fair value of plan assets at beginning of year	197			—			206			—			191			—
Actual return on plan assets	46			—			1			—			25			—
Foreign currency exchange rates	(39		)	—			(10		)	—			(13		)	—
Employer contributions	6			1			7			1			8			1
Benefits paid	(4		)	(3		)	(7		)	(2		)	(5		)	(2		)
Retiree contributions	—			2			—			1			—			1
Fair value of plan assets at end of year	206			—			197			—			206			—
Funded status at end of year	$	4		$	(26	)	$	(5	)	$	(26	)	$	(10	)	$	(22	)
Amounts recognized in Consolidated Balance Sheet
Current liability	$	—		$	(2	)	$	—		$	(2	)	$	—		$	(1	)
Non-current asset (liability)	4			(24		)	(5		)	(24		)	(10		)	(21		)
	$	4		$	(26	)	$	(5	)	$	(26	)	$	(10	)	$	(22	)
Pre-tax Amounts Recognized in Accumulated Other Comprehensive Income (Loss)
Accumulated gain (loss)	$	(25	)	$	9		$	(32	)	$	9		$	(37	)	$	10
Weighted Average Assumptions used as of December 31
Discount rate	2.70		%	3.76		%	3.90		%	3.95		%	3.70		%	3.62		%
Salary increases	4.80		%	N/A			4.60		%	N/A			4.60		%	N/A
Expected return on assets	3.40		%	N/A			4.10		%	N/A			3.90		%	N/A
Healthcare cost trend
Initial	N/A			7.00		%	N/A			7.00		%	N/A			7.00		%
Ultimate in 2025	N/A			5.00		%	N/A			5.00		%	N/A			5.00		%

F-41

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

As of December 31, 2016, 2015, and 2014, the accumulated benefit obligation for the U.K. Pension Plan was $181 million, $169 million, and $183 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 a 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
	2016		2016		2015
Asset Category
Equity securities:
U.K. quoted equities	14	%	14	%	14	%
Overseas quoted equities	26	%	26	%	26	%
Total equity securities	40	%	40	%	40	%
Debt securities:
U.K. Government bonds	47	%	47	%	48	%
U.K. corporate bonds	12	%	12	%	12	%
Debt securities	59	%	59	%	60	%
Cash	1	%	1	%	—	%
Total	100	%	100	%	100	%

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The plan’s assets do not include any direct ownership of equity or debt securities of Apache. The fair value of plan assets is based upon unadjusted quoted prices for identical instruments in active markets, which is a Level 1 fair value measurement. 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, 2016 and December 31, 2015:

	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, 2016
Equity securities:
U.K. quoted equities(1)	$	28	$	—	$	—	$	28
Overseas quoted equities(2)	54		—		—		54
Total equity securities	82		—		—		82
Debt securities:
U.K. Government bonds(3)	97		—		—		97
U.K. corporate bonds(4)	25		—		—		25
Total debt securities	122		—		—		122
Cash	2		—		—		2
Fair value of plan assets	$	206	$	—	$	—	$	206
December 31, 2015
Equity securities:
U.K. quoted equities(1)	$	27	$	—	$	—	$	27
Overseas quoted equities(2)	53		—		—		53
Total equity securities	80		—		—		80
Debt securities:
U.K. Government bonds(3)	93		—		—		93
U.K. corporate bonds(4)	24		—		—		24
Total debt securities	117		—		—		117
Fair value of plan assets	$	197	$	—	$	—	$	197

(1) This category comprises U.K. passive equities, which are benchmarked against the FTSE 350 Index.

(2) This category includes overseas equities, which comprises 30 percent passive global equities benchmarked against the MSCI World (NDR) Index, 12 percent passive global equities (hedged) benchmarked against the MSCI World (NDR) Hedged Index, 30 percent fundamental indexation global equities benchmarked against the FTSE RAFI Developed 1000 index, 12 percent fundamental indexation global equities (hedged) benchmarked against the FTSE RAFI Developed 1000 Hedge Index, and 16 percent emerging markets benchmarked against the MSCI Emerging Markets (NDR) Index, which has 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, which comprises 48 percent index-linked gilts benchmarked against the FTSE Actuaries Government Securities Index-Linked Over 5 Years Index, 37 percent sterling nominal LDI bonds, and 15 percent sterling inflation linked LDI bonds, both benchmarked against ILIM Custom Benchmark index.

(4) This category comprises U.K. corporate bonds: 12 percent benchmarked against the BofAML Sterling Corporate & Collaterlised (excluding Subordinated) 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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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The following tables set forth the components of the net periodic cost and the underlying weighted average actuarial assumptions used for the pension and postretirement benefit plans as of December 31, 2016, 2015, and 2014:

	2016						2015						2014
	Pension Benefits			Postretirement Benefits			Pension Benefits			Postretirement Benefits			Pension Benefits			Postretirement Benefits
	(In millions)
Component of Net Periodic Benefit Costs
Service cost	$	4		$	2		$	5		$	2		$	5		$	3
Interest cost	7			1			8			1			9			1
Expected return on assets	(7		)	—			(8		)	—			(11		)	—
Amortization of actuarial (gain) loss	1			(1		)	2			—			1			—
Curtailment (gain) loss	—			—			—			—			—			—
Net periodic benefit cost	$	5		$	2		$	7		$	3		$	4		$	4
Weighted Average Assumptions used to determine Net Period Benefit Cost for the Years ended December 31
Discount rate	3.90		%	3.95		%	3.70		%	3.62		%	4.60		%	4.33		%
Salary increases	4.60		%	N/A			4.60		%	N/A			4.90		%	N/A
Expected return on assets	4.10		%	N/A			3.90		%	N/A			5.60		%	N/A
Healthcare cost trend
Initial	N/A			7.00		%	N/A			7.00		%	N/A			7.00		%
Ultimate in 2025	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	5		(4		)

Apache expects to contribute approximately $5 million to its pension plan and $2 million to its postretirement benefit plan in 2017. The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:

	Pension Benefits		Postretirement Benefits
	(In millions)
2017	$	4	$	2
2018	4		2
2019	4		2
2020	4		2
2021	4		2
Years 2022-2026	24		9

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

12.    CAPITAL STOCK

Common Stock Outstanding

	2016	2015	2014
Balance, beginning of year	378,034,175	376,504,892	395,772,908
Shares issued for stock-based compensation plans:
Treasury shares issued	11,504	17,525	17,454
Common shares issued	1,393,997	1,511,758	1,665,259
Treasury shares acquired	—	—	(20,950,729	)
Balance, end of year	379,439,676	378,034,175	376,504,892

Net Income (Loss) per Common Share

A reconciliation of the components of basic and diluted net income (loss) per common share for the years ended December 31, 2016, 2015, and 2014 is presented in the table below.

	2016							2015							2014
	Loss			Shares	Per Share			Income (Loss)			Shares	Per Share			Loss			Shares	Per Share
	(In millions, except per share amounts)
Basic and Diluted:
Loss from continuing operations	$	(1,372	)	379	$	(3.62	)	$	(10,844	)	378	$	(28.70	)	$	(6,653	)	384	$	(17.32	)
Income (loss) from discontinued operations	(33		)	379	(0.09		)	492			378	1.30			(1,707		)	384	(4.44		)
Loss attributable to common stock	$	(1,405	)	379	$	(3.71	)	$	(10,352	)	378	$	(27.40	)	$	(8,360	)	384	$	(21.76	)

The diluted EPS calculation excludes options and restricted shares that were anti-dilutive totaling 4.7 million, 7.0 million, and 4.5 million for the years ended December 31, 2016, 2015, and 2014, respectively.

Stock Repurchase Program

Apache’s Board of Directors has authorized the purchase of up to 40 million shares of the Company’s common stock. 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, and through December 31, 2014, had repurchased a total of 32.2 million shares at an average price of $88.96 per share. The Company has not purchased any additional shares during 2016 or 2015, and is not obligated to acquire any specific number of shares.

Common Stock Dividend

The Company paid common stock dividends of $1.00 per share in 2016, $1.00 per share in 2015, and $0.95 per share in 2014.

Stock Compensation Plans

The Company has several stock-based compensation plans, which include stock options, restricted stock, and conditional restricted stock unit plans. On May 12, 2016, the Company's shareholders approved the 2016 Omnibus Compensation Plan (the 2016 Plan), which is intended to provide eligible employees with equity-based incentives. The 2016 Plan provides for the granting of Incentive Stock Options, Non-Qualified Stock Options, Performance Awards, Restricted Stock Awards, Restricted Stock Units, Stock Appreciation Rights, Cash Awards, or any combination of the foregoing. A total of 22.9 million shares were authorized and available for grant under the 2016 Plan as of December 31, 2016. Previously approved plans remain in effect solely for the purpose of governing grants still outstanding that were issued prior to approval of the 2016 Plan. All new grants are issued from the 2016 Plan.

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

For 2016, 2015, and 2014, stock-based compensation expensed was $131 million, $100 million, and $148 million ($93 million, $65 million, and $95 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:

	2016		2015		2014
	(In millions)
Stock-based compensation expensed	$	131	$	100	$	148
Stock-based compensation capitalized	40		53		62
Total stock-based compensation costs	$	171	$	153	$	210

Stock Options

As of December 31, 2016, the Company had issued options to purchase shares of the Company’s common stock under the employee stock option plan adopted in 2005 (the Stock Option Plan), as well as the 2007 Omnibus Equity Compensation Plan (the 2007 Plan), the 2011 Plan, and the 2016 Plan (together, the Omnibus Plans). New shares of Company stock will be issued for employee stock option exercises. Under the Stock Option Plan 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 issued prior to 2016 generally become exercisable ratably over a four-year period and expire 10 years after granted. Options granted in or after 2016 become exercisable ratably over a three-year period and expire 10 years after granted. The Omnibus Plans and the 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 Plan and the Omnibus Plans is presented in the table and narrative below:

	2016
	Shares Under Option		Weighted Average Exercise Price
	(In thousands)
Outstanding, beginning of year	4,931		$	91.52
Granted	873		41.24
Exercised	—		—
Forfeited or expired	(691	)	76.99
Outstanding, end of year(1)	5,113		84.89
Expected to vest(2)	887		46.88
Exercisable, end of year(3)	4,177		93.40

(1) As of December 31, 2016, options outstanding had a weighted average remaining contractual life of 4.6 years and aggregate intrinsic value of $18 million.

(2) As of December 31, 2016, options expected to vest had a weighted average remaining contractual life of 8.7 years and aggregate intrinsic value of $17 million.

(3) As of December 31, 2016, options exercisable had a weighted average remaining contractual life of 3.7 years and aggregate intrinsic value of nil.

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.

	2016			2015	2014
Expected volatility	32.72		%	N/A	N/A
Expected dividend yields	2.42		%	N/A	N/A
Expected term (in years)	6			N/A	N/A
Risk-free rate	1.44		%	N/A	N/A
Weighted-average grant-date fair value	$	10.38		N/A	N/A

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

There were no options exercised during 2016. The intrinsic value of options exercised during 2015 and 2014 was approximately $3 million and $13 million, respectively. As of December 31, 2016, the total compensation cost related to non-vested options not yet recognized was $6 million, which will be recognized over the remaining vesting period of the options.

In January 2017, the Company issued 489,773 options to purchase shares of the Company’s common stock to eligible employees under the 2016 Plan. The total compensation cost of $9 million is estimated to be recognized over a three-year vesting period of these options.

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 2016, the Company awarded 4,049,023 restricted stock units at a weighted-average per-share market price of $47.37. In 2015 and 2014, the Company awarded 2,976,562 and 3,046,744 restricted stock units at a weighted-average per-share market price of $61.65 and $86.87, 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 2016, 2015, and 2014, $113 million ($73 million after tax), $90 million ($58 million after tax), and $111 million ($72 million after tax), respectively, was charged to expense. In 2016, 2015, and 2014, $35 million, $48 million, and $47 million was capitalized, respectively. As of December 31, 2016, there was $233 million of total unrecognized compensation cost related to 6,061,803 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 2016, 2015, and 2014 was approximately $151 million, $149 million, and $138 million, respectively. A summary of restricted stock unit activity for the year ended December 31, 2016, is presented below.

	Shares		Weighted- Average Grant- Date Fair Value
	(In thousands)
Non-vested at January 1, 2016	4,570		$	70.86
Granted	4,049		47.37
Vested	(2,081	)	72.59
Forfeited	(476	)	58.05
Non-vested at December 31, 2016	6,062		55.55

In January 2017, the Company awarded 1,866,606 restricted stock units at a weighted-average per-share market price of $63.25 under the 2016 Plan to eligible employees. The total compensation cost of $118 million, absent any forfeitures, is estimated to be recognized over a three-year vesting period of these restricted stock units.

Total Shareholder Return (TSR) 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 the total shareholder return programs were outstanding at December 31, 2016, as described below:

• In January 2013, the Company’s Board of Directors approved the 2013 TSR 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 canceled 918,016 awards under the 2013 Performance Program for nonexecutive employees. Based on measurements of total shareholder return relative to the designated peer group at December 31, 2015, shares were paid out at 70 percent of target. A total of 29,957 awards were outstanding at December 31, 2016.

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

• In January 2014, the Company’s Board of Directors approved the 2014 TSR Program, pursuant to the 2011 Plan. In January 2014, eligible employees received initial conditional restricted stock unit awards totaling 157,406 units. Based on measurements of total shareholder return relative to the designated peer group at December 31, 2016, shares were paid out at 100 percent of target. A total of 47,867 awards were outstanding at December 31, 2016.

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 2016, 2015, and 2014, $0.7 million ($0.5 million after tax), $0.6 million ($0.4 million after tax), and $18 million ($11 million after tax), respectively, was charged to expense. During 2016, 2015, and 2014, $0.1 million, $0.3 million, and $7 million was capitalized, respectively. As of December 31, 2016, there was $1.2 million of total unrecognized compensation cost related to 77,824 unvested conditional restricted stock units. The weighted-average remaining life of the unvested conditional restricted stock units is approximately 0.7 years.

	Shares		Weighted- Average Grant- Date Fair Value(1)
	(In thousands)
Non-vested at January 1, 2016	172		$	78.22
Granted	—		—
Vested	(34	)	76.07
Forfeited or expired	(60	)	71.20
Non-vested at December 31, 2016	78		77.10

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

Business Performance Restricted Stock Units

Apache has a business performance program for certain eligible employees with 50 percent of the shares payout based upon the TSR program payout model as described above, and the remaining 50 percent of the shares based on performance and financial objectives as defined in the plan. The overall results of the objectives will be calculated at the end of the award’s stated performance period and, if a payout is warranted, applied to the target number of restricted stock units awarded. The business performance shares will immediately vest 50 percent at the end of the three-year performance period, with the remaining 50 percent vesting at the end of the following year. Grants from the total shareholder return programs outstanding at December 31, 2016, are as described below:

• In February 2015, the Company’s Board of Directors approved the 2015 Business Performance Program, pursuant to the 2011 Plan. Eligible employees received initial conditional restricted stock unit awards totaling 602,304 units. The actual amount of shares awarded will be between zero and 150 percent of target. A total of 431,707 units were outstanding as of December 31, 2016, from which a minimum of zero and a maximum of 647,561 shares could be awarded.

• In January 2016, the Company’s Board of Directors approved the 2016 Business Performance Program, pursuant to the 2011 Plan. Eligible employees received the initial conditional restricted stock unit totaling 871,369. The actual amount of shares awarded will be between zero and 200 percent of target. A total of 793,442 units were outstanding as of December 31, 2016, from which a minimum of zero and a maximum of 1,586,884 shares could be awarded.

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The fair value cost of the awards was estimated on the date of grant and is being recorded as compensation expense ratably over the vesting terms. During 2016 and 2015, $14 million ($9 million after tax) and $3 million ($2 million after tax), respectively, were charged to expense. During 2016 and 2015, $2 million and $1 million were capitalized, respectively. As of December 31, 2016, there was $37 million of total unrecognized compensation cost related to 1,225,149 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, 2016	501		$	66.53
Granted	871		34.19
Vested	—		—
Forfeited or expired	(147	)	45.65
Non-vested at December 31, 2016	1,225		45.60

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

In January 2017, the Company’s Board of Directors approved the 2017 Performance Program, pursuant to the 2016 Plan, with terms similar to the 2016 Performance Program described above. Eligible employees received the initial conditional restricted stock unit totaling 604,147 units, with the ultimate number of restricted stock units to be awarded ranging from zero to a maximum of 1,208,294 units. The grant date fair value per award was $66.97.

13.    ACCUMULATED OTHER COMPREHENSIVE LOSS

Components of accumulated other comprehensive loss include the following:

	For the Year Ended December 31,
	2016			2015			2014
	(In millions)
Currency translation adjustment(1)	$	(109	)	$	(109	)	$	(109	)
Unfunded pension and postretirement benefit plan (Note 11)	(3		)	(10		)	(7		)
Accumulated other comprehensive loss	$	(112	)	$	(119	)	$	(116	)

(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).

14.    MAJOR CUSTOMERS

In 2016 and 2015, purchases by China Petroleum & Chemical Corporation and its subsidiaries accounted for 21 percent and 12 percent, respectively, of the Company's worldwide oil and gas production revenues. In 2016 and 2015, purchases by Egyptian General Petroleum Company and its subsidiaries accounted for 12 percent and 11 percent, respectively, of the Company's worldwide oil and gas production revenues. In 2015 and 2014, purchases by Royal Dutch Shell plc and its subsidiaries accounted for 11 percent and 19 percent, respectively, of the Company’s worldwide oil and gas production revenues.

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

15.    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, 2016, the Company had production in four reporting segments: the United States, Canada, Egypt, and the U.K. North Sea. Apache also pursues exploration interests in Suriname that may, over time, result in a reportable discovery and development opportunity. Financial information for each area is presented below:

	United States			Canada			Egypt(1)		North Sea			Other International			Total(1)
	(In millions)
2016
Oil and gas production revenues	$	1,997		$	343		$	2,057	$	970		$	—		$	5,367
Operating Expenses:
Lease operating expenses	553			181			446		314			—			1,494
Gathering and transportation	80			68			44		8			—			200
Taxes other than income	139			20			—		(33		)	—			126
Depreciation, depletion, and amortization	1,138			183			778		519			—			2,618
Exploration	285			88			48		37			15			473
Asset retirement obligation accretion	34			47			—		75			—			156
Impairments	80			367			1		655			—			1,103
Operating Income (Loss)	$	(312	)	$	(611	)	$	740	$	(605	)	$	(15	)	(803		)
Other Income (Expense):
Gain on divestitures, net															21
Other															(34		)
General and administrative															(410		)
Transaction, reorganization, and separation															(39		)
Financing costs, net															(417		)
Net Loss From Continuing Operations Before Income Taxes															$	(1,682	)
Net Property and Equipment	$	11,168		$	1,464		$	3,362	$	2,834		$	39		$	18,867
Total Assets	$	12,403		$	1,591		$	4,893	$	3,584		$	48		$	22,519
Additions to Net Property and Equipment	$	926		$	34		$	459	$	260		$	2		$	1,681

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

	United States			Canada			Egypt(1)			North Sea			Other International			Total(1)
	(In millions)
2015
Oil and gas production revenues	$	2,637		$	498		$	2,095		$	1,280		$	—		$	6,510
Operating Expenses:
Lease operating expenses	739			244			522			349			—			1,854
Gathering and transportation	68			89			45			9			—			211
Taxes other than income	184			26			9			63			—			282
Depreciation, depletion, and amortization	1,558			301			927			514			—			3,300
Exploration	2,145			231			154			237			4			2,771
Asset retirement obligation accretion	28			43			—			74			—			145
Impairments	6,266			1,593			1,255			211			147			9,472
Operating Loss	$	(8,351	)	$	(2,029	)	$	(817	)	$	(177	)	$	(151	)	(11,525		)
Other Income (Expense):
Gain on divestitures, net																281
Other																98
General and administrative																(380		)
Transaction, reorganization, and separation																(132		)
Financing costs, net																(511		)
Net Loss From Continuing Operations Before Income Taxes																$	(12,169	)
Net Property and Equipment	$	11,753		$	2,074		$	3,712		$	3,263		$	36		$	20,838
Total Assets	$	12,782		$	2,225		$	6,165		$	4,280		$	48		$	25,500
Additions to Net Property and Equipment	$	2,099		$	403		$	862		$	715		$	27		$	4,106

2014
Oil and gas production revenues	$	5,744		$	1,092		$	3,643	$	2,316		$	—		$	12,795
Operating Expenses:
Lease operating expenses	921			384			499		434			—			2,238
Gathering and transportation	93			123			40		17			—			273
Taxes other than income	350			31			11		185			—			577
Depreciation, depletion, and amortization	2,408			439			872		807			—			4,526
Exploration	2,113			162			112		119			(7		)	2,499
Asset retirement obligation accretion	43			39			—		72			—			154
Impairments	2,622			2,412			173		1,895			—			7,102
Operating Income (Loss)	$	(2,806	)	$	(2,498	)	$	1,936	$	(1,213	)	$	7		(4,574		)
Other Income (Expense):
Loss on divestitures, net															(1,608		)
Other															285
General and administrative															(453		)
Transaction, reorganization, and separation															(67		)
Financing costs, net															(413		)
Net Loss From Continuing Operations Before Income Taxes															$	(6,830	)
Net Property and Equipment	$	19,507		$	4,197		$	5,141	$	3,300		$	9		$	32,154
Total Assets	$	21,487		$	4,728		$	6,926	$	4,480		$	544		$	38,165
Additions to Net Property and Equipment	$	7,006		$	1,358		$	1,293	$	1,060		$	8		$	10,725

(1) Includes a noncontrolling interest in Egypt.

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

16.    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. In the second quarter of 2015, Apache completed the sale of its Australian LNG business and oil and gas assets, and as such the results of Australia oil and gas assets have been classified as discontinued operations.

	United States			Canada			Egypt(3)		North Sea			Other International			Total(3)(4)
	(In millions, except per boe)
2016
Oil and gas production revenues	$	1,997		$	343		$	2,057	$	970		$	—		$	5,367
Operating cost:
Depreciation, depletion, and amortization(1)	1,055			174			733		498			—			2,460
Asset retirement obligation accretion	34			47			—		75			—			156
Lease operating expenses	553			181			446		314			—			1,494
Gathering and transportation	80			68			44		8			—			200
Exploration expenses	285			88			48		37			15			473
Impairments related to oil and gas properties	61			366			—		—			—			427
Production taxes(2)	135			18			—		(33		)	—			120
Income tax	(72		)	(162		)	354		28			—			148
	2,131			780			1,625		927			15			5,478
Results of operation	$	(134	)	$	(437	)	$	432	$	43		$	(15	)	$	(111	)
2015
Oil and gas production revenues	$	2,637		$	498		$	2,095	$	1,280		$	—		$	6,510
Operating cost:
Depreciation, depletion, and amortization(1)	1,455			251			780		490			—			2,976
Asset retirement obligation accretion	28			43			—		74			—			145
Lease operating expenses	739			244			522		349			—			1,854
Gathering and transportation	68			89			45		9			—			211
Exploration expenses	2,145			231			154		237			4			2,771
Impairments related to oil and gas properties	6,154			1,031			193		11			—			7,389
Production taxes(2)	178			23			—		58			—			259
Income tax	(2,886		)	(369		)	180		26			—			(3,049		)
	7,881			1,543			1,874		1,254			4			12,556
Results of operation	$	(5,244	)	$	(1,045	)	$	221	$	26		$	(4	)	$	(6,046	)
2014
Oil and gas production revenues	$	5,744		$	1,092		$	3,643	$	2,316		$	—		$	12,795
Operating cost:
Depreciation, depletion, and amortization(1)	2,294			382			735		784			—			4,195
Asset retirement obligation accretion	43			39			—		72			—			154
Lease operating expenses	921			384			499		434			—			2,238
Gathering and transportation	93			123			40		17			—			273
Exploration expenses	2,113			162			112		119			(7		)	2,499
Impairments related to oil and gas properties	2,372			1,645			173		1,878			—			6,068
Production taxes(2)	342			27			—		177			—			546
Income tax	(864		)	(421		)	938		(723		)	—			(1,070		)
	7,314			2,341			2,497		2,758			(7		)	14,903
Results of operation	$	(1,570	)	$	(1,249	)	$	1,146	$	(442	)	$	7		$	(2,108	)

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(1) This amount only reflects DD&A of capitalized costs of oil and gas properties and, therefore, does not agree with DD&A reflected on Note 15—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 15—Business Segment Information.

(3) Includes noncontrolling interest in Egypt.

(4) Prior year 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)
2016
Acquisitions:
Proved	$	—		$	1		$	6	$	—	$	38		$	—	$	—	$	45
Unproved	110			7			49		—		4			—		—		170
Exploration	278			23			67		—		84			—		18		470
Development	420			27			353		—		150			—		—		950
Costs incurred(1)	$	808		$	58		$	475	$	—	$	276		$	—	$	18	$	1,635
(1) Includes capitalized interest and asset retirement costs as follows:
Capitalized interest	$	21		$	6		$	—	$	—	$	21		$	—	$	—	$	48
Asset retirement costs	(51		)	(13		)	—		—		(128		)	—		—		(192		)
2015
Acquisitions:
Proved	$	1		$	8		$	29	$	—	$	—		$	—	$	—	$	38
Unproved	313			23			—		—		—			—		—		336
Exploration	194			51			125		32		246			—		29		677
Development	1,729			151			741		98		479			—		—		3,198
Costs incurred(1)	$	2,237		$	233		$	895	$	130	$	725		$	—	$	29	$	4,249
(1)Includes capitalized interest and asset retirement costs as follows:
Capitalized interest	$	—		$	—		$	8	$	6	$	7		$	—	$	—	$	21
Asset retirement costs	123			8			—		—		(66		)	—		—		65
2014
Acquisitions:
Proved	$	102		$	—		$	11	$	—	$	—		$	—	$	—	$	113
Unproved	1,221			141			—		16		—			—		—		1,378
Exploration	505			93			207		131		103			9		1		1,049
Development	5,078			789			1,122		990		956			6		—		8,941
Costs incurred(1)	$	6,906		$	1,023		$	1,340	$	1,137	$	1,059		$	15	$	1	$	11,481
(1) Includes capitalized interest and asset retirement costs as follows:
Capitalized interest	$	17		$	—		$	9	$	90	$	29		$	3	$	—	$	148
Asset retirement costs	43			175			—		55		34			—		—		307
(2) Includes a noncontrolling interest in Egypt.

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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 relating to the Company’s oil and gas acquisition, exploration, and development activities:

	United States			Canada			Egypt(1)			North Sea			Other International		Total(1)
	(In millions)
2016
Proved properties	$	19,170		$	5,434		$	10,169		$	7,920		$	—	$	42,693
Unproved properties	1,465			109			76			280			39		1,969
	20,635			5,543			10,245			8,200			39		44,662
Accumulated DD&A	(10,034		)	(4,120		)	(7,287		)	(5,531		)	—		(26,972		)
	$	10,601		$	1,423		$	2,958		$	2,669		$	39	$	17,690
2015
Proved properties	$	18,692		$	5,812		$	9,798		$	7,426		$	—	$	41,728
Unproved properties	1,615			172			25			429			36		2,277
	20,307			5,984			9,823			7,855			36		44,005
Accumulated DD&A	(9,027		)	(3,958		)	(6,559		)	(4,913		)	—		(24,457		)
	$	11,280		$	2,026		$	3,264		$	2,942		$	36	$	19,548
(1) Includes a noncontrolling interest in Egypt.

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.

F-54

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

	Crude Oil and Condensate
	(Thousands of barrels)
	United States		Canada		Egypt(1)		Australia		North Sea		Argentina		Total(1)
Proved developed reserves:
December 31, 2013	457,981		80,526		119,242		22,524		100,327		14,195		794,795
December 31, 2014	444,440		75,876		128,712		29,996		105,746		—		784,770
December 31, 2015	348,797		67,847		144,164		—		104,255		—		665,063
December 31, 2016	300,900		51,508		138,771		—		91,138		—		582,317
Proved undeveloped reserves:
December 31, 2013	195,835		56,366		16,302		36,703		29,253		2,231		336,690
December 31, 2014	170,125		59,923		14,617		25,775		19,059		—		289,499
December 31, 2015	60,505		38,326		17,856		—		11,309		—		127,996
December 31, 2016	21,088		7,906		20,187		—		10,784		—		59,965
Total proved reserves:
Balance December 31, 2013	653,816		136,892		135,544		59,227		129,580		16,426		1,131,485
Extensions, discoveries and other additions	57,011		9,657		38,074		4,254		17,386		5		126,387
Purchase of minerals in-place	15,240		—		—		—		—		—		15,240
Revisions of previous estimates	3,083		(812	)	2,645		(216	)	(7	)	—		4,693
Production	(48,789	)	(6,421	)	(32,934	)	(7,494	)	(22,154	)	(620	)	(118,412	)
Sale of properties	(65,796	)	(3,517	)	—		—		—		(15,811	)	(85,124	)
Balance December 31, 2014	614,565		135,799		143,329		55,771		124,805		—		1,074,269
Extensions, discoveries and other additions	13,903		4,550		24,524		—		16,579		—		59,556
Purchase of minerals in-place	—		1,763		—		—		—		—		1,763
Revisions of previous estimates	(173,907	)	(27,966	)	27,330		11,189		(2,255	)	—		(165,609	)
Production	(45,138	)	(5,755	)	(33,163	)	(2,778	)	(21,657	)	—		(108,491	)
Sale of properties	(121	)	(2,218	)	—		(64,182	)	(1,908	)	—		(68,429	)
Balance December 31, 2015	409,302		106,173		162,020		—		115,564		—		793,059
Extensions, discoveries and other additions	9,614		3,372		17,599		—		9,766		—		40,351
Purchase of minerals in-place	21		—		—		—		438		—		459
Revisions of previous estimates	(58,882	)	(43,282	)	17,301		—		(3,851	)	—		(88,714	)
Production	(38,000	)	(4,787	)	(37,962	)	—		(19,995	)	—		(100,744	)
Sale of properties	(67	)	(2,062	)	—		—		—		—		(2,129	)
Balance December 31, 2016	321,988		59,414		158,958		—		101,922		—		642,282

(1)    2016, 2015, 2014, and 2013 includes proved reserves of 53 MMbbls, 54 MMbbls, 48 MMbbls, and 45 MMbbls, respectively, attributable to a noncontrolling interest in Egypt.

F-55

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

	Natural Gas Liquids
	(Thousands of barrels)
	United States		Canada		Egypt(1)		Australia	North Sea		Argentina		Total(1)
Proved developed reserves:
December 31, 2013	184,485		26,099		—		—	2,435		4,110		217,129
December 31, 2014	183,565		17,947		1,346		—	1,770		—		204,628
December 31, 2015	150,265		15,246		1,491		—	1,784		—		168,786
December 31, 2016	155,124		13,866		1,266		—	1,627		—		171,883
Proved undeveloped reserves:
December 31, 2013	63,538		9,970		—		—	215		1,009		74,732
December 31, 2014	69,828		7,168		212		—	371		—		77,579
December 31, 2015	24,939		4,839		78		—	295		—		30,151
December 31, 2016	17,311		2,473		131		—	646		—		20,561
Total proved reserves:
Balance December 31, 2013	248,023		36,069		—		—	2,650		5,119		291,861
Extensions, discoveries and other additions	47,516		1,163		1,820		—	1		—		50,500
Purchase of minerals in-place	2,916		—		—		—	—		—		2,916
Revisions of previous estimates	2,594		116		(11	)	—	(2	)	—		2,697
Production	(21,464	)	(2,256	)	(251	)	—	(508	)	(116	)	(24,595	)
Sale of properties	(26,192	)	(9,977	)	—		—	—		(5,003	)	(41,172	)
Balance December 31, 2014	253,393		25,115		1,558		—	2,141		—		282,207
Extensions, discoveries and other additions	5,768		1,473		144		—	689		—		8,074
Purchase of minerals in-place	—		976		—		—	—		—		976
Revisions of previous estimates	(64,226	)	(4,886	)	255		—	(321	)	—		(69,178	)
Production	(19,684	)	(2,236	)	(388	)	—	(413	)	—		(22,721	)
Sale of properties	(47	)	(357	)	—		—	(17	)	—		(421	)
Balance December 31, 2015	175,204		20,085		1,569		—	2,079		—		198,937
Extensions, discoveries and other additions	10,238		755		208		—	671		—		11,872
Purchase of minerals in-place	2		—		—		—	5		—		7
Revisions of previous estimates	6,824		(1,355	)	17		—	141		—		5,627
Production	(19,824	)	(2,098	)	(397	)	—	(623	)	—		(22,942	)
Sale of properties	(9	)	(1,048	)	—		—	—		—		(1,057	)
Balance December 31, 2016	172,435		16,339		1,397		—	2,273		—		192,444

(1)    2016, 2015, and 2014 includes proved reserves of 466 Mbbls, 523 Mbbls, and 519 Mbbls, respectively, attributable to a noncontrolling interest in Egypt.

F-56

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, 2013	2,005,966		1,294,420		621,825		626,543		88,177		289,133		4,926,064
December 31, 2014	1,616,504		990,145		637,187		640,265		87,259		—		3,971,360
December 31, 2015	1,364,174		759,321		776,263		—		85,532		—		2,985,290
December 31, 2016	1,200,379		553,724		675,559		—		86,948		—		2,516,610
Proved undeveloped reserves:
December 31, 2013	667,160		439,037		190,355		975,224		18,988		121,584		2,412,348
December 31, 2014	580,299		527,623		171,696		964,554		23,228		—		2,267,400
December 31, 2015	208,594		162,809		53,969		—		19,760		—		445,132
December 31, 2016	231,304		45,312		42,109		—		23,813		—		342,538
Total proved reserves:
Balance December 31, 2013	2,673,126		1,733,457		812,180		1,601,767		107,165		410,717		7,338,412
Extensions, discoveries and other additions	203,318		383,077		125,899		81,156		23,803		—		817,253
Purchase of minerals in-place	21,337		—		—		—		—		—		21,337
Revisions of previous estimates	35,910		(12,626	)	17,326		—		(54	)	—		40,556
Production	(215,829	)	(117,816	)	(146,522	)	(78,104	)	(20,427	)	(12,722	)	(591,420	)
Sale of properties	(521,059	)	(468,324	)	—		—		—		(397,995	)	(1,387,378	)
Balance December 31, 2014	2,196,803		1,517,768		808,883		1,604,819		110,487		—		6,238,760
Extensions, discoveries and other additions	40,901		121,216		94,777		—		41,755		—		298,649
Purchase of minerals in-place	—		24,727		—		—		—		—		24,727
Revisions of previous estimates	(503,939	)	(325,375	)	61,442		8,162		(22,373	)	—		(782,083	)
Production	(160,614	)	(100,289	)	(134,870	)	(34,352	)	(23,647	)	—		(453,772	)
Sale of properties	(383	)	(315,917	)	—		(1,578,629	)	(930	)	—		(1,895,859	)
Balance December 31, 2015	1,572,768		922,130		830,232		—		105,292		—		3,430,422
Extensions, discoveries and other additions	219,633		30,234		35,202		—		20,814		—		305,883
Purchase of minerals in-place	7		—		—		—		6,677		—		6,684
Revisions of previous estimates	(215,378	)	(242,080	)	(4,305	)	—		4,239		—		(457,524	)
Production	(145,019	)	(88,792	)	(143,461	)	—		(26,261	)	—		(403,533	)
Sale of properties	(328	)	(22,456	)	—		—		—		—		(22,784	)
Balance December 31, 2016	1,431,683		599,036		717,668		—		110,761		—		2,859,148

(1)    2016, 2015, 2014, and 2013 include proved reserves of 239 Bcf, 277 Bcf, 270 Bcf, and 271 Bcf, respectively, attributable to a noncontrolling interest in Egypt.

F-57

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, 2013	976,795		322,362		222,880		126,948		117,457		66,494		1,832,936
December 31, 2014	897,422		258,848		236,256		136,707		122,058		—		1,651,291
December 31, 2015	726,424		209,647		275,033		—		120,293		—		1,331,397
December 31, 2016	656,087		157,662		252,630		—		107,256		—		1,173,635
Proved undeveloped reserves:
December 31, 2013	370,566		139,509		48,028		199,240		32,633		23,504		813,480
December 31, 2014	336,670		155,028		43,446		186,534		23,301		—		744,979
December 31, 2015	120,210		70,300		26,929		—		14,897		—		232,336
December 31, 2016	76,950		17,931		27,336		—		15,399		—		137,616
Total proved reserves:
Balance December 31, 2013	1,347,361		461,871		270,908		326,188		150,090		89,998		2,646,416
Extensions, discoveries and other additions	138,413		74,666		60,877		17,780		21,354		5		313,095
Purchase of minerals in-place	21,712		—		—		—		—		—		21,712
Revisions of previous estimates	11,662		(2,800	)	5,522		(216	)	(18	)	—		14,150
Production	(106,225	)	(28,313	)	(57,605	)	(20,511	)	(26,067	)	(2,856	)	(241,577	)
Sale of properties	(178,831	)	(91,548	)	—		—		—		(87,147	)	(357,526	)
Balance December 31, 2014	1,234,092		413,876		279,702		323,241		145,359		—		2,396,270
Extensions, discoveries and other additions	26,488		26,226		40,464		—		24,227		—		117,405
Purchase of minerals in-place	—		6,860		—		—		—		—		6,860
Revisions of previous estimates	(322,123	)	(87,081	)	37,825		12,549		(6,305	)	—		(365,135	)
Production	(91,591	)	(24,706	)	(56,029	)	(8,503	)	(26,011	)	—		(206,840	)
Sale of properties	(232	)	(55,228	)	—		(327,287	)	(2,080	)	—		(384,827	)
Balance December 31, 2015	846,634		279,947		301,962		—		135,190		—		1,563,733
Extensions, discoveries and other additions	56,458		9,166		23,674		—		13,906		—		103,204
Purchase of minerals in-place	24		—		—		—		1,556		—		1,580
Revisions of previous estimates	(87,954	)	(84,984	)	16,599		—		(3,002	)	—		(159,341	)
Production	(81,994	)	(21,684	)	(62,269	)	—		(24,995	)	—		(190,942	)
Sale of properties	(131	)	(6,852	)	—		—		—		—		(6,983	)
Balance December 31, 2016	733,037		175,593		279,966		—		122,655		—		1,311,251

(1)    2016, 2015, 2014, and 2013 include total proved reserves of 93 MMboe, 101 MMboe, 93 MMboe, and 90 MMboe, respectively, attributable to a noncontrolling interest in Egypt.

During 2016, Apache sold a combined 7 MMboe primarily through divestiture transactions in Canada. The Company added 2 MMboe of estimated proved reserves through purchases of minerals in-place and 103 MMboe from extensions, discoveries, and other additions. The Company recorded 66 MMboe of exploration and development adds in North America, primarily associated with Woodford, Bone Springs, and Wolfcamp drilling programs in the Permian Basin (49 MMboe), Montney and Glauconite drilling in Canada (9 MMboe), and Woodford drilling activity in the MidContinent region (8 MMboe).

F-58

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The international regions contributed 37 MMboe of exploration and development adds during 2016 with Egypt contributing 23 MMboe from onshore exploration and appraisal activity in the Khalda, Khalda 2, and East Beni Suef concessions. The North Sea offshore region contributed 14 MMboe from drilling success in the Beryl, Forties, and Nevis fields.

During 2016, Apache also had combined downward revisions of previously estimated reserves of 159 MMboe. Changes in product prices accounted for 172 MMboe, lease ownership changes accounted for 6 MMboe, offset by engineering and performance upward revisions totaling 19 MMboe.

Approximately 9 percent of Apache’s year-end 2016 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 16, under “Future Net Cash Flows.”

Future Net Cash Flows

Future cash inflows as of December 31, 2016 and 2015 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)			North Sea			Total(2)
	(In millions)
2016
Cash inflows	$	20,067		$	3,625		$	8,778		$	4,734		$	37,204
Production costs	(8,858		)	(2,582		)	(1,967		)	(2,255		)	(15,662		)
Development costs	(1,653		)	(1,565		)	(1,111		)	(2,410		)	(6,739		)
Income tax expense	(32		)	—			(1,775		)	(8		)	(1,815		)
Net cash flows	9,524			(522		)	3,925			61			12,988
10 percent discount rate	(5,319		)	549			(956		)	798			(4,928		)
Discounted future net cash flows(1)	$	4,205		$	27		$	2,969		$	859		$	8,060
2015
Cash inflows	$	26,610		$	7,345		$	11,124		$	6,994		$	52,073
Production costs	(12,178		)	(3,841		)	(2,185		)	(3,209		)	(21,413		)
Development costs	(2,255		)	(1,939		)	(1,515		)	(2,346		)	(8,055		)
Income tax expense	(63		)	—			(2,326		)	(691		)	(3,080		)
Net cash flows	12,114			1,565			5,098			748			19,525
10 percent discount rate	(6,876		)	(868		)	(1,330		)	143			(8,931		)
Discounted future net cash flows(1)	$	5,238		$	697		$	3,768		$	891		$	10,594

(1) Estimated future net cash flows before income tax expense, discounted at 10 percent per annum, totaled approximately $9.5 billionand$13.1 billion as of December 31, 2016 and 2015, respectively.

(2) Includes discounted future net cash flows of approximately $1.0 billionand$1.3 billion in 2016 and 2015, respectively, attributable to a noncontrolling interest in Egypt.

F-59

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,
	2016			2015			2014
	(In millions)
Sales, net of production costs	$	(3,479	)	$	(4,056	)	$	(10,350	)
Net change in prices and production costs	(3,835		)	(21,710		)	(1,029		)
Discoveries and improved recovery, net of related costs	1,153			1,953			6,297
Change in future development costs	309			705			(1,136		)
Previously estimated development costs incurred during the period	986			1,991			4,462
Revision of quantities	(574		)	(2,292		)	256
Purchases of minerals in-place	8			22			508
Accretion of discount	1,313			3,642			4,442
Change in income taxes	1,070			7,264			836
Sales of properties	(52		)	(5,240		)	(4,780		)
Change in production rates and other	567			(3,343		)	(442		)
	$	(2,534	)	$	(21,064	)	$	(936	)

F-60

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

17.    SUPPLEMENTAL QUARTERLY FINANCIAL DATA (Unaudited)

	First			Second			Third			Fourth			Total
	(In millions, except per share amounts)
2016
Revenues and other	$	1,084		$	1,365		$	1,433		$	1,451		$	5,333
Gain (loss) on divestitures	(1		)	17			5			—			21
Expenses(1)	1,454			1,582			1,964			1,594			6,594
Net loss from continuing operations including noncontrolling interest	(371		)	(200		)	(526		)	(143		)	(1,240		)
Net loss from discontinued operations, net of tax	—			—			(33		)	—			(33		)
Net loss including noncontrolling interest	$	(371	)	$	(200	)	$	(559	)	$	(143	)	$	(1,273	)
Net loss attributable to common stock	$	(372	)	$	(244	)	$	(607	)	$	(182	)	$	(1,405	)
Basic and diluted net loss per common share(2):
Net loss from continuing operations	$	(0.98	)	$	(0.65	)	$	(1.51	)	$	(0.48	)	$	(3.62	)
Net loss from discontinued operations	—			—			(0.09		)	—			(0.09		)
Net loss per share	$	(0.98	)	$	(0.65	)	$	(1.60	)	$	(0.48	)	$	(3.71	)
2015
Revenues and other	$	1,653		$	2,019		$	1,531		$	1,405		$	6,608
Gain (loss) on divestitures	(18		)	227			(5		)	77			281
Expenses(1)	2,703			3,163			5,645			6,537			18,048
Net loss from continuing operations including noncontrolling interest	(1,068		)	(917		)	(4,119		)	(5,055		)	(11,159		)
Net income (loss) from discontinued operations, net of tax	(238		)	120			(17		)	627			492
Net loss including noncontrolling interest	$	(1,306	)	$	(797	)	$	(4,136	)	$	(4,428	)	$	(10,667	)
Net loss attributable to common stock	$	(1,334	)	$	(860	)	$	(4,143	)	$	(4,015	)	$	(10,352	)
Basic and diluted net income (loss) per common share(2):
Net loss from continuing operations	$	(2.91	)	$	(2.60	)	$	(10.91	)	$	(12.28	)	$	(28.70	)
Net income (loss) from discontinued operations	(0.63		)	0.32			(0.04		)	1.66			1.30
Net loss per share	$	(3.54	)	$	(2.28	)	$	(10.95	)	$	(10.62	)	$	(27.40	)

(1) Continuing operating expenses for 2016 include non-cash asset impairments totaling $42 million, $238 million, $951 million, and $144 million in the first, second, third, and fourth quarters of 2016, respectively. Continuing operating expenses for 2015 include non-cash asset impairments totaling $2.1 billion, $660 million, $4.1 billion, and $5.1 billion in the first, second, third, and fourth quarters of 2015, respectively.

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

F-61

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

18.    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 is 100 percent owned by Apache Corporation. As such, these condensed consolidating financial statements should be read in conjunction with Apache’s consolidated financial statements and notes thereto, of which this note is an integral part.

F-62

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)

For the Year Ended December 31, 2016

	Apache Corporation			Apache Finance Canada			All Other Subsidiaries of Apache Corporation			Reclassifications & Eliminations			Consolidated
	(In millions)
REVENUES AND OTHER:
Oil and gas production revenues	$	1,035		$	—		$	4,332		$	—		$	5,367
Equity in net income (loss) of affiliates	(575		)	(173		)	—			748			—
Other	15			(19		)	(29		)	(1		)	(34		)
Gain on divestiture	2			—			19			—			21
	477			(192		)	4,322			747			5,354
OPERATING EXPENSES:
Lease operating expenses	285			—			1,209			—			1,494
Gathering and transportation	33			—			167			—			200
Taxes other than income	76			—			50			—			126
Exploration	258			—			215			—			473
General and administrative	344			—			67			(1		)	410
Depreciation, depletion, and amortization	618			—			2,000			—			2,618
Asset retirement obligation accretion	18			—			138			—			156
Impairments	80			—			1,023			—			1,103
Transaction, reorganization, and separation	39			—			—			—			39
Financing costs, net	256			(27		)	188			—			417
	2,007			(27		)	5,057			(1		)	7,036
NET INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(1,530		)	(165		)	(735		)	748			(1,682		)
Provision (benefit) for income taxes	(158		)	8			(292		)	—			(442		)
NET INCOME (LOSS) FROM CONTINUING OPERATIONS INCLUDING NONCONTROLLING INTEREST	(1,372		)	(173		)	(443		)	748			(1,240		)
Net loss from discontinued operations, net of tax	(33		)	—			—			—			(33		)
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTEREST	(1,405		)	(173		)	(443		)	748			(1,273		)
Net income attributable to noncontrolling interest	—			—			132			—			132
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	(1,405	)	$	(173	)	$	(575	)	$	748		$	(1,405	)
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	(1,398	)	$	(173	)	$	(575	)	$	748		$	(1,398	)

F-63

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)

For the Year Ended December 31, 2015

	Apache Corporation			Apache Finance Canada			All Other Subsidiaries of Apache Corporation			Reclassifications & Eliminations		Consolidated
	(In millions)
REVENUES AND OTHER:
Oil and gas production revenues	$	1,446		$	—		$	5,064		$	—	$	6,510
Equity in net income (loss) of affiliates	(5,254		)	(740		)	57			5,937		—
Other	(71		)	54			96			19		98
Gain on divestiture	36			—			245			—		281
	(3,843		)	(686		)	5,462			5,956		6,889
OPERATING EXPENSES:
Lease operating expenses	399			—			1,455			—		1,854
Gathering and transportation	35			—			176			—		211
Taxes other than income	103			—			179			—		282
Exploration	2,096			—			675			—		2,771
General and administrative	296			—			65			19		380
Depreciation, depletion, and amortization	966			—			2,334			—		3,300
Asset retirement obligation accretion	15			—			130			—		145
Impairments	3,885			—			5,587			—		9,472
Transaction, reorganization, and separation	132			—			—			—		132
Financing costs, net	475			(14		)	50			—		511
	8,402			(14		)	10,651			19		19,058
NET INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(12,245		)	(672		)	(5,189		)	5,937		(12,169		)
Provision (benefit) for income taxes	(2,065		)	11			1,044			—		(1,010		)
NET INCOME (LOSS) FROM CONTINUING OPERATIONS INCLUDING NONCONTROLLING INTEREST	(10,180		)	(683		)	(6,233		)	5,937		(11,159		)
Net income (loss) from discontinued operations, net of tax	(172		)	—			664			—		492
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTEREST	(10,352		)	(683		)	(5,569		)	5,937		(10,667		)
Net loss attributable to noncontrolling interest	—			—			(315		)	—		(315		)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	(10,352	)	$	(683	)	$	(5,254	)	$	5,937	$	(10,352	)
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	(10,355	)	$	(683	)	$	(5,254	)	$	5,937	$	(10,355	)

F-64

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)

For the Year Ended December 31, 2014

	Apache Corporation			Apache Finance Canada			All Other Subsidiaries of Apache Corporation			Reclassifications & Eliminations		Consolidated
	(In millions)
REVENUES AND OTHER:
Oil and gas production revenues	$	3,399		$	—		$	9,396		$	—	$	12,795
Equity in net income (loss) of affiliates	(3,489		)	(1,191		)	73			4,607		—
Other	375			55			(150		)	5		285
Loss on divestiture	(1,031		)	—			(577		)	—		(1,608		)
	(746		)	(1,136		)	8,742			4,612		11,472
OPERATING EXPENSES:
Lease operating expenses	509			—			1,729			—		2,238
Gathering and transportation	58			—			215			—		273
Taxes other than income	206			—			371			—		577
Exploration	1,966			—			533			—		2,499
General and administrative	370			—			78			5		453
Depreciation, depletion, and amortization	1,493			—			3,033			—		4,526
Asset retirement obligation accretion	31			—			123			—		154
Impairments	1,626			—			5,476			—		7,102
Transaction, reorganization, and separation	67			—			—			—		67
Financing costs, net	372			(24		)	65			—		413
	6,698			(24		)	11,623			5		18,302
NET INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(7,444		)	(1,112		)	(2,881		)	4,607		(6,830		)
Provision (benefit) for income taxes	789			6			(1,313		)	—		(518		)
NET INCOME (LOSS) FROM CONTINUING OPERATIONS INCLUDING NONCONTROLLING INTEREST	(8,233		)	(1,118		)	(1,568		)	4,607		(6,312		)
Net loss from discontinued operations, net of tax	(127		)	—			(1,580		)	—		(1,707		)
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTEREST	(8,360		)	(1,118		)	(3,148		)	4,607		(8,019		)
Net income attributable to noncontrolling interest	—			—			341			—		341
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	(8,360	)	$	(1,118	)	$	(3,489	)	$	4,607	$	(8,360	)
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	(8,361	)	$	(1,118	)	$	(3,489	)	$	4,607	$	(8,361	)

F-65

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

For the Year Ended December 31, 2016

	Apache Corporation			Apache Finance Canada			All Other Subsidiaries of Apache Corporation			Reclassifications & Eliminations			Consolidated
							(In millions)
CASH PROVIDED BY CONTINUING OPERATING ACTIVITIES	$	625		$	51		$	1,777		$	—		$	2,453
CASH USED IN DISCONTINUED OPERATIONS	—			—			(23		)	—			(23		)
CASH PROVIDED BY OPERATING ACTIVITIES	$	625		$	51		$	1,754		$	—		$	2,430
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property	(813		)	—			(797		)	—			(1,610		)
Additions to gas gathering, transmission, and processing facilities	(111		)	—			(47		)	—			(158		)
Leasehold and property acquisitions	(108		)	—			(73		)	—			(181		)
Proceeds from sale of oil and gas properties, other	88			—			46			—			134
Investment in subsidiaries, net	914			—			—			(914		)	—
Other	(77		)	—			232			—			155
NET CASH USED IN INVESTING ACTIVITIES	(107		)	—			(639		)	(914		)	(1,660		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Intercompany borrowings	—			(23		)	(891		)	914			—
Payments on fixed rate debt	(181		)	—			—			—			(181		)
Dividends paid	(379		)	—			—			—			(379		)
Common stock activity, net	—			(28		)	28			—			—
Distributions to noncontrolling interest	—			—			(293		)	—			(293		)
Other	8			—			(15		)	—			(7		)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES	(552		)	(51		)	(1,171		)	914			(860		)
NET DECREASE IN CASH AND CASH  EQUIVALENTS	(34		)	—			(56		)	—			(90		)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	378			—			1,089			—			1,467
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	344		$	—		$	1,033		$	—		$	1,377

F-66

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

For the Year Ended December 31, 2015

	Apache Corporation			Apache Finance Canada			All Other Subsidiaries of Apache Corporation			Reclassifications & Eliminations			Consolidated
							(In millions)
CASH PROVIDED BY CONTINUING OPERATING ACTIVITIES	$	98		$	18		$	2,438		$	—		$	2,554
CASH PROVIDED BY DISCONTINUED OPERATIONS	—			—			113			—			113
CASH PROVIDED BY OPERATING ACTIVITIES	98			18			2,551			—			2,667
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property	(1,500		)	—			(2,708		)	—			(4,208		)
Additions to gas gathering, transmission, and processing facilities	(156		)	—			(77		)	—			(233		)
Proceeds from sale of Kitimat LNG	—			—			854			—			854
Proceeds from sale of Yara Pilbara	—			—			391			—			391
Leasehold and property acquisitions	(313		)	—			(54		)	—			(367		)
Proceeds from sale of oil and gas properties	163			—			105			—			268
Investment in subsidiaries, net	6,363			—			—			(6,363		)	—
Other	(34		)	—			40			—			6
NET CASH PROVIDED BY (USED IN) CONTINUING INVESTING ACTIVITIES	4,523			—			(1,449		)	(6,363		)	(3,289		)
NET CASH PROVIDED BY DISCONTINUED OPERATIONS	—			—			4,372			—			4,372
NET CASH USED IN INVESTING ACTIVITIES	4,523			—			2,923			(6,363		)	1,083
CASH FLOWS FROM FINANCING ACTIVITIES:
Commercial paper, credit facility, and bank notes, net	(1,570		)	—			—			—			(1,570		)
Intercompany borrowings	(1,621		)	(18		)	(4,724		)	6,363			—
Payments on fixed rate debt	(939		)	—			—			—			(939		)
Dividends paid	(377		)	—			—			—			(377		)
Distributions to noncontrolling interest	—			—			(129		)	—			(129		)
Other	(3		)	—			56			—			53
NET CASH USED IN CONTINUING FINANCING ACTIVITIES	(4,510		)	(18		)	(4,797		)	6,363			(2,962		)
NET CASH USED IN FINANCING ACTIVITIES	(4,510		)	(18		)	(4,797		)	6,363			(2,962		)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	111			—			677			—			788
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	267			—			412			—			679
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	378		$	—		$	1,089		$	—		$	1,467

F-67

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

For the Year Ended December 31, 2014

	Apache Corporation			Apache Finance Canada			All Other Subsidiaries of Apache Corporation			Reclassifications & Eliminations			Consolidated
							(In millions)
CASH PROVIDED BY CONTINUING OPERATING ACTIVITIES	$	3,104		$	17		$	3,892		$	—		$	7,013
CASH PROVIDED BY DISCONTINUED OPERATIONS	—			—			944			—			944
CASH PROVIDED BY OPERATING ACTIVITIES	3,104			17			4,836			—			7,957
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property	(4,364		)	—			(4,244		)	—			(8,608		)
Additions to gas gathering, transmission, and processing facilities	(9		)	—			(872		)	—			(881		)
Proceeds from sale of Deepwater Gulf of Mexico assets	1,360			—			—			—			1,360
Proceeds from sale of Anadarko basin and southern Louisiana assets	1,262			—			—			—			1,262
Leasehold and property acquisitions	(1,475		)	—			—			—			(1,475		)
Proceeds from sale of oil and gas properties	15			—			455			—			470
Investment in subsidiaries, net	1,132			—			—			(1,132		)	—
Other	(186		)	—			(113		)	—			(299		)
NET CASH USED IN CONTINUING INVESTING ACTIVITIES	(2,265		)	—			(4,774		)	(1,132		)	(8,171		)
NET CASH USED IN DISCONTINUED OPERATIONS	—			—			(219		)	—			(219		)
NET CASH USED IN INVESTING ACTIVITIES	(2,265		)	—			(4,993		)	(1,132		)	(8,390		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Commercial paper, credit facility, and bank notes, net	1,570			—			(2		)	—			1,568
Intercompany borrowings	—			8			(1,152		)	1,144			—
Dividends paid	(365		)	—			—			—			(365		)
Distributions to noncontrolling interest	—			—			(140		)	—			(140		)
Shares repurchased	(1,864		)	—			—			—			(1,864		)
Other	(68		)	(28		)	157			(12		)	49
NET CASH USED IN CONTINUING FINANCING ACTIVITIES	(727		)	(20		)	(1,137		)	1,132			(752		)
NET CASH USED IN DISCONTINUED OPERATIONS	—			—			(42		)	—			(42		)
NET CASH USED IN FINANCING ACTIVITIES	(727		)	(20		)	(1,179		)	1,132			(794		)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	112			(3		)	(1,336		)	—			(1,227		)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	155			3			1,748			—			1,906
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	267		$	—		$	412		$	—		$	679

F-68

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

CONDENSED CONSOLIDATING BALANCE SHEET

December 31, 2016

	Apache Corporation			Apache Finance Canada			All Other Subsidiaries of Apache Corporation		Reclassifications & Eliminations			Consolidated
							(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	344		$	—		$	1,033	$	—		$	1,377
Receivables, net of allowance	358			—			770		—			1,128
Inventories	29			—			447		—			476
Drilling advances	4			—			77		—			81
Prepaid assets and other	134			—			45		—			179
Intercompany receivable	5,038			—			—		(5,038		)	—
	5,907			—			2,372		(5,038		)	3,241
PROPERTY AND EQUIPMENT, NET	7,014			—			11,853		—			18,867
OTHER ASSETS:
Intercompany receivable	—			—			12,152		(12,152		)	—
Equity in affiliates	15,517			(1,240		)	706		(14,983		)	—
Deferred charges and other	97			1,000			314		(1,000		)	411
	$	28,535		$	(240	)	$	27,397	$	(33,173	)	$	22,519
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable	$	371		$	(12	)	$	226	$	—		$	585
Other current liabilities	653			3			602		—			1,258
Intercompany payable	—			—			5,038		(5,038		)	—
	1,024			(9		)	5,866		(5,038		)	1,843
LONG-TERM DEBT	8,247			297			—		—			8,544
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Intercompany payable	12,152			—			—		(12,152		)	—
Income taxes	(271		)	5			1,976		—			1,710
Asset retirement obligation	257			—			2,175		—			2,432
Other	888			1			422		(1,000		)	311
	13,026			6			4,573		(13,152		)	4,453
COMMITMENTS AND CONTINGENCIES APACHE SHAREHOLDERS’ EQUITY	6,238			(534		)	15,517		(14,983		)	6,238
Noncontrolling interest	—			—			1,441		—			1,441
TOTAL EQUITY	6,238			(534		)	16,958		(14,983		)	7,679
	$	28,535		$	(240	)	$	27,397	$	(33,173	)	$	22,519

F-69

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

CONDENSED CONSOLIDATING BALANCE SHEET

December 31, 2015

	Apache Corporation			Apache Finance Canada			All Other Subsidiaries of Apache Corporation		Reclassifications & Eliminations			Consolidated
							(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	378		$	—		$	1,089	$	—		$	1,467
Receivables, net of allowance	314			—			939		—			1,253
Inventories	34			—			536		—			570
Drilling advances	16			—			156		—			172
Prepaid assets and other	102			—			188		—			290
Intercompany receivable	5,212			—			—		(5,212		)	—
	6,056			—			2,908		(5,212		)	3,752
PROPERTY AND EQUIPMENT, NET	6,546			—			14,292		—			20,838
OTHER ASSETS:
Intercompany receivable	—			—			10,744		(10,744		)	—
Equity in affiliates	16,092			(807		)	446		(15,731		)	—
Deferred charges and other	96			1,001			813		(1,000		)	910
	$	28,790		$	194		$	29,203	$	(32,687	)	$	25,500
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable	$	409		$	—		$	209	$	—		$	618
Other current liabilities	539			3			681		—			1,223
Intercompany payable	—			—			5,212		(5,212		)	—
	948			3			6,102		(5,212		)	1,841
LONG-TERM DEBT	8,418			298			—		—			8,716
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Intercompany payable	10,744			—			—		(10,744		)	—
Income taxes	(412		)	4			2,937		—			2,529
Asset retirement obligation	271			—			2,291		—			2,562
Other	933			250			179		(1,000		)	362
	11,536			254			5,407		(11,744		)	5,453
COMMITMENTS AND CONTINGENCIES APACHE SHAREHOLDERS’ EQUITY	7,888			(361		)	16,092		(15,731		)	7,888
Noncontrolling interest	—			—			1,602		—			1,602
TOTAL EQUITY	7,888			(361		)	17,694		(15,731		)	9,490
	$	28,790		$	194		$	29,203	$	(32,687	)	$	25,500

F-70

INDEX TO EXHIBITS

EXHIBIT NO.		DESCRIPTION
3.1	–	Restated Certificate of Incorporation of Registrant, dated September 19, 2013, as filed with the Secretary of State of Delaware on September 19, 2013 (incorporated by reference to Exhibit 3.2 to Registrant’s Current Report on Form 8-K filed September 20, 2013, SEC File No. 001-4300).
3.2	–	Certificate of Amendment of Restated Certificate of Incorporation of Registrant, dated May 14, 2015, as filed with the Secretary of State of Delaware on May 14, 2015 (incorporated by reference to Exhibit 3.2 to Registrant’s Current Report on Form 8-K filed May 20, 2015, SEC File No. 001-04300).
3.3	–	Bylaws of Registrant, as amended February 3, 2016, (incorporated by reference to Exhibit 3.1 to Registrant’s Current Report on Form 8-K filed February 9, 2016, SEC File No. 001-4300).
4.1	–	Form of Certificate for Registrant’s Common Stock (incorporated by reference to Exhibit 4.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014, SEC File No. 001-4300).
4.2	–	Form of 3.625% Notes due 2021 (incorporated by reference to Exhibit 4.1 to Registrant’s Current Report on Form 8-K, dated November 30, 2010, filed on December 3, 2010, SEC File No. 001-4300).
4.3	–	Form of 5.250% Notes due 2042 (incorporated by reference to Exhibit 4.2 to Registrant’s Current Report on Form 8-K, dated November 30, 2010, filed on December 3, 2010, SEC File No. 001-4300).
4.4	–	Form of 5.100% Notes due 2040 (incorporated by reference to Exhibit 4.1 to Registrant’s Current Report on Form 8-K, dated August 17, 2010, filed on August 20, 2010, SEC File No. 001-4300).
4.5	–	Form of 1.75% Notes due 2017 (incorporated by reference to Exhibit 4.1 to Registrant’s Current Report on Form 8-K, dated April 3, 2012, filed on April 9, 2012, SEC File No. 001-4300).
4.6	–	Form of 3.25% Note due 2022 (incorporated by reference to Exhibit 4.2 to Registrant’s Current Report on Form 8-K, dated April 3, 2012, filed on April 9, 2012, SEC File No. 001-4300).
4.7	–	Form of 4.75% Notes due 2043 (incorporated by reference to Exhibit 4.3 to Registrant’s Current Report on Form 8-K, dated April 3, 2012, filed on April 9, 2012, SEC File No. 001-4300).
4.8	–	Form of 2.625% Notes due 2023 (incorporated by reference to Exhibit 4.1 to Registrant’s Current Report on Form 8-K, dated November 28, 2012, filed on December 4, 2012, SEC File No. 001-4300).
4.9	–	Form of 4.250% Notes due 2044 (incorporated by reference to Exhibit 4.2 to Registrant’s Current Report on Form 8-K, dated November 28, 2012, filed on December 4, 2012, SEC File No. 001-4300).
4.10	–	Rights Agreement, dated January 31, 1996, between Registrant and Wells Fargo Bank, N.A. (as successor-in-interest to Norwest Bank Minnesota, N.A.), rights agent, relating to the declaration of a rights dividend to Registrant's common shareholders of record on January 31, 1996 (incorporated by reference to Exhibit (a) to Registrant's Registration Statement on Form 8-A, dated January 24, 1996, SEC File No. 001-4300).
4.11	–	Amendment No. 1, dated as of January 31, 2006, to the Rights Agreement dated as of January 31, 1996 between Registrant and Wells Fargo Bank, N.A. (as successor-in-interest to Norwest Bank Minnesota, N.A.) (incorporated by reference to Exhibit 4.4 to Registrant's Amendment No. 1 to Registration Statement on Form 8-A, dated January 31, 2006, SEC File No. 001-4300).
4.12	–	Amendment No. 2, dated March 10, 2014, to the Rights Agreement by and between Registrant and Wells Fargo Bank, N.A. (incorporated by reference to Exhibit 4.3 to Amendment No. 2 to Registrant’s Registration Statement on Form 8-A, filed March 10, 2014, SEC File No. 001-4300).
4.13	–	Senior Indenture, dated February 15, 1996, between Registrant and The Bank of New York Mellon Trust Company, N.A. (formerly known as the Bank of New York Trust Company, N.A., as successor-in-interest to JPMorgan Chase Bank), formerly known as The Chase Manhattan Bank, as trustee, governing the senior debt securities and guarantees (incorporated by reference to Exhibit 4.6 to Registrant’s Registration Statement on Form S-3, dated May 23, 2003, Reg. No. 333-105536).
4.14	–	First Supplemental Indenture to the Senior Indenture, dated as of November 5, 1996, between Registrant and The Bank of New York Mellon Trust Company, N.A. (formerly known as the Bank of New York Trust Company, N.A., as successor-in-interest to JPMorgan Chase Bank, formerly known as The Chase Manhattan Bank), as trustee, governing the senior debt securities and guarantees (incorporated by reference to Exhibit 4.7 to Registrant’s Registration Statement on Form S-3, dated May 23, 2003, Reg. No. 333-105536).
4.15	–	Form of Indenture among Apache Finance Pty Ltd, Registrant and The Bank of New York Mellon Trust Company, N.A. (formerly known as the Bank of New York Trust Company, N.A., as successor-in-interest to The Chase Manhattan Bank), as trustee, governing the debt securities and guarantees (incorporated by reference to Exhibit 4.1 to Registrant’s Registration Statement on Form S-3, dated November 12, 1997, Reg. No. 333-339973).
4.16	–	Form of Indenture among Registrant, Apache Finance Canada Corporation and The Bank of New York Mellon Trust Company, N.A. (formerly known as the Bank of New York Trust Company, N.A., as successor-in-interest to The Chase Manhattan Bank), as trustee, governing the debt securities and guarantees (incorporated by reference to Exhibit 4.1 to Amendment No. 1 to Registrant’s Registration Statement on Form S-3, dated November 12, 1999, Reg. No. 333-90147).

INDEX TO EXHIBITS

EXHIBIT NO.		DESCRIPTION
4.17	–	Senior Indenture, dated May 19, 2011, between Registrant and Wells Fargo Bank, National Association, as trustee, governing the senior debt securities of Apache Corporation (incorporated by reference to Exhibit 4.14 to Registrant’s Registration Statement on Form S-3, dated May 23, 2011, Reg. No. 333-174429).
4.18	–	Senior Indenture, dated May 19, 2011, among Apache Finance Pty Ltd, Apache Corporation, as guarantor, and Wells Fargo Bank, National Association, as trustee, governing the senior debt securities of Apache Finance Pty Ltd and the related guarantees (incorporated by reference to Exhibit 4.16 to Registrant’s Registration Statement on Form S-3, dated May 23, 2011, Reg. No. 333-174429).
4.19	–	Senior Indenture, dated May 19, 2011, among Apache Finance Canada Corporation, Apache Corporation, as guarantor, and Wells Fargo Bank, National Association, as trustee, governing the senior debt securities of Apache Finance Corporation and the related guarantees (incorporated by reference to Exhibit 4.20 to Registrant’s Registration Statement on Form S-3, dated May 23, 2011, Reg. No. 333-174429).
†4.20	–	Form of Apache Corporation November 10, 2010 First Non-Qualified Stock Option Agreement for Certain Employees of Apache Corporation (incorporated by reference to Exhibit 4.6 to Registrant’s Registration Statement on Form S-8 filed on November 10, 2010, Reg. No. 333-170533).
†4.21	–	Form of Apache Corporation November 10, 2010 Second Non-Qualified Stock Option Agreement for Certain Employees of Apache Corporation (incorporated by reference to Exhibit 4.7 to Registrant’s Registration Statement on Form S-8 filed on November 10, 2010, Reg. No. 333-170533).
†4.22	–	Form of Apache Corporation November 10, 2010 Non-Statutory Stock Option Agreement for Certain Employees of Apache Corporation (incorporated by reference to Exhibit 4.8 to Registrant’s Registration Statement on Form S-8 filed on November 10, 2010, Reg. No. 333-170533).
10.1	–	Credit Agreement, dated August 12, 2011, among Registrant, the lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, and Citibank, N.A., Bank of America, N.A., and Wells Fargo Bank, National Association, as Syndication Agents (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed August 18, 2011, SEC File No. 001-4300).
10.2	–	First Amendment to Credit Agreement, dated as of July 17, 2013, among Apache Corporation, the lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, and the other agents party thereto, amending Credit Agreement, dated as of August 12, 2011, among the same parties (incorporated by reference to Exhibit 10.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2013, SEC File No. 001-4300).
10.3	–	Credit Agreement, dated as of June 4, 2012, among Apache Corporation, the lenders party thereto, JPMorgan Chase Bank, N.A., as Global Administrative Agent, Bank of America, N.A. and Citibank, N.A., as Global Syndication Agents, and The Royal Bank of Scotland plc and Royal Bank of Canada, as Global Documentation Agents (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed June 7, 2012, SEC File No. 001-04300).
10.4	–	Credit Agreement, dated as of June 4, 2012, among Apache Canada Ltd., the lenders party thereto, JPMorgan Chase Bank, N.A., as Global Administrative Agent, Royal Bank of Canada, as Canadian Administrative Agent, Bank of America, N.A. and Citibank, N.A., as Global Syndication Agents, and The Royal Bank of Scotland plc and Royal Bank of Canada, as Global Documentation Agents (incorporated by reference to Exhibit 10.2 to Registrant’s Current Report on Form 8-K filed June 7, 2012, SEC File No. 001-04300).
10.5	–	Syndicated Facility Agreement, dated as of June 4, 2012, among Apache Energy Limited (ACN 009 301 964), the lenders party thereto, JPMorgan Chase Bank, N.A., as Global Administrative Agent, Citisecurities Limited (ABN 51 008 489 610), as Australian Administrative Agent, Bank of America, N.A. and Citibank, N.A., as Global Syndication Agents, and The Royal Bank of Scotland plc and Royal Bank of Canada, as Global Documentation Agents (incorporated by reference to Exhibit 10.3 to Registrant’s Current Report on Form 8-K filed June 7, 2012, SEC File No. 001-04300).
10.6	–	Credit Agreement, dated December 11, 2014, among Apache Corporation, the lenders party thereto, Citibank, N.A., as Administrative Agent, Bank of America, N.A. and JPMorgan Chase Bank, N.A., as Co-Syndication Agents, and The Royal Bank of Scotland plc and Wells Fargo Bank, National Association, as Co-Documentation Agents (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed December 15, 2014, SEC File No. 001-4300).
10.7	–	Credit Agreement, dated as of June 4, 2015, among Apache Corporation, the lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A. and Citibank, N.A., as Co-Syndication Agents, and Royal Bank of Canada, HSBC Bank USA, National Association, The Bank of Tokyo-Mitsubishi UFJ, Ltd., Wells Fargo Bank, National Association, and Mizuho Bank, Ltd., as Co-Documentation Agents (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed June 9, 2015, SEC File No. 001-04300).

INDEX TO EXHIBITS

EXHIBIT NO.		DESCRIPTION
10.8	–	First Amendment to Credit Agreement, dated as of September 9, 2015, among Apache Corporation, the lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, and the other agents party thereto, amending Credit Agreement, dated as of June 4, 2015 among Apache Corporation, the lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A. and Citibank, N.A., as Co-Syndication Agents, and Royal Bank of Canada, HSBC Bank USA, National Association, The Bank of Tokyo-Mitsubishi UFJ, Ltd., Wells Fargo Bank, National Association, and Mizuho Bank, Ltd., as Co-Documentation Agents (incorporated by reference to Exhibit 10.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2015, SEC File No. 001-04300).
10.9	–	Second Amendment to Credit Agreement, dated as of February 22, 2016, among Apache Corporation, the lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, and the other agents party thereto, amending Credit Agreement, dated as of June 4, 2015, among Apache Corporation, the lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A. and Citibank, N.A., as Co-Syndication Agents, and Royal Bank of Canada, HSBC Bank USA, National Association, The Bank of Tokyo-Mitsubishi UFJ, Ltd., Wells Fargo Bank, National Association, and Mizuho Bank, Ltd., as Co-Documentation Agents (incorporated by reference to Exhibit 10.9 to Registrant’s Annual Report on Form 10-K for the year ended December 31, 2015, SEC File No. 001-4300).
10.10	–	Credit Agreement, dated as of February 22, 2016, among Apache Corporation, the lenders party thereto, the issuing banks party thereto, J.P. Morgan Europe Limited, as Administrative Agent, HSBC Bank USA, National Association, Royal Bank of Canada, The Bank of Nova Scotia, The Toronto-Dominion Bank, New York Branch, and Bank of Montreal, as Co-Syndication Agents, and Deutsche Bank AG New York Branch and Société Générale, as Co-Documentation Agents (incorporated by reference to Exhibit 10.10 to Registrant's Annual Report on Form 10-K for year ended December 31, 2015, SEC File No. 001-4300).
†10.11	–	Apache Corporation Corporate Incentive Compensation Plan A (Senior Officers' Plan), dated July 16, 1998 (incorporated by reference to Exhibit 10.13 to Registrant's Annual Report on Form 10-K for year ended December 31, 1998, SEC File No. 001-4300).
†10.12	–	First Amendment to Apache Corporation Corporate Incentive Compensation Plan A, dated November 20, 2008, effective as of January 1, 2005 (incorporated by reference to Exhibit 10.17 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2008, SEC File No. 001-4300).
†10.13	–	Apache Corporation Corporate Incentive Compensation Plan B (Strategic Objectives Format), dated July 16, 1998 (incorporated by reference to Exhibit 10.14 to Registrant's Annual Report on Form 10-K for year ended December 31, 1998, SEC File No. 001-4300).
†10.14	–	First Amendment to Apache Corporation Corporate Incentive Compensation Plan B, dated November 20, 2008, effective as of January 1, 2005 (incorporated by reference to Exhibit 10.19 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2008, SEC File No. 001-4300).
†10.15	–	Apache Corporation 401(k) Savings Plan, as amended and restated, dated March 17, 2015, effective January 31, 2014 (incorporated by reference to Exhibit 10.15 to Registrant's Annual Report on Form 10-K for year ended December 31, 2015, SEC File No. 001-4300).
†10.16	–	Amendment to Apache Corporation 401(k) Savings Plan, dated April 17, 2014 (incorporated by reference to Exhibit 10.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014, SEC File No. 001-4300.)
†10.17	–	Amendment to Apache Corporation 401(k) Savings Plan, dated May 16, 2014 (incorporated by reference to Exhibit 10.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2014, SEC File No. 001-4300).
†10.18	–	Amendment to Apache Corporation 401(k) Savings Plan, effective February 3, 2016 (incorporated by reference to Exhibit 10.18 to Registrant's Annual Report on Form 10-K for year ended December 31, 2015, SEC File No. 001-4300).
†10.19	–	Non-Qualified Retirement/Savings Plan of Apache Corporation, as amended and restated, dated July 16, 2014, effective January 1, 2015 (incorporated by reference to Exhibit 10.2 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2014, SEC File No. 001-4300).
†10.20	–	Non-Qualified Restorative Retirement Savings Plan of Apache Corporation, as amended and restated, dated July 16, 2014, effective January 1, 2015 (incorporated by reference to Exhibit 10.3 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2014, SEC File No. 001-4300).
†10.21	–	Apache Corporation 2016 Omnibus Compensation Plan, dated February 3, 2016, effective May 12, 2016 (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed May 16, 2016, SEC File No. 001-4300).
†10.22	–	Apache Corporation 2011 Omnibus Equity Compensation Plan, as amended and restated May 12, 2016 (incorporated by reference to Exhibit 10.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2016, SEC File No. 001-4300).

INDEX TO EXHIBITS

EXHIBIT NO.		DESCRIPTION
†10.23	–	Apache Corporation 2007 Omnibus Equity Compensation Plan, as amended and restated May 4, 2011 (incorporated by reference to Exhibit 10.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2011, SEC File No. 001-4300).
†10.24	–	Apache Corporation 2005 Stock Option Plan, as amended and restated September 16, 2013 (incorporated by reference to Exhibit 10.3 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2013, File No. 001-4300).
†10.25	–	Apache Corporation Income Continuance Plan, as amended and restated July 14, 2010, effective January 1, 2009 (incorporated by reference to Exhibit 10.5 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, SEC File No. 001-4300).
†10.26	–	Apache Corporation Deferred Delivery Plan, as amended and restated May 12, 2016 (incorporated by reference to Exhibit 10.3 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2016, SEC File No. 001-4300).
†10.27	–	Apache Corporation Non-Employee Directors’ Compensation Plan, as amended and restated May 14, 2015 (incorporated by reference to Exhibit 10.5 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2015, SEC File No. 001-4300).
†10.28	–	Apache Corporation Outside Directors’ Retirement Plan, as amended and restated July 16, 2014, effective June 30, 2014 (incorporated by reference to Exhibit 10.5 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2014, SEC File No. 001-4300).
†10.29	–	Apache Corporation Equity Compensation Plan for Non-Employee Directors, as amended and restated February 8, 2007 (incorporated by reference to Exhibit 10.2 to Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, 2007, SEC File No. 001-4300).
†10.30	–	Apache Corporation Non-Employee Directors’ Restricted Stock Units Program, as amended and restated May 14, 2015 (incorporated by reference to Exhibit 10.6 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2015, SEC File No. 001-4300).
†10.31	–	Apache Corporation Non-Employee Directors’ Restricted Stock Units Program, effective May 12, 2016, pursuant to Apache Corporation 2016 Omnibus Compensation Plan (incorporated by reference to Exhibit 10.4 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2016, SEC File No. 001-4300).
†10.32	–	Apache Corporation Outside Directors’ Deferral Program, effective May 12, 2016, pursuant to Apache Corporation 2016 Omnibus Compensation Plan (incorporated by reference to Exhibit 10.5 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2016, SEC File No. 001-4300).
†10.33	–	Apache Corporation Outside Directors’ Deferral Program, effective July 16, 2014, pursuant to Apache Corporation 2011 Omnibus Equity Compensation Plan (incorporated by reference to Exhibit 10.7 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2014, SEC File No. 001-4300).
†10.34	–	Employment Agreement between Registrant and G. Steven Farris, dated June 6, 1988, and First Amendment, dated November 20, 2008, effective as of January 1, 2005 (incorporated by reference to Exhibit 10.44 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2008, SEC File No. 001-4300).
†10.35	–	Retirement Agreement, dated January 19, 2015, between Registrant and G. Steven Farris (incorporated by reference to Exhibit 10.39 to Registrant’s Annual Report on Form 10-K for the year ended December 31, 2014, SEC File No. 001-4300).
†10.36	–	Apache Corporation Executive Termination Policy (incorporated by reference to Exhibit 10.2 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2015, SEC File No. 001-4300).
†10.37	–	2016 Employee Release and Settlement Agreement between Registrant and Thomas E. Voytovich, effective November 30, 2015 (incorporated by reference to Exhibit 10.41 to Registrant's Annual Report on Form 10-K for year ended December 31, 2015, SEC File No. 001-4300).
†10.38	–	Form of Stock Option Award Agreement, dated May 6, 2009 (incorporated by reference to Exhibit 10.39 to Registrant's Annual Report on Form 10-K for year ended December 31, 2009, SEC File No. 001-4300).
†10.39	–	Form of 2014 Performance Agreement (Total Shareholder Return), dated January 9, 2014 (incorporated by reference to Exhibit 10.46 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2013, SEC File No. 001-4300).
†10.40	–	Form of 2014 Performance Agreement (Business Performance), dated February 3, 2014 (incorporated by reference to Exhibit 10.47 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2013, SEC File No. 001-4300).
†10.41	–	Form of 2015 Performance Share Program Award Notice and Agreement, dated February 19, 2015 (incorporated by reference to Exhibit 10.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2015, SEC File No. 001-4300).

INDEX TO EXHIBITS

EXHIBIT NO.		DESCRIPTION
†10.42	–	Restricted Stock Unit Award Agreement between Registrant and John J. Christmann, dated February 18, 2015 (incorporated by reference to Exhibit 10.7 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2015, SEC File No. 001-4300).
†10.43	–	2015 Long Term Cash Performance Program Award Notice and Agreement between Registrant and Stephen J. Riney, dated April 8, 2015 (incorporated by reference to Exhibit 10.2 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2015, SEC File No. 001-4300).
†10.44	–	Form of 2016 Performance Share Program Award Notice and Agreement, dated January 7, 2016 (incorporated by reference to Exhibit 10.59 to Registrant's Annual Report on Form 10-K for year ended December 31, 2015, SEC File No. 001-4300).
*†10.45	–	Form of 2017 Performance Share Program Award Notice and Agreement, dated December 13, 2016.
†10.46	–	Form of Restricted Stock Unit Award Agreement, dated February 3, 2016 (incorporated by reference to Exhibit 10.60 to Registrant's Annual Report on Form 10-K for year ended December 31, 2015, SEC File No. 001-4300).
†10.47	–	Form of Restricted Stock Unit Award Agreement dated September 14, 2016 (2016 Omnibus Compensation Plan) (incorporated by reference to Exhibit 10.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2016, SEC File No. 001-4300).
*†10.48	–	Form of Stock Option Grant Agreement, dated December 13, 2016 (2016 Omnibus Compensation Plan).
†10.49	–	Form of Stock Option Award Agreement, dated February 3, 2016 (incorporated by reference to Exhibit 10.61 to Registrant's Annual Report on Form 10-K for year ended December 31, 2015, SEC File No. 001-4300).
†10.50	–	Amendment of Stock Option Grants (2011 Omnibus Equity Compensation Plan), dated January 20, 2015, between Registrant and G. Steven Farris (incorporated by reference to Exhibit 10.63 to Registrant's Annual Report on Form 10-K for the year ended December 31, 2014, SEC File No. 001-4300).
†10.51	–	Amendment of Restricted Stock Unit Awards (2007 and 2011 Omnibus Equity Compensation Plans), dated January 20, 2015, between Registrant and G. Steven Farris (incorporated by reference to Exhibit 10.64 to Registrant's Annual Report on Form 10-K for the year ended December 31, 2014, SEC File No. 001-4300).
†10.52	–	Amendment of 2014 Performance Program (Business Performance) Award (2011 Omnibus Compensation Plan), dated January 20, 2015, between Registrant and G. Steven Farris (incorporated by reference to Exhibit 10.65 to Registrant's Annual Report on Form 10-K for the year ended December 31, 2014, SEC File No. 001-4300).
†10.53	–	Amendment of 2014 Performance Program (Business Performance) Award (2011 Omnibus Equity Compensation Plan), effective November 30, 2015, between Registrant and Thomas E. Voytovich (incorporated by reference to Exhibit 10.74 to Registrant's Annual Report on Form 10-K for year ended December 31, 2015, SEC File No. 001-4300).
†10.54	–	Amendment of Restricted Stock Unit Awards (2011 Omnibus Equity Compensation Plan), effective November 30, 2015, between Registrant and Thomas E. Voytovich (incorporated by reference to Exhibit 10.75 to Registrant's Annual Report on Form 10-K for year ended December 31, 2015, SEC File No. 001-4300).
†10.55	–	Amendment of Stock Option Grants (2007 and 2011 Omnibus Equity Compensation Plans), effective November 30, 2015, between Registrant and Thomas E. Voytovich (incorporated by reference to Exhibit 10.76 to Registrant's Annual Report on Form 10-K for year ended December 31, 2015, SEC File No. 001-4300).
†10.56	–	Amendment of Stock Option Grants (2005 Stock Option Plan), effective November 30, 2015, between Registrant and Thomas E. Voytovich (incorporated by reference to Exhibit 10.77 to Registrant's Annual Report on Form 10-K for year ended December 31, 2015, SEC File No. 001-4300).
*12.1	–	Statement of Computation of Ratios of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividends.
*21.1	–	Subsidiaries of Registrant.
*23.1	–	Consent of Ernst & Young LLP.
*23.2	–	Consent of Ryder Scott Company, L.P., Petroleum Consultants.
*24.1	–	Power of Attorney (included as a part of the signature pages to this report).
*31.1	–	Certification (pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Exchange Act) by Principal Executive Officer.
*31.2	–	Certification (pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Exchange Act) by Principal Financial Officer.
*32.1	–	Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by Principal Executive Officer and Principal Financial Officer.
*99.1	–	Report of Ryder Scott Company, L.P., Petroleum Consultants.
*101.INS	–	XBRL Instance Document.
*101.SCH	–	XBRL Taxonomy Schema Document.
*101.CAL	–	XBRL Calculation Linkbase Document.

INDEX TO EXHIBITS

EXHIBIT NO.		DESCRIPTION
*101.DEF	–	XBRL Definition Linkbase Document.
*101.LAB	–	XBRL Label Linkbase Document.
*101.PRE	–	XBRL Presentation Linkbase Document.

* Filed herewith.

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

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

EX-10.45

SCHEDULE A

Apache Corporation

2017 Performance Share Program

AWARD NOTICE

Recipient Name:[Name]

Company:Apache Corporation

Notice: A summary of the terms of Conditional Grants of Restricted Stock Units (“RSUs”) under the 2017 Performance Share Program is set out in this notice (the “Award Notice”) but subject always to the terms of the Apache Corporation 2016 Omnibus Compensation Plan (the “Plan”) and the 2017 Performance Share Program Agreement (the “Agreement”). In the event of any inconsistency between the terms of this Award Notice, the terms of the Plan and the Agreement, the terms of the Plan and the Agreement shall prevail.

Selected Eligible Persons have been awarded a conditional grant of Apache Corporation RSUs in accordance with the terms of the Plan and the Agreement.

Details of the RSUs which you are conditionally entitled to receive is provided to you in this Award Notice and maintained on your account at netbenefits.fidelity.com

Type of Award: A conditional award of RSUs based on a target percentage of annual base salary determined at the beginning of the Performance Period derived from job level (the “Conditional Grant”).

Restricted Stock Unit: A Restricted Stock Unit (“RSU”) as defined in the Plan and meaning the right granted to the Recipient of the Conditional Grant, as adjusted at the end of the Performance Period, to receive one share of Stock for each RSU at the end of the specified Vesting Period.

Stock: The $0.625 par value common stock of the Company or as otherwise defined in the Plan.

Grant: A Conditional Grant related to ______ Restricted Stock Units (“Target Amount”)

Grant Date:[Date]

1

Conditions: Subject always to the terms of the Plan and the Agreement, the Conditional Grant of RSUs shall be made as of the Grant Date. At the end of the Performance Period, the Committee shall derive and confirm the number of Conditional Grant RSUs that will actually be awarded as RSUs to the Recipient based upon measurement of the specific performance goals, applicable performance percentage levels and applicable weighting percentages during the Performance Period as set forth in Schedule B to the Agreement, provided that the Recipient remains an Eligible Person and employed by the Company or its Affiliate as of the final day of the Performance Period. Once granted at the conclusion of the Performance Period, such RSUs shall remain subject to a vesting schedule (as set forth below) (the “Vesting Period”). Once vested, the Recipient shall be paid the value of his or her RSUs in shares of Stock (net of shares withheld for applicable tax withholdings) provided that the Recipient remains employed as an Eligible Person during the Vesting Period including the vesting date.

Performance Measure: The performance measures for the Conditional Grant, the performance percentage levels, and the applicable weighting percentages to be applied over the Performance Period are set forth on Schedule B to the Agreement.

At the end of the Performance Period, the Committee shall determine and certify the attainment of each performance goal based on the established performance percentage levels and apply the applicable weighting percentages to determine the Final Amount of RSUs to be awarded to each Recipient.

Performance Period: The three-year period commencing January 1, 2017 and ending December 31, 2019.

Vesting Period: Except upon a change of control (as described below), death, or Disability (as described below), cessation of employment during the Performance Period shall result in the immediate forfeiture of the entire amount of the Conditional Grant. Any such RSUs awarded shall vest in accordance with the following schedule, provided that the Recipient remains employed as an Eligible Person as of such vesting date:

First day following the close of the Performance Period - 50% vested.

First anniversary of the first day following the close of the Performance Period - an additional 50% vested.

Except as described below, cessation of employment will result in the immediate forfeiture of all unvested RSUs.

Upon such vesting, the applicable shares of Stock, subject to required tax withholding, shall be transferred by the Company to the Recipient within thirty (30) days of such vesting date.

2

Vesting is accelerated to 100% upon the Recipient’s death or cessation of employment by reason of Disability during the Performance Period or the subsequent Vesting Period (or, only in the case of death, while treated as an Eligible Person following Retirement (as described herein)). Upon death or cessation of employment by reason of Disability during the Performance Period, the number of RSUs (and related shares of Stock) granted and vested shall be deemed to be 1.00 times the Conditional Grant amount of RSUs (the Target Amount). Upon such vesting, the applicable shares of Stock, subject to required tax withholding, shall be transferred by the Company to the Recipient’s designated beneficiary, legal representatives, heirs, or legatees, as applicable, in accordance with the terms of the Plan and this Agreement. The Recipient can name a beneficiary on a form approved by the Committee.

Vesting is accelerated to 100% upon the Recipient’s Involuntary Termination or Voluntary Termination with Cause occurring (i) on or after a 409A Change of Control which occurs on or before the end of the Performance Period provided that the Recipient is an Eligible Person at the time of such termination, with vesting to be in the number of RSUs determined by applying the multiple of 1.00 to the Target Amount or (ii) on or after a 409A Change of Control which occurs after completion of the Performance Period. Upon such vesting, the applicable shares of Stock, subject to required tax withholding, shall be transferred by the Company to the Recipient within thirty (30) days of such vesting date.

If, during the Vesting Period, and after the end of the Performance Period, the Recipient's termination of employment from the Company and the Affiliates occurs by reason of his or her Retirement, the Recipient may be deemed to continue to be employed as an Eligible Person for purposes of this Grant and may continue to vest over the Vesting Period provided that the Recipient meets the Retirement Conditions set forth in section 6 of the Agreement. In the event of a 409A Change of Control during such continued Vesting Period, vesting is accelerated to 100%. Upon such vesting, the applicable shares of Stock, subject to required tax withholding, shall be transferred by the Company to the Recipient within thirty (30) days of such vesting date.

Withholding: The Company and the Recipient will comply with all federal and state laws and regulations respecting the required withholding, deposit and payment of any income, employment, or other taxes relating to the Grant.

Clawback: This Grant is subject to the Company's Executive Compensation Clawback Policy (a copy of which is provided with this Notice) and the recoupment and reimbursement policies as provided in the Agreement.

3

Dividends: The Company will credit each of the Recipient's Conditional Grant RSUs and RSUs, as applicable, with Dividend Equivalents. For purposes of this Grant, a Dividend Equivalent is an amount equal to the cash dividend payable per share of Stock multiplied by the number of shares of Stock then underlying such outstanding Conditional Grant RSUs or RSUs, as applicable. Such amount will be credited to a book entry account on Recipient's behalf at the time the Company pays any cash dividend on its Stock. The Recipient's rights in any such Dividend Equivalents will vest at the same time as, and only to the extent that, the underlying Conditional Grant RSUs or RSUs, as applicable, vest and will be distributed at the same time in cash (subject to applicable withholdings), and only to the extent, as the related RSUs are to be distributed to the Recipient as provided in the Agreement and to which such Dividend Equivalents apply. Dividend Equivalents on Conditional Grant RSUs will accrue and be credited by the Company but will be subject to the same performance goals, applicable performance percentage levels and applicable weighting percentages as the related Conditional Grant RSUs. Dividend Equivalents (as so adjusted) will not be paid to a Recipient until such Recipient becomes vested in the related RSUs granted at the end of the Performance Period and will be forfeited in the event of the forfeiture and cancellation of the related Conditional Grant RSUs and RSUs pursuant to this Agreement.

Acceptance Please complete the on-line grant acceptance as promptly as possible to accept or reject your Conditional Grant. You can access this through your account at netbenefits.fidelity.com. By accepting your Conditional Grant, you will have agreed to the terms and conditions set forth in the Agreement, including, but not limited to, the non-compete and non-disparagement provisions set forth in sections 6 and 7 of the Agreement, and the terms and conditions of the Plan. If you do not accept your grant you will be unable to receive your Conditional Grant or the related RSUs.

4

SCHEDULE B

Apache Corporation

2017 Performance Share Program

PERFORMANCE MEASURES

Performance Goals: 1.Total Shareholder Return

At the end of the Performance Period, the Committee shall derive and confirm a portion of the number of Conditional Grant RSUs that will actually be awarded as RSUs to the Recipient based upon measurement of total shareholder return (“TSR”) of Stock as compared to a designated Peer Group during the Performance Period, provided that the Recipient remains an Eligible Person and employed by the Company or its Affiliate as of the final day of the Performance Period.

TSR is determined by dividing (i) the sum of the cumulative amount of a company’s dividends for the performance period (assuming same-day reinvestment into the company’s common stock on the ex-dividend date) and the share price of the company at the end of the performance period minus the share price at the beginning of the performance period by (ii) the share price at the beginning of the performance period.

• Begin Price = Average per share closing price of a share or share equivalent on the applicable stock exchange for the month of December immediately preceding the beginning of the performance period

• End Price = Average per share closing price of a share or share equivalent on the applicable stock exchange for the month in which the performance period ends

• Dividends = Includes dividends paid throughout performance period

• TSR ranking compared to designated Peer Group (11 companies selected)

◦ Anadarko Petroleum Corporation

◦ Chesapeake Energy Corporation

◦ ConocoPhillips Company

◦ Devon Energy Corporation

◦ EOG Resources, Inc.

◦ Hess Corporation

◦ Marathon Oil Corporation

◦ Murphy Oil Corporation

◦ Noble Energy Inc.

◦ Occidental Petroleum Corporation

◦ Pioneer Natural Resources Co.

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• Apache’s performance over a three-year performance period will be directly ranked within the peer group, resulting in the application of a single multiplier to the target shares to derive the number of shares awarded. The multiplier will range from 0 for performance in the bottom quartile to 2.0 for ranking 1st among the peer group.

• Should consolidation among peers in the marketplace occur, the ranking schedule would adjust to accommodate the reduced number of peers.

2. Business Performance

The Committee shall derive and confirm a portion of the number of Conditional Grant RSUs that will actually be awarded as RSUs to the Recipient based upon quantitative performance measures at the end of the Performance Period related to the following criteria:

• Cash Flow from Operations; and

• Reserves Added per Debt Adjusted Share

The Committee will consider all of the above performance measures related to the Company as a whole as follows:

Metric	Weighting	Threshold	Target	Max
Total Shareholder Return	50%	9th	6th	1st - 2nd
Cash Flow from Operations	25%	-10%	Plan	+10%
Reserves added per debt adjusted share	25%	-10%	Plan	+10%

Performance Period:Three calendar years

• 1/1/2017 to 12/31/2019

Measurement: At the conclusion of the three-year performance period, a calculation of TSR performance will be made and confirmed. 50% of the total Target Amount of RSUs will be determined based upon the final TSR performance as follows:

Rank Against Peers	Payout Multiple
1	2.00
2	2.00
3	1.75
4	1.50
5	1.25
6	1.00
7	0.80
8	0.60
9	0.40
10	0.00
11	0.00
12	0.00

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Cash Flow from Operations will be evaluated annually during the three-year performance period against their respective performance targets as determined at the beginning of each year (performance target for each calendar year to be determined prior to March 31). Performance will be measured as a percentage above or below target. 25% of the total Target Amount of RSUs will be determined based upon the three-year average of the Cash Flow from Operations performance.

Reserves Added per Debt Adjusted Share will be evaluated annually during the three-year performance period against their respective performance targets as determined at the beginning of each year (performance target for each calendar year to be determined prior to March 31). Performance will be measured as a percentage above or below target. 25% of the total Target Amount of RSUs will be determined based upon the three-year average Reserves Added per Debt Adjusted Share.

The three-year average performance for cash flow from operations and reserves added per debt adjusted share will be interpolated as follows to determine the final achievement percentage for each metric.

Metric	Threshold	Target	Max
Cash Flow from Operations	-10%	Plan	+10%
Reserves added per debt adjusted share	-10%	Plan	+10%

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Apache Corporation

2017 Performance Share Program Agreement

This 2017 Performance Share Program Agreement (the “Agreement”) relating to a conditional grant of Restricted Stock Units (as defined in the definition section of the Apache Corporation 2016 Omnibus Compensation Plan (the “Plan”)) (the “Conditional Grant”), dated as of the Grant Date set forth in the Notice of Award under the 2017 Performance Share Program attached as Schedule A hereto (the “Award Notice”), is made between Apache Corporation (together with its Affiliates, the “Company”) and each Recipient. The Award Notice is included in and made part of this Agreement.

In this Agreement and each Award Notice, unless the context otherwise requires, words and expressions shall have the meanings given to them in the Plan except as herein defined.

Definitions

“409A Change of Control” means a Change of Control that constitutes, with respect to the Company, a “change in the ownership or effective control of the corporation, or in the ownership of a substantial portion of the assets of the corporation” within the meaning of Section 409A(a)(2)(A)(v) of the Internal Revenue Code of 1986, as amended (the “Code”) and Treasury Regulations Section 1.409A-3(i)(5).

“Award Notice” means the separate notice, along with Schedule B, given to each Recipient specifying the Target Amount and other applicable performance percentage levels, performance criteria and applicable weighting percentages for that individual.

“Base Salary” means, with regard to any Recipient, such Recipient’s annual base compensation as an employee of the Company determined immediately prior to the beginning of the Performance Period, without regard to any bonus, pension, profit sharing, stock option, life insurance or salary continuation plan which the Recipient either receives or is otherwise entitled to have paid on his or her behalf.

“Conditional Grant” means the conditional entitlement, evidenced by this Agreement to receive all or a portion of a Target Amount and Final Amount, subject to and in accordance with the provisions of this Agreement.

“Disability” or “Disabled” means the Recipient is unable to engage in any substantial gainful activity by reason of any medically determinable physical or mental impairment which can be expected to result in death or which has lasted or can be expected to last for a continuous period of not less than 12 months. Recipient agrees that a final and binding determination of “Disability” will be made by the Company’s representative under the Company’s group long-term disability plan or any successor thereto or, if there is no such representative and there is a dispute as to the determination of “Disability,” it will be decided in a court of law in Harris County, Texas.

“Fair Market Value” means the fair market value of a share of the Stock as determined by the Committee by the reasonable application of such reasonable valuation method, consistently applied, as the Committee deems appropriate; provided, however, that if the Committee has not made such determination, such fair market value shall be the per share closing price of the Stock as reported on The New York Stock Exchange, Inc. Composite Transactions Reporting System (“Composite Tape”) for a particular date or, if the Stock is not so listed at any time, as reported on NASDAQ or on such other exchange or electronic trading system as, on the date in question, reports the largest number of traded shares of stock; provided further, however, that, if there are no Stock transactions on such date, the Fair Market Value shall be determined as of the immediately preceding date on which there were Stock transactions.

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“Final Amount” means with regard to any Recipient, such number of shares of Restricted Stock Units (“RSUs”) as specified in each Recipient’s Award Notice, times the applicable multiple factor determined under the Performance Measures at the end of the Performance Period.

“Involuntary Termination” means the termination of employment of the Recipient by the Company or its successor for any reason on or after a 409A Change of Control; provided, that the termination does not result from an act of the Recipient that constitutes common-law fraud, a felony, or a gross malfeasance of duty.

“Payout Amount” means the vested portion of the Final Amount, along with any Dividend Equivalents related thereto as specified in the Award Notice, expressed as shares of Stock underlying the RSUs and related Dividend Equivalents.

“Peer Group” means the group of companies selected by the Committee for purposes of this Agreement as set forth in the Award Notice. Should consolidation among any Peer Group companies in the marketplace occur during the Performance Period, the Committee will determine the appropriate adjustments to accommodate the reduced number of Peer Group companies for the Performance Period. Should a Change of Control of the Company occur during the Performance Period, the Committee will determine the appropriate adjustments to measure Apache Corporation’s TSR for the Performance Period. The Peer Group companies for any particular Performance Period shall be determined at the commencement of such Performance Period.

“Performance Measures” means, as set forth in the Award Notice, (i) Apache Corporation’s TSR over the Performance Period compared to the TSR of the Company’s Peer Group over the Performance Period, or (ii) Apache Corporation’s achievement of pre-established performance goals over the Performance Period, as applicable. For purposes of determining TSR performance, at the end of the Performance Period, the Peer Group companies and the Company will be ranked together based on their TSR for the Performance Period from the highest TSR being number 1 to the lowest TSR being the number of Peer Group companies, including the Company, remaining in the group at the end of the Performance Period. Based on the Company’s relative TSR rank amongst the Peer Group companies for the Performance Period, a Recipient who remains employed as of the last day of the Performance Period will be issued RSUs at the close of the Performance Period as determined by the Company’s percentile rank as set forth in the Award Notice (the Final Amount). At the end of the Performance Period, the Committee shall also determine and certify the levels of other specific performance goals achieved and apply the applicable performance percentage levels and weighting percentages as set forth in the Award Notice. Based on the Company’s level of goal achievement, a Recipient who remains employed as of the last day of the Performance Period will be issued RSUs on the day following the close of the Performance Period as determined by the Committee as set forth in the Award Notice (the Final Amount).

“Performance Period” means the three-year period as specified in the Award Notice.

“Recipient” means an Eligible Person who has been designated by the Committee at the Grant Date at the beginning of the Performance Period to receive one or more Conditional Grants under the Plan. For purposes of this Agreement, the group of Eligible Persons shall include all full-time and designated part-time employees of the Company who are employed as employees of the Company (as designated by the Company for payroll purposes) on the date immediately prior to the beginning of the Performance Period, but excluding Egyptian nationals employed outside of the United States, employees categorized by the Company (for payroll purposes) as non-exempt support and field staff, leased employees, interns, or any employee of the Company who is covered under a collective bargaining agreement, unless such collective bargaining agreement specifically provides for coverage under the Plan.

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“Retirement” means, with respect to a Recipient and for purposes of this Agreement, the date the Recipient terminates employment with the Company after (i) attaining age 65 and (ii) earning at least 15 Years of Service.

“Years of Service” means the total number of months from the Recipient's date of hire by the Company to the date of termination of employment divided by 12.

“Target Amount” means, with regard to any Recipient, such number of RSUs as specified in each Recipient’s Award Notice. Such Target Amount shall be based upon a target percentage of annual Base Salary determined at the beginning of the Performance Period derived from job level.

“Total Shareholder Return” or “TSR” is determined by dividing (i) the sum of the cumulative amount of a company’s dividends for the Performance Period (assuming same-day reinvestment into the company’s common stock on the ex-dividend date) and the share price of the company at the end of the Performance Period minus the share price at the beginning of the Performance Period, by (ii) the share price at the beginning of the Performance Period.

“Voluntary Termination with Cause” occurs upon a Recipient’s separation from service of his own volition and one or more of the following conditions occurs without the Recipient’s consent on or after a 409A Change of Control:

(a) There is a material diminution in the Recipient’s base compensation, compared to his rate of base compensation on the date of the 409A Change of Control.

(b) There is a material diminution in the Recipient’s authority, duties or responsibilities.

(c) There is a material diminution in the authority, duties or responsibilities of the Recipient’s supervisor, such as a requirement that the Recipient (or his supervisor) report to a corporate officer or employee instead of reporting directly to the board of directors.

(d) There is a material diminution in the budget over which the Recipient retains authority.

(e) There is a material change in the geographic location at which the Recipient must perform his service, including, for example the assignment of the Recipient to a regular workplace that is more than 50 miles from his regular workplace on the date of the 409A Change of Control.

The Recipient must notify the Company of the existence of one or more adverse conditions specified in clauses (a) through (e) above within 90 days of the initial existence of the adverse condition. The notice must be provided in writing to Apache Corporation’s Executive Vice President, Human Resources or his/her delegate. The notice may be provided by personal delivery or it may be sent by email, inter-office mail, regular mail (whether or not certified), fax, or any similar method. Apache Corporation’s Executive Vice President, Human Resources, or his/her delegate shall acknowledge receipt of the notice within 5 business days; the acknowledgement shall be sent to the Recipient by certified mail. Notwithstanding the foregoing provisions of this definition, if the Company remedies the adverse condition within 30 days of being notified of the adverse condition, no Voluntary Termination with Cause shall occur.

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Terms

1.Conditional Grant of RSUs. Subject to the provisions of this Agreement and the provisions of the Plan and Award Notice, the Company shall conditionally grant to the Recipient, pursuant to the Plan, a right to receive the Target Amount of RSUs set forth in the Recipient’s Award Notice. Such Target Amount shall be adjusted to a Final Amount at the end of the Performance Period based upon the results of the Performance Measures, as determined by the Committee. Notwithstanding the foregoing, the Target Amount shall be adjusted to a Final Amount of RSUs at the conclusion of the Performance Period solely for each Recipient who remains employed as of the last day of the Performance Period. The award of the Final Amount shall give the Recipient the right, upon vesting, to an equal number of shares of $0.625 par value common stock of the Company (“Stock”).

2.Vesting and Payment of Stock. Subject to the provisions of Section 3, the Payout Amounts shall be payable in increments strictly in accordance with the following schedule:

(a)The entitlement to receive the number of shares of Stock pursuant to the RSUs comprising the Final Amount shall vest fifty percent (50%) and become transferable as of the first day following the close of the Performance Period, provided that the Recipient remains employed as an Eligible Person on such date. Except as otherwise provided herein, such Stock, subject to applicable withholding, shall be transferred by the Company to the Recipient within thirty (30) days of such vesting date.

(b)The entitlement to receive the remaining fifty percent (50%) of the shares of Stock pursuant to the RSUs comprising the Final Amount shall vest and become transferable as of the first anniversary of the first day following the close of the Performance Period, provided that the Recipient remains employed as an Eligible Person on such applicable vesting date. Except as otherwise provided herein, such Stock, subject to applicable withholding, shall be transferred by the Company to the Recipient within thirty (30) days of such vesting date.

3.Termination of Employment, Death, or Disability on or prior to the end of the Performance Period. Except as set forth below, a cessation of employment with the Company prior to the end of the Performance Period will result in the Target Amount being forfeited for all purposes.

(a)If the Recipient dies while employed by the Company, or if the Recipient is no longer employed by the Company by reason of Disability (as defined in this Agreement), during the Performance Period, the Recipient shall be entitled to an amount equal to the Target Amount of RSUs and shall become 100% vested in such Target Amount. Payment shall be made as soon as administratively practicable, but in no event (i) in the case of death, shall the payment occur later than the last day of the calendar year following the calendar year in which such death occurs or (ii) in the case of cessation of employment by reason of Disability, shall the payment occur later than thirty (30) days following the date upon which the Recipient is Disabled and is no longer employed by the Company. If clause (ii) is applicable and the payment period spans two consecutive calendar years, payment shall be made in the second calendar year of such consecutive calendar years. Such payment shall be made to the Recipient’s designated beneficiary, legal representatives, heirs, or legatees, as applicable. Each Recipient may designate a beneficiary on a form approved by the Committee.

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4.Termination of Employment, Retirement, Death or Disability after the end of the Performance Period. Except as set forth below, each Conditional Grant shall be subject to the condition that the Recipient has remained an Eligible Person from the award of the Conditional Grant of RSUs until the applicable vesting date as follows:

(a)If the Recipient voluntarily leaves the employment of the Company (other than for reason of Retirement), or if the employment of the Recipient is terminated by the Company for any reason or no reason, any Final Amounts not previously vested shall thereafter be void and forfeited for all purposes.

(b)A Recipient shall become 100% vested in all Final Amounts on the date the Recipient dies while employed by the Company (or while continuing to vest pursuant to section 4(c) below), or on the date the Recipient is no longer employed by the Company by reason of Disability. Payment shall be made as soon as administratively practicable, but in no event (i) in the case of death, shall the payment occur later than the last day of the calendar year following the calendar year in which such death occurs or (ii) in the case of cessation of employment by reason of Disability, shall the payment occur later than thirty (30) days following the date upon which the Recipient is Disabled and is no longer employed by the Company. If clause (ii) is applicable and the payment period spans two consecutive calendar years, payment shall be made in the second calendar year of such consecutive calendar years. Such payment shall be made to the Recipient’s designated beneficiary, legal representatives, heirs, or legatees, as applicable. Each Recipient may designate a beneficiary on a form approved by the Committee.

(c)If the Recipient leaves the employment of the Company by reason of Retirement, any Final Amounts not previously vested shall continue to vest following the Recipient's termination of employment by reason of Retirement after the end of the Performance Period as if the Recipient remained an Eligible Person in the employ of the Company, provided that such Recipient shall be entitled to continue vesting only if such Recipient satisfies the Retirement Conditions set forth in section 6 below (except in the case of death). Stock, which vests pursuant to this section 4(c) and subject to applicable withholding, shall be transferred by the Company to the Recipient who is retired, within thirty (30) days of such vesting date.

5.Change of Control.

(a)Pursuant to Section 13.1(d) of the Plan, the following provisions of this section 5 of the Agreement shall supersede Sections 13.1(a), (b) and (c) of the Plan. Without any further action by the Committee or the Board, in the event of the Recipient’s Involuntary Termination or Voluntary Termination with Cause which occurs (i) on or after a 409A Change of Control of the Company and (ii) prior to the end of the Performance Period, the Recipient shall become 100% vested as of the date of such Involuntary Termination or Voluntary Termination with Cause in the number of RSUs determined by applying the multiple of 1.00 to the Target Amount. Subject to section 13(d) of this Agreement, payment shall occur within thirty (30) days of the date of such Involuntary Termination or Voluntary Termination with Cause.

(b)In the event of a Recipient’s Involuntary Termination or Voluntary Termination with Cause occurring on or after a 409A Change of Control of the Company which occurs after the end of the Performance Period, the Recipient shall become 100% vested in the Final Amount of RSUs as of the date of such Involuntary Termination or Voluntary Termination with Cause. Subject to section 13(d) of this Agreement, payment shall occur within thirty (30) days of the date of such Involuntary Termination or Voluntary Termination with Cause.

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(c)In the event of a 409A Change of Control of the Company following the Recipient's termination of employment by reason of Retirement after the end of the Performance Period while the Recipient is continuing to vest pursuant to section 4(c), the Recipient shall become 100% vested in the unvested Final Amount of RSUs as of the date of the 409A Change of Control. Subject to section 13(d) of this Agreement, payment shall occur within thirty (30) days of the 409A Change of Control.

6.Conditions to Post-Retirement Vesting. If the Recipient has attained age 65 and has completed at least 15 Years of Service and such Recipient terminates employment with the Company and the Affiliates by reason of Retirement, it is agreed by the Company and the Recipient that:

(a)subject to the provisions of this section 6(a) and sections 6(b) and 6(c), such Recipient shall continue to vest in the unvested Final Amount of RSUs following the date of his or her termination by reason of Retirement as if the Recipient continued in employment as an Eligible Person provided that the Grant Date of the unvested RSUs is at least three (3) months prior to such termination date and the Recipient has provided not less than three (3) months’ advance written notice prior to such termination date to Apache Corporation’s Senior Vice President, Human Resources, or his or her delegate, and to his or her direct manager, regarding the Recipient's intent to terminate employment for reason of Retirement; provided, however, a Recipient who is at least age 65 and has completed at least 15 Years of Service need not provide such three (3) months’ advance written notice of his or her intent to terminate employment by reason of Retirement if the Company elects to require such Recipient to, or (as part of a reduction in force or otherwise in writing in exchange for a written release) offers such Recipient the opportunity to, terminate employment with the Company by reason of Retirement; and it is further agreed that

(b)in consideration for the continued vesting treatment afforded to the Recipient under section 6(a), Recipient shall, during the continuing Vesting Period after Retirement (the “Continued Vesting Period”) refrain from becoming employed by, or consulting with, or becoming substantially involved in the business of, any business that competes with the Company or its Affiliate in the business of exploration or production of oil or natural gas within the geographic area in which the Recipient is working or has worked for the Company or its Affiliate, and/or for which the Recipient is or was responsible, at the time of termination of employment or the immediately preceding three-year period (a “Competitive Business”); provided, that the Recipient may purchase and hold for investment purposes less than five percent (5%) of the shares of any Competitive Business whose shares are regularly traded on a national securities exchange or inter-dealer quotation system, and provided further, that the Recipient may provide services solely as a director of any Competitive Business whose shares are regularly traded on a national securities exchange or inter-dealer quotation system if, during the Continued Vesting Period, (i) the Recipient only attends board and board committee meetings, votes on recommendations of management, and discharges his/her fiduciary obligations under the law and (ii) the Recipient is not involved in, and does not advise or consult on, the marketing, government relations, customer relations, or the day-to-day management, supervision, or operations of such Competitive Business; and it is further agreed that

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(c)in consideration for the continued vesting treatment afforded to the Recipient under section 6(a), Recipient shall, during the Continued Vesting Period, refrain from making, or causing or assisting any other person to make, any oral or written communication to any third party about the Company, any Affiliate and/or any of the employees, officers or directors of the Company or any Affiliate which impugns or attacks, or is otherwise critical of, the reputation, business or character of such entity or person; or that discloses private or confidential information about their business affairs; or that constitutes an intrusion into their seclusion or private lives; or that gives rise to unreasonable publicity about their private lives; or that places them in a false light before the public; or that constitutes a misappropriation of their name or likeness.

Notwithstanding the foregoing provisions of this section 6 of the Agreement, in the event that the Recipient fails to satisfy any of the conditions set forth in sections 6(a), (b) and (c) above, the Recipient shall not be entitled to vest in any unvested Final Amount of RSUs after the date of Retirement and the unvested Final Amount of RSUs subject to this Agreement shall be forfeited.

7.Prohibited Activity. In consideration for this Grant and except as permitted by Section 6(b) above, the Recipient agrees not to engage in any “Prohibited Activity” while employed by the Company or within three years after the date of the Recipient’s termination of employment.  A “Prohibited Activity” will be deemed to have occurred, as determined by the Committee in its sole and absolute discretion, if the Recipient (i) divulges any non-public, confidential or proprietary information of the Company, but excluding information that (a) becomes generally available to the public other than as a result of the Recipient’s public use, disclosure, or fault, or (b) becomes available to the Recipient on a non-confidential basis after the Recipient’s employment termination date from a source other than the Company prior to the public use or disclosure by the Recipient, provided that such source is not bound by a confidentiality agreement or otherwise prohibited from transmitting the information by contractual, legal or fiduciary obligation, (ii) directly or indirectly, consults with or becomes affiliated with, participate or engage in, or becomes employed by any business that is competitive with the Company, wherever from time to time conducted throughout the world, including situations where the Recipient solicits or participates in or assists in any way in the solicitation or recruitment, directly or indirectly, of any employees of the Company; or (iii) engages in publishing any oral or written statements about the Company, and/or any of its directors, officers, or employees that are disparaging, slanderous, libelous, or defamatory; or that disclose private or confidential information about their business affairs; or that constitute an intrusion into their seclusion or private lives; or that give rise to unreasonable publicity about their private lives; or that place them in a false light before the public; or that constitute a misappropriation of their name or likeness.

8.Payment and Tax Withholding. Upon receipt of any entitlement to Stock under this Agreement and, if applicable, upon the Recipient's attainment of eligibility to terminate employment by reason of Retirement pursuant to section 4(c), the Recipient shall make appropriate arrangements with the Company to provide for the amount of minimum tax and social security withholding, if any, required by law, including without limitation Sections 3102 and 3402 or any successor section(s) of the Internal Revenue Code and applicable state and local income and other tax laws. Upon receipt of entitlement to Stock under this Agreement, each payment of the Payout Amount shall be made in shares of Stock, determined by the Committee, such that the withheld number of shares shall be sufficient to cover the withholding amount required by this Section (including any amount to cover benefit tax charges arising thereon). The payment of a Payout Amount shall be based on the Fair Market Value of the shares of Stock on the applicable date of vesting to which such tax withholding relates. Where appropriate, shares shall be withheld by the Company to satisfy applicable tax withholding requirements rather than paid directly to the Recipient.

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9.No Ownership Rights Prior to Issuance of Stock. Neither the Recipient nor any other person shall become the beneficial owner of the Stock underlying the Conditional Grant, nor have any rights of a shareholder (including, without limitation, dividend and voting rights) with respect to any such Stock, unless and until and after such Stock has been actually issued to the recipient and transferred on the books and records of the Company or its agent in accordance with the terms of the Plan and this Agreement.

10.Non-Transferability of Conditional Grant and Unvested Final Amount. The Conditional Grant and any unvested Final Amount shall not be transferable otherwise than by testamentary will or the laws of descent and distribution, or in accordance with a valid beneficiary designation on a form approved by the Committee, subject to the conditions and exceptions set forth in Section 15.2 of the Plan.

11.No Right to Continued Employment. Neither the RSUs or Stock issued pursuant to a Conditional Grant nor any terms contained in this Agreement shall confer upon the Recipient any express or implied right to be retained in the employment or service of the Company for any period, nor restrict in any way the right of the Company, which right is hereby expressly reserved, to terminate the Recipient’s employment or service at any time for any reason or no reason. The Recipient acknowledges and agrees that any right to receive RSUs or Stock pursuant to a Conditional Grant is earned only by continuing as an employee of the Company at the will of the Company, or satisfaction of any other applicable terms and conditions contained in the Plan and this Agreement, and not through the act of being hired, being granted the Conditional Grant, or acquiring RSUs or Stock pursuant to the Conditional Grant hereunder.

12.The Plan. In consideration for this Conditional Grant, the Recipient agrees to comply with the terms of the Plan and this Agreement. This Agreement is subject to all the terms, provisions and conditions of the Plan, which are incorporated herein by reference, and to such regulations as may from time to time be adopted by the Committee. Unless defined herein, capitalized terms are used herein as defined in the Plan. In the event of any conflict between the provisions of the Plan and this Agreement, the provisions of the Plan shall control, and this Agreement shall be deemed to be modified accordingly. The Plan and the prospectus describing the Plan can be found on the Company’s HR intranet and the Plan document can be found on Fidelity’s website (netbenefits.fidelity.com). A paper copy of the Plan and the prospectus shall be provided to the recipient upon the Recipient’s written request to the Company at 2000 Post Oak Blvd., Suite 100, Houston, Texas 77056-4400, Attention: Corporate Secretary.

13.Compliance with Laws and Regulations.

(a)The Conditional Grant and any obligation of the Company to deliver RSUs or Stock hereunder shall be subject in all respects to (i) all applicable laws, rules and regulations and (ii) any registration, qualification, approvals or other requirements imposed by any government or regulatory agency or body which the Committee shall, in its discretion, determine to be necessary or applicable. Moreover, the Company shall not deliver any certificates for Stock to the Recipient or any other person pursuant to this Agreement if doing so would be contrary to applicable law. If at any time the Company determines, in its discretion, that the listing, registration or qualification of Stock upon any national securities exchange or under any applicable law, or the consent or approval of any governmental regulatory body, is necessary or desirable, the Company shall not be required to deliver any certificates for Stock to the Recipient or any other person pursuant to this Agreement unless and until such listing, registration, qualification, consent or approval has been effected or obtained, or otherwise provided for, free of any conditions not acceptable to the Company.

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(b)It is intended that the issuance of any Stock received in respect of the Conditional Grant shall have been registered under the Securities Act of 1933 (“Securities Act”). If the Recipient is an “affiliate” of the Company, as that term is defined in Rule 144 under the Securities Act (“Rule 144”), the Recipient may not sell the Stock received except in compliance with Rule 144. Certificates representing Stock issued to an “affiliate” of the Company may bear a legend setting forth such restrictions on the disposition or transfer of the Stock as the Company deems appropriate to comply with Federal and state securities laws.

(c)If, at any time, a registration statement with respect to the issuance of the Stock is not effective under the Securities Act, and/or there is no current prospectus in effect under the Securities Act with respect to the Stock, the Recipient shall execute, prior to the delivery of any Stock to the Recipient by the Company pursuant to this Agreement, an agreement (in such form as the Company may specify) in which the Recipient represents and warrants that the Recipient is purchasing or acquiring the Stock acquired under this Agreement for the Recipient’s own account, for investment only and not with a view to the resale or distribution thereof, and represents and agrees that any subsequent offer for sale or distribution of any kind of such Stock shall be made only pursuant to either (i) a registration statement on an appropriate form under the Securities Act, which registration statement has become effective and is current with regard to the Stock being offered or sold, or (ii) a specific exemption from the registration requirements of the Securities Act, but in claiming such exemption the Recipient shall, prior to any offer for sale of such Stock, obtain a prior favorable written opinion, in form and substance satisfactory to the Company, from counsel for or approved by the Company, as to the applicability of such exemption thereto.

(d)This Conditional Grant is intended to comply with, or be exempt from, the applicable requirements of Section 409A of the Code and the rules and regulations issued thereunder and shall be administered accordingly. Notwithstanding anything in this Agreement to the contrary, if the RSUs constitute “deferred compensation” under Section 409A of the Code and any RSUs become payable pursuant to the Recipient's termination of employment, settlement of the RSUs shall be delayed for a period of six months after the Recipient's termination of employment if the Recipient is a “specified employee” as defined under Code Section 409A(a)(2)(B)(i) and if required pursuant to Section 409A of the Code. If settlement of the RSUs is delayed, the RSUs shall be settled on the first day of the first calendar month following the end of the six-month delay period. If the Recipient dies during the six-month delay, the RSUs shall be settled and paid to the Recipient's designated beneficiary, legal representatives, heirs or legatees, as applicable, as soon as practicable after the date of death. Notwithstanding any provision to the contrary herein, payments made with respect to this Conditional Grant may only be made in a manner and upon an event permitted by Section 409A of the Code, and all payments to be made upon a termination of employment hereunder may only be made upon a “separation from service,” as such term is defined in Section 11.1 of the Plan. Recipient shall not have any right to determine a date of payment of any amount under this Agreement. This Agreement may be amended without the consent of the Recipient in any respect deemed by the Board or the Committee to be necessary in order to preserve compliance with Section 409A of the Code. If the Grant and this Agreement is subject to Section 409A of the Code and the rules and regulations issued thereunder, and, except as set forth in section 5(a), the vesting date shall be the “designated payment date” or “specified date” under Treasury Regulation 1.409A-3(d).

14.Notices. Unless otherwise provided in this Agreement, all notices by the Recipient or the Recipient’s assignees shall be addressed to the Administrative Agent, Fidelity, through the Recipient’s account at netbenefits.fidelity.com, or such other address as the Company may from time to time specify. All notices to the Recipient shall be addressed to the Recipient at the Recipient’s address in the Company’s records.

15.Other Plans. The Recipient acknowledges that any income derived from the Conditional Grant shall not affect the Recipient’s participation in, or benefits under, any other benefit plan or other contract or arrangement maintained by the Company or any Affiliate.

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16.Terms of Employment. The Plan is a discretionary plan. The Recipient hereby acknowledges that neither the Plan nor this Agreement forms part of his terms of employment and nothing in the Plan may be construed as imposing on the Company or any Affiliate a contractual obligation to offer participation in the Plan to any employee of the Company or any Affiliate. The Company or any Affiliate is under no obligation to grant further Stock to any Recipient under the Plan. The Recipient hereby acknowledges that if he ceases to be an employee of the Company or any Affiliate for any reason or no reason, he shall not be entitled by way of compensation for loss of office or otherwise howsoever to any sum.

17.Data Protection. By accepting this Agreement (whether by electronic means or otherwise), the Recipient hereby consents to the holding and processing of personal data provided by him to the Company for all purposes necessary for the operation of the Plan. These include, but are not limited to:

(a)administering and maintaining Recipient records;

(b)providing information to any registrars, brokers or third party administrators of the Plan; and

(c)providing information to future purchasers of the Company or the business in which the Recipient works.

18.Clawback Policy. If required by the Sarbanes-Oxley Act of 2002 and/or by the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010, each Recipient's Award shall be conditioned on repayment or forfeiture in accordance with applicable law. In addition, the Company's Executive Compensation Clawback Policy is hereby incorporated by reference and shall form a part of this Agreement and each Recipient's Award shall be subject to such Policy. In connection with a material negative accounting restatement by the Company as the result of fraud, intentional misconduct, or gross negligence by the Recipient, Awards and payments in connection with Awards granted under this Agreement may be subject to recovery and Recipient may be required to repay to the Company all or a portion of any Award or payments received in connection with any Award hereunder. In the event that the Company determines to seek recovery with respect to an Award under this Agreement, an affected Recipient may elect to repay the applicable clawback amount in cash or, if shares of Stock received pursuant to an affected Award are still owned by the Recipient, in net after-tax shares of Stock received pursuant to the Award. The date for determination of the value of the applicable compensation to be repaid shall be the vesting date of the affected Award and the amount of any applicable repayment shall be determined based upon the net after-tax amount realized by the Recipient as income on such vesting date, applying the highest marginal tax rate for federal, state and local income taxes.

19.Severability. If any provision of this Agreement is held invalid or unenforceable, the remainder of this Agreement shall nevertheless remain in full force and effect, and if any provision is held invalid or unenforceable with respect to particular circumstances, it shall nevertheless remain in full force and effect in all other circumstances, to the fullest extent permitted by law.

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Apache Corporation

Executive Compensation Clawback Policy

Should the Company’s reported financial or operating results be subject to a material negative restatement as the result of fraud, intentional misconduct, or gross negligence of an executive officer, the Company has the right to recover from such executive officer an amount corresponding to any incentive award or portion thereof (including any cash bonus or equity-based award) that the Company determines would not have been granted, vested, or paid had the Company’s results as originally reported been equal to the Company’s results as subsequently restated. The Company will apply a three-year lookback period from the date of any such material negative restatement. Subject to applicable law, the Company has the right to recover such amount by requiring the executive officer to re-pay such amount to the Company by direct payment to the Company or such other means or combination of means as the Company determines to be appropriate.

If the Company determines to seek a recovery pursuant to this policy, it shall make a written demand for repayment from the executive officer and, if such person does not, within a reasonable period of time following such demand, tender repayment in response to such demand, and the Company determines that he or she is unlikely to do so, the Company may seek a court order against the executive officer for such repayment.

The Company may not seek recovery to the extent it determines (i) that to do so would not be cost effective or (ii) that it would be better for the Company not to do so. In making such determination, the Company shall take into account such considerations as it deems appropriate, including, without limitation, (A) the likelihood of success under governing law versus the cost and effort involved, (B) whether the assertion of a claim may prejudice the interests of the Company, including in any related proceeding or investigation, (C) the passage of time since the occurrence of the act in the event of fraud or intentional illegal conduct, and (D) any pending legal proceeding relating to such fraud or intentional illegal conduct.

This Policy applies to any incentive compensation for years commencing after the adoption of this Policy.

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EX-10.48

SCHEDULE A

Apache Corporation

Stock Option Grant Agreement

GRANT NOTICE

Participant Name:______________________

Company:Apache Corporation

Notice: A summary of the terms of your grant of a Stock Option to purchase Shares (“Option”) is set out in this notice (the “Grant Notice”) but subject always to the terms of the Apache Corporation 2016 Omnibus Compensation Plan (the “Plan”) and the Stock Option Award Agreement (the “Agreement”). In the event of any inconsistency between the terms of this Grant Notice, the terms of the Plan and the Agreement, the terms of the Plan and the Agreement shall prevail.

You have been granted a Stock Option to purchase Shares in accordance with the terms of the Plan and the Stock Option Award Agreement attached hereto. Details of the Option are provided to you in this Grant Notice and maintained on your account at netbenefits.fidelity.com

Type of Award: Non-Qualified Stock Option

Plan: Apache Corporation 2016 Omnibus Compensation Plan

Grant:Grant Date:  ______________

Option Price per Share: $_____________

Number of Shares subject to the Option: __________________ Shares

Exercisability: Subject to the terms of the Plan and this Agreement, your Option may be exercised on and after the vesting dates indicated below as to the percentage of Shares subject to your Option set forth below opposite each such date, plus any Shares as to which your Option could have been exercised previously but was not so exercised.

Percentage of Shares	Vesting Date
1/3	The first anniversary of the Grant Date
1/3	The second anniversary of the Grant Date
1/3	The third anniversary of the Grant Date

Except as explained below, upon a termination of your employment with the Company or the Affiliates, your vesting period will expire and the Option, to the extent vested and exercisable at such termination date, will be exercisable during the three-month period following your termination (a one-year period if your termination is due to a qualifying disability). However, if your employment is terminated by the Company or an Affiliate for Cause, then any portion of the Option that has not been exercised as of such termination date will immediately terminate and be forfeited.

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Notwithstanding the foregoing, if your termination of employment from the Company or the Affiliates occurs by reason of your Retirement: (A) after attaining age 60, the Option, to the extent vested and exercisable at such retirement date, will be exercisable until the earlier to occur of (1) the third anniversary of such retirement date or (2) the Expiration Date and (B) after attaining age 65 and earning at least 15 Years of Service, (1) you will be deemed to continue to be employed for purposes of vesting in this Option and you will continue to vest over the Vesting Period and (2) to the extent vested and exercisable on or after such retirement date, this Option will be exercisable for all or any portion of the full number of Shares available for purchase under this Option until the Expiration Date of this Option; provided, in each case, that you meet the Retirement conditions set forth in section 5 of the Agreement.

Upon your death during the Vesting Period (or during the period that you continue to vest in connection with your Retirement as described above), your Option will become immediately fully exercisable by your designated beneficiary, your legal representatives, your heirs, or your legatees, as applicable, in accordance with the terms of the Plan. You can name a designated beneficiary on a form approved by the Committee.

Vesting of your Option is accelerated to 100% upon your Involuntary Termination or Voluntary Termination with Cause occurring on or after a Change of Control during the Vesting Period. Vesting of your Option is accelerated to 100% upon the occurrence of a Change of Control if you are continuing to vest in your Option following your termination by reason of Retirement as described above.

Expiration Date: Your Option will expire ten years from the Grant Date, subject to earlier termination as set forth in the Plan and this Agreement.

Acceptance: Please complete the on-line grant acceptance as promptly as possible to accept or reject your Option. You can access this through your account at www.netbenefits.com. By accepting your Option, you will have agreed to the terms and conditions set forth in this Agreement, including, but not limited to, the non-compete and non-disparagement provisions set forth in sections 4(c), 5, and 6 of the Agreement, and the terms and conditions of the Plan. If you do not accept your Grant you will be unable to exercise your Option.

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Stock Option Award Agreement

This Stock Option Award Agreement (this “Agreement”), dated as of the Grant Date set forth in the Notice of Option Grant attached as Schedule A hereto (the “Grant Notice”), is made between Apache Corporation (the “Company”) and the Participant set forth in the Grant Notice. The Grant Notice is included in and made part of this Agreement.

In this Agreement and each Grant Notice, unless the context otherwise requires, words and expressions shall have the meanings given to them in the Plan except as herein defined.

Definitions

“Disability” or “Disabled” means the Participant is unable to engage in any substantial gainful activity by reason of any medically determinable physical or mental impairment which can be expected to result in death or which has lasted or can be expected to last for a continuous period of not less than 12 months. Participant agrees that a final and binding determination of “Disability” will be made by the Company’s representative under the Company’s group long-term disability plan or any successor thereto or, if there is no such representative and there is a dispute as to the determination of “Disability,” it will be decided in a court of law in Harris County, Texas.

“Grant Notice” means the separate notice given to each Participant specifying the number of Shares underlying the Option granted to the Participant (the “Grant”).

“Involuntary Termination” means the termination of employment of the Participant by the Company or its successor for any reason on or after a Change of Control; provided, that the termination does not result from an act of the Participant that constitutes common-law fraud, a felony, or a gross malfeasance of duty.

“Retirement” means, with respect to a Participant and for purposes of this Agreement, the date the Participant terminates employment with the Company or the Affiliates after (a) attaining age 60 or (b) attaining age 65 and earning at least 15 Years of Service.

“Years of Service” means the total number of months from the Participant’s date of hire by the Company or the Affiliates to the date of termination of employment divided by 12.

“Voluntary Termination with Cause” occurs upon a Participant’s separation from service of his own volition and one or more of the following conditions occurs without the Participant’s consent on or after a Change of Control:

(a) There is a material diminution in the Participant’s base compensation, compared to his rate of base compensation on the date of the Change of Control.

(b) There is a material diminution in the Participant’s authority, duties, or responsibilities.

(c) There is a material diminution in the authority, duties, or responsibilities of the Participant’s supervisor, such as a requirement that the Participant (or his supervisor) report to a corporate officer or employee instead of reporting directly to the board of directors.

(d) There is a material diminution in the budget over which the Participant retains authority.

(e) There is a material change in the geographic location at which the Participant must perform his service, including, for example the assignment of the Participant to a regular workplace that is more than 50 miles from his regular workplace on the date of the Change of Control.

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The Participant must notify the Company of the existence of one or more adverse conditions specified in clauses (a) through (e) above within 90 days of the initial existence of the adverse condition. The notice must be provided in writing to Apache Corporation’s Senior Vice President, Human Resources, or his or her delegate. The notice may be provided by personal delivery or it may be sent by email, inter-office mail, regular mail (whether or not certified), fax, or any similar method. Apache Corporation’s Senior Vice President, Human Resources, or his or her delegate shall acknowledge receipt of the notice within 5 business days; the acknowledgement shall be sent to the Participant by certified mail. Notwithstanding the foregoing provisions of this definition, if the Company remedies the adverse condition within 30 days of being notified of the adverse condition, no Voluntary Termination with Cause shall occur.

Terms

1. Grant of the Option.

(a)Subject to the provisions of this Agreement and the provisions of the Apache Corporation 2016 Omnibus Compensation Plan (the “Plan”), the Company hereby grants to the Participant, pursuant to the Plan, the right and option (the “Option”) to purchase all or any part of the number of shares of $0.625 par value common stock of the Company (“Shares”) set forth in the Grant Notice at the Option Price per Share and on the other terms as set forth in the Grant Notice.

(b)The Option is intended to be a Non-Qualified Stock Option.

2. Exercisability of the Option.

The Option shall vest and become exercisable in accordance with the exercisability schedule and other terms set forth in the Grant Notice. The Option shall terminate on the Expiration Date (the “Expiration Date”) set forth in the Grant Notice, subject to earlier termination as set forth in the Plan and this Agreement.

3. Method of Exercise of the Option.

(a)The Participant may exercise the Option, to the extent then exercisable, by contacting Fidelity, the Plan’s Administrative Agent, at www.netbenefits.com or calling 1-800-544-9354, specifying the number of Shares with respect to which such Option is being exercised.

(b)At the time the Participant exercises the Option, the Participant shall pay the Option Price of the Shares as to which the Option is being exercised to the Company, subject to such terms, conditions and limitations as the Committee may prescribe: (i) in cash, including the wire transfer of funds in U.S. dollars to Fidelity; (ii) by personal, certified, or cashier’s check payable in U.S. dollars sent or delivered to Fidelity; (iii) by delivery to Fidelity of certificates representing a number of Shares then owned by the Participant having an aggregate Fair Market Value at the Exercise Date equal to the aggregate such Option Price; (iv) by certification or attestation to Fidelity of the Participant's ownership as of the Exercise Date of a number of Shares having an aggregate Fair Market Value at the Exercise Date not greater than the aggregate Option Price; (v) by delivery to Fidelity of a properly executed written notice of exercise together with irrevocable instructions to a broker to promptly deliver to the Company, by wire transfer or check as provided in clause (i) or (ii) of this Section 3(b), the amount of the proceeds of the sale of all or a portion of the Shares as to which the Option is so exercised or of a loan from the broker to the Participant necessary to pay the aggregate such Option Price; or (vi) by a combination of the consideration provided for in the foregoing clauses (i), (ii), (iii), (iv), and (v).

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(c)The Company’s obligation to deliver the Shares to which the Participant is entitled upon exercise of the Option is conditioned on payment in full to the Company of the aggregate Option Price of those Shares and the required tax withholding related to such exercise.

4.Termination.

The Option shall terminate upon termination of the Participant’s employment with the Company and the Affiliates for any reason, and no Shares may thereafter be purchased under the Option except as provided below. Notwithstanding anything contained in this Agreement, the Option shall not be exercised after the Expiration Date.

(a)Termination by Company or Affiliate without Cause or by Participant. If such termination of the Participant’s employment is by the Company or an Affiliate without Cause or by the Participant other than under circumstances described in paragraph (b), (c), (d), or (e) of this Section 4, the Option, to the extent exercisable as of the date of such termination, shall thereafter be exercisable for a period of three months from the date of such termination.

(b)Death and Disability. If such termination of the Participant’s employment is due to the Participant’s death or Disability, the Option, and 100% of the Shares subject to the Option, shall thereafter be exercisable until the earlier to occur of (1) the first anniversary of the date of such termination or (2) the Expiration Date.

(c)Retirement. If the Participant leaves the employment of the Company and the Affiliates by reason of Retirement: (i) after attaining age 60, any Options granted to the Participant pursuant to the Grant Notice, to the extent vested and exercisable at such retirement date, shall thereafter be exercisable for all or any portion of the full number of Shares available for purchase under the Option until the earlier to occur of (A) the third anniversary of the date of such retirement or (B) the Expiration Date and (ii) after attaining age 65 and earning at least 15 Years of Service, any Options granted to the Participant pursuant to the Grant Notice (A) not previously vested shall continue to vest following the Participant’s termination of employment by reason of Retirement as if the Participant remained in the employ of the Company or the Affiliate and (B) to the extent vested and exercisable on or after such retirement date, shall thereafter be exercisable for all or any portion of the full number of Shares available for purchase under the Option until the Expiration Date of such Option; provided, in each case, that such Participant shall be entitled to continue exercising or continue vesting only if such Participant satisfies the Retirement conditions set forth in section 5 below (except in the case of death).

(d)Termination for Cause. If the Participant’s employment is terminated by the Company or an Affiliate for Cause, as defined in Section 11.2 of the Plan, then the portion of the Option that has not been exercised shall immediately terminate.

(e)Change of Control. In the event of a Participant’s Involuntary Termination or Voluntary Termination with Cause occurring on or after a Change of Control of the Company which occurs during the Vesting Period (or during the continued vesting period, if any, under section 4(c) above), the Participant shall become 100% fully vested in the unvested Options granted to the Participant pursuant to the Grant Notice as of the date of his Involuntary Termination or Voluntary Termination with Cause (or if accelerated vesting is due to the application of the continued vesting period under section 4(c) above, the date of the Change of Control), and all such newly vested Options shall thereafter be fully exercisable as of such date.

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5.Conditions to Post-Retirement Exercise or Vesting.

(a)If the Participant has attained age 60 and such Participant terminates employment with the Company and the Affiliates by reason of Retirement, it is agreed by the Company and the Participant that any Options granted to the Participant pursuant to the Grant Notice, to the extent vested and exercisable at such retirement date, shall thereafter be exercisable for all or any portion of the full number of Shares available for purchase under the Option until the earlier to occur of (1) the third anniversary of the date of such retirement or (2) the Expiration Date (the “Additional Period”). In consideration for the foregoing, it is agreed by the Company and the Participant that Participant shall, during such Additional Period:

(i)refrain from becoming employed by, or consulting with, or becoming substantially involved in the business of, any business that competes with the Company or its Affiliate in the business of exploration or production of oil or natural gas within the geographic area in which the Participant is working or has worked for the Company or its Affiliate, and/or for which the Participant is or was responsible, at the time of termination of employment or the immediately preceding three-year period (a “Competitive Business”); provided, that the Participant may purchase and hold for investment purposes less than five percent (5%) of the shares of any Competitive Business whose shares are regularly traded on a national securities exchange or inter-dealer quotation system, and provided further, that the Participant may provide services solely as a director of any Competitive Business whose shares are regularly traded on a national securities exchange or inter-dealer quotation system if, during the Additional Period, (i) the Participant only attends board and board committee meetings, votes on recommendations of management, and discharges his/her fiduciary obligations under the law and (ii) the Participant is not involved in, and does not advise or consult on, the marketing, government relations, customer relations, or the day-to-day management, supervision, or operations of such Competitive Business; and

(ii)refrain from making, or causing or assisting any other person to make, any oral or written communication to any third party about the Company, any Affiliate and/or any of the employees, officers, or directors of the Company or any Affiliate which impugns or attacks, or is otherwise critical of, the reputation, business, or character of such entity or person; or that discloses private or confidential information about their business affairs; or that constitutes an intrusion into their seclusion or private lives; or that gives rise to unreasonable publicity about their private lives; or that places them in a false light before the public; or that constitutes a misappropriation of their name or likeness.

(b)If the Participant has attained age 65 and has completed at least 15 Years of Service and such Participant terminates employment with the Company and the Affiliates by reason of Retirement, it is agreed by the Company and the Participant that

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(i)subject to the provisions of this section 5(b)(i) and sections 5(b)(ii) and 5(b)(iii), (A) such Participant shall continue to vest in the unvested Options following the date of his or her termination by reason of Retirement as if the Participant continued in employment provided that the Grant Date of the unvested Options is at least three (3) months prior to such termination date and the Participant has provided not less than three (3) months’ advance written notice prior to such termination date to Apache Corporation’s Senior Vice President, Human Resources, or his or her delegate, and to his or her direct manager, regarding the Participant's intent to terminate employment for reason of Retirement and (B) to the extent vested and exercisable on or after the date of his or her termination by reason of Retirement, such Participant may exercise Options for all or any portion of the full number of Shares available for purchase under the Option until the Expiration Date of such Option; provided, however, a Participant who is at least age 65 and has completed at least 15 Years of Service need not provide such three (3) months’ advance written notice of his or her intent to terminate employment by reason of Retirement if the Company elects to require such Participant to, or (as part of a reduction in force or otherwise in writing in exchange for a written release) offers such Participant the opportunity to, terminate employment with the Company or an Affiliate by reason of Retirement; and it is further agreed that

(ii)in consideration for the continued vesting and exercise treatment afforded to the Participant under section 5(b)(i), Participant shall, during the continuing Vesting Period after Retirement (the “Continued Vesting Period”), refrain from becoming employed by, or consulting with, or becoming substantially involved in the business of, any business that competes with the Company or its Affiliate in the business of exploration or production of oil or natural gas within the geographic area in which the Participant is working or has worked for the Company or its Affiliate, and/or for which the Participant is or was responsible, at the time of termination of employment or the immediately preceding three-year period (a “Competitive Business”); provided, that the Participant may purchase and hold for investment purposes less than five percent (5%) of the shares of any Competitive Business whose shares are regularly traded on a national securities exchange or inter-dealer quotation system, and provided further, that the Participant may provide services solely as a director of any Competitive Business whose shares are regularly traded on a national securities exchange or inter-dealer quotation system if, during the Continued Vesting Period, (i) the Participant only attends board and board committee meetings, votes on recommendations of management, and discharges his/her fiduciary obligations under the law and (ii) the Participant is not involved in, and does not advise or consult on, the marketing, government relations, customer relations, or the day-to-day management, supervision, or operations of such Competitive Business; and it is further agreed that

(iii)in consideration for the continued vesting and exercise treatment afforded to the Participant under section 5(b)(i), Participant shall, during the Continued Vesting Period, refrain from making, or causing or assisting any other person to make, any oral or written communication to any third party about the Company, any Affiliate and/or any of the employees, officers, or directors of the Company or any Affiliate which impugns or attacks, or is otherwise critical of, the reputation, business, or character of such entity or person; or that discloses private or confidential information about their business affairs; or that constitutes an intrusion into their seclusion or private lives; or that gives rise to unreasonable publicity about their private lives; or that places them in a false light before the public; or that constitutes a misappropriation of their name or likeness.

Notwithstanding the foregoing provisions of this section 5 of the Agreement, in the event that the Participant fails to satisfy any of the conditions set forth in sections 5(a) and (b) above, the Participant shall not be entitled to exercise or vest in any unexercised or unvested Options after the date of Retirement and the unexercised or unvested Options subject to this Agreement shall be forfeited.

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6.Prohibited Activity.

In consideration for this Grant and except as permitted under sections 5(a)(i) and 5(b)(ii) above, the Participant agrees not to engage in any “Prohibited Activity” while employed by the Company or an Affiliate or within three years after the date of the Participant’s termination of employment.  A “Prohibited Activity” will be deemed to have occurred, as determined by the Committee in its sole and absolute discretion, if the Participant (i) divulges any non-public, confidential or proprietary information of the Company or an Affiliate, but excluding information that (a) becomes generally available to the public other than as a result of the Participant’s public use, disclosure, or fault or (b) becomes available to the Participant on a non-confidential basis after the Participant’s employment termination date from a source other than the Company or an Affiliate prior to the public use or disclosure by the Participant, provided that such source is not bound by a confidentiality agreement or otherwise prohibited from transmitting the information by contractual, legal, or fiduciary obligation; (ii) directly or indirectly, consults with or becomes affiliated with, participate or engage in, or becomes employed by any business that is competitive with the Company or an Affiliate, wherever from time to time conducted throughout the world, including situations where the Participant solicits or participates in or assists in any way in the solicitation or recruitment, directly or indirectly, of any employees of the Company or an Affiliate; or (iii) engages in publishing any oral or written statements about the Company, and/or any of its Affiliates, directors, officers, or employees that are disparaging, slanderous, libelous, or defamatory; or that disclose private or confidential information about their business affairs; or that constitute an intrusion into their seclusion or private lives; or that give rise to unreasonable publicity about their private lives; or that place them in a false light before the public; or that constitute a misappropriation of their name or likeness.

7. Non-Transferability of the Option.

The Option shall not be transferable otherwise than by testamentary will or the laws of descent and distribution, or in accordance with a valid beneficiary designation on a form approved by the Committee, and is exercisable, during the lifetime of the Optionee, only by him, subject to the conditions and exceptions set forth in Section 15.2 of the Plan.

8. Taxes and Withholdings.

At the time of receipt of Shares upon the exercise of all or any part of the Option, the Participant shall pay to the Company in cash (or make other arrangements, in accordance with Section 12 of the Plan, for the satisfaction of) any taxes of any kind and social security payments due or potentially payable or required to be withheld with respect to such Shares; provided, however, that pursuant to any procedures, and subject to any limitations as the Committee may prescribe and subject to applicable law, the Participant may elect to satisfy, in whole or in part, such withholding obligations by (a) directing Fidelity, as the Plan’s Administrative Agent, to withhold Shares otherwise issuable to the Participant upon exercise of the Option; (b) certification or attestation to Fidelity of the Participant’s ownership, as of the Exercise Date, of a number of Shares having an aggregate Fair Market Value as of the Exercise Date not greater than such tax and other obligations; and/or (c) delivery to Fidelity of a number of Shares then owned by the Participant having an aggregate Fair Market Value as of the Exercise Date not greater than such tax and other obligations. Any such election made by the Participant must be (i) made on or prior to the applicable Exercise Date and (ii) irrevocable, made in writing, signed by the Participant, and shall be subject to any restrictions or limitations that the Committee, in its sole discretion, deems appropriate.

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9. No Rights as a Shareholder.

Neither the Participant nor any other person shall become the beneficial owner of the Shares subject to the Option, nor have any rights to dividends or other rights as a shareholder with respect to any such Shares, until the Participant has actually received such Shares following the exercise of the Option in accordance with the terms of the Plan and this Agreement.

10. No Right to Continued Employment.

Neither the Option nor any terms contained in this Agreement shall confer upon the Participant any express or implied right to be retained in the employment or service of the Company or any Affiliate for any period, nor restrict in any way the right of the Company or any Affiliate, which right is hereby expressly reserved, to terminate the Participant’s employment or service at any time for any reason. The Participant acknowledges and agrees that any right to exercise the Option is earned only by continuing as an employee of the Company or an Affiliate at the will of the Company or such Affiliate, or satisfaction of any other applicable terms and conditions contained in the Plan and this Agreement, and not through the act of being hired, being granted the Option or acquiring Shares hereunder.

11. The Plan.

In consideration for this Grant, the Participant agrees to comply with the terms of the Plan and this Agreement. Unless defined herein, capitalized terms are used herein as defined in the Plan. In the event of any conflict between the provisions of the Plan and this Agreement, the provisions of the Plan shall control, and this Agreement shall be deemed to be modified accordingly. This Agreement is subject to all the terms, provisions and conditions of the Plan, which are incorporated herein by reference, and to such regulations as may from time to time be adopted by the Committee. The Plan and the prospectus describing the Plan can be found on the Company’s HR intranet and the Fidelity website (www.netbenefits.com). A paper copy of the Plan and the prospectus shall be provided to the Participant upon the Participant’s written request to the Company at 2000 Post Oak Blvd., Suite 100, Houston, Texas 77056-4400, Attention: Corporate Secretary.

12. Compliance with Laws and Regulations.

(a)The Option and the obligation of the Company to sell and deliver Shares hereunder shall be subject in all respects to (i) all applicable Federal and state laws, rules and regulations and (ii) any registration, qualification, approvals, or other requirements imposed by any government or regulatory agency or body which the Committee shall, in its discretion, determine to be necessary or applicable. Moreover, the Option may not be exercised if its exercise, or the receipt of Shares pursuant thereto, would be contrary to applicable law. If at any time the Company determines, in its discretion, that the listing, registration, or qualification of Shares upon any national securities exchange or under any state or Federal law, or the consent or approval of any governmental regulatory body, is necessary or desirable, the Company shall not be required to deliver any certificates for Shares to the Participant or any other person pursuant to this Agreement unless and until such listing, registration, qualification, consent, or approval has been effected or obtained, or otherwise provided for, free of any conditions not acceptable to the Company.

(b)It is intended that the issuance of the Shares received upon the exercise of the Option shall have been registered under the Securities Act. If the Participant is an “affiliate” of the Company, as that term is defined in Rule 144 under the Securities Act (“Rule 144”), the Participant may not sell the Shares received except in compliance with Rule 144. Certificates representing Shares issued to an “affiliate”

9

of the Company may bear a legend setting forth such restrictions on the disposition or transfer of the Shares as the Company deems appropriate to comply with Federal and state securities laws.

(c)If at the time of exercise of all or part of the Option, a registration statement with respect to the issuance of the Shares is not effective under the Securities Act, and/or there is no current prospectus in effect under the Securities Act with respect to the Shares, the Participant shall execute, prior to the delivery of any Shares to the Participant by the Company pursuant to this Agreement, an agreement (in such form as the Company may specify) in which the Participant represents and warrants that the Participant is purchasing or acquiring the shares acquired under this Agreement for the Participant's own account, for investment only and not with a view to the resale or distribution thereof, and represents and agrees that any subsequent offer for sale or distribution of any kind of such Shares shall be made only pursuant to either (i) a registration statement on an appropriate form under the Securities Act, which registration statement has become effective and is current with regard to the Shares being offered or sold, or (ii) a specific exemption from the registration requirements of the Securities Act, but in claiming such exemption the Participant shall, prior to any offer for sale of such Shares, obtain a prior favorable written opinion, in form and substance satisfactory to the Company, from counsel for or approved by the Company, as to the applicability of such exemption thereto.

13. Notices.

Except as otherwise provided in this Agreement, all notices by the Participant or the Participant’s assignees shall be addressed to the Administrative Agent, Fidelity, through the Participant’s account at www.netbenefits.com, or such other address as the Company may from time to time specify. All notices to the Participant shall be addressed to the Participant at the Participant’s address in the Company's records.

14. Other Plans.

The Participant acknowledges that any income derived from the exercise of the Option shall not affect the Participant’s participation in, or benefits under, any other benefit plan or other contract or arrangement maintained by the Company or any Affiliate.

15.Terms of Employment.

The Plan is a discretionary plan. The Participant hereby acknowledges that neither the Plan nor this Agreement forms part of his terms of employment and nothing in the Plan may be construed as imposing on the Company or any Affiliate a contractual obligation to offer participation in the Plan to any employee of the Company or any Affiliate. The Company or any Affiliate is under no obligation to grant further Shares to any Participant under the Plan. The Participant hereby acknowledges that if he ceases to be an employee of the Company or any Affiliate for any reason or no reason, he shall not be entitled by way of compensation for loss of office or otherwise howsoever to any sum or other benefit to compensate him for the loss of any rights under this Agreement or the Plan.

10

16.Data Protection.

By accepting this Agreement (whether by electronic means or otherwise), the Participant hereby consents to the holding and processing of personal data provided by him to the Company for all purposes necessary for the operation of the Plan. These include, but are not limited to:

(a)administering and maintaining Participant records;

(b)providing information to any registrars, brokers or third party administrators of the Plan; and

(c)providing information to future purchasers of the Company or the business in which the Participant works.

17.Severability.

If any provision of this Agreement is held invalid or unenforceable, the remainder of this Agreement shall nevertheless remain in full force and effect, and if any provision is held invalid or unenforceable with respect to particular circumstances, it shall nevertheless remain in full force and effect in all other circumstances, to the fullest extent permitted by law.

*****

11

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)	2016			2015*			2014*			2013*		2012*
EARNINGS
Pretax income (loss) from continuing operations	$	(1,682	)	$	(12,169	)	$	(6,830	)	$	947	$	2,712
Add:Fixed charges excluding capitalized interest	470			540			466			538		525
Adjusted Earnings	$	(1,212	)	$	(11,629	)	$	(6,364	)	$	1,485	$	3,237
FIXED CHARGES AND PREFERRED STOCK DIVIDENDS
Interest expense including capitalized interest (1)	$	464		$	486		$	499		$	560	$	500
Amortization of debt expense	8			11			6			8		7
Interest component of lease rental expenditures (2)	47			57			45			69		62
Fixed charges	519			554			550			637		569
Preferred stock dividend requirements (3)	—			—			—			6,526		368
Noncontrolling interest	132			(315		)	341			56		—
Combined Fixed Charges and Preferred Stock Dividends (1)	$	651		$	239		$	891		$	7,219	$	937
Ratio of Earnings to Fixed Charges (4)	—			—			—			2.33		5.69
Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends (5)(6)	—			—			—			—		3.45

*Financial information for all prior year periods has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1 to consolidated financial statements.

(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, which is calculated using the effective tax rate, that would be required to cover its preferred stock dividends.

(4) The Company’s 2016, 2015, and 2014 earnings are inadequate to cover fixed charges, with a deficit of $1.7 billion, $12.2 billion, and $6.9 billion, respectively.

(5) The Company’s 2016, 2015, and 2014 earnings are inadequate to cover fixed charges and noncontrolling interest, with a deficit of $1.9 billion, $11.9 billion, and $7.3 billion, respectively.

(6) The Company's 2013 earnings are inadequate to cover fixed charges, preferred stock dividend requirements, and noncontrolling interest, with a deficit of $5.7 billion.

EX-21.1

	Exhibit 21.1
Apache Corporation (a Delaware corporation)
Listing of Subsidiaries as of December 31, 2016
Exact Name of Subsidiary and Name	Jurisdiction of
under which Subsidiary does Business	Incorporation or Organization

Alta Vista Oil Corporation	Delaware
Apache Alaska Corporation	Delaware
Apache Corporation (New Jersey)	New Jersey
Apache Crude Oil Marketing, Inc.	Delaware
Apache Deepwater LLC	Delaware
Apache Fertilizer Holdings II Corporation LDC	Cayman Islands
Apache Finance Louisiana Corporation	Delaware
Apache Foundation	Minnesota
Apache Gathering Company	Delaware
Apache Holdings, Inc.	Delaware
Apache International Employment Inc.	Delaware
Apache Louisiana Holdings LLC	Delaware
Apache Louisiana Minerals LLC	Delaware
Apache Marketing, Inc.	Delaware
Apache Midstream LLC	Delaware
Alpine High Gathering LLC (formerly Alpine Gathering LLC)	Delaware
Alpine High Pipeline LLC	Delaware
Alpine High Processing LLC (formerly Alpine Processing LLC)	Delaware
Apache North America LLC	Delaware
Apache Finance Australia Pty Limited	Australian Capital Territory
Apache Finance Egypt I S.a.r.l.	Luxembourg
Apache Finance Egypt II S.a.r.l.	Luxembourg
Apache Luxembourg Holdings I S.a.r.l.	Luxembourg
Apache Luxembourg Holdings II S.a.r.l.	Luxembourg
Apache Luxembourg Holdings III LDC	Cayman Islands
Apache Luxembourg Holdings VI LDC	Cayman Islands
Apache Luxembourg Holdings IV S.a. r.l.	Luxembourg
Apache Oil Corporation	Texas
Apache Overseas LLC	Delaware
Apache Asia Holdings Corporation LDC	Cayman Islands
Apache Asia Pacific Corporation LDC	Cayman Islands
Apache East Ras Budran Corporation LDC	Cayman Islands
Apache Egypt Investment Corporation LDC	Cayman Islands
Apache Egypt Holdings I Corporation LDC	Cayman Islands
Apache Egypt Holdings IV Corporation LDC	Cayman Islands
Apache Natural Gas Transportation Fuels LLC	Delaware
Apache Egypt Holdings III Corporation LDC	Cayman Islands
Apache Egypt GP Corporation LDC	Cayman Islands
Apache Egypt Holdings II Corporation LDC	Cayman Islands
Apache Abu Gharadig Corporation LDC	Cayman Islands
Apache East Bahariya Corporation LDC	Cayman Islands
Apache El Diyur Corporation LDC	Cayman Islands
Apache Faiyum Corporation LDC	Cayman Islands

	Exhibit 21.1
Apache Corporation (a Delaware corporation)
Listing of Subsidiaries as of December 31, 2016
Exact Name of Subsidiary and Name	Jurisdiction of
under which Subsidiary does Business	Incorporation or Organization

Apache Khalda Corporation LDC	Cayman Islands
Apache Egypt Midstream Holdings I LDC	Cayman Islands
Apache Khalda II Corporation LDC	Cayman Islands
Apache Matruh Corporation LDC	Cayman Islands
Apache Mediterranean Corporation LDC	Cayman Islands
Apache North Bahariya Corporation LDC	Cayman Islands
Apache North El Diyur Corporation LDC	Cayman Islands
Apache North Tarek Corporation LDC	Cayman Islands
Apache Qarun Corporation LDC	Cayman Islands
Apache Qarun Exploration Company LDC	Cayman Islands
Apache Shushan Corporation LDC	Cayman Islands
Apache South Umbarka Corporation LDC	Cayman Islands
Apache Umbarka Corporation LDC	Cayman Islands
Apache West Kalabsha Corporation LDC	Cayman Islands
Apache West Kanayis Corporation LDC	Cayman Islands
Apache UK Corporation LDC	Cayman Islands
Apache International Finance III S.a.r.l.	Luxembourg
Apache North Sea Limited	England and Wales
Apache North Sea Production Limited	England and Wales
Apache UK Investment Limited	England and Wales
Apache Beryl I Limited	Cayman Islands
Apache Beryl III Limited	England and Wales
Beryl North Sea II Limited	Cayman Islands
SAGE North Sea Limited	Cayman Islands
Apache EMEA Corporation LDC	Cayman Islands
Apache Exploration LDC	Cayman Islands
Apache Fertilizer Holdings Corporation LDC	Cayman Islands
Apache International Holdings S.a.r.l.	Luxembourg
Apache International Finance S.a.r.l.	Luxembourg
Apache International Finance II S.a.r.l.	Luxembourg
Apache Finance Pty Limited	Australian Capital Territory
Apache Ravensworth Corporation LDC	Cayman Islands
Apache Latin America II Corporation LDC	Cayman Islands
Apache Madera Corporation LDC	Cayman Islands
Apache Netherlands Investment B.V.	The Netherlands
Apache Suriname Corporation LDC	Cayman Islands
Apache Netherlands Investment II B.V.	The Netherlands
Apache Suriname 58 Corporation LDC	Cayman Islands
Apache Overseas Holdings LLC	Delaware
Apache Switzerland Holdings AG	Switzerland
Apache Kenya Holdings LLC	Delaware
Apache Kenya Limited	Kenya
Apache Overseas Holdings II, Inc.	Delaware

	Exhibit 21.1
Apache Corporation (a Delaware corporation)
Listing of Subsidiaries as of December 31, 2016
Exact Name of Subsidiary and Name	Jurisdiction of
under which Subsidiary does Business	Incorporation or Organization

Apache Permian Basin Investment Corporation	Delaware
Apache Permian Basin Corporation	Delaware
Apache Permian Exploration and Production LLC	Delaware
LeaCo New Mexico Exploration and Production LLC	Delaware
Permian Basin Joint Venture LLC (95%)	Delaware
ZPZ Delaware I LLC	Delaware
Apache Shady Lane Ranch Inc.	Delaware
Apache Shelf Exploration LLC	Delaware
Apache Shelf, Inc.	Delaware
Apache Texas Property Holding Company LLC	Delaware
Apache UK Limited	England and Wales
Apache Well Containment LLC	Delaware
Apache Western Exploration LLC	Delaware
BLPL Holdings LLC	Delaware
Clear Creek Hunting Preserve, Inc.	Wyoming
Cordillera Energy Partners III, LLC	Colorado
Cottonwood Aviation, Inc.	Delaware
CV Energy Corporation	Delaware
DEK Energy Company	Delaware
Apache Canada Ltd.	Alberta, Canada
Apache Canada Chile Holdings ULC	Alberta, Canada
Apache Chile Energìa SPA	Chile
Apache Austria Investment LLC	Delaware
Apache Canada Properties Ltd.	Alberta, Canada
Apache FC Capital Canada Inc.	Alberta, Canada
Apache Finance Canada Corporation	Nova Scotia, Canada
Apache Canada Management Ltd	Alberta, Canada
Apache Canada Holdings Ltd	Alberta, Canada
Apache Canada Management II Ltd	Alberta, Canada
Apache Finance Canada III ULC	Alberta, Canada
Apache Finance Canada IV ULC	Alberta, Canada
Apache Finance Canada II Corporation	Nova Scotia, Canada
Edge Petroleum Exploration Company	Delaware
Granite Operating Company	Texas
Phoenix Exploration Resources, Ltd.	Delaware
Texas International Company	Delaware
Texas and New Mexico Exploration LLC	Delaware
ZPZ Acquisitions, Inc.	Delaware
ZPZ Delaware II LLC	Delaware
Phoenix Exploration Louisiana C LLC (75%)	Delaware
ZPZ Delaware III LLC	Delaware

EX-23.1

Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

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

(1) Registration Statements (Form S-3 Nos. 333-57785, 333-75633, 333-32580, 333-105536, 333-155884, 333-174429, and 333-197491) 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, 333-190619, and 333-212237) of Apache Corporation;

of our reports dated February 24, 2017, with respect to the consolidated financial statements of Apache Corporation and the effectiveness of internal control over financial reporting of Apache Corporation, included in this Annual Report (Form 10-K) of Apache Corporation for the year ended December 31, 2016.

/s/ ERNST & YOUNG LLP

Houston, Texas

February 24, 2017

EX-23.2

TBPE REGISTERED ENGINEERING FIRM F-1580                        FAX (713) 651-0849

1100 LOUISIANA    SUITE 4600        HOUSTON, TEXAS 77002-5294     TELEPHONE (713) 651-9191

EXHIBIT 23.2

Consent of Ryder Scott Company, L.P.

As independent petroleum engineers, we hereby consent to the incorporation by reference in this Form 10-K of Apache Corporation to our Firm's name and our Firm's review of the proved oil and gas reserve quantities of Apache Corporation as of December 31, 2016, to the incorporation by reference of our Firm's name and review into Apache Corporation's previously filed Registration Statements on Form S-3 (Nos. 333-57785, 333-75633, 333-32580, 333-105536, 333-155884, 333-174429, and 333-197491), on Form S-4 (No. 333-107934 and 333-166964), and on Form S-8 (Nos. 33-59721, 33-63817, 333-26255, 333-32557, 333-36131, 333-31092, 333-48758, 333-97403, 333-102330, 333-103758, 333-106213, 333-125232, 333-125233, 333-135044, 333-143115, 333-170533, 333-175250, 333-178672, 333-190619, and 333-212237), and to the inclusion of our report, dated January 25, 2017, as an exhibit to this Form 10-K filed with the Securities and Exchange Commission.

/s/ Ryder Scott Company, L.P.

Ryder Scott Company, L.P.

TBPE Firm Registration No. F-1580

Houston, Texas

February 23, 2017

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

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

EX-31.1

EXHIBIT 31.1

CERTIFICATIONS

I, John J. Christmann IV, certify that:

1.	I have reviewed this annual report on Form 10-K of Apache Corporation;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
	(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
	(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
	(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
	(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ John J. Christmann IV

John J. Christmann IV

Chief Executive Officer and President

(principal executive officer)

Date: February 24, 2017

EX-31.2

EXHIBIT 31.2

CERTIFICATIONS

I, Stephen J. Riney, certify that:

1.	I have reviewed this annual report on Form 10-K of Apache Corporation;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
	(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
	(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	(d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
	(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
	(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ Stephen J. Riney

Stephen J. Riney

Executive Vice President and Chief Financial Officer

(principal financial officer)

Date: February 24, 2017

EX-32.1

EXHIBIT 32.1

APACHE CORPORATION

Certification of Principal Executive Officer

and Principal Financial Officer

I, John J. Christmann IV, certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to my knowledge, the annual report on Form 10-K of Apache Corporation for the period ending December 31, 2016, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. §78m or §78o (d)) and that information contained in such report fairly represents, in all material respects, the financial condition and results of operations of Apache Corporation.

/s/ John J. Christmann IV
By:	John J. Christmann IV
Title:	Chief Executive Officer and President
	(principal executive officer)

Date: February 24, 2017

I, Stephen J. Riney, certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to my knowledge, the annual report on Form 10-K of Apache Corporation for the period ending December 31, 2016, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. §78m or §78o (d)) and that information contained in such report fairly represents, in all material respects, the financial condition and results of operations of Apache Corporation.

/s/ Stephen J. Riney
By:	Stephen J. Riney
Title:	Executive Vice President and Chief Financial Officer
	(principal financial officer)

Date: February 24, 2017

EX-99.1

APACHE CORPORATION

Estimated

Future Reserves

Attributable to Certain

Leasehold and Royalty Interests

and

Derived Through Certain Production Sharing Contracts

SEC Parameters

As of

December 31, 2016

/s/ Ali A. Porbandarwala

Ali A. Porbandarwala, P.E.

TBPE License No. 107652

Vice President

[SEAL]

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

January 25, 2017

Apache Corporation

2000 Post Oak Boulevard, Suite 100

Houston, Texas 77056-4400

Gentlemen:

At the request of Apache Corporation (Apache), Ryder Scott Company, L.P. (Ryder Scott) has conducted a reserves audit of the estimates of the proved reserves as of December 31, 2016 prepared by Apache’s engineering and geological staff based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our third party reserves audit, completed on January 25, 2017 and presented herein, was prepared for public disclosure by Apache in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations. The estimated reserves shown herein represent Apache’s estimated net reserves attributable to the leasehold and royalty interestsand derived through certain production sharing contracts in certain properties owned by Apache and the portion of those reserves reviewed by Ryder Scott, as of December 31, 2016. The properties reviewed by Ryder Scott incorporate Apache’s reserve determinations and are attributable to the interests of Apache Corporation (U.S.A), Apache Canada Limited (Canada), Apache Egypt Companies (Egypt), and Apache North Sea Limited (United Kingdom).

The properties reviewed by Ryder Scott account for a portion of Apache’s total net proved reserves as of December 31, 2016. Based on the estimates of total net proved reserves prepared by Apache, the reserves audit conducted by Ryder Scott addresses 86.4 percent of the total proved developed net liquid hydrocarbon reserves, 90.9 percent of the total proved developed net gas reserves, 47.9 percent of the total proved undeveloped net liquid hydrocarbon reserves, and 29.6 percent of the total proved undeveloped net gas reserves of Apache.

The wells or locations for which estimates of reserves were reviewed by Ryder Scott were selected by Apache. Apache informed Ryder Scott that the selected reserves for each country included at least 86.8 percent or more of the total discounted future net income at 10 percent attributable to the respective country’s total interests of Apache (coverage) based on SEC hydrocarbon price parameters as of December 31, 2016. Total coverage of world-wide reserves is 92.0 percent of the total discounted future net income at 10 percent.

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

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

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

Apache Corporation – Total All Regions

January 25, 2017

Page 2

Based on our review, including the data, technical processes and interpretations presented by Apache, it is our opinion that the overall procedures and methodologies utilized by Apache in preparing their estimates of the proved reserves as of December 31, 2016 comply with the current SEC regulations and that the overall proved reservesfor the reviewed properties as estimated by Apache are, in the aggregate, reasonable within the established audit tolerance guidelines of 10 percent as set forth in the SPE auditing standards.

The estimated reserves presented in this report are related to hydrocarbon prices. Apache has informed us that in the preparation of their reserve and income projections, as of December 31, 2016, they used average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered may differ significantly from the estimated quantities presented in this report. The net reserves as estimated by Apache attributable to Apache's interest and entitlement in properties that we reviewed and the reserves of properties that we did not review are summarized as follows:

SEC PARAMETERS

Estimated Net Proved Reserves

Certain Leasehold and Royalty Interests and

Derived Through Certain Production Sharing Contracts of

Apache Corporation (Total All Regions)

As of December 31, 2016

	% Crude Oil & Condensate Reserves Reviewed	% Natural Gas Liquids Reserves Reviewed	% Gas Reserves Reviewed	Reviewed by Ryder Scott			Not Reviewed			Total
				Crude Oil & Condensate MBarrels	Natural Gas Liquids MBarrels	Sales Gas MMCF	Crude Oil & Condensate MBarrels	Natural Gas Liquids MBarrels	Sales Gas MMCF	Crude Oil & Condensate MBarrels	Natural Gas Liquids MBarrels	Sales Gas MMCF
Developed	84.3	93.5	90.9	491,115	160,644	2,288,286	91,202	11,238	228,324	582,317	171,882	2,516,610
Undeveloped	48.7	45.7	29.6	29,192	9,394	101,305	30,773	11,167	241,233	59,965	20,561	342,538
Total Proved	81.0	88.4	83.6	520,307	170,038	2,389,591	121,975	22,405	469,557	642,282	192,443	2,859,148

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SEC PARAMETERS

Estimated Net Proved Reserves

Certain Leasehold and Royalty Interests and

Derived Through Certain Production Sharing Contracts of

Apache Corporation (Summary by Region)

As of December 31, 2016

	% Crude Oil & Condensate Reserves Reviewed	% Natural Gas Liquids Reserves Reviewed	% Gas Reserves Reviewed	Reviewed by Ryder Scott			Not Reviewed			Total
				Crude Oil & Condensate MBarrels	Natural Gas Liquids MBarrels	Sales Gas MMCF	Crude Oil & Condensate MBarrels	Natural Gas Liquids MBarrels	Sales Gas MMCF	Crude Oil & Condensate MBarrels	Natural Gas Liquids MBarrels	Sales Gas MMCF
USA
Developed	79.9	94.1	89.5	240,294	146,046	1,074,426	60,606	9,077	125,954	300,900	155,123	1,200,380
Undeveloped	66.9	51.2	19.7	14,109	8,855	45,546	6,979	8,456	185,758	21,088	17,311	231,304
Total Proved	79.0	89.8	78.2	254,403	154,901	1,119,972	67,585	17,533	311,712	321,988	172,434	1,431,684
Canada
Developed	95.2	85.4	85.4	49,024	11,848	473,064	2,485	2,018	80,660	51,509	13,866	553,724
Undeveloped	19.5	0.6	0.0	1,540	14	0	6,366	2,459	45,312	7,906	2,473	45,312
Total Proved	85.1	72.6	79.0	50,564	11,862	473,064	8,851	4,477	125,972	59,415	16,339	599,036
Egypt
Developed	85.1	88.7	96.8	118,092	1,123	653,848	20,679	143	21,711	138,771	1,266	675,559
Undeveloped	21.0	47.3	88.3	4,246	62	37,180	15,941	69	4,928	20,187	131	42,108
Total Proved	77.0	84.8	96.3	122,338	1,185	691,028	36,620	212	26,639	158,958	1,397	717,667
United Kingdom
Developed	91.8	100.0	100.0	83,705	1,627	86,948	7,432	0	0	91,137	1,627	86,948
Undeveloped	86.2	71.7	78.0	9,297	463	18,579	1,487	183	5,234	10,784	646	23,813
Total Proved	91.2	91.9	95.3	93,002	2,090	105,527	8,919	183	5,234	101,921	2,273	110,761

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

Reserves Included in This Report

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

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

Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative

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degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At Apache’s request, this report addresses only the proved reserves attributable to the properties reviewed herein.

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

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

Audit Data, Methodology, Procedure and Assumptions

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

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than not to be achieved.” The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project

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have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserve category must meet the SEC definitions as noted above.

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

The proved reserves, prepared by Apache, for the properties that we reviewed were estimated by performance methods, the volumetric method, analogy, or a combination of methods. Approximately 90 percent of the proved producing reserves attributable to producing wells and/or reservoirs that we reviewed were estimated by performance methods or a combination of methods. These performance methods include, but may not be limited to, decline curve analysis, material balance and/or reservoir simulation which utilized extrapolations of historical production and pressure data available through November 2016, in those cases where such data were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by Apache or obtained from public data sources and were considered sufficient for the purpose thereof. The remaining 10 percent of the proved producing reserves that we reviewed were estimated by the volumetric method, analogy, or a combination of methods. These methods were used where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate.

Approximately 100 percent of the proved developed non-producing and undeveloped reserves that we reviewed were estimated by the volumetric method or analogy. The volumetric analysis utilized pertinent well and seismic data furnished to Ryder Scott by Apache for our review or which we have obtained from public data sources that were available through November 2016. The data utilized from the analogues in conjunction with well and seismic data incorporated into the volumetric analysis were considered sufficient for the purpose thereof.

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

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

The hydrocarbon prices furnished by Apache for the properties reviewed by us are based on SEC price parameters using the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-

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month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described.

The initial SEC hydrocarbon prices in effect on December 31, 2016 for the properties reviewed by us were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used by Apache for the geographic areas reviewed by us. In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements. In cases where there are numerous contracts or price references within the same geographic area, the benchmark price is represented by the unweighted arithmetic average of the initial 12-month average first-day-of-the-month benchmark prices used.

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

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

Geographic Area	Product	Price Reference	Average Benchmark Prices U.S.A.	Average Realized Prices U.S.A.
North America
United States	Oil/Condensate	WTI Cushing	$42.82/Bbl	$39.34/Bbl
	NGLs	Mt. Belvieu Non-Tet Propane	$19.87/Bbl	$11.35/Bbl
	Gas	Henry Hub	$2.48/MMBTU	$2.11/MCF
Canada	Oil/Condensate	WTI Cushing	$42.82/Bbl	$35.40/Bbl
	NGLs	WTI Cushing	$42.82/Bbl	$9.74/Bbl
	Gas	AECO	$1.64/MMBTU	$1.72/MCF
Egypt	Oil/Condensate	Brent	$42.82/Bbl	$41.68/Bbl
	NGLs	Brent	$42.82/Bbl	$27.78/Bbl
	Gas	Contracts	Contract	$2.95/MCF
United Kingdom	Oil/Condensate	Brent	$42.82/Bbl	$40.80/Bbl
	NGLs	Brent	$42.82/Bbl	$21.24/Bbl
	Gas	NBP	$4.64/MMBTU	$4.77/MCF

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

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

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

Development costs furnished by Apache are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished by Apache were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Apache. The estimated net cost of abandonment after salvage was included by Apache for properties where abandonment costs net of salvage were significant. Apache’s estimates of the net abandonment costs were accepted without independent verification.

The proved developed non-producing and undeveloped reserves for the properties reviewed by us have been incorporated herein in accordance with Apache’s plans to develop these reserves as of December 31, 2016. The implementation of Apache’s development plans as presented to us is subject to the approval process adopted by Apache’s management. As the result of our inquiries during the course of our review, Apache has informed us that the development activities for the properties reviewed by us have been subjected to and received the internal approvals required by Apache’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to Apache. Additionally, Apache has informed us that they are not aware of any legal, regulatory or political obstacles that would significantly alter their plans. While these plans could change from those under existing economic conditions as of December 31, 2016, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

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

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

Test data and other related information were used by Apache to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by Apache. Wells or

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locations that are not currently producing may start producing earlier or later than anticipated in Apache’s estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies.

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

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

The proved reserves for the properties located in Egypt are subject to the contractual fiscal terms contained in production sharing contracts. For these properties, Ryder Scott audited the gross economic inputs used by Apache in the economic models for Egypt through a comparison of Apache and Ryder Scott’s gross economic volumes. Apache’s gross economic volumes were then used as input to the economic models to generate the net interests used to determine the net reserves summarized in this report. Ryder Scott reviewed the fiscal terms of such contracts and discussed with Apache the net economic benefit attributed to such operations for the determination of the net hydrocarbon volumes and income thereof. Ryder Scott has not conducted an exhaustive audit or verification of such contractual information. Neither our review of such contractual information nor our acceptance of Apache’s representations regarding such contractual information should be construed as a legal opinion on this matter.

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

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

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

Apache has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In performing our audit of Apache’s forecast of future proved production, we have relied upon data furnished by Apache with

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

Audit Opinion

Based on our review, including the data, technical processes and interpretations presented by Apache, it is our opinion that the overall procedures and methodologies utilized by Apache in preparing their estimates of the proved reserves as of December 31, 2016 comply with the current SEC regulations and that the overall proved reservesfor the reviewed properties as estimated by Apache are, in the aggregate, reasonable within the established audit tolerance guidelines of 10 percent as set forth in the SPE auditing standards.

We were in reasonable agreement with Apache's estimates of proved reserves for the properties which we reviewed; although in certain cases there was more than an acceptable variance between Apache’s estimates and our estimates due to a difference in interpretation of data or due to our having access to data which were not available to Apache when its reserve estimates were prepared.  However not withstanding, it is our opinion that on an aggregate basis the data presented herein for the properties that we reviewed fairly reflects the estimated net reserves owned by Apache.

Other Properties

Other properties, as used herein, are those properties of Apache which we did not review. The proved net reserves attributable to the other properties account for 13.6 percent of the total proved developed net liquid hydrocarbon reserves, 9.1 percent of the total proved developed net gas reserves, 52.1 percent of the total proved undeveloped net liquid hydrocarbon reserves, and 70.4 percent of the total proved undeveloped net gas reserves based on estimates prepared by Apache as of December 31, 2016. The other properties represent 8.0 percent of the total proved discounted future net income at 10 percent based on the unescalated pricing policy of the SEC as taken from reserve and income projections prepared by Apache as of December 31, 2016.

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

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Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1937. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

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

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

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

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

Terms of Usage

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

Apache makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, Apache has certain registration statements filed with the SEC under the 1933 Securities Actinto which any subsequently filed Form 10-Kis incorporated by reference. We have consented to the incorporation by reference in the registration statements on Form S-3, Form S-4, and Form S-8 of Apache of the references to our name as well as to the references to our third party report for Apache, which appears in the December 31, 2016 annual report on Form 10-K of Apache. Our written consent for such use is included as a separate exhibit to the filings made with the SEC by Apache.

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

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

Very truly yours,

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

/s/ Ali A. Porbandarwala

Ali A. Porbandarwala, P.E.

TBPE License No. 107652

Vice President

[SEAL]

AAP (FWZ)/pl

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Mr. Ali A. Porbandarwala was the primary technical person responsible for overseeing the estimate of the reserves, future production and income prepared by Ryder Scott presented herein.

Mr. Porbandarwala, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 2008, is a Vice President responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Porbandarwala served in a number of engineering positions with ExxonMobil Corporation. For more information regarding Mr. Porbandarwala’s geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Company/Employees.

Mr. Porbandarwala earned a Bachelor of Science degree in Chemical Engineering from The University of Kansas in 2001 and a Masters in Business Administration from The University of Texas at Austin in 2007 and is a licensed Professional Engineer in the State of Texas. He is also a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers.

In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Porbandarwala fulfills. As part of his 2016 continuing education hours, Mr. Porbandarwala attended 20hours of formalized training including the 2016 RSC Reserves Conference and/or various professional society presentations specifically relating to the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register.

Based on his educational background, professional training and more than 8 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Porbandarwala has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

As Adapted From:

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

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

PREAMBLE

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

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

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

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

Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale. Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

Page 2

centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.

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

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

RESERVES (SEC DEFINITIONS)

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

Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

PROVED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:

Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

Page 3

PROVED RESERVES (SEC DEFINITIONS) CONTINUED

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From:

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

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and

PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)

Sponsored and Approved by:

SOCIETY OF PETROLEUM ENGINEERS (SPE)

WORLD PETROLEUM COUNCIL (WPC)

AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)

SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)

Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).

DEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:

Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Developed Producing (SPE-PRMS Definitions)

While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.

Developed Producing Reserves

Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate.

Improved recovery reserves are considered producing only after the improved recovery project is in operation.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

Page 2

Developed Non-Producing

Developed Non-Producing Reserves include shut-in and behind-pipe reserves.

Shut-In

Shut-in Reserves are expected to be recovered from:

(1) completion intervals which are open at the time of the estimate, but which have not started producing;

(2) wells which were shut-in for market conditions or pipeline connections; or

(3) wells not capable of production for mechanical reasons.

Behind-Pipe

Behind-pipe Reserves are expected to be recovered from zones in existing wells, which will require additional completion work or future re-completion prior to start of production.

In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

UNDEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:

Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

XML

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2016	Jan. 31, 2017	Jun. 30, 2016
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2016
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	FY
Trading Symbol	APA
Entity Registrant Name	APACHE CORP
Entity Central Index Key	0000006769
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		379,687,129
Entity Public Float			$ 21,118,858,691

XML

Statement of Consolidated Operations - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015		Dec. 31, 2014
Oil and gas production revenues:
Oil and gas production revenues	$ 5,367	$ 6,510	[1]	$ 12,795	[1]
Other	(34)	98	[1]	285	[1]
Gain (loss) on divestiture	21	281	[1],[2]	(1,608)	[1],[2]
Total revenues and other	5,354	6,889	[1]	11,472	[1]
OPERATING EXPENSES:
Lease operating expenses	1,494	1,854	[1]	2,238	[1]
Gathering and transportation	200	211	[1]	273	[1]
Taxes other than income	126	282	[1]	577	[1]
Exploration Expense	473	2,771	[1]	2,499	[1]
General and administrative	410	380	[1]	453	[1]
Oil and gas property and equipment
Depreciation, depletion, and amortization	2,618	3,300	[2]	4,526	[2]
Asset retirement obligation accretion	156	145	[1],[2]	154	[1],[2]
Impairments	1,103	9,472	[1],[2]	7,102	[1],[2]
Transaction, reorganization, and separation	39	132	[1]	67	[1]
Financing costs, net	417	511	[1]	413	[1]
Total operating expenses	7,036	19,058	[1]	18,302	[1]
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(1,682)	(12,169)	[1]	(6,830)	[1]
Current income tax provision	391	435	[1]	1,281	[1]
Deferred income tax benefit	(833)	(1,445)	[1],[2]	(1,799)	[1],[2]
Net loss from continuing operations including noncontrolling interest	(1,240)	(11,159)	[1]	(6,312)	[1]
Net income (loss) from discontinued operations, net of tax	(33)	492	[1]	(1,707)	[1]
NET LOSS INCLUDING NONCONTROLLING INTEREST	(1,273)	(10,667)	[1],[2],[3],[4]	(8,019)	[1],[2],[3],[4]
Net income (loss) attributable to noncontrolling interest	132	(315)	[1]	341	[1]
Net income (loss) attributable to common shareholders	(1,405)	(10,352)	[1]	(8,360)	[1]
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS:
Net loss from continuing operations attributable to common shareholders	(1,372)	(10,844)	[1]	(6,653)	[1]
Net income (loss) from discontinued operations	(33)	492	[1],[2]	(1,707)	[1],[2]
Net income (loss) attributable to common shareholders	$ (1,405)	$ (10,352)	[1]	$ (8,360)	[1]
BASIC AND DILUTED NET INCOME (LOSS) PER COMMON SHARE:
Basic and diluted net loss from continuing operations per share	$ (3.62)	$ (28.70)	[1]	$ (17.32)	[1]
Basic and diluted net loss from discontinued operations per share	(0.09)	1.30	[1]	(4.44)	[1]
Basic and diluted net loss per share	$ (3.71)	$ (27.40)	[1]	$ (21.76)	[1]
WEIGHTED-AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
Basic (in shares)	379	378	[1]	384	[1]
Diluted (in shares)	379	378	[1]	384	[1]
DIVIDENDS DECLARED PER COMMON SHARE	$ 1.00	$ 1.00	[1],[4]	$ 1.00	[1],[4]
Oil and gas property and equipment [Member]
Oil and gas property and equipment
Depreciation, depletion, and amortization	$ 2,460	$ 2,976	[1]	$ 4,195	[1]
Other assets [Member]
Oil and gas property and equipment
Depreciation, depletion, and amortization	158	324	[1]	331	[1]
Oil [Member]
Oil and gas production revenues:
Oil and gas production revenues	4,172	5,107	[1]	10,110	[1]
Natural Gas [Member]
Oil and gas production revenues:
Oil and gas production revenues	967	1,176	[1]	2,017	[1]
Natural Gas Liquids [Member]
Oil and gas production revenues:
Oil and gas production revenues	$ 228	$ 227	[1]	$ 668	[1]

[1] Financial information for 2015 and 2014 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

[2] Financial information for 2015 and 2014 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

[3] Financial information for 2015 and 2014 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

[4] Financial information for 2015, 2014, and 2013 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

XML

Statement of Consolidated Comprehensive Income (Loss) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	[1]	Dec. 31, 2014	[1]
Statement of Comprehensive Income [Abstract]
NET LOSS INCLUDING NONCONTROLLING INTEREST	$ (1,273)	$ (10,667)	[2],[3],[4]	$ (8,019)	[2],[3],[4]
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and postretirement benefit plan, net of tax	7	(3)	[4]	0
Commodity cash flow hedge activity, net of tax:
Change in fair value of derivative instruments	0	0		(1)
Commodity cash flow hedge activity, net of tax	7	(3)		(1)
COMPREHENSIVE LOSS INCLUDING NONCONTROLLING INTEREST	(1,266)	(10,670)		(8,020)
Comprehensive income (loss) attributable to noncontrolling interest	132	(315)		341
COMPREHENSIVE LOSS ATTRIBUTABLE TO COMMON STOCK	$ (1,398)	$ (10,355)		$ (8,361)

[1] Financial information for 2015 and 2014 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

[2] Financial information for 2015 and 2014 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

[3] Financial information for 2015 and 2014 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

[4] Financial information for 2015, 2014, and 2013 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

XML

Statement of Consolidated Cash Flows - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2016		Dec. 31, 2015		Dec. 31, 2014
CASH FLOWS FROM OPERATING ACTIVITIES:
NET LOSS INCLUDING NONCONTROLLING INTEREST		$ (1,273)		$ (10,667)	[1],[2],[3],[4]	$ (8,019)	[1],[2],[3],[4]
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Loss (income) from discontinued operations		33		(492)	[2],[3]	1,707	[2],[3]
Loss (gain) on divestitures		(21)		(281)	[2],[3]	1,608	[2],[3]
Exploratory dry hole expense and unproved leasehold impairments		353		2,595	[3]	2,294	[3]
Depreciation, depletion, and amortization		2,618		3,300	[3]	4,526	[3]
Asset retirement obligation accretion		156		145	[2],[3]	154	[2],[3]
Impairments		1,103		9,472	[2],[3]	7,102	[2],[3]
Benefit from deferred income taxes		(833)		(1,445)	[2],[3]	(1,799)	[2],[3]
Other		164		7	[3]	(231)	[3]
Changes in operating assets and liabilities:
Receivables		126		663	[3]	757	[3]
Inventories		(27)		21	[3]	(31)	[3]
Drilling advances		91		138	[3]	107	[3]
Deferred charges and other		115		(345)	[3]	(301)	[3]
Accounts payable		(63)		(489)	[3]	(216)	[3]
Accrued expenses		(9)		(156)	[3]	(572)	[3]
Deferred credits and noncurrent liabilities		(80)		88	[3]	(73)	[3]
NET CASH PROVIDED BY CONTINUING OPERATING ACTIVITIES		2,453		2,554	[3]	7,013	[3]
NET CASH PROVIDED BY (USED IN) DISCONTINUED OPERATIONS		(23)		113	[3]	944	[3]
NET CASH PROVIDED BY OPERATING ACTIVITIES		2,430		2,667	[3]	7,957	[3]
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property		(1,610)		(4,208)	[3]	(8,608)	[3]
Additions to gas gathering, transmission, and processing facilities		(158)		(233)	[3]	(881)	[3]
Leasehold and property acquisitions		(181)		(367)	[3]	(1,475)	[3]
Proceeds from sale of Kitimat LNG		0		854	[3]	0	[3]
Proceeds from sale of Yara Pilbara		0		391	[3]	0	[3]
Proceeds from sale of oil and gas properties, other		134		268	[3]	470	[3]
Other, net		155		6	[3]	(299)	[3]
NET CASH USED IN CONTINUING INVESTING ACTIVITIES		(1,660)		(3,289)	[3]	(8,171)	[3]
NET CASH PROVIDED BY (USED IN) DISCONTINUED OPERATIONS		0		4,372	[3]	(219)	[3]
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES		(1,660)		1,083	[3]	(8,390)	[3]
CASH FLOWS FROM FINANCING ACTIVITIES:
Commercial paper, credit facilities and bank notes, net		0		(1,570)	[3]	1,568	[3]
Payments on fixed rate debt		(181)		(939)	[3]	0	[3]
Distributions to noncontrolling interest		(293)		(129)	[3]	(140)	[3]
Dividends paid		(379)		(377)	[3]	(365)	[3]
Treasury stock activity, net		0		0	[3]	(1,864)	[3]
Other		(7)		53	[3]	49	[3]
NET CASH USED IN CONTINUING FINANCING ACTIVITIES		(860)		(2,962)	[3]	(752)	[3]
NET CASH USED IN DISCONTINUED OPERATIONS		0		0	[3]	(42)	[3]
NET CASH USED IN FINANCING ACTIVITIES		(860)		(2,962)	[3]	(794)	[3]
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(90)		788	[3]	(1,227)	[3]
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	[3]	1,467	[5]	679		1,906
CASH AND CASH EQUIVALENTS AT END OF PERIOD		1,377		1,467	[3],[5]	679	[3]
SUPPLEMENTARY CASH FLOW DATA:
Interest paid, net of capitalized interest		413		461	[3]	260	[3]
Income taxes paid, net of refunds		305		573	[3]	1,357	[3]
Deepwater Gulf of Mexico [Member]
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from sale of productive assets		0		0	[3]	1,360	[3]
Anadarko Basin and Southern Louisiana [Member]
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from sale of productive assets		$ 0		$ 0	[3]	$ 1,262	[3]

[1] Financial information for 2015 and 2014 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

[2] Financial information for 2015 and 2014 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

[3] Financial information for 2015 and 2014 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

[4] Financial information for 2015, 2014, and 2013 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

[5] Financial information for 2015 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

XML

Consolidated Balance Sheet - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015	[2]
CURRENT ASSETS:
Cash and cash equivalents	$ 1,377	$ 1,467	[1]
Receivables, net of allowance	1,128	1,253
Inventories	476	570
Drilling advances	81	172
Prepaid assets and other	179	290
Total current assets	3,241	3,752
Oil and gas, on the basis of successful efforts accounting:
Proved properties	42,693	41,728
Unproved properties and properties under development	1,969	2,277
Gathering, transmission, and processing facilities	976	1,052
Other	1,111	1,093
Property and equipment, gross	46,749	46,150
Less: Accumulated depreciation, depletion, and amortization	(27,882)	(25,312)
Property and equipment, net	18,867	20,838
OTHER ASSETS:
Deferred charges and other	411	910
Total assets	22,519	25,500
CURRENT LIABILITIES:
Accounts payable	585	618
Other current liabilities	1,258	1,223
Total current liabilities	1,843	1,841
Long-term debt	8,544	8,716
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes	1,710	2,529
Asset retirement obligation	2,432	2,562
Other	311	362
Total deferred credits and other noncurrent liabilities	4,453	5,453
COMMITMENTS AND CONTINGENCIES (Note 10)
EQUITY:
Common stock, $0.625 par, 860,000,000 shares authorized, 412,612,102 and 411,218,105 shares issued, respectively	258	257
Paid-in capital	12,364	12,619
Accumulated deficit	(3,385)	(1,980)
Treasury stock, at cost, 33,172,426 and 33,183,930 shares, respectively	(2,887)	(2,889)
Accumulated other comprehensive loss	(112)	(119)
APACHE SHAREHOLDERS’ EQUITY	6,238	7,888
Noncontrolling interest	1,441	1,602
TOTAL EQUITY	7,679	9,490	[3]
TOTAL LIABILITIES AND EQUITY	$ 22,519	$ 25,500

[1] Financial information for 2015 and 2014 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

[2] Financial information for 2015 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

[3] Financial information for 2015, 2014, and 2013 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

XML

Consolidated Balance Sheet (Parenthetical) - $ / shares	Dec. 31, 2016	Dec. 31, 2015	[1]
Statement of Financial Position [Abstract]
Common stock, par value	$ 0.625	$ 0.625
Common stock, shares authorized	860,000,000	860,000,000
Common stock, shares issued	412,612,102	411,218,105
Treasury stock, shares	33,172,426	33,183,930

[1] Financial information for 2015 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

XML

Statement of Consolidated Changes in Equity - USD ($) $ in Millions		Total		Common Stock [Member]	Paid-In Capital [Member]	Retained Earnings (Accumulated Deficit) [Member]	Treasury Stock [Member]	Accumulated Other Comprehensive (Loss) [Member]	Parent [Member]	Noncontrolling Interest [Member]
Beginning Balance at Dec. 31, 2013	[1]	$ 30,756		$ 255	$ 12,403	$ 17,395	$ (1,027)	$ (115)	$ 28,911	$ 1,845
Net income (loss)	[1]	(8,019)	[2],[3],[4]			(8,360)			(8,360)	341
Postretirement benefit plans, net of tax	[2]	0
Distributions to noncontrolling interest	[1]	(140)								(140)
Commodity hedges, net of tax	[1]	(1)						(1)	(1)
Common dividends ($1.00 per share)	[1]	(380)				(380)			(380)
Common stock activity, net	[1]	(10)		1	(11)				(10)
Treasury stock activity, net	[1]	(1,864)			(1)		(1,863)		(1,864)
Compensation expense	[1]	202			202				202
Other	[1]	(3)			(3)				(3)
Ending Balance at Dec. 31, 2014	[1]	20,541		256	12,590	8,655	(2,890)	(116)	18,495	2,046
Net income (loss)	[1]	(10,667)	[2],[3],[4]			(10,352)			(10,352)	(315)
Postretirement benefit plans, net of tax	[1]	(3)	[2]					(3)	(3)
Distributions to noncontrolling interest	[1]	(129)								(129)
Common dividends ($1.00 per share)	[1]	(378)			(95)	(283)			(378)
Common stock activity, net	[1]	(14)		1	(15)				(14)
Treasury stock activity, net	[1]	0			(1)		1		0
Compensation expense	[1]	140			140				140
Ending Balance at Dec. 31, 2015	[1]	9,490	[5]	257	12,619	(1,980)	(2,889)	(119)	7,888	1,602
Net income (loss)		(1,273)				(1,405)			(1,405)	132
Postretirement benefit plans, net of tax		7						7	7
Distributions to noncontrolling interest		(293)								(293)
Common dividends ($1.00 per share)		(379)			(379)	0			(379)
Common stock activity, net		(38)		1	(39)				(38)
Treasury stock activity, net		1			(1)		2		1
Compensation expense		164			164				164
Ending Balance at Dec. 31, 2016		$ 7,679		$ 258	$ 12,364	$ (3,385)	$ (2,887)	$ (112)	$ 6,238	$ 1,441

[1] Financial information for 2015, 2014, and 2013 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

[2] Financial information for 2015 and 2014 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

[3] Financial information for 2015 and 2014 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

[4] Financial information for 2015 and 2014 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

[5] Financial information for 2015 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

XML

Statement of Consolidated Changes in Equity (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	[2]	Dec. 31, 2014	[2]
Common stock, dividends, per share	$ 1.00	$ 1.00	[1]	$ 1.00	[1]
Retained Earnings (Accumulated Deficit) [Member]
Common stock, dividends, per share	1.00	1.00		1.00
Parent [Member]
Common stock, dividends, per share	$ 1.00	$ 1.00		$ 1.00

[1] Financial information for 2015 and 2014 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

[2] Financial information for 2015, 2014, and 2013 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

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Nature of Operations

12 Months Ended

Dec. 31, 2016

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Nature of Operations

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 four geographic areas: the United States (U.S.), Canada, Egypt, and the United Kingdom (U.K.) North Sea (North Sea). Apache also has exploration interests in Suriname that may, over time, result in a reportable discovery and development opportunity.

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2016

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

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 include reclassifications that were made to conform to the current-year presentation. During the second quarter of 2015, Apache completed the sale of its Australian LNG business and oil and gas assets. In March 2014, Apache completed the sale of all of its operations in Argentina. Results of operations and cash flows for the divested Australia assets and Argentina operations are reflected as discontinued operations in the Company’s financial statements for all periods presented. Significant policies are discussed below.

Recast Financial Information for Change in Accounting Principle

In the second quarter of 2016, Apache voluntarily changed its method of accounting for its oil and gas exploration and development activities from the full cost method to the successful efforts method of accounting. The financial information for prior periods has been recast to reflect retrospective application of the successful efforts method, as prescribed by the Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 932 “Extractive Activities—Oil and Gas.” Although the full cost method of accounting for oil and gas exploration and development activities continues to be an accepted alternative, the successful efforts method of accounting is the generally preferred method of the U.S. Securities and Exchange Commission (SEC) and is more widely used in the industry such that the change improves comparability of the Company’s financial statements to its peers. The Company believes the successful efforts method provides a more representational depiction of assets and operating results. The successful efforts method also provides for the Company’s investments in oil and gas properties to be assessed for impairment in accordance with ASC 360 “Property, Plant, and Equipment” rather than valuations based on prices and costs prescribed under the full cost method as of the balance sheet date. For more detailed information regarding the effects of the change to the successful efforts method, please refer to Note 2—Change in Accounting Principle. The Company has recast certain historical information for the years ended 2015 and 2014, including the Statement of Consolidated Operations, Statement of Consolidated Comprehensive Income (Loss), Statement of Consolidated Cash Flows, Consolidated Balance Sheet, Statement of Consolidated Changes in Equity, and related information in Notes 1, 2, 3, 4, 6, 7, 8, 9, 12, 13, 15, 16, 17, and 18.

In addition, in the first quarter of 2016, the Company retrospectively adopted a new accounting standard update for all periods presented which requires debt issuance costs to be presented as a direct deduction from the carrying value of the associated debt liability, consistent with debt discounts. For more information regarding this update, please refer to Note 8—Debt and Financing Costs.

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. Sinopec International Petroleum Exploration and Production Corporation (Sinopec) owns a one-third minority participation in Apache’s Egypt oil and gas business as a noncontrolling interest, which is reflected as a separate component of equity in Apache’s consolidated balance sheet. 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 and assets held for sale at year-end (see Note 3—Acquisitions and Divestitures), the estimate of proved oil and gas reserves and related present value estimates of future net cash flows therefrom (see Note 16—Supplemental Oil and Gas Disclosures), the assessment of asset retirement obligations (see Note 7—Asset Retirement Obligation), the estimates of fair value for long-lived assets and goodwill (see “Fair Value Measurements,” “Property and Equipment,” and “Goodwill” sections in this Note 1 below), and the estimate of income taxes (see Note 9—Income Taxes).

Fair Value Measurements

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

Recurring fair value measurements are presented in further detail in Note 8—Debt and Note 11—Retirement and Deferred Compensation Plans.

Apache also uses fair value measurements on a nonrecurring basis when certain qualitative assessments of its assets indicate a potential impairment. For the year ended December 31, 2016, the Company recorded asset impairments totaling $1.1 billion in connection with fair value assessments in the current low commodity price environment. Impairments totaling $427 million and $135 million were recorded for proved properties and gathering, transmission, and processing (GTP) facilities, respectively, which were written down to their fair values. These impairments are discussed in further detail below in “Property and Equipment.” Also in 2016, the Company recorded $486 million for a U.K. Petroleum Revenue Tax (PRT) decommissioning asset that is no longer expected to be realizable from future abandonment activities in the North Sea and $55 million for inventory write-downs.

In 2016, the U.K. government enacted Finance Bill 2016, providing tax relief to exploration and production (E&P) companies operating in the U.K. North Sea. Under the enacted legislation, the U.K. PRT rate was reduced to zero from the previously enacted 35 percent rate in effect from January 1, 2016. PRT expense ceased prospectively from that date. As a further result of this change, the Company reduced the recoverable PRT decommissioning asset that would have been realized from future abandonment activities by $486 million ($292 million net of tax). This recoverable PRT decommissioning asset had an aggregate remaining value of $8 million as of December 31, 2016, which is recorded in “Deferred charges and other” on the consolidated balance sheet. The recoverable value of the PRT decommissioning asset was estimated using the income approach. The expected future cash flows used in the determination were based on anticipated spending and timing of planned future abandonment activities for applicable fields, considering all available information at the date of review. Apache has classified this fair value measurement as Level 3 in the fair value hierarchy.

For the year ended December 31, 2015, the Company recorded asset impairments totaling $9.5 billion in connection with fair value assessments. Impairments totaling $7.4 billion and $1.7 billion were recorded for proved properties and GTP facilities, respectively, which were written down to their fair values. These impairments are discussed in further detail below in “Property and Equipment.” Also in 2015, the Company recorded $163 million for the impairment of goodwill, $148 million for the impairment of an equity method investment sold in the fourth quarter, and $55 million for inventory write-downs. For a discussion of the equity method investment impairment, see Note 3—Acquisitions and Divestitures.

For the year ended December 31, 2014, the Company recorded asset impairments totaling $7.1 billion in connection with fair value assessments, including $6.1 billion for proved properties, $347 million for the impairment of goodwill, $655 million for the impairment of assets held for sale, and $32 million for inventory write-downs. The Company also recorded $833 million in impairments related to the sale of the Company’s Australian assets and an additional $271 million in impairment of proved properties and inventory in Australia. These impairments are classified as discontinued operations in 2014. For discussion of these impairments, see “Property and Equipment” and “Goodwill” below and Note 3—Acquisitions and Divestitures.

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, 2016 and 2015, Apache had $1.4 billion and $1.5 billion, 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 doubtful 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, 2016, 2015, and 2014, the Company had an allowance for doubtful accounts of $93 million, $103 million, and $98 million, respectively.

The following table describes changes to the Company’s allowance for doubtful accounts for 2016, 2015, and 2014:

	2016			2015			2014
	(In millions)
Allowance for doubtful accounts at beginning of year	$	103		$	98		$	78
Additional provisions for the year	14			40			4
Uncollectible accounts written off net of recoveries	(24		)	(35		)	16
Allowance for doubtful accounts at end of year	$	93		$	103		$	98

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, net of any impairments. 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 successful efforts method of accounting for its oil and gas property. Under this method of accounting, exploration costs such as exploratory geological and geophysical costs, delay rentals, and exploration overhead are expensed as incurred. All costs related to production, general corporate overhead, and similar activities are expensed as incurred. If an exploratory well provides evidence to justify potential development of reserves, drilling costs associated with the well are initially capitalized, or suspended, pending a determination as to whether a commercially sufficient quantity of proved reserves can be attributed to the area as a result of drilling. This determination may take longer than one year in certain areas depending on, among other things, the amount of hydrocarbons discovered, the outcome of planned geological and engineering studies, the need for additional appraisal drilling activities to determine whether the discovery is sufficient to support an economic development plan, and government sanctioning of development activities in certain international locations. At the end of each quarter, management reviews the status of all suspended exploratory well costs in light of ongoing exploration activities; in particular, whether the Company is making sufficient progress in its ongoing exploration and appraisal efforts or, in the case of discoveries requiring government sanctioning, whether development negotiations are underway and proceeding as planned. If management determines that future appraisal drilling or development activities are unlikely to occur, associated suspended exploratory well costs are expensed.

Acquisition costs of unproved properties are assessed for impairment at least annually and are transferred to proved oil and gas properties to the extent the costs are associated with successful exploration activities. Significant undeveloped leases are assessed individually for impairment based on the Company’s current exploration plans. Unproved oil and gas properties with individually insignificant lease acquisition costs are amortized on a group basis over the average lease term at rates that provide for full amortization of unsuccessful leases upon lease expiration or abandonment. Costs of expired or abandoned leases are charged to exploration expense, while costs of productive leases are transferred to proved oil and gas properties. Costs of maintaining and retaining unproved properties, as well as amortization of individually insignificant leases and impairment of unsuccessful leases, are included in exploration costs in the statement of consolidated operations.

Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of crude oil and natural gas, are capitalized. Depreciation of the cost of proved oil and gas properties is calculated using the unit-of-production (UOP) method. The UOP calculation multiplies the percentage of estimated proved reserves produced each quarter by the carrying value of those reserves. The reserve base used to calculate depreciation for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. With respect to lease and well equipment costs, which include development costs and successful exploration drilling costs, the reserve base includes only proved developed reserves. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are included in the depreciable cost.

Oil and gas properties are grouped for depreciation in accordance with ASC 932 “Extractive Activities - Oil and Gas.” The basis for grouping is a reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field.

When circumstances indicate that proved oil and gas properties may be impaired, the Company compares unamortized capitalized costs to the expected undiscounted pre-tax future cash flows for the associated assets grouped at the lowest level for which identifiable cash flows are independent of cash flows of other assets. If the expected undiscounted pre-tax future cash flows, based on Apache’s estimate of future crude oil and natural gas prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally estimated using the income approach described in the ASC 820 “Fair Value Measurement.” If applicable, the Company utilizes accepted bids as the basis for determining fair value. The expected future cash flows used for impairment reviews and related fair value calculations are typically based on judgmental assessments of future production volumes, commodity prices, operating costs, and capital investment plans, considering all available information at the date of review. These assumptions are applied to develop future cash flow projections that are then discounted to estimated fair value, using a discount rate believed to be consistent with those applied by market participants. Apache has classified these fair value measurements as Level 3 in the fair value hierarchy.

The following table represents non-cash impairments of the carrying value of the Company’s proved and unproved property and equipment for 2016, 2015, and 2014:

	For the Year Ended December 31,
	2016		2015		2014
	(In millions)
Oil and Gas Property:
Proved	$	427	$	7,389	$	6,068
Unproved	272		2,462		1,976

The fair values of the impaired proved properties as of the most recent date of impairment were $306 million, $3.9 billion, and $4.8 billion for 2016, 2015, and 2014, respectively.

In the statement of consolidated operations, unproved property impairments are recorded in exploration expense, and proved property impairments are recorded in impairments.

Gains and losses on significant divestitures are recognized in the statement of consolidated operations. See Note 3—Acquisitions and Divestitures for more detail.

Gathering, Transmission, and Processing Facilities

GTP facilities totaled $976 million and $1.1 billion at December 31, 2016 and 2015, respectively, with accumulated depreciation for these assets totaling $130 million and $160 million for the respective periods. GTP facilities are depreciated on a straight-line basis over the estimated useful lives of the assets. The estimation of useful life takes into consideration anticipated production lives from the fields serviced by the GTP assets, whether Apache-operated or third party, as well as potential development plans by Apache for undeveloped acreage within or in close proximity to those fields.

The Company assesses the carrying amount of its GTP facilities whenever events or changes in circumstances indicate that their carrying amount may not be recoverable. If the carrying amount of these facilities is more than the sum of the undiscounted cash flows, an impairment loss is recognized for the excess of the carrying value over its fair value. During 2016, the Company recorded impairments of $135 million on certain GTP assets in the North Sea, which were written down to their fair values of $142 million. The fair values of the impaired assets were determined using a combination of the income approach and the market approach. The income approach considers internal estimates of future throughput volumes, processing rates, and costs. These assumptions were applied to develop future cash flow projections that were then discounted to estimated fair value, using a discount rate believed to be consistent with those applied by market participants. Apache has classified these non-recurring fair value measurements as Level 3 in the fair value hierarchy. During 2015, the Company recorded impairments of $1.7 billion on certain GTP assets, including $1.1 billion in Egypt, $555 million in Canada, and $103 million in the U.S., which were written down to their fair values of $306 million in aggregate. During 2014, the Company recorded impairments of $1.1 billion of its GTP assets related to the sale of Apache’s Wheatstone and Kitimat LNG projects, and the remaining carrying value of those assets was reclassified to “Assets held for sale” on the Company’s consolidated balance sheet as of December 31, 2014. The $430 million impairment of GTP assets related to Apache's Wheatstone LNG project is reflected in discontinued operations in the Company's statement of consolidated operations.

The costs of GTP facilities retired or otherwise disposed of and associated accumulated depreciation are removed from Apache’s consolidated financial statements, and the resulting gain or loss is reflected in “Gain (loss) on divestitures” under “Revenues and Other” in the Company’s statement of consolidated operations. No gain or loss on the sales of GTP facilities was recognized during 2016. During 2015, Apache recorded a gain on the sale of GTP facilities totaling $59 million associated with the Company’s divestitures of certain Permian Basin assets. During 2014, the Company recorded a loss totaling $180 million associated with divestitures of certain Anadarko basin and southern Louisiana assets.

Other Property and Equipment

Other property and equipment includes computer software and equipment, buildings, vehicles, furniture and fixtures, land, and other equipment. These assets are depreciated on a straight-line basis over the estimated useful lives of the assets, which range from 3 to 20 years. Accumulated depreciation for these assets totaled $780 million and $693 million at December 31, 2016 and 2015, 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. 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.

CapitalizedInterest

For significant projects, interest is capitalized as part of the historical cost of developing and constructing assets. Significant oil and gas investments in unproved properties actively being explored, significant exploration and development projects that have not commenced production, significant midstream development activities that are in progress, and investments in equity method affiliates that are undergoing the construction of assets that have not commenced principal operations qualify for interest capitalization. Interest is capitalized until the asset is ready for service. Capitalized interest is determined by multiplying the Company’s weighted-average borrowing cost on debt by the average amount of qualifying costs incurred. Once an asset subject to interest capitalization is completed and placed in service, the associated capitalized interest is expensed through depreciation or impairment.

Goodwill

Goodwill represents the excess of the purchase price of an entity over the estimated fair value of the assets acquired and liabilities assumed, and it is recorded in “Deferred charges and other” in the Company's consolidated balance sheet. The Company assesses the carrying amount of goodwill by testing for impairment annually and when impairment indicators arise. The impairment test requires allocating goodwill and all other assets and liabilities to assigned reporting units. As of December 31, 2016, Apache assesses each country as a reporting unit. The fair value of each unit is determined and compared to the book value of the reporting unit. If the fair value of the reporting unit is less than the book value, including goodwill, then goodwill is written down to the implied fair value of the goodwill through a charge to expense.

In order to determine the fair value of each reporting unit, the Company uses a combination of the income approach and the market approach. The income approach considers management views on current operating measures as well as assumptions pertaining to market forces in the oil and gas industry, such as future production, future commodity prices, and costs. These assumptions are applied to develop future cash flow projections that are then discounted to estimate fair value, using a discount rate similar to those used by the Company in the valuation of acquisitions and divestitures. To assess the reasonableness of its fair value estimate, the Company uses a market approach to compare the fair value to similar businesses whose securities are actively traded in the public market. This requires management to make certain judgments about the selection of comparable companies, recent comparable asset transactions, and transaction premiums. Associated market multiples are applied to various financial metrics of the reporting unit to estimate fair value. Apache has classified this reporting unit estimation as a non-recurring Level 3 fair value measurement.

When there is a disposal of a reporting unit or a portion of a reporting unit that constitutes a business, goodwill associated with that business is included in the carrying amount to determine the gain or loss on disposal. The amount of goodwill allocated to the carrying amount of a business can significantly impact the amount of gain or loss recognized on the sale of that business. The amount of goodwill to be included in that carrying amount is based on the relative fair value of the business to be disposed of and the portion of the reporting unit that will be retained.

The following presents the changes to goodwill for the years ended 2016, 2015, and 2014:

	United States			Canada			Egypt		North Sea			Total
	(In millions)
Goodwill at December 31, 2013	$	384		$	103		$	87	$	163		$	737
Divested	(140		)	—			—		—			(140		)
Impairments	(244		)	(103		)	—		—			(347		)
Goodwill at December 31, 2014	—			—			87		163			250
Impairments	—			—			—		(163		)	(163		)
Goodwill at December 31, 2015	—			—			87		—			87
Impairments	—			—			—		—			—
Goodwill at December 31, 2016	$	—		$	—		$	87	$	—		$	87

Reductions in estimated net present value of expected future cash flows from oil and gas properties resulted in implied fair values below the carrying values of Apache’s U.S., North Sea, and Canada reporting units. These goodwill impairments have been recorded in “Impairments” in the Company’s statement of consolidated operations.

Accounts Payable

Included in accounts payable at December 31, 2016 and 2015, are liabilities of approximately $86 million and $129 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 North American natural gas production. Since the Company’s production fluctuates because of operational issues, it is occasionally necessary to purchase third-party oil and gas to fulfill sales obligations and commitments. The costs of third-party oil and gas purchases totaled $159 million, $105 million, and $70 million, for 2016, 2015, and 2014, respectively, which offset the related sales proceeds recorded as “Other” under “Revenues and Other” in the statement of consolidated operations.

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. As of December 31, 2016, Apache had no open derivative positions.

When applicable, 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 “Other” 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 2014 oil and gas cash flow hedges, including terminated contracts, were recognized in oil and gas production revenues when the forecasted transaction occurred. For more information, please refer to Note 5—Derivative Instruments and Hedging Activities.

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 ability to realize 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 record U.S. deferred income taxes on foreign subsidiaries that are deemed to be permanently reinvested. When such earnings are no longer deemed permanently reinvested, Apache will recognize the appropriate U.S. current or deferred income tax liabilities. For more information, please refer to Note 9—Income Taxes.

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. For further discussion, please refer to Note 9—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 2016 of $25 million, a loss in 2015 of $11 million, and a gain in 2014 of $8 million.

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 potential dilution, using the treasury stock method, which assumes that options were exercised and restricted stock was fully vested.

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 12—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 $2 million, $1 million, and $35,000 as financing cash inflows in 2016, 2015, and 2014, 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 January 2017, the FASB issued Accounting Standards Update (ASU) 2017-04, “Simplifying the Test for Goodwill Impairment.” ASU 2017-04 seeks to simplify the accounting for goodwill by eliminating the second step in the goodwill impairment test which requires an entity to determine the implied fair value of the reporting unit’s goodwill. Under the new guidance, an entity will recognize an impairment loss if the carrying value of the net assets assigned to the reporting unit exceeds the fair value of the reporting unit, with the impairment loss not to exceed the amount of goodwill allocated to the reporting unit. This update will be applied prospectively and is effective for annual and interim goodwill impairment tests conducted in fiscal years beginning after December 15, 2019. Early adoption is permitted for annual and interim goodwill impairment testing dates after January 1, 2017. The Company plans to early adopt this ASU, and does not expect the adoption to have a material impact on its consolidated financial statements.

In August 2016, the FASB issued Accounting Standards Update (ASU) 2016-15, Statement of Cash Flows (Topic 230).  ASU 2016-15 seeks to reduce the existing diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows. This update is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years, with early adoption permitted. The Company is currently evaluating the provisions of ASU 2016-15 and assessing the impact, if any, it may have on its statement of consolidated cash flows.

In June 2016, the FASB issued ASU 2016-13, “Financial Instruments - Credit Losses.”  The standard changes the impairment model for most financial assets and certain other instruments, including trade and other receivables, held-to-maturity debt securities and loans, and requires entities to use a new forward-looking expected loss model that will result in the earlier recognition of allowance for losses. This update is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. Early adoption is permitted for a fiscal year beginning after December 15, 2018, including interim periods within that fiscal year.  The Company does not expect to adopt the guidance early. Entities will apply the standard’s provisions as a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is adopted. The Company is evaluating the new guidance and does not believe this standard will have a material impact on its consolidated financial statements.

In March 2016, the FASB issued ASU 2016-09, which seeks to simplify accounting for share-based payment transactions including income tax consequences, classification of awards as either equity or liabilities, and the classification on the statement of cash flows. The new standard requires the Company to recognize the income tax effects of awards in the income statement when the awards vest or are settled. The guidance is effective for fiscal years beginning after December 15, 2016. The Company has evaluated the new guidance and recorded a cumulative-effect adjustment of $11 million as of January 1, 2017 representing an increase in accumulated deficit with the offset to paid-in capital to reflect actual forfeitures versus the previously-estimated forfeiture rate.

In February 2016, the FASB issued ASU 2016-02, a new lease standard requiring lessees to recognize lease assets and lease liabilities for most leases classified as operating leases under previous U.S. GAAP. The guidance is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The Company will be required to use a modified retrospective approach for leases that exist or are entered into after the beginning of the earliest comparative period in the financial statements. The Company is currently evaluating the impact of adopting this standard on its consolidated financial statements.

In May 2014, the FASB and the International Accounting Standards Board (IASB) issued a joint revenue recognition standard, ASU 2014-09. The new standard removes inconsistencies in existing standards, changes the way companies recognize revenue from contracts with customers, and increases disclosure requirements. The codification was amended through additional ASUs and, as amended, requires companies to recognize revenue to depict the transfer of goods or services to customers in amounts that reflect the consideration to which the company expects to be entitled in exchange for those goods or services. The guidance is effective for annual and interim periods beginning after December 15, 2017. The standard is required to be adopted using either the full retrospective approach, with all prior periods presented adjusted, or the modified retrospective approach, with a cumulative adjustment to retained earnings on the opening balance sheet. The Company will adopt the new standard utilizing the modified retrospective approach. Upon preliminary evaluation, the Company does not expect the adoption of this ASU to have a material impact on its consolidated financial statements. The Company is continuing to evaluate the disclosure requirements of this ASU and does not plan on early adopting the standard.

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Change in Accounting Principle

12 Months Ended

Dec. 31, 2016

Accounting Changes and Error Corrections [Abstract]

Change in Accounting Principle

CHANGE IN ACCOUNTING PRINCIPLE

During the second quarter of 2016, the Company voluntarily changed its method of accounting for oil and gas exploration and development activities from the full cost method to the successful efforts method. Accordingly, financial information for prior periods has been recast to reflect retrospective application of the successful efforts method. In general, under successful efforts, exploration expenditures such as exploratory dry holes, exploratory geological and geophysical costs, delay rentals, unproved impairments, and exploration overhead are charged against earnings as incurred, versus being capitalized under the full cost method of accounting. Successful efforts also provides for the assessment of potential property impairments under ASC 360 by comparing the net carrying value of oil and gas properties with associated projected undiscounted pre-tax future net cash flows. If the expected undiscounted pre-tax future net cash flows are lower than the unamortized capitalized costs, the capitalized cost is reduced to fair value. Under the full cost method of accounting, a write-down would be required if the net carrying value of oil and gas properties exceeds a full cost “ceiling,” using an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months. In addition, gains or losses, if applicable, are generally recognized on the dispositions of oil and gas property and equipment under the successful efforts method, as opposed to an adjustment to the net carrying value of the remaining assets under the full cost method. Apache’s consolidated financial statements have been recast to reflect these differences.

The following tables present the effects of the change to the successful efforts method in the statement of consolidated operations:

	Changes to the Statement of Consolidated Operations and Statement of Consolidated Comprehensive Income (Loss)
For the Year Ended December 31, 2016	Under Full Cost			Changes*			As Reported Under Successful Efforts
	(In millions, except per share data)
Oil revenues	$	3,983		$	189		$	4,172
Natural gas revenues	997			(30		)	967
NGL revenues	228			—			228
Oil and gas production revenues	5,208			159			5,367
Other	(38		)	4			(34		)
Gain on divestiture	17			4			21
Exploration	—			473			473
Depreciation, depletion, and amortization:
Oil and gas property and equipment
Recurring	1,974			486			2,460
Additional	1,438			(1,438		)	—
Impairments	677			426			1,103
Financing costs, net	365			52			417
Current income tax provision	232			159			391
Deferred income tax benefit	(721		)	(112		)	(833		)
NET LOSS FROM CONTINUING OPERATIONS INCLUDING NONCONTROLLING INTEREST	(1,361		)	121			(1,240		)
Net income (loss) attributable to noncontrolling interest	(26		)	158			132
NET LOSS FROM CONTINUING OPERATIONS ATTRIBUTABLE TO COMMON SHAREHOLDERS	(1,335		)	(37		)	(1,372		)
Net loss from discontinued operations, net of tax	(33		)	—			(33		)
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS	(1,368		)	(37		)	(1,405		)
Per Common Share
Basic and diluted net loss from continuing operations per share	$	(3.52	)	$	(0.10	)	$	(3.62	)
Basic and diluted net loss from discontinued operations per share	(0.09		)	—			(0.09		)
Basic and diluted net loss per share	$	(3.61	)	$	(0.10	)	$	(3.71	)
Other Comprehensive Income
COMPREHENSIVE LOSS ATTRIBUTABLE TO COMMON STOCK	(1,361		)	(37		)	(1,398		)

	Changes to the Statement of Consolidated Operations and Statement of Consolidated Comprehensive Income (Loss)
For the Year Ended December 31, 2015	Under Full Cost			Changes*			As Reported Under Successful Efforts
	(In millions, except per share data)
Oil revenues	$	4,999		$	108		$	5,107
Natural gas revenues	1,157			19			1,176
NGL revenues	227			—			227
Oil and gas production revenues	6,383			127			6,510
Other	(76		)	174			98
Gain on divestiture	59			222			281
Exploration	—			2,771			2,771
General and administrative	377			3			380
Depreciation, depletion, and amortization:
Oil and gas property and equipment
Recurring	3,531			(555		)	2,976
Additional	25,517			(25,517		)	—
Impairments	1,920			7,552			9,472
Financing costs, net	299			212			511
Current income tax provision	309			126			435
Deferred income tax benefit	(5,778		)	4,333			(1,445		)
NET LOSS FROM CONTINUING OPERATIONS INCLUDING NONCONTROLLING INTEREST	(22,757		)	11,598			(11,159		)
Net loss attributable to noncontrolling interest	(409		)	94			(315		)
NET LOSS FROM CONTINUING OPERATIONS ATTRIBUTABLE TO COMMON SHAREHOLDERS	(22,348		)	11,504			(10,844		)
Net income (loss) from discontinued operations, net of tax	(771		)	1,263			492
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS	(23,119		)	12,767			(10,352		)
Per Common Share
Basic and diluted net loss from continuing operations per share	$	(59.16	)	$	30.46		$	(28.70	)
Basic and diluted net income (loss) from discontinued operations per share	(2.04		)	3.34			1.30
Basic and diluted net loss per share	$	(61.20	)	$	33.80		$	(27.40	)
Other Comprehensive Income
Pension and postretirement benefit plan, net of tax	$	—		$	(3	)	$	(3	)
COMPREHENSIVE LOSS ATTRIBUTABLE TO COMMON STOCK	(23,119		)	12,764			(10,355		)

	Changes to the Statement of Consolidated Operations and Statement of Consolidated Comprehensive Income (Loss)
For the Year Ended December 31, 2014	Under Full Cost			Changes*			As Reported Under Successful Efforts
	(In millions, except per share data)
Oil revenues	$	10,040		$	70		$	10,110
Natural gas revenues	1,983			34			2,017
NGL revenues	668			—			668
Oil and gas production revenues	12,691			104			12,795
Other	290			(5		)	285
Loss on divestiture	(180		)	(1,428		)	(1,608		)
Exploration	—			2,499			2,499
General and administrative	451			2			453
Depreciation, depletion, and amortization:
Oil and gas property and equipment
Recurring	4,388			(193		)	4,195
Additional	5,001			(5,001		)	—
Impairments	1,919			5,183			7,102
Financing costs, net	211			202			413
Current income tax provision	1,177			104			1,281
Deferred income tax benefit	(514		)	(1,285		)	(1,799		)
NET LOSS FROM CONTINUING OPERATIONS INCLUDING NONCONTROLLING INTEREST	(3,472		)	(2,840		)	(6,312		)
Net income attributable to noncontrolling interest	343			(2		)	341
NET LOSS FROM CONTINUING OPERATIONS ATTRIBUTABLE TO COMMON SHAREHOLDERS	(3,815		)	(2,838		)	(6,653		)
Net loss from discontinued operations, net of tax	(1,588		)	(119		)	(1,707		)
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS	(5,403		)	(2,957		)	(8,360		)
Per Common Share
Basic and diluted net loss from continuing operations per share	$	(9.93	)	$	(7.39	)	$	(17.32	)
Basic and diluted net loss from discontinued operations per share	(4.13		)	(0.31		)	(4.44		)
Basic and diluted net loss per share	$	(14.06	)	$	(7.70	)	$	(21.76	)
Other Comprehensive Income
COMPREHENSIVE LOSS ATTRIBUTABLE TO COMMON STOCK	$	(5,404	)	$	(2,957	)	$	(8,361	)

The following tables present the effects of the change to the successful efforts method in the statement of consolidated cash flows:

	Changes to the Statement of Consolidated Cash Flows
For the Year Ended December 31, 2016	Under Full Cost			Changes*			As Reported Under Successful Efforts
	(In millions)
Net loss including noncontrolling interest	$	(1,394	)	$	121		$	(1,273	)
Gain on divestitures, net	(17		)	(4		)	(21		)
Exploratory dry hole expense and unproved leasehold impairments	—			353			353
Depreciation, depletion, and amortization	3,570			(952		)	2,618
Impairments	677			426			1,103
Benefit from deferred income taxes	(721		)	(112		)	(833		)
Changes in operating assets and liabilities	138			15			153
Net cash provided by continuing operating activities	2,606			(153		)	2,453
Additions to oil and gas property	(1,776		)	166			(1,610		)
Net cash used in investing activities	(1,826		)	166			(1,660		)
Other	6			(13		)	(7		)
Net cash used in financing activities	(847		)	(13		)	(860		)
NET DECREASE IN CASH	(90		)	—			(90		)
BEGINNING CASH BALANCE	1,467			—			1,467
ENDING CASH BALANCE	1,377			—			1,377

	Changes to the Statement of Consolidated Cash Flows
For the Year Ended December 31, 2015	Under Full Cost			Changes*			As Reported Under Successful Efforts
	(In millions)
Net loss including noncontrolling interest	$	(23,528	)	$	12,861		$	(10,667	)
Loss (income) from discontinued operations	771			(1,263		)	(492		)
Gain on divestitures, net	(59		)	(222		)	(281		)
Exploratory dry hole expense and unproved leasehold impairments	—			2,595			2,595
Depreciation, depletion, and amortization	29,372			(26,072		)	3,300
Impairments	1,920			7,552			9,472
Other noncash items, net	161			(154		)	7
Benefit from deferred income taxes	(5,778		)	4,333			(1,445		)
Changes in operating assets and liabilities	(170		)	90			(80		)
Net cash provided by operating activities - continuing operations	2,834			(280		)	2,554
Net cash provided by operating activities - discontinued operations	150			(37		)	113
Additions to oil and gas property	(4,578		)	370			(4,208		)
Net cash used in investing activities - continuing operations	(3,659		)	370			(3,289		)
Net cash provided by investing activities - discontinued operations	4,335			37			4,372
NET INCREASE IN CASH	698			90			788
BEGINNING CASH BALANCE	769			(90		)	679
ENDING CASH BALANCE	1,467			—			1,467

	Changes to the Statement of Consolidated Cash Flows
For the Year Ended December 31, 2014	Under Full Cost			Changes*			As Reported Under Successful Efforts
	(In millions)
Net loss including noncontrolling interest	$	(5,060	)	$	(2,959	)	$	(8,019	)
Income from discontinued operations	1,588			119			1,707
Loss on divestitures, net	180			1,428			1,608
Exploratory dry hole expense and unproved leasehold impairments	—			2,294			2,294
Depreciation, depletion, and amortization	9,720			(5,194		)	4,526
Impairments	1,919			5,183			7,102
Benefit from deferred income taxes	(514		)	(1,285		)	(1,799		)
Changes in operating assets and liabilities	(239		)	(90		)	(329		)
Net cash provided by operating activities - continuing operations	7,517			(504		)	7,013
Net cash provided by operating activities - discontinued operations	944			—			944
Additions to oil and gas property	(9,022		)	414			(8,608		)
Net cash used in investing activities - continuing operations	(8,585		)	414			(8,171		)
Net cash used in investing activities - discontinued operations	(219		)	—			(219		)
NET DECREASE IN CASH	(1,137		)	(90		)	(1,227		)
BEGINNING CASH BALANCE	1,906			—			1,906
ENDING CASH BALANCE	769			(90		)	679

The following tables present the effects of the change to the successful efforts method in the consolidated balance sheet:

	Changes to the Consolidated Balance Sheet
December 31, 2016	Under Full Cost			Changes*			As Reported Under Successful Efforts
	(In millions)
PROPERTY AND EQUIPMENT:
Property and equipment - cost	$	95,371		$	(48,622	)	$	46,749
Less: Accumulated depreciation, depletion, and amortization	(83,230		)	55,348			(27,882		)
PROPERTY AND EQUIPMENT, NET	12,141			6,726			18,867
TOTAL ASSETS	15,793			6,726			22,519
Income taxes	353			1,357			1,710
Paid-in capital	12,225			139			12,364
Accumulated deficit	(8,521		)	5,136			(3,385		)
Accumulated other comprehensive loss	(109		)	(3		)	(112		)
Noncontrolling interest	1,344			97			1,441
TOTAL EQUITY	2,310			5,369			7,679

	Changes to the Consolidated Balance Sheet
December 31, 2015	Under Full Cost			Changes*			As Reported Under Successful Efforts
	(In millions)
PROPERTY AND EQUIPMENT:
Property and equipment - cost	$	93,825		$	(47,675	)	$	46,150
Less: Accumulated depreciation, depletion, and amortization	(79,706		)	54,394			(25,312		)
PROPERTY AND EQUIPMENT, NET	14,119			6,719			20,838
TOTAL ASSETS	18,781			6,719			25,500
Income taxes	1,072			1,457			2,529
Paid-in capital	12,467			152			12,619
Accumulated deficit	(7,153		)	5,173			(1,980		)
Accumulated other comprehensive loss	(116		)	(3		)	(119		)
Noncontrolling interest	1,662			(60		)	1,602
TOTAL EQUITY	4,228			5,262			9,490

*In conjunction with recasting the financial information for the adoption of the successful efforts method of accounting, the Company corrected certain immaterial errors in the North Sea pertaining to the improper calculation of deferred tax liabilities associated with capitalized interest under the full cost method.

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Acquisitions and Divestitures

12 Months Ended

Dec. 31, 2016

Business Combinations [Abstract]

Acquisitions and Divestitures

Activity

Yara Pilbara Holdings Pty Limited Sale

In October 2015, Apache sold its 49 percent interest in Yara Pilbara Holdings Pty Limited (YPHPL) for total cash proceeds of $391 million. The investment in YPHPL was 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 the results of operations recorded as a component of “Other” under “Revenue and other” in the Company’s statement of consolidated operations. As of September 30, 2015, Apache recognized an impairment of $148 million on the YPHPL equity investment based on negotiated sales proceeds. No additional gain or loss was recorded upon completion of the sale.

Canada Divestiture

In April 2015, Apache completed the sale of its 50 percent interest in the Kitimat LNG project and upstream acreage in the Horn River and Liard natural gas basins to Woodside Petroleum Limited (Woodside). Proceeds at closing were $854 million, of which approximately $344 million was associated with LNG assets and $510 million was associated with upstream assets. For additional details related to post-closing adjustments, please see Note 10—Commitments and Contingencies.

The Kitimat LNG assets were classified as held for sale and impaired $655 million in the fourth quarter of 2014. In 2015, Apache recognized a $146 million gain on the sale of the upstream assets upon completion of the sale.

Australia Divestitures

Woodside Sale In April 2015, Apache completed the sale of the Wheatstone LNG project and associated upstream oil and gas assets to Woodside. Proceeds at closing were $2.8 billion, of which approximately $1.4 billion was associated with LNG assets and $1.4 billion was associated with the upstream assets.

The Wheatstone LNG assets and associated upstream assets were classified as held for sale and impaired $833 million in the fourth quarter of 2014. An additional impairment of approximately $49 million was recognized in the first quarter of 2015. During the third quarter of 2016, Apache recognized an additional $23 million loss on the sale related to post-closing adjustments.

Consortium Sale In June 2015, Apache completed the sale of its Australian subsidiary Apache Energy Limited (AEL) to a consortium of private equity funds managed by Macquarie Capital Group Limited and Brookfield Asset Management Inc. Total proceeds of $1.9 billion include customary, post-closing adjustments for the period between the effective date, October 1, 2014, and closing. A loss of approximately $139 million was recognized for the sale of AEL.

Upon closing of the sale of substantially all Australian operations, the associated results of operations for the divested Australian assets and the losses on disposal were classified as discontinued operations in the Company’s financial statements for all periods presented.

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

	For the Year Ended December 31,
	2016			2015			2014
	(In millions)
Revenues and other from discontinued operations	$	—		$	288		$	1,050
Impairment on Woodside sale	$	—		$	(49	)	$	(833	)
Loss on Woodside sale	(23		)	—			—
Loss on Consortium sale	—			(139		)	—
Income (loss) from divested Australian operations	—			28			(12		)
Income tax benefit (expense)	—			652			(231		)
Income (loss) from Australian discontinued operations, net of tax	$	(23	)	$	492		$	(1,076	)

Leasehold and Property Acquisitions

Apache completed $367 million of leasehold and property acquisitions during 2015, primarily in our North America onshore regions.

Divestiture of Other Oil and Gas Properties

Apache recorded $268 million of proceeds from the divestiture of other oil and gas properties during 2015. An associated $135 million of gain was recorded in 2015.

2014 Activity

Anadarko Basin and Southern Louisiana Divestitures

In December 2014, Apache completed the sale of certain Anadarko basin and non-core southern Louisiana oil and gas assets for approximately $1.3 billion in two separate transactions. In the Anadarko basin, Apache sold approximately 115,000 net acres in Wheeler County, Texas, and western Oklahoma. In southern Louisiana, Apache sold its working interest in approximately 90,000 net acres. The effective date of both of these transactions is October 1, 2014. Apache recognized a net $823 million loss on these transactions, of which approximately $10 million was associated with goodwill and approximately $180 million was associated with GTP facilities.

Gulf of Mexico Deepwater Divestiture

On June 30, 2014, Apache completed the sale of non-operated interests in the Lucius and Heidelberg development projects and 11 primary-term deepwater exploration blocks in the Gulf of Mexico for $1.4 billion. The effective date of the transaction was May 1, 2014. Apache recognized a $332 million loss as a result of the transaction, of which approximately $130 million was associated with goodwill.

Canada Divestiture

On April 30, 2014, Apache completed the sale of primarily dry gas producing hydrocarbon assets in the Deep Basin area of western Alberta and British Columbia, Canada, for $374 million. The assets comprise 328,400 net acres in the Ojay, Noel, and Wapiti areas. Apache retained 100 percent of its working interest in horizons below the Cretaceous in the Wapiti area, including rights to the liquids-rich Montney and other deeper horizons. The effective date of the transaction was January 1, 2014. Apache recognized a $237 million loss related to the sale of the assets.

Argentina Divestiture

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 (subject to customary closing adjustments) 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.

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

	For the Year Ended December 31,
	2016			2015		2014
	(In millions)
Revenues and other from discontinued operations	$	—		$	—	$	87
Loss from Argentina divestiture	$	(10	)	$	—	$	(654	)
Loss from operations in Argentina	—			—		(1		)
Income tax benefit	—			—		23
Loss from discontinued operations, net of tax	$	(10	)	$	—	$	(632	)

Leasehold and Property Acquisitions

Apache completed $1.5 billion of leasehold and property acquisitions during 2014, primarily in our North America onshore regions.

Divestiture of Other Oil and Gas Properties

Apache recorded $96 million of proceeds from the divestiture of other oil and gas properties during 2014. An associated $216 million of loss was recorded in 2014.

Transaction, Reorganization, and Separation

Apache recorded $39 million, $132 million, and $67 million of expenses during 2016, 2015, and 2014, respectively, primarily related to various transactions, company reorganization, and employee separation.

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Capitalized Exploratory Well Costs

12 Months Ended

Dec. 31, 2016

Extractive Industries [Abstract]

Capitalized Exploratory Well Costs

CAPITALIZED EXPLORATORY WELL COSTS

The following summarizes the changes in capitalized exploratory well costs for each of the last three years ended December 31, 2016, 2015, and 2014. Additions pending the determination of proved reserves excludes amounts capitalized and subsequently charged to expense within the same year.

	2016			2015			2014
	(In millions)
Balance at January 1	$	245		$	849		$	630
Additions pending determination of proved reserves	249			382			622
Divestitures and other	—			(557		)	(54		)
Reclassifications to proved properties	(211		)	(369		)	(207		)
Charged to exploration expense	(19		)	(60		)	(142		)
Balance at December 31(1)	$	264		$	245		$	849

⁽¹⁾ Includes $49 million of assets that were held for sale in Australia at December 31, 2014.

The following provides an aging of capitalized exploratory well costs and the number of projects for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling:

	2016		2015		2014
	(In millions)
Exploratory well costs capitalized for a period of one year or less	$	119	$	184	$	504
Exploratory well costs capitalized for a period greater than one year	145		61		345
Balance at December 31(1)	$	264	$	245	$	849
Number of projects with exploratory well costs capitalized for a period greater than one year	3		2		18

⁽¹⁾ Includes $49 million of assets that were held for sale in Australia at December 31, 2014.

The following summarizes a further aging by geographic area of those exploratory well costs that have been capitalized for a period greater than one year since the completion of drilling at December 31, 2016:

							2013 and
	Total		2015		2014		Prior
North Sea	$	113	$	53	$	58	$	2
Other International	32		28		3		1
	$	145	$	81	$	61	$	3

Projects with suspended exploratory well costs capitalized for a period greater than one year since the completion of drilling are those identified by management as exhibiting sufficient quantities of hydrocarbons to justify potential development. Management is actively pursuing efforts to assess whether reserves can be attributed to these projects.

Suspended exploratory well costs capitalized for a period greater than one year since the completion of drilling at December 31, 2016 primarily relate to the Seagull and Corona discoveries in the North Sea. In Seagull, appraisal work continues as the Company interprets the multi-azimuth 3-D survey acquired in late 2015. The survey will be used to create a development plan to be submitted to the Oil and Gas Authority in the U.K. in 2017. The suspended exploratory well costs related to the Corona discovery are pending development plan approval. In December 2016, the Company submitted the full field development plan to the Oil and Gas Authority in the U.K. Remaining activities required to classify the associated reserves as proved include approval of development plans and project sanctioning.

The remaining capitalized well costs in excess of one year relate to exploratory drilling in Suriname. The suspended exploratory well costs for the Block 53 Popokai well are pending the results of the Block 53 Kolibrie exploratory well. The Company plans to drill Kolibrie in 2017.

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Derivative Instruments and Hedging Activities

12 Months Ended

Dec. 31, 2016

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments and Hedging Activities

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. When appropriate, 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. As of December 31, 2016, Apache had no open commodity derivative positions.

Subsequent to December 31, 2016, the Company entered into put option derivative contracts not designated as cash flow hedges for 2017 crude oil production of 175,000 barrels per day. These contracts will be settled against either NYMEX WTI or Dated Brent between July 1, 2017 and December 31, 2017, with a weighted average strike price of $50.47 per barrel. Apache paid a total premium of $100 million for these contracts, averaging $3.09 per barrel.

Derivative Activity Recorded in the Statement of Consolidated Operations

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

	Gain (Loss) on Derivatives Recognized in Income	For the Year Ended December 31,
		2016		2015		2014
		(In millions)
Derivatives not designated as cash flow hedges:
Realized loss		$	—	$	—	$	(16	)
Unrealized gain (loss)		—		—		300
Gain (loss) on derivatives not designated as cash flow hedges	Revenues and Other: Other	$	—	$	—	$	284

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 (loss) to net cash provided by operating activities.”

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Other Current Liabilities

12 Months Ended

Dec. 31, 2016

Payables and Accruals [Abstract]

Other Current Liabilities

OTHER CURRENT LIABILITIES

The following table provides detail of the Company’s other current liabilities at December 31, 2016 and 2015:

	December 31,
	2016		2015
	(In millions)
Accrued operating expenses	$	110	$	139
Accrued exploration and development	463		637
Accrued compensation and benefits	201		166
Accrued interest	145		144
Accrued income taxes	22		47
Current asset retirement obligation	66		36
Current debt	—		1
Refundable deposits	174		—
Other	77		53
Total Other current liabilities	$	1,258	$	1,223

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Asset Retirement Obligation

12 Months Ended

Dec. 31, 2016

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligation

ASSET RETIREMENT OBLIGATION

The following table describes changes to the Company’s asset retirement obligation (ARO) liability for the years ended December 31, 2016 and 2015:

	2016			2015
	(In millions)
Asset retirement obligation at beginning of year	$	2,598		$	2,952
Liabilities incurred	41			68
Liabilities divested	(7		)	(490		)
Liabilities settled	(57		)	(90		)
Accretion expense	156			158
Revisions in estimated liabilities	(233		)	—
Asset retirement obligation at end of year	2,498			2,598
Less current portion	(66		)	(36		)
Asset retirement obligation, long-term	$	2,432		$	2,562

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 for 2015 includes discontinued operations of $13 million, which are included in “Net income (loss) from discontinued operations, net of tax” in the statement of consolidated operations.

During 2016 and 2015, the Company recorded $41 million and $68 million, respectively, in abandonment liabilities resulting from Apache’s 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, 2016

Debt Disclosure [Abstract]

Debt

DEBT

Overview

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

In November 2016, the Company initiated a program to purchase in the open market up to $250 million in aggregate principal amount of senior notes issued under its indentures. In the fourth quarter of 2016, Apache purchased and canceled $181 million aggregate principal amount of its senior notes through open market repurchases for $182 million in cash, including accrued interest and $0.5 million of premium. These repurchases resulted in a $1 million net loss on extinguishment of debt, which is included in “Financing costs, net” in Apache's consolidated statement of operations. The net loss includes an acceleration of related discount and deferred financing costs.

In January 2017, Apache purchased and canceled an additional $69 million aggregate principal amount of senior notes for $71 million in cash, including accrued interest and $1 million of premium, which completed the open market repurchase program.

The following table presents the carrying value of the Company’s debt at December 31, 2016 and 2015:

	December 31,
	2016			2015
	(In millions)
Commercial paper	$	—		$	—
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)	493			500
3.25% notes due 2022(1)	857			919
2.625% notes due 2023(1)	528			531
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)	1,499			1,500
5.25% notes due 2042(1)	500			500
4.75% notes due 2043(1)	1,413			1,500
4.25% notes due 2044(1)	780			800
7.375% debentures due 2047	150			150
7.625% debentures due 2096	150			150
	8,350			8,530
Subsidiary and other obligations:
Notes due in 2017	—			1
Apache Finance Canada 7.75% notes due 2029	300			300
	300			301
Debt before unamortized discount and debt issuance costs	8,650			8,831
Unamortized discount	(50		)	(53		)
Debt issuance costs	(56		)	(61		)
Total debt	8,544			8,717
Current maturities	—			(1		)
Long-term debt	$	8,544		$	8,716

(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, 2016, excluding discounts and debt issuance costs, are as follows:

	(In millions)
2017	$	—
2018	550
2019	150
2020	—
2021	493
Thereafter(1)	7,457
Total Debt(1), excluding discounts and debt issuance costs	$	8,650

(1) In January 2017, Apache purchased and canceled $69 million aggregate principal amount of senior notes (see overview above), which reduces “Thereafter” and “Total Debt” maturities to $7.4 billion and $8.6 billion, respectively, as of January 31, 2017.

In April 2015, the FASB issued ASU 2015-03 “Simplifying the Presentation of Debt Issuance Costs,” which requires debt issuance costs to be presented as a direct deduction from the carrying value of the associated debt liability. The Company adopted this update in the first quarter of 2016 and applied the changes retrospectively for all periods presented. At December 31, 2015, the Company had debt issuance costs of $61 million classified as a long-term asset as a component of “Deferred charges and other” on the balance sheet that have been netted against “Long-term debt” in these financial statements. As of December 31, 2016, long-term debt is presented net of debt issuance costs of $56 million.

Fair Value

The Company’s debt is recorded at the carrying amount, net of unamortized discount and debt issuance costs, 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, 2016				December 31, 2015
	Carrying     Amount		Fair     Value		Carrying     Amount		Fair     Value
	(In millions)
Commercial paper	$	—	$	—	$	—	$	—
Notes and debentures	8,544		9,183		8,717		8,330
Total Debt	$	8,544	$	9,183	$	8,717	$	8,330

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, 2016 and 2015, there was no outstanding balance on Apache’s lines of credit.

Unsecured Committed Bank Credit Facilities

In June 2015, the Company entered into a five-year revolving credit facility which matures in June 2020, subject to Apache’s two, one-year extension options. The facility provides for aggregate commitments of $3.5 billion (including a $750 million letter of credit subfacility), with rights to increase commitments up to an aggregate $4.5 billion. Proceeds from borrowings may be used for general corporate purposes. Apache’s available borrowing capacity under this facility supports its commercial paper program. In connection with entry into the $3.5 billion facility, Apache terminated $5.3 billion in commitments under existing credit facilities. As of December 31, 2016, there were no borrowings under this credit facility, leaving aggregate available borrowing capacity at $3.5 billion.

At the Company’s option, the interest rate per annum for borrowings under the 2015 facility is either a base rate, as defined, plus a margin or the London Inter-bank Offered Rate (LIBOR), plus a margin. The Company also pays quarterly a facility fee at per annum rate on total commitments. The margins and the facility fee vary based upon the Company’s senior long-term debt rating. At December 31, 2016, the base rate margin was 0.075 percent, the LIBOR margin was 1.075 percent, and the facility fee was 0.175 percent.

The financial covenants of the 2015 credit facility require the Company to maintain an adjusted debt-to-capital ratio of not greater than 60 percent at the end of any fiscal quarter. For purposes of this calculation, capital excludes the effects of non-cash write-downs, impairments, and related charges occurring after June 30, 2015.

The 2015 facility’s negative covenants restrict the ability of the Company and its subsidiaries to create liens securing debt on its hydrocarbon-related assets, with exceptions for liens typically arising in the oil and gas industry, purchase money liens, liens on subsidiary assets located outside of the United States and Canada, and liens arising as a matter of law, such as tax and mechanics’ liens. The Company also may incur liens on assets if debt secured thereby does not exceed 5 percent of the Company’s consolidated assets, or approximately $1.1 billion as of December 31, 2016. Negative covenants also restrict Apache’s ability to merge with another entity unless it is the surviving entity, dispose of substantially all of its assets, and guarantee debt of non-consolidated entities in excess of the stated threshold.

In February 2016, Apache entered into a three-year letter of credit facility providing £900 million in commitments, with options to increase commitments to £1.075 billion and extend the term by one year. The facility is available for letters of credit denominated in pounds sterling, U.S. Dollars, Canadian Dollars, and any other foreign currency consented to by an issuing bank. The facility also is available for loans in pounds sterling, U.S. Dollars, and Canadian Dollars to cash collateralize letters of credit or obligations to provide letters of credit, in each case, to the extent letters of credit are unavailable under the facility. The facility’s representations and warranties, covenants, and events of default are substantially similar to those in Apache’s 2015 $3.5 billion revolving credit facility.

Commissions are payable on letters of credit outstanding under the 2016 facility at a per annum rate equal to a LIBOR margin. Borrowings bear interest per annum at a base rate or LIBOR, plus a margin. A facility fee at a per annum rate on aggregate commitments also is payable. Letter of credit commissions, the interest margin, and the facility fee vary depending on Apache’s senior unsecured long-term debt rating. At December 31, 2016, the LIBOR margin was 1.075 percent, the base rate margin was 0.075 percent, and the facility fee was 0.175 percent.

The 2016 facility is available for the Company’s letter of credit needs, particularly those which may arise in respect of abandonment obligations assumed in various North Sea acquisitions. As of December 31, 2016, three letters of credit aggregating approximately £147.5 million and no borrowings were outstanding under this facility.

There are no clauses in the 2015 $3.5 billion or 2016 £900 million credit facilities that permit the lenders to accelerate payments or refuse to lend based on unspecified material adverse changes. The agreements for these facilities 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 payment maturity and terminate lending and issuance commitments for nonpayment and other breaches, and if the Company or any of its U.S. or Canadian subsidiaries defaults on other indebtedness in excess of the stated threshold, is insolvent, or has any unpaid, non-appealable judgment against it for payment of money in excess of the stated threshold. Lenders may also accelerate payment maturity and terminate lending and issuance commitments if the Company undergoes a specified change in control or any borrower has specified pension plan liabilities in excess of the stated threshold. The Company was in compliance with the terms of these credit facilities as of December 31, 2016.

Commercial Paper Program

The Company has available a $3.5 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 the Company’s 2015 committed credit facility. At December 31, 2016 and 2015, the Company had no 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 18—Supplemental Guarantor Information.

Financing Costs, Net

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

	For the Year Ended December 31,
	2016			2015			2014
	(In millions)
Interest expense	$	464		$	486		$	499
Amortization of deferred loan costs	8			11			6
Capitalized interest	(48		)	(15		)	(85		)
Loss on extinguishment of debt	1			39			—
Interest income	(8		)	(10		)	(7		)
Financing costs, net	$	417		$	511		$	413

As of December 31, 2016, the Company has $50 million of debt discounts, which will be charged to interest expense over the life of the related debt issuances. Discount amortization of $3 million was recorded as interest expense in each of 2016, 2015, and 2014.

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Income Taxes

12 Months Ended

Dec. 31, 2016

Income Tax Disclosure [Abstract]

Income Taxes

INCOME TAXES

Loss from continuing operations before income taxes is composed of the following:

	For the Year Ended December 31,
	2016			2015			2014
	(In millions)
U.S.	$	(997	)	$	(9,386	)	$	(4,807	)
Foreign	(685		)	(2,783		)	(2,023		)
Total	$	(1,682	)	$	(12,169	)	$	(6,830	)

The total income tax provision (benefit) from continuing operations consists of the following:

	For the Year Ended December 31,
	2016			2015			2014
	(In millions)
Current income taxes:
Federal	$	(14	)	$	363		$	(10	)
State	(30		)	41			1
Foreign	435			31			1,290
	391			435			1,281
Deferred income taxes:
Federal	(257		)	(1,123		)	(671		)
State	—			(51		)	(45		)
Foreign	(576		)	(271		)	(1,083		)
	(833		)	(1,445		)	(1,799		)
Total	$	(442	)	$	(1,010	)	$	(518	)

The total income tax provision (benefit) differs from the amounts computed by applying the U.S. statutory income tax rate to loss before income taxes. A reconciliation of the tax on the Company’s loss from continuing operations before income taxes and total tax expense is shown below:

	For the Year Ended December 31,
	2016			2015			2014
	(In millions)
Income tax expense (benefit) at U.S. statutory rate	$	(589	)	$	(4,259	)	$	(2,391	)
State income tax, less federal effect(1)	(19		)	(7		)	(28		)
Taxes related to foreign operations	303			(662		)	(147		)
Tax credits	(1		)	(6		)	—
Tax on distributed foreign earnings	80			726			311
Foreign tax credits	(136		)	(2,090		)	—
Deferred tax on undistributed foreign earnings	(31		)	1,903			560
Tax impact of goodwill adjustments	—			82			161
Change in U.K. tax rate	(238		)	(414		)	—
Net change in tax contingencies	(19		)	20			(3		)
Canadian USD functional currency election	158			—			—
Valuation allowances(1)	10			3,746			1,021
All other, net	40			(49		)	(2		)
	$	(442	)	$	(1,010	)	$	(518	)

(1) The change in state valuation allowance is included as a component of state income tax.

The net deferred income tax liability reflects the net tax impact of temporary differences between the asset and liability amounts carried on the balance sheet under the U.S. GAAP method of accounting and amounts utilized for income tax purposes. The net deferred income tax liability consists of the following:

	December 31,
	2016			2015
	(In millions)
Deferred tax assets:
Deferred income	$	105		$	20
U.S. and state net operating losses	1,095			329
Foreign net operating losses	1,424			1,507
Tax credits and other tax incentives	62			82
Foreign tax credits	2,226			2,090
Accrued expenses and liabilities	153			136
Asset retirement obligation	875			1,037
Property and equipment	1,189			1,534
Total deferred tax assets	7,129			6,735
Valuation allowance	(5,401		)	(5,434		)
Net deferred tax assets	1,728			1,301
Deferred tax liabilities:
Deferred income	—			140
Investment in foreign subsidiaries	1,872			1,903
Equity investments	23			5
Property and equipment	1,533			1,773
Other	5			4
Total deferred tax liabilities	3,433			3,825
Net deferred income tax liability	$	1,705		$	2,524

Net deferred tax assets and liabilities are included in the consolidated balance sheet as follows:

	December 31,
	2016		2015
	(In millions)
Assets:
Deferred charges and other	$	5	$	5
Liabilities:
Deferred income taxes	1,710		2,529
Net deferred income tax liability	$	1,705	$	2,524

In 2016, the U.K. government enacted Finance Bill 2016, which provides tax relief to E&P companies operating in the North Sea through a reduction of Supplementary Charge from 20 percent to 10 percent, effective January 1, 2016. As a result of the enacted legislation, in 2016, Apache recorded a deferred tax benefit of $238 million related to the remeasurement of the Company’s December 31, 2015 U.K. deferred income tax liability.

In 2015, Apache repatriated the sales proceeds from the divestment of its interest in LNG projects and Australian upstream assets. Upon the repatriation of these proceeds, Apache recognized a U.S. current income tax liability of $560 million. Also in 2015, the U.K. government enacted Finance Bill 2015, which provided a reduction of Supplementary Charge from 32 percent to 20 percent, effective January 1, 2015. As a result of the enacted legislation, in 2015, Apache recorded a deferred tax benefit of $414 million related to the remeasurement of the Company’s December 31, 2014 U.K. deferred income tax liability.

In 2014, Apache evaluated its permanent reinvestment position and determined that undistributed earnings from certain foreign subsidiaries located in Apache’s Australia, Egypt, and North Sea regions will no longer be permanently reinvested. As a result of this change in position, the Company recorded $560 million of U.S. deferred income tax expense on undistributed earnings that were previously considered permanently reinvested as a component of continuing operations. In addition, the Company recorded $311 million of U.S. deferred income tax expense on foreign earnings that were distributed to the U.S. in 2014. The Company’s Canadian subsidiaries do not currently have undistributed earnings.

The Company has recorded an increase in valuation allowance against certain deferred tax assets, primarily driven by asset impairments. The Company has assessed the future potential to realize 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 and expectations for the future.

In 2016, 2015, and 2014, the Company's valuation allowance decreased by $33 million, increased by $3.9 billion, and increased by $966 million, respectively, as detailed in the table below:

	2016			2015		2014
	(In millions)
Balance at beginning of year	$	5,434		$	1,564	$	598
State(1)	(43		)	151		62
U.S.	139			2,159		—
Foreign(2)	(129		)	1,560		1,021
Discontinued operations(3)	—			—		(117		)
Balance at end of year	$	5,401		$	5,434	$	1,564

(1) Reported as a component of state income taxes.

(2) In 2015, Apache’s subsidiaries completed the sale of its interest in the Kitimat LNG project. As such, the deferred tax assets, liabilities, and valuation allowance related to the project were removed for 2015.

(3) In 2014, Apache’s subsidiaries completed the sale of all of the Company’s operations in Argentina. As such, the deferred tax assets, liabilities, and valuation allowance related to Argentina were removed for 2014.

On December 31, 2016, the Company had net operating losses as follows:

	Amount		Expiration
	(In millions)
Net operating losses:
U.S.	$	2,452	2018 - 2037
State	4,774		Various
Canada	125		2028 - 2035

The Company has a U.S. net operating loss carryforward of $2.5 billion, which includes $197 million of net operating loss subject to annual limitation under Section 382 of the Internal Revenue Code. The Company also has $829 million of capital loss carryforwards in Canada, which have an indefinite carryover period. The Company has recorded a valuation allowance against the U.S. net operating loss subject to Section 382 limitation, the state net operating loss, the Canadian net operating loss, and the Canadian capital loss because it is probable that these attributes will expire unutilized.

On December 31, 2016, the Company had foreign tax credits as follows:

	Amount		Expiration
	(In millions)
Foreign tax credits	$	2,226	2025-2026

The Company has a $2.2 billion U.S. foreign tax credit carryforward. The Company has recorded a valuation allowance against the U.S. foreign tax credits listed above because it is probable that these attributes will expire unutilized.

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. Tax positions generally refer to a position taken in a previously filed income tax return or expected to be included in a tax return to be filed in the future that is reflected in the measurement of current and deferred income tax assets and liabilities. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:

	2016			2015		2014
	(In millions)
Balance at beginning of year	$	19		$	—	$	3
Additions based on tax positions related to the current year	15			19		—
Reductions for tax positions of prior years	(19		)	—		(3		)
Balance at end of year	$	15		$	19	$	—

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, 2016, 2015, and 2014 the Company recorded tax expense of nil, tax expense of $1 million, and tax benefit of $1 million, respectively, for interest and penalties. At December 31, 2016, 2015, and 2014 the Company had an accrued liability for interest and penalties of nil, $1 million, and nil, respectively.

In 2016 and 2015, the Company recorded a $4 million net reduction and a $19 million increase in its reserve for uncertain tax positions, respectively. In 2014, the Internal Revenue Service concluded its audit of the 2011 and 2012 tax years, and the Company reduced its unrecognized tax benefit by $3 million as a result of the conclusion of this audit.

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.	2012
Canada	2012
Egypt	1998
U.K.	2014

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2016

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

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 $15 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 Claims

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) in an amount up to $67.5 million pursuant to the terms and conditions of stock purchase agreements entered in 2006 between Company subsidiaries and subsidiaries of Pioneer.

Louisiana Restoration

Louisiana surface owners often file lawsuits or assert claims against oil and gas companies, including Apache, claiming that operators and working interest owners in the chain of title are liable for environmental damages on the leased premises, including damages measured by the cost of restoration of the leased premises to their original condition, regardless of the value of the underlying property. 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 as noted. Further, 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 these lawsuits and claims.

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. Plaintiff seeks unspecified 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 many defendants in the lawsuit. In 2014 the Louisiana state government passed a law (SB 469) clarifying that only entities authorized under the Coastal Zone Management Act may bring litigation to assert claims arising out of the permitted activities. Plaintiff is not one of those authorized entities. On February 13, 2015, the federal court entered judgment in favor of defendants dismissing all of plaintiff’s claims with prejudice on various grounds, and plaintiff appealed the case to the 5^th Circuit Court of Appeals. The appeal is still pending. The overall exposure related to this lawsuit is not currently determinable. While an adverse judgment against Apache might be possible, Apache intends to continue to vigorously oppose the claims, including by defending against plaintiff’s appeal of the federal court’s judgment.

On November 8, 2013, Plaquemines Parish, Louisiana, filed three lawsuits against Apache and other oil and gas producers in the Parish’s 25th Judicial District Court, captioned Parish of Plaquemines v. Rozel Operating Company et al., Docket No. 60-996; Parish of Plaquemines v. Apache Oil Corporation et al., Docket No. 610; and Parish of Plaquemines v. HHE Energy Company et al., Docket No. 60-983. On or about February 4, 2016, Cameron Parish, Louisiana, filed six new lawsuits against Apache and other oil and gas producers in the Parish’s 38th Judicial District Court, captioned Parish of Cameron v. BEPCO, L.P., et al., Docket No. 10-19572; Parish of Cameron v. BP America Production Company et al., Docket No. 10-19576; Parish of Cameron v. Apache Corporation (of Delaware) et al., Docket No. 10-19579; Parish of Cameron v. Atlantic Richfield Company et al., Docket No. 10-19577; Parish of Cameron v. Alpine Exploration Companies, Inc., et al., Docket No. 19580; and Parish of Cameron v. Auster Oil and Gas, Inc., et al, Docket No. 10-19582. On July 28, 2016, Vermillion Parish, Louisiana, filed an amended petition against Apache and other oil and gas producers in the 15^th Judicial District Court, captioned Keith Stutes, District Attorneyfor the 15^th Judicial District of the State of Louisiana v. Gulfport Energy, et al., Docket No.102156. On September 30, 2016, St. Bernard Parish, Louisiana, filed an Amended Petition against Apache and other oil and gas producers in the 34^th Judicial District Court, captioned The Parish of St. Bernard v. Atlantic Richfield et al., Docket No. 16-1228. Many similar lawsuits have been filed against other oil and gas producers in Parishes across south Louisiana. In these cases, the Parishes, as plaintiffs, allege 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 Parish or the State of Louisiana. Plaintiffs allege that defendants caused substantial damage to land and water bodies located in the coastal zone of Louisiana. Plaintiffs seek, 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. While an adverse judgment against Apache might be possible, Apache intends to vigorously oppose these claims.

Apollo Exploration Lawsuit

In a case captioned Apollo Exploration, LLC, Cogent Exploration, Ltd. Co. & SellmoCo, LLC v. Apache Corporation, Cause No. CV50538 in the 385th Judicial District Court, Midland County, Texas, in a Fourth Amended Petition filed on March 21, 2016, plaintiffs allege damages in excess of $500 million (having previously claimed in excess of $1.1 billion) relating to purchase and sale agreements, mineral leases, and areas of mutual interest agreements concerning properties located in Hartley, Moore, Potter, and Oldham Counties, Texas. Apache believes that plaintiffs’ claims lack merit, and further that plaintiffs’ alleged damages are grossly inflated. Apache will vigorously oppose the claims.

Escheat Audits

In September 2010, the State of Delaware, Department of Finance, Division of Revenue (Unclaimed Property) (Delaware), notified Apache Corporation that Delaware’s consultant, Kelmar Associates (Kelmar), would examine Apache’s books and records and those of its subsidiaries and related entities to determine compliance with Delaware Escheat Laws.

Delaware completed its audit of the Company's accounts payable, payroll, and royalty payments, on which the Company expects an assessment of less than $200,000. However, Delaware suspended its audit before completing its examination of the Company’s accounts receivable, following the June 2016 Temple-Inland v. Cook court decision, in which the Delaware federal court determined thatDelaware’s current method and technique for estimating a company’s unclaimed property liability violates the due process requirements of the U.S. Constitution.  In response to that decision, the Delaware Legislature is considering changes to its unclaimed property statute.  The timing and extent of any legislative modifications is currently unknown.

Burrup-Related Gas Supply Lawsuits

In the cases captioned Radhika Oswal v. Australia and New Zealand Banking Group Limited (ANZ) et al., No. SCI 2011 4653 and Pankaj Oswal v. Australia and New Zealand Banking Group Limited (ANZ) et al., No. SCI 2012 01995, in the Supreme Court of Victoria, Australia, trial commenced on May 30, 2016. In August 2016, the cases settled on confidential terms including an exchange of consideration that did not have a material effect on the Company’s financial position.

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, 2016, the Company had an undiscounted reserve for environmental remediation of approximately $51 million. Apache is not aware of any environmental claims existing as of December 31, 2016 that have not been provided for or would otherwise have a material impact on its financial position or results of operations. There can be no assurance however, that current regulatory requirements will not change or past non-compliance with environmental laws will not be discovered on the Company’s properties.

Apache Canada Ltd. (ACL) reported a produced water release from a water injection pipeline in a remote area of the Belloy Field that occurred on or about May 4, 2016, and an H2S leak at the Zama 10-33-115-06 on or about September 19, 2016. The causes of these incidents remain under investigation. With respect to previous releases of produced water that occurred in the Zama area on or between October 3 and October 25, 2013, and in the Belloy Field on or about January 20, 2014, the Company resolved all of the charges associated with these releases with the Crown. The Company does not expect the economic impact of any of these incidents to have a material effect on the Company’s financial position, results of operations, or liquidity.

LNG Divestiture Dispute

Each of Woodside and the Company asserted claims against the other resulting in court proceedings in the Supreme Court of Western Australia and the Court of Queen’s Bench of Alberta, Calgary. Woodside also initiated third party expert determination proceedings at the ICC International Centre for ADR concerning certain aspects of its purchase price adjustment claims. Each of these proceedings has now been dismissed by agreement in November 2016. The parties have resolved the central matters in dispute on mutually agreeable terms and there was no significant impact on the Company’s financial position, results of operations, or liquidity.

Australian Operations Divestiture Dispute

By a Sale and Purchase Agreement dated April 9, 2015 (SPA), the Company and its subsidiaries divested their remaining Australian operations to Quadrant Energy Pty Ltd (Quadrant). Closing occurred on June 5, 2015. By letter dated June 6, 2016, Quadrant provided the Company with a notice of claim under the SPA claiming approximately $200 million in the aggregate. The Company believes that these claims lack merit and will not have a material adverse effect on the Company’s financial position, results of operation, or liquidity.

Contractual Obligations

At December 31, 2016, contractual obligations for long-term operating leases, capital leases, and purchase obligations are as follows:

Net Minimum Commitments	Total		2017		2018-2019		2020-2021		2022 & Beyond
	(In millions)
Drilling rigs	$	244	$	177	$	67	$	—	$	—
Purchase obligations(1)	680		119		287		250		24
Operating lease obligations(2)	258		56		95		37		70
Capital lease obligations	$	43	$	1	$	3	$	3	$	36
Total Net Minimum Commitments	$	1,225	$	353	$	452	$	290	$	130

(1) Includes minimum commitments associated with long-term take-or-pay contracts, NGL processing agreements, drilling work program commitments, and agreements to secure capacity rights on third-party pipelines.

(2) Amounts include long-term lease payments for office space, aircraft, supply and standby vessels, gas pipeline and land leases, and equipment related to exploration, development, and production activities, such as compressors. The Company expects to receive $10 million in sublease income associated with these leases.

The table above includes leases for buildings, facilities, and related equipment with varying expiration dates through 2042. Net rental expense for continuing operations was $59 million, $57 million, and $45 million for 2016, 2015, and 2014, respectively. Costs incurred under take-or-pay and throughput obligations were $86 million, $92 million, and $89 million for 2016, 2015, and 2014, respectively.

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Retirement and Deferred Compensation Plans

12 Months Ended

Dec. 31, 2016

Compensation and Retirement Disclosure [Abstract]

Retirement and Deferred Compensation Plans

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, at its discretion, 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 Canada Ltd. and Apache North Sea Limited maintain separate retirement plans, as required under the laws of Canada and the U.K., respectively.

The aggregate annual cost to Apache of all U.S. plans, the money purchase retirement plan, non-qualified retirement/savings plan, and non-qualified restorative retirement savings plan was $82 million, $77 million, and $107 million for 2016, 2015, and 2014, 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 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 or at the date they become eligible for Medicare, 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, 2016, 2015, and 2014, 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.

	2016						2015						2014
	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	$	202		$	26		$	216		$	22		$	189		$	28
Service cost	4			2			5			2			5			3
Interest cost	7			1			8			1			9			1
Foreign currency exchange rate changes	(39		)	—			(10		)	—			(13		)	—
Actuarial losses (gains)	32			(2		)	(10		)	—			31			(9		)
Effect of curtailment and settlements	—			—			—			2			—			—
Benefits paid	(4		)	(3		)	(7		)	(2		)	(5		)	(2		)
Retiree contributions	—			2			—			1			—			1
Projected benefit obligation at end of year	202			26			202			26			216			22
Change in Plan Assets
Fair value of plan assets at beginning of year	197			—			206			—			191			—
Actual return on plan assets	46			—			1			—			25			—
Foreign currency exchange rates	(39		)	—			(10		)	—			(13		)	—
Employer contributions	6			1			7			1			8			1
Benefits paid	(4		)	(3		)	(7		)	(2		)	(5		)	(2		)
Retiree contributions	—			2			—			1			—			1
Fair value of plan assets at end of year	206			—			197			—			206			—
Funded status at end of year	$	4		$	(26	)	$	(5	)	$	(26	)	$	(10	)	$	(22	)
Amounts recognized in Consolidated Balance Sheet
Current liability	$	—		$	(2	)	$	—		$	(2	)	$	—		$	(1	)
Non-current asset (liability)	4			(24		)	(5		)	(24		)	(10		)	(21		)
	$	4		$	(26	)	$	(5	)	$	(26	)	$	(10	)	$	(22	)
Pre-tax Amounts Recognized in Accumulated Other Comprehensive Income (Loss)
Accumulated gain (loss)	$	(25	)	$	9		$	(32	)	$	9		$	(37	)	$	10
Weighted Average Assumptions used as of December 31
Discount rate	2.70		%	3.76		%	3.90		%	3.95		%	3.70		%	3.62		%
Salary increases	4.80		%	N/A			4.60		%	N/A			4.60		%	N/A
Expected return on assets	3.40		%	N/A			4.10		%	N/A			3.90		%	N/A
Healthcare cost trend
Initial	N/A			7.00		%	N/A			7.00		%	N/A			7.00		%
Ultimate in 2025	N/A			5.00		%	N/A			5.00		%	N/A			5.00		%

As of December 31, 2016, 2015, and 2014, the accumulated benefit obligation for the U.K. Pension Plan was $181 million, $169 million, and $183 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 a 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
	2016		2016		2015
Asset Category
Equity securities:
U.K. quoted equities	14	%	14	%	14	%
Overseas quoted equities	26	%	26	%	26	%
Total equity securities	40	%	40	%	40	%
Debt securities:
U.K. Government bonds	47	%	47	%	48	%
U.K. corporate bonds	12	%	12	%	12	%
Debt securities	59	%	59	%	60	%
Cash	1	%	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, 2016 and December 31, 2015:

	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, 2016
Equity securities:
U.K. quoted equities(1)	$	28	$	—	$	—	$	28
Overseas quoted equities(2)	54		—		—		54
Total equity securities	82		—		—		82
Debt securities:
U.K. Government bonds(3)	97		—		—		97
U.K. corporate bonds(4)	25		—		—		25
Total debt securities	122		—		—		122
Cash	2		—		—		2
Fair value of plan assets	$	206	$	—	$	—	$	206
December 31, 2015
Equity securities:
U.K. quoted equities(1)	$	27	$	—	$	—	$	27
Overseas quoted equities(2)	53		—		—		53
Total equity securities	80		—		—		80
Debt securities:
U.K. Government bonds(3)	93		—		—		93
U.K. corporate bonds(4)	24		—		—		24
Total debt securities	117		—		—		117
Fair value of plan assets	$	197	$	—	$	—	$	197

(1) This category comprises U.K. passive equities, which are benchmarked against the FTSE 350 Index.

(2) This category includes overseas equities, which comprises 30 percent passive global equities benchmarked against the MSCI World (NDR) Index, 12 percent passive global equities (hedged) benchmarked against the MSCI World (NDR) Hedged Index, 30 percent fundamental indexation global equities benchmarked against the FTSE RAFI Developed 1000 index, 12 percent fundamental indexation global equities (hedged) benchmarked against the FTSE RAFI Developed 1000 Hedge Index, and 16 percent emerging markets benchmarked against the MSCI Emerging Markets (NDR) Index, which has 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, which comprises 48 percent index-linked gilts benchmarked against the FTSE Actuaries Government Securities Index-Linked Over 5 Years Index, 37 percent sterling nominal LDI bonds, and 15 percent sterling inflation linked LDI bonds, both benchmarked against ILIM Custom Benchmark index.

(4) This category comprises U.K. corporate bonds: 12 percent benchmarked against the BofAML Sterling Corporate & Collaterlised (excluding Subordinated) 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, 2016, 2015, and 2014:

	2016						2015						2014
	Pension Benefits			Postretirement Benefits			Pension Benefits			Postretirement Benefits			Pension Benefits			Postretirement Benefits
	(In millions)
Component of Net Periodic Benefit Costs
Service cost	$	4		$	2		$	5		$	2		$	5		$	3
Interest cost	7			1			8			1			9			1
Expected return on assets	(7		)	—			(8		)	—			(11		)	—
Amortization of actuarial (gain) loss	1			(1		)	2			—			1			—
Curtailment (gain) loss	—			—			—			—			—			—
Net periodic benefit cost	$	5		$	2		$	7		$	3		$	4		$	4
Weighted Average Assumptions used to determine Net Period Benefit Cost for the Years ended December 31
Discount rate	3.90		%	3.95		%	3.70		%	3.62		%	4.60		%	4.33		%
Salary increases	4.60		%	N/A			4.60		%	N/A			4.90		%	N/A
Expected return on assets	4.10		%	N/A			3.90		%	N/A			5.60		%	N/A
Healthcare cost trend
Initial	N/A			7.00		%	N/A			7.00		%	N/A			7.00		%
Ultimate in 2025	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	5		(4		)

Apache expects to contribute approximately $5 million to its pension plan and $2 million to its postretirement benefit plan in 2017. The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:

	Pension Benefits		Postretirement Benefits
	(In millions)
2017	$	4	$	2
2018	4		2
2019	4		2
2020	4		2
2021	4		2
Years 2022-2026	24		9

XML

Capital Stock

12 Months Ended

Dec. 31, 2016

Equity [Abstract]

Capital Stock

CAPITAL STOCK

Common Stock Outstanding

	2016	2015	2014
Balance, beginning of year	378,034,175	376,504,892	395,772,908
Shares issued for stock-based compensation plans:
Treasury shares issued	11,504	17,525	17,454
Common shares issued	1,393,997	1,511,758	1,665,259
Treasury shares acquired	—	—	(20,950,729	)
Balance, end of year	379,439,676	378,034,175	376,504,892

Net Income (Loss) per Common Share

A reconciliation of the components of basic and diluted net income (loss) per common share for the years ended December 31, 2016, 2015, and 2014 is presented in the table below.

	2016							2015							2014
	Loss			Shares	Per Share			Income (Loss)			Shares	Per Share			Loss			Shares	Per Share
	(In millions, except per share amounts)
Basic and Diluted:
Loss from continuing operations	$	(1,372	)	379	$	(3.62	)	$	(10,844	)	378	$	(28.70	)	$	(6,653	)	384	$	(17.32	)
Income (loss) from discontinued operations	(33		)	379	(0.09		)	492			378	1.30			(1,707		)	384	(4.44		)
Loss attributable to common stock	$	(1,405	)	379	$	(3.71	)	$	(10,352	)	378	$	(27.40	)	$	(8,360	)	384	$	(21.76	)

The diluted EPS calculation excludes options and restricted shares that were anti-dilutive totaling 4.7 million, 7.0 million, and 4.5 million for the years ended December 31, 2016, 2015, and 2014, respectively.

Stock Repurchase Program

Apache’s Board of Directors has authorized the purchase of up to 40 million shares of the Company’s common stock. 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, and through December 31, 2014, had repurchased a total of 32.2 million shares at an average price of $88.96 per share. The Company has not purchased any additional shares during 2016 or 2015, and is not obligated to acquire any specific number of shares.

Common Stock Dividend

The Company paid common stock dividends of $1.00 per share in 2016, $1.00 per share in 2015, and $0.95 per share in 2014.

Stock Compensation Plans

The Company has several stock-based compensation plans, which include stock options, restricted stock, and conditional restricted stock unit plans. On May 12, 2016, the Company's shareholders approved the 2016 Omnibus Compensation Plan (the 2016 Plan), which is intended to provide eligible employees with equity-based incentives. The 2016 Plan provides for the granting of Incentive Stock Options, Non-Qualified Stock Options, Performance Awards, Restricted Stock Awards, Restricted Stock Units, Stock Appreciation Rights, Cash Awards, or any combination of the foregoing. A total of 22.9 million shares were authorized and available for grant under the 2016 Plan as of December 31, 2016. Previously approved plans remain in effect solely for the purpose of governing grants still outstanding that were issued prior to approval of the 2016 Plan. All new grants are issued from the 2016 Plan.

For 2016, 2015, and 2014, stock-based compensation expensed was $131 million, $100 million, and $148 million ($93 million, $65 million, and $95 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:

	2016		2015		2014
	(In millions)
Stock-based compensation expensed	$	131	$	100	$	148
Stock-based compensation capitalized	40		53		62
Total stock-based compensation costs	$	171	$	153	$	210

Stock Options

As of December 31, 2016, the Company had issued options to purchase shares of the Company’s common stock under the employee stock option plan adopted in 2005 (the Stock Option Plan), as well as the 2007 Omnibus Equity Compensation Plan (the 2007 Plan), the 2011 Plan, and the 2016 Plan (together, the Omnibus Plans). New shares of Company stock will be issued for employee stock option exercises. Under the Stock Option Plan 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 issued prior to 2016 generally become exercisable ratably over a four-year period and expire 10 years after granted. Options granted in or after 2016 become exercisable ratably over a three-year period and expire 10 years after granted. The Omnibus Plans and the 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 Plan and the Omnibus Plans is presented in the table and narrative below:

	2016
	Shares Under Option		Weighted Average Exercise Price
	(In thousands)
Outstanding, beginning of year	4,931		$	91.52
Granted	873		41.24
Exercised	—		—
Forfeited or expired	(691	)	76.99
Outstanding, end of year(1)	5,113		84.89
Expected to vest(2)	887		46.88
Exercisable, end of year(3)	4,177		93.40

(1) As of December 31, 2016, options outstanding had a weighted average remaining contractual life of 4.6 years and aggregate intrinsic value of $18 million.

(2) As of December 31, 2016, options expected to vest had a weighted average remaining contractual life of 8.7 years and aggregate intrinsic value of $17 million.

(3) As of December 31, 2016, options exercisable had a weighted average remaining contractual life of 3.7 years and aggregate intrinsic value of nil.

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.

	2016			2015	2014
Expected volatility	32.72		%	N/A	N/A
Expected dividend yields	2.42		%	N/A	N/A
Expected term (in years)	6			N/A	N/A
Risk-free rate	1.44		%	N/A	N/A
Weighted-average grant-date fair value	$	10.38		N/A	N/A

There were no options exercised during 2016. The intrinsic value of options exercised during 2015 and 2014 was approximately $3 million and $13 million, respectively. As of December 31, 2016, the total compensation cost related to non-vested options not yet recognized was $6 million, which will be recognized over the remaining vesting period of the options.

In January 2017, the Company issued 489,773 options to purchase shares of the Company’s common stock to eligible employees under the 2016 Plan. The total compensation cost of $9 million is estimated to be recognized over a three-year vesting period of these options.

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 2016, the Company awarded 4,049,023 restricted stock units at a weighted-average per-share market price of $47.37. In 2015 and 2014, the Company awarded 2,976,562 and 3,046,744 restricted stock units at a weighted-average per-share market price of $61.65 and $86.87, 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 2016, 2015, and 2014, $113 million ($73 million after tax), $90 million ($58 million after tax), and $111 million ($72 million after tax), respectively, was charged to expense. In 2016, 2015, and 2014, $35 million, $48 million, and $47 million was capitalized, respectively. As of December 31, 2016, there was $233 million of total unrecognized compensation cost related to 6,061,803 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 2016, 2015, and 2014 was approximately $151 million, $149 million, and $138 million, respectively. A summary of restricted stock unit activity for the year ended December 31, 2016, is presented below.

	Shares		Weighted- Average Grant- Date Fair Value
	(In thousands)
Non-vested at January 1, 2016	4,570		$	70.86
Granted	4,049		47.37
Vested	(2,081	)	72.59
Forfeited	(476	)	58.05
Non-vested at December 31, 2016	6,062		55.55

In January 2017, the Company awarded 1,866,606 restricted stock units at a weighted-average per-share market price of $63.25 under the 2016 Plan to eligible employees. The total compensation cost of $118 million, absent any forfeitures, is estimated to be recognized over a three-year vesting period of these restricted stock units.

Total Shareholder Return (TSR) 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 the total shareholder return programs were outstanding at December 31, 2016, as described below:

• In January 2013, the Company’s Board of Directors approved the 2013 TSR 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 canceled 918,016 awards under the 2013 Performance Program for nonexecutive employees. Based on measurements of total shareholder return relative to the designated peer group at December 31, 2015, shares were paid out at 70 percent of target. A total of 29,957 awards were outstanding at December 31, 2016.

• In January 2014, the Company’s Board of Directors approved the 2014 TSR Program, pursuant to the 2011 Plan. In January 2014, eligible employees received initial conditional restricted stock unit awards totaling 157,406 units. Based on measurements of total shareholder return relative to the designated peer group at December 31, 2016, shares were paid out at 100 percent of target. A total of 47,867 awards were outstanding at December 31, 2016.

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 2016, 2015, and 2014, $0.7 million ($0.5 million after tax), $0.6 million ($0.4 million after tax), and $18 million ($11 million after tax), respectively, was charged to expense. During 2016, 2015, and 2014, $0.1 million, $0.3 million, and $7 million was capitalized, respectively. As of December 31, 2016, there was $1.2 million of total unrecognized compensation cost related to 77,824 unvested conditional restricted stock units. The weighted-average remaining life of the unvested conditional restricted stock units is approximately 0.7 years.

	Shares		Weighted- Average Grant- Date Fair Value(1)
	(In thousands)
Non-vested at January 1, 2016	172		$	78.22
Granted	—		—
Vested	(34	)	76.07
Forfeited or expired	(60	)	71.20
Non-vested at December 31, 2016	78		77.10

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

Business Performance Restricted Stock Units

Apache has a business performance program for certain eligible employees with 50 percent of the shares payout based upon the TSR program payout model as described above, and the remaining 50 percent of the shares based on performance and financial objectives as defined in the plan. The overall results of the objectives will be calculated at the end of the award’s stated performance period and, if a payout is warranted, applied to the target number of restricted stock units awarded. The business performance shares will immediately vest 50 percent at the end of the three-year performance period, with the remaining 50 percent vesting at the end of the following year. Grants from the total shareholder return programs outstanding at December 31, 2016, are as described below:

• In February 2015, the Company’s Board of Directors approved the 2015 Business Performance Program, pursuant to the 2011 Plan. Eligible employees received initial conditional restricted stock unit awards totaling 602,304 units. The actual amount of shares awarded will be between zero and 150 percent of target. A total of 431,707 units were outstanding as of December 31, 2016, from which a minimum of zero and a maximum of 647,561 shares could be awarded.

• In January 2016, the Company’s Board of Directors approved the 2016 Business Performance Program, pursuant to the 2011 Plan. Eligible employees received the initial conditional restricted stock unit totaling 871,369. The actual amount of shares awarded will be between zero and 200 percent of target. A total of 793,442 units were outstanding as of December 31, 2016, from which a minimum of zero and a maximum of 1,586,884 shares 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 2016 and 2015, $14 million ($9 million after tax) and $3 million ($2 million after tax), respectively, were charged to expense. During 2016 and 2015, $2 million and $1 million were capitalized, respectively. As of December 31, 2016, there was $37 million of total unrecognized compensation cost related to 1,225,149 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, 2016	501		$	66.53
Granted	871		34.19
Vested	—		—
Forfeited or expired	(147	)	45.65
Non-vested at December 31, 2016	1,225		45.60

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

In January 2017, the Company’s Board of Directors approved the 2017 Performance Program, pursuant to the 2016 Plan, with terms similar to the 2016 Performance Program described above. Eligible employees received the initial conditional restricted stock unit totaling 604,147 units, with the ultimate number of restricted stock units to be awarded ranging from zero to a maximum of 1,208,294 units. The grant date fair value per award was $66.97.

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Accumulated Other Comprehensive Loss

12 Months Ended

Dec. 31, 2016

Equity [Abstract]

Accumulated Other Comprehensive Loss

ACCUMULATED OTHER COMPREHENSIVE LOSS

Components of accumulated other comprehensive loss include the following:

	For the Year Ended December 31,
	2016			2015			2014
	(In millions)
Currency translation adjustment(1)	$	(109	)	$	(109	)	$	(109	)
Unfunded pension and postretirement benefit plan (Note 11)	(3		)	(10		)	(7		)
Accumulated other comprehensive loss	$	(112	)	$	(119	)	$	(116	)

(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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Major Customers

12 Months Ended

Dec. 31, 2016

Risks and Uncertainties [Abstract]

Major Customers

MAJOR CUSTOMERS

In 2016 and 2015, purchases by China Petroleum & Chemical Corporation and its subsidiaries accounted for 21 percent and 12 percent, respectively, of the Company's worldwide oil and gas production revenues. In 2016 and 2015, purchases by Egyptian General Petroleum Company and its subsidiaries accounted for 12 percent and 11 percent, respectively, of the Company's worldwide oil and gas production revenues. In 2015 and 2014, purchases by Royal Dutch Shell plc and its subsidiaries accounted for 11 percent and 19 percent, respectively, of the Company’s worldwide oil and gas production revenues.

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Business Segment Information

12 Months Ended

Dec. 31, 2016

Segment Reporting [Abstract]

Business Segment Information

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, 2016, the Company had production in four reporting segments: the United States, Canada, Egypt, and the U.K. North Sea. Apache also pursues exploration interests in Suriname that may, over time, result in a reportable discovery and development opportunity. Financial information for each area is presented below:

	United States			Canada			Egypt(1)		North Sea			Other International			Total(1)
	(In millions)
2016
Oil and gas production revenues	$	1,997		$	343		$	2,057	$	970		$	—		$	5,367
Operating Expenses:
Lease operating expenses	553			181			446		314			—			1,494
Gathering and transportation	80			68			44		8			—			200
Taxes other than income	139			20			—		(33		)	—			126
Depreciation, depletion, and amortization	1,138			183			778		519			—			2,618
Exploration	285			88			48		37			15			473
Asset retirement obligation accretion	34			47			—		75			—			156
Impairments	80			367			1		655			—			1,103
Operating Income (Loss)	$	(312	)	$	(611	)	$	740	$	(605	)	$	(15	)	(803		)
Other Income (Expense):
Gain on divestitures, net															21
Other															(34		)
General and administrative															(410		)
Transaction, reorganization, and separation															(39		)
Financing costs, net															(417		)
Net Loss From Continuing Operations Before Income Taxes															$	(1,682	)
Net Property and Equipment	$	11,168		$	1,464		$	3,362	$	2,834		$	39		$	18,867
Total Assets	$	12,403		$	1,591		$	4,893	$	3,584		$	48		$	22,519
Additions to Net Property and Equipment	$	926		$	34		$	459	$	260		$	2		$	1,681

	United States			Canada			Egypt(1)			North Sea			Other International			Total(1)
	(In millions)
2015
Oil and gas production revenues	$	2,637		$	498		$	2,095		$	1,280		$	—		$	6,510
Operating Expenses:
Lease operating expenses	739			244			522			349			—			1,854
Gathering and transportation	68			89			45			9			—			211
Taxes other than income	184			26			9			63			—			282
Depreciation, depletion, and amortization	1,558			301			927			514			—			3,300
Exploration	2,145			231			154			237			4			2,771
Asset retirement obligation accretion	28			43			—			74			—			145
Impairments	6,266			1,593			1,255			211			147			9,472
Operating Loss	$	(8,351	)	$	(2,029	)	$	(817	)	$	(177	)	$	(151	)	(11,525		)
Other Income (Expense):
Gain on divestitures, net																281
Other																98
General and administrative																(380		)
Transaction, reorganization, and separation																(132		)
Financing costs, net																(511		)
Net Loss From Continuing Operations Before Income Taxes																$	(12,169	)
Net Property and Equipment	$	11,753		$	2,074		$	3,712		$	3,263		$	36		$	20,838
Total Assets	$	12,782		$	2,225		$	6,165		$	4,280		$	48		$	25,500
Additions to Net Property and Equipment	$	2,099		$	403		$	862		$	715		$	27		$	4,106

2014
Oil and gas production revenues	$	5,744		$	1,092		$	3,643	$	2,316		$	—		$	12,795
Operating Expenses:
Lease operating expenses	921			384			499		434			—			2,238
Gathering and transportation	93			123			40		17			—			273
Taxes other than income	350			31			11		185			—			577
Depreciation, depletion, and amortization	2,408			439			872		807			—			4,526
Exploration	2,113			162			112		119			(7		)	2,499
Asset retirement obligation accretion	43			39			—		72			—			154
Impairments	2,622			2,412			173		1,895			—			7,102
Operating Income (Loss)	$	(2,806	)	$	(2,498	)	$	1,936	$	(1,213	)	$	7		(4,574		)
Other Income (Expense):
Loss on divestitures, net															(1,608		)
Other															285
General and administrative															(453		)
Transaction, reorganization, and separation															(67		)
Financing costs, net															(413		)
Net Loss From Continuing Operations Before Income Taxes															$	(6,830	)
Net Property and Equipment	$	19,507		$	4,197		$	5,141	$	3,300		$	9		$	32,154
Total Assets	$	21,487		$	4,728		$	6,926	$	4,480		$	544		$	38,165
Additions to Net Property and Equipment	$	7,006		$	1,358		$	1,293	$	1,060		$	8		$	10,725

(1) Includes a noncontrolling interest in Egypt.

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Supplemental Oil and Gas Disclosures (Unaudited)

12 Months Ended

Dec. 31, 2016

Extractive Industries [Abstract]

Supplemental Oil and Gas Disclosures (Unaudited)

 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. In the second quarter of 2015, Apache completed the sale of its Australian LNG business and oil and gas assets, and as such the results of Australia oil and gas assets have been classified as discontinued operations.

	United States			Canada			Egypt(3)		North Sea			Other International			Total(3)(4)
	(In millions, except per boe)
2016
Oil and gas production revenues	$	1,997		$	343		$	2,057	$	970		$	—		$	5,367
Operating cost:
Depreciation, depletion, and amortization(1)	1,055			174			733		498			—			2,460
Asset retirement obligation accretion	34			47			—		75			—			156
Lease operating expenses	553			181			446		314			—			1,494
Gathering and transportation	80			68			44		8			—			200
Exploration expenses	285			88			48		37			15			473
Impairments related to oil and gas properties	61			366			—		—			—			427
Production taxes(2)	135			18			—		(33		)	—			120
Income tax	(72		)	(162		)	354		28			—			148
	2,131			780			1,625		927			15			5,478
Results of operation	$	(134	)	$	(437	)	$	432	$	43		$	(15	)	$	(111	)
2015
Oil and gas production revenues	$	2,637		$	498		$	2,095	$	1,280		$	—		$	6,510
Operating cost:
Depreciation, depletion, and amortization(1)	1,455			251			780		490			—			2,976
Asset retirement obligation accretion	28			43			—		74			—			145
Lease operating expenses	739			244			522		349			—			1,854
Gathering and transportation	68			89			45		9			—			211
Exploration expenses	2,145			231			154		237			4			2,771
Impairments related to oil and gas properties	6,154			1,031			193		11			—			7,389
Production taxes(2)	178			23			—		58			—			259
Income tax	(2,886		)	(369		)	180		26			—			(3,049		)
	7,881			1,543			1,874		1,254			4			12,556
Results of operation	$	(5,244	)	$	(1,045	)	$	221	$	26		$	(4	)	$	(6,046	)
2014
Oil and gas production revenues	$	5,744		$	1,092		$	3,643	$	2,316		$	—		$	12,795
Operating cost:
Depreciation, depletion, and amortization(1)	2,294			382			735		784			—			4,195
Asset retirement obligation accretion	43			39			—		72			—			154
Lease operating expenses	921			384			499		434			—			2,238
Gathering and transportation	93			123			40		17			—			273
Exploration expenses	2,113			162			112		119			(7		)	2,499
Impairments related to oil and gas properties	2,372			1,645			173		1,878			—			6,068
Production taxes(2)	342			27			—		177			—			546
Income tax	(864		)	(421		)	938		(723		)	—			(1,070		)
	7,314			2,341			2,497		2,758			(7		)	14,903
Results of operation	$	(1,570	)	$	(1,249	)	$	1,146	$	(442	)	$	7		$	(2,108	)

(1) This amount only reflects DD&A of capitalized costs of oil and gas properties and, therefore, does not agree with DD&A reflected on Note 15—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 15—Business Segment Information.

(3) Includes noncontrolling interest in Egypt.

(4) Prior year 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)
2016
Acquisitions:
Proved	$	—		$	1		$	6	$	—	$	38		$	—	$	—	$	45
Unproved	110			7			49		—		4			—		—		170
Exploration	278			23			67		—		84			—		18		470
Development	420			27			353		—		150			—		—		950
Costs incurred(1)	$	808		$	58		$	475	$	—	$	276		$	—	$	18	$	1,635
(1) Includes capitalized interest and asset retirement costs as follows:
Capitalized interest	$	21		$	6		$	—	$	—	$	21		$	—	$	—	$	48
Asset retirement costs	(51		)	(13		)	—		—		(128		)	—		—		(192		)
2015
Acquisitions:
Proved	$	1		$	8		$	29	$	—	$	—		$	—	$	—	$	38
Unproved	313			23			—		—		—			—		—		336
Exploration	194			51			125		32		246			—		29		677
Development	1,729			151			741		98		479			—		—		3,198
Costs incurred(1)	$	2,237		$	233		$	895	$	130	$	725		$	—	$	29	$	4,249
(1)Includes capitalized interest and asset retirement costs as follows:
Capitalized interest	$	—		$	—		$	8	$	6	$	7		$	—	$	—	$	21
Asset retirement costs	123			8			—		—		(66		)	—		—		65
2014
Acquisitions:
Proved	$	102		$	—		$	11	$	—	$	—		$	—	$	—	$	113
Unproved	1,221			141			—		16		—			—		—		1,378
Exploration	505			93			207		131		103			9		1		1,049
Development	5,078			789			1,122		990		956			6		—		8,941
Costs incurred(1)	$	6,906		$	1,023		$	1,340	$	1,137	$	1,059		$	15	$	1	$	11,481
(1) Includes capitalized interest and asset retirement costs as follows:
Capitalized interest	$	17		$	—		$	9	$	90	$	29		$	3	$	—	$	148
Asset retirement costs	43			175			—		55		34			—		—		307
(2) Includes a noncontrolling interest in Egypt.

Capitalized Costs

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

	United States			Canada			Egypt(1)			North Sea			Other International		Total(1)
	(In millions)
2016
Proved properties	$	19,170		$	5,434		$	10,169		$	7,920		$	—	$	42,693
Unproved properties	1,465			109			76			280			39		1,969
	20,635			5,543			10,245			8,200			39		44,662
Accumulated DD&A	(10,034		)	(4,120		)	(7,287		)	(5,531		)	—		(26,972		)
	$	10,601		$	1,423		$	2,958		$	2,669		$	39	$	17,690
2015
Proved properties	$	18,692		$	5,812		$	9,798		$	7,426		$	—	$	41,728
Unproved properties	1,615			172			25			429			36		2,277
	20,307			5,984			9,823			7,855			36		44,005
Accumulated DD&A	(9,027		)	(3,958		)	(6,559		)	(4,913		)	—		(24,457		)
	$	11,280		$	2,026		$	3,264		$	2,942		$	36	$	19,548
(1) Includes a noncontrolling interest in Egypt.

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, 2013	457,981		80,526		119,242		22,524		100,327		14,195		794,795
December 31, 2014	444,440		75,876		128,712		29,996		105,746		—		784,770
December 31, 2015	348,797		67,847		144,164		—		104,255		—		665,063
December 31, 2016	300,900		51,508		138,771		—		91,138		—		582,317
Proved undeveloped reserves:
December 31, 2013	195,835		56,366		16,302		36,703		29,253		2,231		336,690
December 31, 2014	170,125		59,923		14,617		25,775		19,059		—		289,499
December 31, 2015	60,505		38,326		17,856		—		11,309		—		127,996
December 31, 2016	21,088		7,906		20,187		—		10,784		—		59,965
Total proved reserves:
Balance December 31, 2013	653,816		136,892		135,544		59,227		129,580		16,426		1,131,485
Extensions, discoveries and other additions	57,011		9,657		38,074		4,254		17,386		5		126,387
Purchase of minerals in-place	15,240		—		—		—		—		—		15,240
Revisions of previous estimates	3,083		(812	)	2,645		(216	)	(7	)	—		4,693
Production	(48,789	)	(6,421	)	(32,934	)	(7,494	)	(22,154	)	(620	)	(118,412	)
Sale of properties	(65,796	)	(3,517	)	—		—		—		(15,811	)	(85,124	)
Balance December 31, 2014	614,565		135,799		143,329		55,771		124,805		—		1,074,269
Extensions, discoveries and other additions	13,903		4,550		24,524		—		16,579		—		59,556
Purchase of minerals in-place	—		1,763		—		—		—		—		1,763
Revisions of previous estimates	(173,907	)	(27,966	)	27,330		11,189		(2,255	)	—		(165,609	)
Production	(45,138	)	(5,755	)	(33,163	)	(2,778	)	(21,657	)	—		(108,491	)
Sale of properties	(121	)	(2,218	)	—		(64,182	)	(1,908	)	—		(68,429	)
Balance December 31, 2015	409,302		106,173		162,020		—		115,564		—		793,059
Extensions, discoveries and other additions	9,614		3,372		17,599		—		9,766		—		40,351
Purchase of minerals in-place	21		—		—		—		438		—		459
Revisions of previous estimates	(58,882	)	(43,282	)	17,301		—		(3,851	)	—		(88,714	)
Production	(38,000	)	(4,787	)	(37,962	)	—		(19,995	)	—		(100,744	)
Sale of properties	(67	)	(2,062	)	—		—		—		—		(2,129	)
Balance December 31, 2016	321,988		59,414		158,958		—		101,922		—		642,282

(1)    2016, 2015, 2014, and 2013 includes proved reserves of 53 MMbbls, 54 MMbbls, 48 MMbbls, and 45 MMbbls, respectively, attributable to a noncontrolling interest in Egypt.

	Natural Gas Liquids
	(Thousands of barrels)
	United States		Canada		Egypt(1)		Australia	North Sea		Argentina		Total(1)
Proved developed reserves:
December 31, 2013	184,485		26,099		—		—	2,435		4,110		217,129
December 31, 2014	183,565		17,947		1,346		—	1,770		—		204,628
December 31, 2015	150,265		15,246		1,491		—	1,784		—		168,786
December 31, 2016	155,124		13,866		1,266		—	1,627		—		171,883
Proved undeveloped reserves:
December 31, 2013	63,538		9,970		—		—	215		1,009		74,732
December 31, 2014	69,828		7,168		212		—	371		—		77,579
December 31, 2015	24,939		4,839		78		—	295		—		30,151
December 31, 2016	17,311		2,473		131		—	646		—		20,561
Total proved reserves:
Balance December 31, 2013	248,023		36,069		—		—	2,650		5,119		291,861
Extensions, discoveries and other additions	47,516		1,163		1,820		—	1		—		50,500
Purchase of minerals in-place	2,916		—		—		—	—		—		2,916
Revisions of previous estimates	2,594		116		(11	)	—	(2	)	—		2,697
Production	(21,464	)	(2,256	)	(251	)	—	(508	)	(116	)	(24,595	)
Sale of properties	(26,192	)	(9,977	)	—		—	—		(5,003	)	(41,172	)
Balance December 31, 2014	253,393		25,115		1,558		—	2,141		—		282,207
Extensions, discoveries and other additions	5,768		1,473		144		—	689		—		8,074
Purchase of minerals in-place	—		976		—		—	—		—		976
Revisions of previous estimates	(64,226	)	(4,886	)	255		—	(321	)	—		(69,178	)
Production	(19,684	)	(2,236	)	(388	)	—	(413	)	—		(22,721	)
Sale of properties	(47	)	(357	)	—		—	(17	)	—		(421	)
Balance December 31, 2015	175,204		20,085		1,569		—	2,079		—		198,937
Extensions, discoveries and other additions	10,238		755		208		—	671		—		11,872
Purchase of minerals in-place	2		—		—		—	5		—		7
Revisions of previous estimates	6,824		(1,355	)	17		—	141		—		5,627
Production	(19,824	)	(2,098	)	(397	)	—	(623	)	—		(22,942	)
Sale of properties	(9	)	(1,048	)	—		—	—		—		(1,057	)
Balance December 31, 2016	172,435		16,339		1,397		—	2,273		—		192,444

(1)    2016, 2015, and 2014 includes proved reserves of 466 Mbbls, 523 Mbbls, and 519 Mbbls, respectively, attributable to a noncontrolling interest in Egypt.

	Natural Gas
	(Millions of cubic feet)
	United States		Canada		Egypt(1)		Australia		North Sea		Argentina		Total(1)
Proved developed reserves:
December 31, 2013	2,005,966		1,294,420		621,825		626,543		88,177		289,133		4,926,064
December 31, 2014	1,616,504		990,145		637,187		640,265		87,259		—		3,971,360
December 31, 2015	1,364,174		759,321		776,263		—		85,532		—		2,985,290
December 31, 2016	1,200,379		553,724		675,559		—		86,948		—		2,516,610
Proved undeveloped reserves:
December 31, 2013	667,160		439,037		190,355		975,224		18,988		121,584		2,412,348
December 31, 2014	580,299		527,623		171,696		964,554		23,228		—		2,267,400
December 31, 2015	208,594		162,809		53,969		—		19,760		—		445,132
December 31, 2016	231,304		45,312		42,109		—		23,813		—		342,538
Total proved reserves:
Balance December 31, 2013	2,673,126		1,733,457		812,180		1,601,767		107,165		410,717		7,338,412
Extensions, discoveries and other additions	203,318		383,077		125,899		81,156		23,803		—		817,253
Purchase of minerals in-place	21,337		—		—		—		—		—		21,337
Revisions of previous estimates	35,910		(12,626	)	17,326		—		(54	)	—		40,556
Production	(215,829	)	(117,816	)	(146,522	)	(78,104	)	(20,427	)	(12,722	)	(591,420	)
Sale of properties	(521,059	)	(468,324	)	—		—		—		(397,995	)	(1,387,378	)
Balance December 31, 2014	2,196,803		1,517,768		808,883		1,604,819		110,487		—		6,238,760
Extensions, discoveries and other additions	40,901		121,216		94,777		—		41,755		—		298,649
Purchase of minerals in-place	—		24,727		—		—		—		—		24,727
Revisions of previous estimates	(503,939	)	(325,375	)	61,442		8,162		(22,373	)	—		(782,083	)
Production	(160,614	)	(100,289	)	(134,870	)	(34,352	)	(23,647	)	—		(453,772	)
Sale of properties	(383	)	(315,917	)	—		(1,578,629	)	(930	)	—		(1,895,859	)
Balance December 31, 2015	1,572,768		922,130		830,232		—		105,292		—		3,430,422
Extensions, discoveries and other additions	219,633		30,234		35,202		—		20,814		—		305,883
Purchase of minerals in-place	7		—		—		—		6,677		—		6,684
Revisions of previous estimates	(215,378	)	(242,080	)	(4,305	)	—		4,239		—		(457,524	)
Production	(145,019	)	(88,792	)	(143,461	)	—		(26,261	)	—		(403,533	)
Sale of properties	(328	)	(22,456	)	—		—		—		—		(22,784	)
Balance December 31, 2016	1,431,683		599,036		717,668		—		110,761		—		2,859,148

(1)    2016, 2015, 2014, and 2013 include proved reserves of 239 Bcf, 277 Bcf, 270 Bcf, and 271 Bcf, respectively, 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, 2013	976,795		322,362		222,880		126,948		117,457		66,494		1,832,936
December 31, 2014	897,422		258,848		236,256		136,707		122,058		—		1,651,291
December 31, 2015	726,424		209,647		275,033		—		120,293		—		1,331,397
December 31, 2016	656,087		157,662		252,630		—		107,256		—		1,173,635
Proved undeveloped reserves:
December 31, 2013	370,566		139,509		48,028		199,240		32,633		23,504		813,480
December 31, 2014	336,670		155,028		43,446		186,534		23,301		—		744,979
December 31, 2015	120,210		70,300		26,929		—		14,897		—		232,336
December 31, 2016	76,950		17,931		27,336		—		15,399		—		137,616
Total proved reserves:
Balance December 31, 2013	1,347,361		461,871		270,908		326,188		150,090		89,998		2,646,416
Extensions, discoveries and other additions	138,413		74,666		60,877		17,780		21,354		5		313,095
Purchase of minerals in-place	21,712		—		—		—		—		—		21,712
Revisions of previous estimates	11,662		(2,800	)	5,522		(216	)	(18	)	—		14,150
Production	(106,225	)	(28,313	)	(57,605	)	(20,511	)	(26,067	)	(2,856	)	(241,577	)
Sale of properties	(178,831	)	(91,548	)	—		—		—		(87,147	)	(357,526	)
Balance December 31, 2014	1,234,092		413,876		279,702		323,241		145,359		—		2,396,270
Extensions, discoveries and other additions	26,488		26,226		40,464		—		24,227		—		117,405
Purchase of minerals in-place	—		6,860		—		—		—		—		6,860
Revisions of previous estimates	(322,123	)	(87,081	)	37,825		12,549		(6,305	)	—		(365,135	)
Production	(91,591	)	(24,706	)	(56,029	)	(8,503	)	(26,011	)	—		(206,840	)
Sale of properties	(232	)	(55,228	)	—		(327,287	)	(2,080	)	—		(384,827	)
Balance December 31, 2015	846,634		279,947		301,962		—		135,190		—		1,563,733
Extensions, discoveries and other additions	56,458		9,166		23,674		—		13,906		—		103,204
Purchase of minerals in-place	24		—		—		—		1,556		—		1,580
Revisions of previous estimates	(87,954	)	(84,984	)	16,599		—		(3,002	)	—		(159,341	)
Production	(81,994	)	(21,684	)	(62,269	)	—		(24,995	)	—		(190,942	)
Sale of properties	(131	)	(6,852	)	—		—		—		—		(6,983	)
Balance December 31, 2016	733,037		175,593		279,966		—		122,655		—		1,311,251

(1)    2016, 2015, 2014, and 2013 include total proved reserves of 93 MMboe, 101 MMboe, 93 MMboe, and 90 MMboe, respectively, attributable to a noncontrolling interest in Egypt.

During 2016, Apache sold a combined 7 MMboe primarily through divestiture transactions in Canada. The Company added 2 MMboe of estimated proved reserves through purchases of minerals in-place and 103 MMboe from extensions, discoveries, and other additions. The Company recorded 66 MMboe of exploration and development adds in North America, primarily associated with Woodford, Bone Springs, and Wolfcamp drilling programs in the Permian Basin (49 MMboe), Montney and Glauconite drilling in Canada (9 MMboe), and Woodford drilling activity in the MidContinent region (8 MMboe).

The international regions contributed 37 MMboe of exploration and development adds during 2016 with Egypt contributing 23 MMboe from onshore exploration and appraisal activity in the Khalda, Khalda 2, and East Beni Suef concessions. The North Sea offshore region contributed 14 MMboe from drilling success in the Beryl, Forties, and Nevis fields.

During 2016, Apache also had combined downward revisions of previously estimated reserves of 159 MMboe. Changes in product prices accounted for 172 MMboe, lease ownership changes accounted for 6 MMboe, offset by engineering and performance upward revisions totaling 19 MMboe.

Approximately 9 percent of Apache’s year-end 2016 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 16, under “Future Net Cash Flows.”

Future Net Cash Flows

Future cash inflows as of December 31, 2016 and 2015 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)			North Sea			Total(2)
	(In millions)
2016
Cash inflows	$	20,067		$	3,625		$	8,778		$	4,734		$	37,204
Production costs	(8,858		)	(2,582		)	(1,967		)	(2,255		)	(15,662		)
Development costs	(1,653		)	(1,565		)	(1,111		)	(2,410		)	(6,739		)
Income tax expense	(32		)	—			(1,775		)	(8		)	(1,815		)
Net cash flows	9,524			(522		)	3,925			61			12,988
10 percent discount rate	(5,319		)	549			(956		)	798			(4,928		)
Discounted future net cash flows(1)	$	4,205		$	27		$	2,969		$	859		$	8,060
2015
Cash inflows	$	26,610		$	7,345		$	11,124		$	6,994		$	52,073
Production costs	(12,178		)	(3,841		)	(2,185		)	(3,209		)	(21,413		)
Development costs	(2,255		)	(1,939		)	(1,515		)	(2,346		)	(8,055		)
Income tax expense	(63		)	—			(2,326		)	(691		)	(3,080		)
Net cash flows	12,114			1,565			5,098			748			19,525
10 percent discount rate	(6,876		)	(868		)	(1,330		)	143			(8,931		)
Discounted future net cash flows(1)	$	5,238		$	697		$	3,768		$	891		$	10,594

(1) Estimated future net cash flows before income tax expense, discounted at 10 percent per annum, totaled approximately $9.5 billionand$13.1 billion as of December 31, 2016 and 2015, respectively.

(2) Includes discounted future net cash flows of approximately $1.0 billionand$1.3 billion in 2016 and 2015, respectively, 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,
	2016			2015			2014
	(In millions)
Sales, net of production costs	$	(3,479	)	$	(4,056	)	$	(10,350	)
Net change in prices and production costs	(3,835		)	(21,710		)	(1,029		)
Discoveries and improved recovery, net of related costs	1,153			1,953			6,297
Change in future development costs	309			705			(1,136		)
Previously estimated development costs incurred during the period	986			1,991			4,462
Revision of quantities	(574		)	(2,292		)	256
Purchases of minerals in-place	8			22			508
Accretion of discount	1,313			3,642			4,442
Change in income taxes	1,070			7,264			836
Sales of properties	(52		)	(5,240		)	(4,780		)
Change in production rates and other	567			(3,343		)	(442		)
	$	(2,534	)	$	(21,064	)	$	(936	)

XML

Supplemental Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2016

Quarterly Financial Information Disclosure [Abstract]

Supplemental Quarterly Financial Data (Unaudited)

SUPPLEMENTAL QUARTERLY FINANCIAL DATA (Unaudited)

	First			Second			Third			Fourth			Total
	(In millions, except per share amounts)
2016
Revenues and other	$	1,084		$	1,365		$	1,433		$	1,451		$	5,333
Gain (loss) on divestitures	(1		)	17			5			—			21
Expenses(1)	1,454			1,582			1,964			1,594			6,594
Net loss from continuing operations including noncontrolling interest	(371		)	(200		)	(526		)	(143		)	(1,240		)
Net loss from discontinued operations, net of tax	—			—			(33		)	—			(33		)
Net loss including noncontrolling interest	$	(371	)	$	(200	)	$	(559	)	$	(143	)	$	(1,273	)
Net loss attributable to common stock	$	(372	)	$	(244	)	$	(607	)	$	(182	)	$	(1,405	)
Basic and diluted net loss per common share(2):
Net loss from continuing operations	$	(0.98	)	$	(0.65	)	$	(1.51	)	$	(0.48	)	$	(3.62	)
Net loss from discontinued operations	—			—			(0.09		)	—			(0.09		)
Net loss per share	$	(0.98	)	$	(0.65	)	$	(1.60	)	$	(0.48	)	$	(3.71	)
2015
Revenues and other	$	1,653		$	2,019		$	1,531		$	1,405		$	6,608
Gain (loss) on divestitures	(18		)	227			(5		)	77			281
Expenses(1)	2,703			3,163			5,645			6,537			18,048
Net loss from continuing operations including noncontrolling interest	(1,068		)	(917		)	(4,119		)	(5,055		)	(11,159		)
Net income (loss) from discontinued operations, net of tax	(238		)	120			(17		)	627			492
Net loss including noncontrolling interest	$	(1,306	)	$	(797	)	$	(4,136	)	$	(4,428	)	$	(10,667	)
Net loss attributable to common stock	$	(1,334	)	$	(860	)	$	(4,143	)	$	(4,015	)	$	(10,352	)
Basic and diluted net income (loss) per common share(2):
Net loss from continuing operations	$	(2.91	)	$	(2.60	)	$	(10.91	)	$	(12.28	)	$	(28.70	)
Net income (loss) from discontinued operations	(0.63		)	0.32			(0.04		)	1.66			1.30
Net loss per share	$	(3.54	)	$	(2.28	)	$	(10.95	)	$	(10.62	)	$	(27.40	)

(1) Continuing operating expenses for 2016 include non-cash asset impairments totaling $42 million, $238 million, $951 million, and $144 million in the first, second, third, and fourth quarters of 2016, respectively. Continuing operating expenses for 2015 include non-cash asset impairments totaling $2.1 billion, $660 million, $4.1 billion, and $5.1 billion in the first, second, third, and fourth quarters of 2015, respectively.

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

XML

Supplemental Guarantor Information

12 Months Ended

Dec. 31, 2016

Guarantees [Abstract]

Supplemental Guarantor Information

 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 is 100 percent owned by Apache Corporation. As such, these condensed consolidating financial statements should be read in conjunction with Apache’s consolidated financial statements and notes thereto, of which this note is an integral part.

	Apache Corporation			Apache Finance Canada			All Other Subsidiaries of Apache Corporation			Reclassifications & Eliminations			Consolidated
	(In millions)
REVENUES AND OTHER:
Oil and gas production revenues	$	1,035		$	—		$	4,332		$	—		$	5,367
Equity in net income (loss) of affiliates	(575		)	(173		)	—			748			—
Other	15			(19		)	(29		)	(1		)	(34		)
Gain on divestiture	2			—			19			—			21
	477			(192		)	4,322			747			5,354
OPERATING EXPENSES:
Lease operating expenses	285			—			1,209			—			1,494
Gathering and transportation	33			—			167			—			200
Taxes other than income	76			—			50			—			126
Exploration	258			—			215			—			473
General and administrative	344			—			67			(1		)	410
Depreciation, depletion, and amortization	618			—			2,000			—			2,618
Asset retirement obligation accretion	18			—			138			—			156
Impairments	80			—			1,023			—			1,103
Transaction, reorganization, and separation	39			—			—			—			39
Financing costs, net	256			(27		)	188			—			417
	2,007			(27		)	5,057			(1		)	7,036
NET INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(1,530		)	(165		)	(735		)	748			(1,682		)
Provision (benefit) for income taxes	(158		)	8			(292		)	—			(442		)
NET INCOME (LOSS) FROM CONTINUING OPERATIONS INCLUDING NONCONTROLLING INTEREST	(1,372		)	(173		)	(443		)	748			(1,240		)
Net loss from discontinued operations, net of tax	(33		)	—			—			—			(33		)
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTEREST	(1,405		)	(173		)	(443		)	748			(1,273		)
Net income attributable to noncontrolling interest	—			—			132			—			132
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	(1,405	)	$	(173	)	$	(575	)	$	748		$	(1,405	)
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	(1,398	)	$	(173	)	$	(575	)	$	748		$	(1,398	)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)

For the Year Ended December 31, 2015

	Apache Corporation			Apache Finance Canada			All Other Subsidiaries of Apache Corporation			Reclassifications & Eliminations		Consolidated
	(In millions)
REVENUES AND OTHER:
Oil and gas production revenues	$	1,446		$	—		$	5,064		$	—	$	6,510
Equity in net income (loss) of affiliates	(5,254		)	(740		)	57			5,937		—
Other	(71		)	54			96			19		98
Gain on divestiture	36			—			245			—		281
	(3,843		)	(686		)	5,462			5,956		6,889
OPERATING EXPENSES:
Lease operating expenses	399			—			1,455			—		1,854
Gathering and transportation	35			—			176			—		211
Taxes other than income	103			—			179			—		282
Exploration	2,096			—			675			—		2,771
General and administrative	296			—			65			19		380
Depreciation, depletion, and amortization	966			—			2,334			—		3,300
Asset retirement obligation accretion	15			—			130			—		145
Impairments	3,885			—			5,587			—		9,472
Transaction, reorganization, and separation	132			—			—			—		132
Financing costs, net	475			(14		)	50			—		511
	8,402			(14		)	10,651			19		19,058
NET INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(12,245		)	(672		)	(5,189		)	5,937		(12,169		)
Provision (benefit) for income taxes	(2,065		)	11			1,044			—		(1,010		)
NET INCOME (LOSS) FROM CONTINUING OPERATIONS INCLUDING NONCONTROLLING INTEREST	(10,180		)	(683		)	(6,233		)	5,937		(11,159		)
Net income (loss) from discontinued operations, net of tax	(172		)	—			664			—		492
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTEREST	(10,352		)	(683		)	(5,569		)	5,937		(10,667		)
Net loss attributable to noncontrolling interest	—			—			(315		)	—		(315		)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	(10,352	)	$	(683	)	$	(5,254	)	$	5,937	$	(10,352	)
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	(10,355	)	$	(683	)	$	(5,254	)	$	5,937	$	(10,355	)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)

For the Year Ended December 31, 2014

	Apache Corporation			Apache Finance Canada			All Other Subsidiaries of Apache Corporation			Reclassifications & Eliminations		Consolidated
	(In millions)
REVENUES AND OTHER:
Oil and gas production revenues	$	3,399		$	—		$	9,396		$	—	$	12,795
Equity in net income (loss) of affiliates	(3,489		)	(1,191		)	73			4,607		—
Other	375			55			(150		)	5		285
Loss on divestiture	(1,031		)	—			(577		)	—		(1,608		)
	(746		)	(1,136		)	8,742			4,612		11,472
OPERATING EXPENSES:
Lease operating expenses	509			—			1,729			—		2,238
Gathering and transportation	58			—			215			—		273
Taxes other than income	206			—			371			—		577
Exploration	1,966			—			533			—		2,499
General and administrative	370			—			78			5		453
Depreciation, depletion, and amortization	1,493			—			3,033			—		4,526
Asset retirement obligation accretion	31			—			123			—		154
Impairments	1,626			—			5,476			—		7,102
Transaction, reorganization, and separation	67			—			—			—		67
Financing costs, net	372			(24		)	65			—		413
	6,698			(24		)	11,623			5		18,302
NET INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(7,444		)	(1,112		)	(2,881		)	4,607		(6,830		)
Provision (benefit) for income taxes	789			6			(1,313		)	—		(518		)
NET INCOME (LOSS) FROM CONTINUING OPERATIONS INCLUDING NONCONTROLLING INTEREST	(8,233		)	(1,118		)	(1,568		)	4,607		(6,312		)
Net loss from discontinued operations, net of tax	(127		)	—			(1,580		)	—		(1,707		)
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTEREST	(8,360		)	(1,118		)	(3,148		)	4,607		(8,019		)
Net income attributable to noncontrolling interest	—			—			341			—		341
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	(8,360	)	$	(1,118	)	$	(3,489	)	$	4,607	$	(8,360	)
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	(8,361	)	$	(1,118	)	$	(3,489	)	$	4,607	$	(8,361	)

	Apache Corporation			Apache Finance Canada			All Other Subsidiaries of Apache Corporation			Reclassifications & Eliminations			Consolidated
							(In millions)
CASH PROVIDED BY CONTINUING OPERATING ACTIVITIES	$	625		$	51		$	1,777		$	—		$	2,453
CASH USED IN DISCONTINUED OPERATIONS	—			—			(23		)	—			(23		)
CASH PROVIDED BY OPERATING ACTIVITIES	$	625		$	51		$	1,754		$	—		$	2,430
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property	(813		)	—			(797		)	—			(1,610		)
Additions to gas gathering, transmission, and processing facilities	(111		)	—			(47		)	—			(158		)
Leasehold and property acquisitions	(108		)	—			(73		)	—			(181		)
Proceeds from sale of oil and gas properties, other	88			—			46			—			134
Investment in subsidiaries, net	914			—			—			(914		)	—
Other	(77		)	—			232			—			155
NET CASH USED IN INVESTING ACTIVITIES	(107		)	—			(639		)	(914		)	(1,660		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Intercompany borrowings	—			(23		)	(891		)	914			—
Payments on fixed rate debt	(181		)	—			—			—			(181		)
Dividends paid	(379		)	—			—			—			(379		)
Common stock activity, net	—			(28		)	28			—			—
Distributions to noncontrolling interest	—			—			(293		)	—			(293		)
Other	8			—			(15		)	—			(7		)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES	(552		)	(51		)	(1,171		)	914			(860		)
NET DECREASE IN CASH AND CASH  EQUIVALENTS	(34		)	—			(56		)	—			(90		)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	378			—			1,089			—			1,467
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	344		$	—		$	1,033		$	—		$	1,377

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

For the Year Ended December 31, 2015

	Apache Corporation			Apache Finance Canada			All Other Subsidiaries of Apache Corporation			Reclassifications & Eliminations			Consolidated
							(In millions)
CASH PROVIDED BY CONTINUING OPERATING ACTIVITIES	$	98		$	18		$	2,438		$	—		$	2,554
CASH PROVIDED BY DISCONTINUED OPERATIONS	—			—			113			—			113
CASH PROVIDED BY OPERATING ACTIVITIES	98			18			2,551			—			2,667
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property	(1,500		)	—			(2,708		)	—			(4,208		)
Additions to gas gathering, transmission, and processing facilities	(156		)	—			(77		)	—			(233		)
Proceeds from sale of Kitimat LNG	—			—			854			—			854
Proceeds from sale of Yara Pilbara	—			—			391			—			391
Leasehold and property acquisitions	(313		)	—			(54		)	—			(367		)
Proceeds from sale of oil and gas properties	163			—			105			—			268
Investment in subsidiaries, net	6,363			—			—			(6,363		)	—
Other	(34		)	—			40			—			6
NET CASH PROVIDED BY (USED IN) CONTINUING INVESTING ACTIVITIES	4,523			—			(1,449		)	(6,363		)	(3,289		)
NET CASH PROVIDED BY DISCONTINUED OPERATIONS	—			—			4,372			—			4,372
NET CASH USED IN INVESTING ACTIVITIES	4,523			—			2,923			(6,363		)	1,083
CASH FLOWS FROM FINANCING ACTIVITIES:
Commercial paper, credit facility, and bank notes, net	(1,570		)	—			—			—			(1,570		)
Intercompany borrowings	(1,621		)	(18		)	(4,724		)	6,363			—
Payments on fixed rate debt	(939		)	—			—			—			(939		)
Dividends paid	(377		)	—			—			—			(377		)
Distributions to noncontrolling interest	—			—			(129		)	—			(129		)
Other	(3		)	—			56			—			53
NET CASH USED IN CONTINUING FINANCING ACTIVITIES	(4,510		)	(18		)	(4,797		)	6,363			(2,962		)
NET CASH USED IN FINANCING ACTIVITIES	(4,510		)	(18		)	(4,797		)	6,363			(2,962		)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	111			—			677			—			788
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	267			—			412			—			679
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	378		$	—		$	1,089		$	—		$	1,467

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

For the Year Ended December 31, 2014

	Apache Corporation			Apache Finance Canada			All Other Subsidiaries of Apache Corporation			Reclassifications & Eliminations			Consolidated
							(In millions)
CASH PROVIDED BY CONTINUING OPERATING ACTIVITIES	$	3,104		$	17		$	3,892		$	—		$	7,013
CASH PROVIDED BY DISCONTINUED OPERATIONS	—			—			944			—			944
CASH PROVIDED BY OPERATING ACTIVITIES	3,104			17			4,836			—			7,957
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property	(4,364		)	—			(4,244		)	—			(8,608		)
Additions to gas gathering, transmission, and processing facilities	(9		)	—			(872		)	—			(881		)
Proceeds from sale of Deepwater Gulf of Mexico assets	1,360			—			—			—			1,360
Proceeds from sale of Anadarko basin and southern Louisiana assets	1,262			—			—			—			1,262
Leasehold and property acquisitions	(1,475		)	—			—			—			(1,475		)
Proceeds from sale of oil and gas properties	15			—			455			—			470
Investment in subsidiaries, net	1,132			—			—			(1,132		)	—
Other	(186		)	—			(113		)	—			(299		)
NET CASH USED IN CONTINUING INVESTING ACTIVITIES	(2,265		)	—			(4,774		)	(1,132		)	(8,171		)
NET CASH USED IN DISCONTINUED OPERATIONS	—			—			(219		)	—			(219		)
NET CASH USED IN INVESTING ACTIVITIES	(2,265		)	—			(4,993		)	(1,132		)	(8,390		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Commercial paper, credit facility, and bank notes, net	1,570			—			(2		)	—			1,568
Intercompany borrowings	—			8			(1,152		)	1,144			—
Dividends paid	(365		)	—			—			—			(365		)
Distributions to noncontrolling interest	—			—			(140		)	—			(140		)
Shares repurchased	(1,864		)	—			—			—			(1,864		)
Other	(68		)	(28		)	157			(12		)	49
NET CASH USED IN CONTINUING FINANCING ACTIVITIES	(727		)	(20		)	(1,137		)	1,132			(752		)
NET CASH USED IN DISCONTINUED OPERATIONS	—			—			(42		)	—			(42		)
NET CASH USED IN FINANCING ACTIVITIES	(727		)	(20		)	(1,179		)	1,132			(794		)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	112			(3		)	(1,336		)	—			(1,227		)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	155			3			1,748			—			1,906
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	267		$	—		$	412		$	—		$	679

	Apache Corporation			Apache Finance Canada			All Other Subsidiaries of Apache Corporation		Reclassifications & Eliminations			Consolidated
							(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	344		$	—		$	1,033	$	—		$	1,377
Receivables, net of allowance	358			—			770		—			1,128
Inventories	29			—			447		—			476
Drilling advances	4			—			77		—			81
Prepaid assets and other	134			—			45		—			179
Intercompany receivable	5,038			—			—		(5,038		)	—
	5,907			—			2,372		(5,038		)	3,241
PROPERTY AND EQUIPMENT, NET	7,014			—			11,853		—			18,867
OTHER ASSETS:
Intercompany receivable	—			—			12,152		(12,152		)	—
Equity in affiliates	15,517			(1,240		)	706		(14,983		)	—
Deferred charges and other	97			1,000			314		(1,000		)	411
	$	28,535		$	(240	)	$	27,397	$	(33,173	)	$	22,519
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable	$	371		$	(12	)	$	226	$	—		$	585
Other current liabilities	653			3			602		—			1,258
Intercompany payable	—			—			5,038		(5,038		)	—
	1,024			(9		)	5,866		(5,038		)	1,843
LONG-TERM DEBT	8,247			297			—		—			8,544
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Intercompany payable	12,152			—			—		(12,152		)	—
Income taxes	(271		)	5			1,976		—			1,710
Asset retirement obligation	257			—			2,175		—			2,432
Other	888			1			422		(1,000		)	311
	13,026			6			4,573		(13,152		)	4,453
COMMITMENTS AND CONTINGENCIES APACHE SHAREHOLDERS’ EQUITY	6,238			(534		)	15,517		(14,983		)	6,238
Noncontrolling interest	—			—			1,441		—			1,441
TOTAL EQUITY	6,238			(534		)	16,958		(14,983		)	7,679
	$	28,535		$	(240	)	$	27,397	$	(33,173	)	$	22,519

CONDENSED CONSOLIDATING BALANCE SHEET

December 31, 2015

	Apache Corporation			Apache Finance Canada			All Other Subsidiaries of Apache Corporation		Reclassifications & Eliminations			Consolidated
							(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	378		$	—		$	1,089	$	—		$	1,467
Receivables, net of allowance	314			—			939		—			1,253
Inventories	34			—			536		—			570
Drilling advances	16			—			156		—			172
Prepaid assets and other	102			—			188		—			290
Intercompany receivable	5,212			—			—		(5,212		)	—
	6,056			—			2,908		(5,212		)	3,752
PROPERTY AND EQUIPMENT, NET	6,546			—			14,292		—			20,838
OTHER ASSETS:
Intercompany receivable	—			—			10,744		(10,744		)	—
Equity in affiliates	16,092			(807		)	446		(15,731		)	—
Deferred charges and other	96			1,001			813		(1,000		)	910
	$	28,790		$	194		$	29,203	$	(32,687	)	$	25,500
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable	$	409		$	—		$	209	$	—		$	618
Other current liabilities	539			3			681		—			1,223
Intercompany payable	—			—			5,212		(5,212		)	—
	948			3			6,102		(5,212		)	1,841
LONG-TERM DEBT	8,418			298			—		—			8,716
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Intercompany payable	10,744			—			—		(10,744		)	—
Income taxes	(412		)	4			2,937		—			2,529
Asset retirement obligation	271			—			2,291		—			2,562
Other	933			250			179		(1,000		)	362
	11,536			254			5,407		(11,744		)	5,453
COMMITMENTS AND CONTINGENCIES APACHE SHAREHOLDERS’ EQUITY	7,888			(361		)	16,092		(15,731		)	7,888
Noncontrolling interest	—			—			1,602		—			1,602
TOTAL EQUITY	7,888			(361		)	17,694		(15,731		)	9,490
	$	28,790		$	194		$	29,203	$	(32,687	)	$	25,500

XML

Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2016

Accounting Policies [Abstract]

Principles of Consolidation

Principles of Consolidation

The accompanying consolidated financial statements include the accounts of Apache and its subsidiaries after elimination of intercompany balances and transactions. The Company’s undivided interests in oil and gas exploration and production ventures and partnerships are proportionately consolidated. The Company consolidates all other investments in which, either through direct or indirect ownership, Apache has more than a 50 percent voting interest or controls the financial and operating decisions. Noncontrolling interests represent third-party ownership in the net assets of a consolidated Apache subsidiary and are reflected separately in the Company’s financial statements. Sinopec International Petroleum Exploration and Production Corporation (Sinopec) owns a one-third minority participation in Apache’s Egypt oil and gas business as a noncontrolling interest, which is reflected as a separate component of equity in Apache’s consolidated balance sheet. 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 and assets held for sale at year-end (see Note 3—Acquisitions and Divestitures), the estimate of proved oil and gas reserves and related present value estimates of future net cash flows therefrom (see Note 16—Supplemental Oil and Gas Disclosures), the assessment of asset retirement obligations (see Note 7—Asset Retirement Obligation), the estimates of fair value for long-lived assets and goodwill (see “Fair Value Measurements,” “Property and Equipment,” and “Goodwill” sections in this Note 1 below), and the estimate of income taxes (see Note 9—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. 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).

Recurring fair value measurements are presented in further detail in Note 8—Debt and Note 11—Retirement and Deferred Compensation Plans.

Apache also uses fair value measurements on a nonrecurring basis when certain qualitative assessments of its assets indicate a potential impairment. For the year ended December 31, 2016, the Company recorded asset impairments totaling $1.1 billion in connection with fair value assessments in the current low commodity price environment. Impairments totaling $427 million and $135 million were recorded for proved properties and gathering, transmission, and processing (GTP) facilities, respectively, which were written down to their fair values. These impairments are discussed in further detail below in “Property and Equipment.” Also in 2016, the Company recorded $486 million for a U.K. Petroleum Revenue Tax (PRT) decommissioning asset that is no longer expected to be realizable from future abandonment activities in the North Sea and $55 million for inventory write-downs.

In 2016, the U.K. government enacted Finance Bill 2016, providing tax relief to exploration and production (E&P) companies operating in the U.K. North Sea. Under the enacted legislation, the U.K. PRT rate was reduced to zero from the previously enacted 35 percent rate in effect from January 1, 2016. PRT expense ceased prospectively from that date. As a further result of this change, the Company reduced the recoverable PRT decommissioning asset that would have been realized from future abandonment activities by $486 million ($292 million net of tax). This recoverable PRT decommissioning asset had an aggregate remaining value of $8 million as of December 31, 2016, which is recorded in “Deferred charges and other” on the consolidated balance sheet. The recoverable value of the PRT decommissioning asset was estimated using the income approach. The expected future cash flows used in the determination were based on anticipated spending and timing of planned future abandonment activities for applicable fields, considering all available information at the date of review. Apache has classified this fair value measurement as Level 3 in the fair value hierarchy.

For the year ended December 31, 2015, the Company recorded asset impairments totaling $9.5 billion in connection with fair value assessments. Impairments totaling $7.4 billion and $1.7 billion were recorded for proved properties and GTP facilities, respectively, which were written down to their fair values. These impairments are discussed in further detail below in “Property and Equipment.” Also in 2015, the Company recorded $163 million for the impairment of goodwill, $148 million for the impairment of an equity method investment sold in the fourth quarter, and $55 million for inventory write-downs. For a discussion of the equity method investment impairment, see Note 3—Acquisitions and Divestitures.

For the year ended December 31, 2014, the Company recorded asset impairments totaling $7.1 billion in connection with fair value assessments, including $6.1 billion for proved properties, $347 million for the impairment of goodwill, $655 million for the impairment of assets held for sale, and $32 million for inventory write-downs. The Company also recorded $833 million in impairments related to the sale of the Company’s Australian assets and an additional $271 million in impairment of proved properties and inventory in Australia. These impairments are classified as discontinued operations in 2014. For discussion of these impairments, see “Property and Equipment” and “Goodwill” below and Note 3—Acquisitions and Divestitures.

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, 2016 and 2015, Apache had $1.4 billion and $1.5 billion, 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 doubtful 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.

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, net of any impairments. 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 successful efforts method of accounting for its oil and gas property. Under this method of accounting, exploration costs such as exploratory geological and geophysical costs, delay rentals, and exploration overhead are expensed as incurred. All costs related to production, general corporate overhead, and similar activities are expensed as incurred. If an exploratory well provides evidence to justify potential development of reserves, drilling costs associated with the well are initially capitalized, or suspended, pending a determination as to whether a commercially sufficient quantity of proved reserves can be attributed to the area as a result of drilling. This determination may take longer than one year in certain areas depending on, among other things, the amount of hydrocarbons discovered, the outcome of planned geological and engineering studies, the need for additional appraisal drilling activities to determine whether the discovery is sufficient to support an economic development plan, and government sanctioning of development activities in certain international locations. At the end of each quarter, management reviews the status of all suspended exploratory well costs in light of ongoing exploration activities; in particular, whether the Company is making sufficient progress in its ongoing exploration and appraisal efforts or, in the case of discoveries requiring government sanctioning, whether development negotiations are underway and proceeding as planned. If management determines that future appraisal drilling or development activities are unlikely to occur, associated suspended exploratory well costs are expensed.

Acquisition costs of unproved properties are assessed for impairment at least annually and are transferred to proved oil and gas properties to the extent the costs are associated with successful exploration activities. Significant undeveloped leases are assessed individually for impairment based on the Company’s current exploration plans. Unproved oil and gas properties with individually insignificant lease acquisition costs are amortized on a group basis over the average lease term at rates that provide for full amortization of unsuccessful leases upon lease expiration or abandonment. Costs of expired or abandoned leases are charged to exploration expense, while costs of productive leases are transferred to proved oil and gas properties. Costs of maintaining and retaining unproved properties, as well as amortization of individually insignificant leases and impairment of unsuccessful leases, are included in exploration costs in the statement of consolidated operations.

Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of crude oil and natural gas, are capitalized. Depreciation of the cost of proved oil and gas properties is calculated using the unit-of-production (UOP) method. The UOP calculation multiplies the percentage of estimated proved reserves produced each quarter by the carrying value of those reserves. The reserve base used to calculate depreciation for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. With respect to lease and well equipment costs, which include development costs and successful exploration drilling costs, the reserve base includes only proved developed reserves. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are included in the depreciable cost.

Oil and gas properties are grouped for depreciation in accordance with ASC 932 “Extractive Activities - Oil and Gas.” The basis for grouping is a reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field.

When circumstances indicate that proved oil and gas properties may be impaired, the Company compares unamortized capitalized costs to the expected undiscounted pre-tax future cash flows for the associated assets grouped at the lowest level for which identifiable cash flows are independent of cash flows of other assets. If the expected undiscounted pre-tax future cash flows, based on Apache’s estimate of future crude oil and natural gas prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally estimated using the income approach described in the ASC 820 “Fair Value Measurement.” If applicable, the Company utilizes accepted bids as the basis for determining fair value. The expected future cash flows used for impairment reviews and related fair value calculations are typically based on judgmental assessments of future production volumes, commodity prices, operating costs, and capital investment plans, considering all available information at the date of review. These assumptions are applied to develop future cash flow projections that are then discounted to estimated fair value, using a discount rate believed to be consistent with those applied by market participants. Apache has classified these fair value measurements as Level 3 in the fair value hierarchy.

The following table represents non-cash impairments of the carrying value of the Company’s proved and unproved property and equipment for 2016, 2015, and 2014:

	For the Year Ended December 31,
	2016		2015		2014
	(In millions)
Oil and Gas Property:
Proved	$	427	$	7,389	$	6,068
Unproved	272		2,462		1,976

The fair values of the impaired proved properties as of the most recent date of impairment were $306 million, $3.9 billion, and $4.8 billion for 2016, 2015, and 2014, respectively.

In the statement of consolidated operations, unproved property impairments are recorded in exploration expense, and proved property impairments are recorded in impairments.

Gains and losses on significant divestitures are recognized in the statement of consolidated operations. See Note 3—Acquisitions and Divestitures for more detail.

Gathering, Transmission, and Processing Facilities

Gathering, Transmission, and Processing Facilities

GTP facilities totaled $976 million and $1.1 billion at December 31, 2016 and 2015, respectively, with accumulated depreciation for these assets totaling $130 million and $160 million for the respective periods. GTP facilities are depreciated on a straight-line basis over the estimated useful lives of the assets. The estimation of useful life takes into consideration anticipated production lives from the fields serviced by the GTP assets, whether Apache-operated or third party, as well as potential development plans by Apache for undeveloped acreage within or in close proximity to those fields.

The Company assesses the carrying amount of its GTP facilities whenever events or changes in circumstances indicate that their carrying amount may not be recoverable. If the carrying amount of these facilities is more than the sum of the undiscounted cash flows, an impairment loss is recognized for the excess of the carrying value over its fair value. During 2016, the Company recorded impairments of $135 million on certain GTP assets in the North Sea, which were written down to their fair values of $142 million. The fair values of the impaired assets were determined using a combination of the income approach and the market approach. The income approach considers internal estimates of future throughput volumes, processing rates, and costs. These assumptions were applied to develop future cash flow projections that were then discounted to estimated fair value, using a discount rate believed to be consistent with those applied by market participants. Apache has classified these non-recurring fair value measurements as Level 3 in the fair value hierarchy. During 2015, the Company recorded impairments of $1.7 billion on certain GTP assets, including $1.1 billion in Egypt, $555 million in Canada, and $103 million in the U.S., which were written down to their fair values of $306 million in aggregate. During 2014, the Company recorded impairments of $1.1 billion of its GTP assets related to the sale of Apache’s Wheatstone and Kitimat LNG projects, and the remaining carrying value of those assets was reclassified to “Assets held for sale” on the Company’s consolidated balance sheet as of December 31, 2014. The $430 million impairment of GTP assets related to Apache's Wheatstone LNG project is reflected in discontinued operations in the Company's statement of consolidated operations.

The costs of GTP facilities retired or otherwise disposed of and associated accumulated depreciation are removed from Apache’s consolidated financial statements, and the resulting gain or loss is reflected in “Gain (loss) on divestitures” under “Revenues and Other” in the Company’s statement of consolidated operations. No gain or loss on the sales of GTP facilities was recognized during 2016. During 2015, Apache recorded a gain on the sale of GTP facilities totaling $59 million associated with the Company’s divestitures of certain Permian Basin assets. During 2014, the Company recorded a loss totaling $180 million associated with divestitures of certain Anadarko basin and southern Louisiana assets.

Other Property and Equipment

Other Property and Equipment

Other property and equipment includes computer software and equipment, buildings, vehicles, furniture and fixtures, land, and other equipment. These assets are depreciated on a straight-line basis over the estimated useful lives of the assets, which range from 3 to 20 years. Accumulated depreciation for these assets totaled $780 million and $693 million at December 31, 2016 and 2015, 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. 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, and it is recorded in “Deferred charges and other” in the Company's consolidated balance sheet. The Company assesses the carrying amount of goodwill by testing for impairment annually and when impairment indicators arise. The impairment test requires allocating goodwill and all other assets and liabilities to assigned reporting units. As of December 31, 2016, Apache assesses each country as a reporting unit. The fair value of each unit is determined and compared to the book value of the reporting unit. If the fair value of the reporting unit is less than the book value, including goodwill, then goodwill is written down to the implied fair value of the goodwill through a charge to expense.

In order to determine the fair value of each reporting unit, the Company uses a combination of the income approach and the market approach. The income approach considers management views on current operating measures as well as assumptions pertaining to market forces in the oil and gas industry, such as future production, future commodity prices, and costs. These assumptions are applied to develop future cash flow projections that are then discounted to estimate fair value, using a discount rate similar to those used by the Company in the valuation of acquisitions and divestitures. To assess the reasonableness of its fair value estimate, the Company uses a market approach to compare the fair value to similar businesses whose securities are actively traded in the public market. This requires management to make certain judgments about the selection of comparable companies, recent comparable asset transactions, and transaction premiums. Associated market multiples are applied to various financial metrics of the reporting unit to estimate fair value. Apache has classified this reporting unit estimation as a non-recurring Level 3 fair value measurement.

When there is a disposal of a reporting unit or a portion of a reporting unit that constitutes a business, goodwill associated with that business is included in the carrying amount to determine the gain or loss on disposal. The amount of goodwill allocated to the carrying amount of a business can significantly impact the amount of gain or loss recognized on the sale of that business. The amount of goodwill to be included in that carrying amount is based on the relative fair value of the business to be disposed of and the portion of the reporting unit that will be retained.

The following presents the changes to goodwill for the years ended 2016, 2015, and 2014:

	United States			Canada			Egypt		North Sea			Total
	(In millions)
Goodwill at December 31, 2013	$	384		$	103		$	87	$	163		$	737
Divested	(140		)	—			—		—			(140		)
Impairments	(244		)	(103		)	—		—			(347		)
Goodwill at December 31, 2014	—			—			87		163			250
Impairments	—			—			—		(163		)	(163		)
Goodwill at December 31, 2015	—			—			87		—			87
Impairments	—			—			—		—			—
Goodwill at December 31, 2016	$	—		$	—		$	87	$	—		$	87

Reductions in estimated net present value of expected future cash flows from oil and gas properties resulted in implied fair values below the carrying values of Apache’s U.S., North Sea, and Canada reporting units. These goodwill impairments have been recorded in “Impairments” in the Company’s statement of consolidated operations.

Accounts Payable

Accounts Payable

Included in accounts payable at December 31, 2016 and 2015, are liabilities of approximately $86 million and $129 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 North American natural gas production. Since the Company’s production fluctuates because of operational issues, it is occasionally necessary to purchase third-party oil and gas to fulfill sales obligations and commitments. The costs of third-party oil and gas purchases totaled $159 million, $105 million, and $70 million, for 2016, 2015, and 2014, respectively, which offset the related sales proceeds recorded as “Other” under “Revenues and Other” in the statement of consolidated operations.

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. As of December 31, 2016, Apache had no open derivative positions.

When applicable, 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 “Other” 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 2014 oil and gas cash flow hedges, including terminated contracts, were recognized in oil and gas production revenues when the forecasted transaction occurred.

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 ability to realize 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 record U.S. deferred income taxes on foreign subsidiaries that are deemed to be permanently reinvested. When such earnings are no longer deemed permanently reinvested, Apache will recognize the appropriate U.S. current or deferred income tax liabilities. For more information, please refer to Note 9—Income Taxes.

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. For further discussion, please refer to Note 9—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 2016 of $25 million, a loss in 2015 of $11 million, and a gain in 2014 of $8 million.

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 potential dilution, using the treasury stock method, which assumes that options were exercised and restricted stock was fully vested.

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 12—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 $2 million, $1 million, and $35,000 as financing cash inflows in 2016, 2015, and 2014, respectively.

Treasury Stock

Treasury Stock

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

New Pronouncements Issued But Not Yet Adopted

New Pronouncements Issued But Not Yet Adopted

In January 2017, the FASB issued Accounting Standards Update (ASU) 2017-04, “Simplifying the Test for Goodwill Impairment.” ASU 2017-04 seeks to simplify the accounting for goodwill by eliminating the second step in the goodwill impairment test which requires an entity to determine the implied fair value of the reporting unit’s goodwill. Under the new guidance, an entity will recognize an impairment loss if the carrying value of the net assets assigned to the reporting unit exceeds the fair value of the reporting unit, with the impairment loss not to exceed the amount of goodwill allocated to the reporting unit. This update will be applied prospectively and is effective for annual and interim goodwill impairment tests conducted in fiscal years beginning after December 15, 2019. Early adoption is permitted for annual and interim goodwill impairment testing dates after January 1, 2017. The Company plans to early adopt this ASU, and does not expect the adoption to have a material impact on its consolidated financial statements.

In August 2016, the FASB issued Accounting Standards Update (ASU) 2016-15, Statement of Cash Flows (Topic 230).  ASU 2016-15 seeks to reduce the existing diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows. This update is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years, with early adoption permitted. The Company is currently evaluating the provisions of ASU 2016-15 and assessing the impact, if any, it may have on its statement of consolidated cash flows.

In June 2016, the FASB issued ASU 2016-13, “Financial Instruments - Credit Losses.”  The standard changes the impairment model for most financial assets and certain other instruments, including trade and other receivables, held-to-maturity debt securities and loans, and requires entities to use a new forward-looking expected loss model that will result in the earlier recognition of allowance for losses. This update is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. Early adoption is permitted for a fiscal year beginning after December 15, 2018, including interim periods within that fiscal year.  The Company does not expect to adopt the guidance early. Entities will apply the standard’s provisions as a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is adopted. The Company is evaluating the new guidance and does not believe this standard will have a material impact on its consolidated financial statements.

In March 2016, the FASB issued ASU 2016-09, which seeks to simplify accounting for share-based payment transactions including income tax consequences, classification of awards as either equity or liabilities, and the classification on the statement of cash flows. The new standard requires the Company to recognize the income tax effects of awards in the income statement when the awards vest or are settled. The guidance is effective for fiscal years beginning after December 15, 2016. The Company has evaluated the new guidance and recorded a cumulative-effect adjustment of $11 million as of January 1, 2017 representing an increase in accumulated deficit with the offset to paid-in capital to reflect actual forfeitures versus the previously-estimated forfeiture rate.

In February 2016, the FASB issued ASU 2016-02, a new lease standard requiring lessees to recognize lease assets and lease liabilities for most leases classified as operating leases under previous U.S. GAAP. The guidance is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The Company will be required to use a modified retrospective approach for leases that exist or are entered into after the beginning of the earliest comparative period in the financial statements. The Company is currently evaluating the impact of adopting this standard on its consolidated financial statements.

In May 2014, the FASB and the International Accounting Standards Board (IASB) issued a joint revenue recognition standard, ASU 2014-09. The new standard removes inconsistencies in existing standards, changes the way companies recognize revenue from contracts with customers, and increases disclosure requirements. The codification was amended through additional ASUs and, as amended, requires companies to recognize revenue to depict the transfer of goods or services to customers in amounts that reflect the consideration to which the company expects to be entitled in exchange for those goods or services. The guidance is effective for annual and interim periods beginning after December 15, 2017. The standard is required to be adopted using either the full retrospective approach, with all prior periods presented adjusted, or the modified retrospective approach, with a cumulative adjustment to retained earnings on the opening balance sheet. The Company will adopt the new standard utilizing the modified retrospective approach. Upon preliminary evaluation, the Company does not expect the adoption of this ASU to have a material impact on its consolidated financial statements. The Company is continuing to evaluate the disclosure requirements of this ASU and does not plan on early adopting the standard.

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Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2016

Accounting Policies [Abstract]

Schedule of Allowance for Doubtful Accounts

The following table describes changes to the Company’s allowance for doubtful accounts for 2016, 2015, and 2014:

	2016			2015			2014
	(In millions)
Allowance for doubtful accounts at beginning of year	$	103		$	98		$	78
Additional provisions for the year	14			40			4
Uncollectible accounts written off net of recoveries	(24		)	(35		)	16
Allowance for doubtful accounts at end of year	$	93		$	103		$	98

Schedule of Non-cash Impairments of Proved and Unproved Property and Equipment

The following table represents non-cash impairments of the carrying value of the Company’s proved and unproved property and equipment for 2016, 2015, and 2014:

	For the Year Ended December 31,
	2016		2015		2014
	(In millions)
Oil and Gas Property:
Proved	$	427	$	7,389	$	6,068
Unproved	272		2,462		1,976

Schedule of Goodwill

The following presents the changes to goodwill for the years ended 2016, 2015, and 2014:

	United States			Canada			Egypt		North Sea			Total
	(In millions)
Goodwill at December 31, 2013	$	384		$	103		$	87	$	163		$	737
Divested	(140		)	—			—		—			(140		)
Impairments	(244		)	(103		)	—		—			(347		)
Goodwill at December 31, 2014	—			—			87		163			250
Impairments	—			—			—		(163		)	(163		)
Goodwill at December 31, 2015	—			—			87		—			87
Impairments	—			—			—		—			—
Goodwill at December 31, 2016	$	—		$	—		$	87	$	—		$	87

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Change in Accounting Principle (Tables)

12 Months Ended

Dec. 31, 2016

Accounting Changes and Error Corrections [Abstract]

Schedule of effects of the change to the successful efforts method

The following tables present the effects of the change to the successful efforts method in the statement of consolidated operations:

	Changes to the Statement of Consolidated Operations and Statement of Consolidated Comprehensive Income (Loss)
For the Year Ended December 31, 2016	Under Full Cost			Changes*			As Reported Under Successful Efforts
	(In millions, except per share data)
Oil revenues	$	3,983		$	189		$	4,172
Natural gas revenues	997			(30		)	967
NGL revenues	228			—			228
Oil and gas production revenues	5,208			159			5,367
Other	(38		)	4			(34		)
Gain on divestiture	17			4			21
Exploration	—			473			473
Depreciation, depletion, and amortization:
Oil and gas property and equipment
Recurring	1,974			486			2,460
Additional	1,438			(1,438		)	—
Impairments	677			426			1,103
Financing costs, net	365			52			417
Current income tax provision	232			159			391
Deferred income tax benefit	(721		)	(112		)	(833		)
NET LOSS FROM CONTINUING OPERATIONS INCLUDING NONCONTROLLING INTEREST	(1,361		)	121			(1,240		)
Net income (loss) attributable to noncontrolling interest	(26		)	158			132
NET LOSS FROM CONTINUING OPERATIONS ATTRIBUTABLE TO COMMON SHAREHOLDERS	(1,335		)	(37		)	(1,372		)
Net loss from discontinued operations, net of tax	(33		)	—			(33		)
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS	(1,368		)	(37		)	(1,405		)
Per Common Share
Basic and diluted net loss from continuing operations per share	$	(3.52	)	$	(0.10	)	$	(3.62	)
Basic and diluted net loss from discontinued operations per share	(0.09		)	—			(0.09		)
Basic and diluted net loss per share	$	(3.61	)	$	(0.10	)	$	(3.71	)
Other Comprehensive Income
COMPREHENSIVE LOSS ATTRIBUTABLE TO COMMON STOCK	(1,361		)	(37		)	(1,398		)

	Changes to the Statement of Consolidated Operations and Statement of Consolidated Comprehensive Income (Loss)
For the Year Ended December 31, 2015	Under Full Cost			Changes*			As Reported Under Successful Efforts
	(In millions, except per share data)
Oil revenues	$	4,999		$	108		$	5,107
Natural gas revenues	1,157			19			1,176
NGL revenues	227			—			227
Oil and gas production revenues	6,383			127			6,510
Other	(76		)	174			98
Gain on divestiture	59			222			281
Exploration	—			2,771			2,771
General and administrative	377			3			380
Depreciation, depletion, and amortization:
Oil and gas property and equipment
Recurring	3,531			(555		)	2,976
Additional	25,517			(25,517		)	—
Impairments	1,920			7,552			9,472
Financing costs, net	299			212			511
Current income tax provision	309			126			435
Deferred income tax benefit	(5,778		)	4,333			(1,445		)
NET LOSS FROM CONTINUING OPERATIONS INCLUDING NONCONTROLLING INTEREST	(22,757		)	11,598			(11,159		)
Net loss attributable to noncontrolling interest	(409		)	94			(315		)
NET LOSS FROM CONTINUING OPERATIONS ATTRIBUTABLE TO COMMON SHAREHOLDERS	(22,348		)	11,504			(10,844		)
Net income (loss) from discontinued operations, net of tax	(771		)	1,263			492
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS	(23,119		)	12,767			(10,352		)
Per Common Share
Basic and diluted net loss from continuing operations per share	$	(59.16	)	$	30.46		$	(28.70	)
Basic and diluted net income (loss) from discontinued operations per share	(2.04		)	3.34			1.30
Basic and diluted net loss per share	$	(61.20	)	$	33.80		$	(27.40	)
Other Comprehensive Income
Pension and postretirement benefit plan, net of tax	$	—		$	(3	)	$	(3	)
COMPREHENSIVE LOSS ATTRIBUTABLE TO COMMON STOCK	(23,119		)	12,764			(10,355		)

	Changes to the Statement of Consolidated Operations and Statement of Consolidated Comprehensive Income (Loss)
For the Year Ended December 31, 2014	Under Full Cost			Changes*			As Reported Under Successful Efforts
	(In millions, except per share data)
Oil revenues	$	10,040		$	70		$	10,110
Natural gas revenues	1,983			34			2,017
NGL revenues	668			—			668
Oil and gas production revenues	12,691			104			12,795
Other	290			(5		)	285
Loss on divestiture	(180		)	(1,428		)	(1,608		)
Exploration	—			2,499			2,499
General and administrative	451			2			453
Depreciation, depletion, and amortization:
Oil and gas property and equipment
Recurring	4,388			(193		)	4,195
Additional	5,001			(5,001		)	—
Impairments	1,919			5,183			7,102
Financing costs, net	211			202			413
Current income tax provision	1,177			104			1,281
Deferred income tax benefit	(514		)	(1,285		)	(1,799		)
NET LOSS FROM CONTINUING OPERATIONS INCLUDING NONCONTROLLING INTEREST	(3,472		)	(2,840		)	(6,312		)
Net income attributable to noncontrolling interest	343			(2		)	341
NET LOSS FROM CONTINUING OPERATIONS ATTRIBUTABLE TO COMMON SHAREHOLDERS	(3,815		)	(2,838		)	(6,653		)
Net loss from discontinued operations, net of tax	(1,588		)	(119		)	(1,707		)
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS	(5,403		)	(2,957		)	(8,360		)
Per Common Share
Basic and diluted net loss from continuing operations per share	$	(9.93	)	$	(7.39	)	$	(17.32	)
Basic and diluted net loss from discontinued operations per share	(4.13		)	(0.31		)	(4.44		)
Basic and diluted net loss per share	$	(14.06	)	$	(7.70	)	$	(21.76	)
Other Comprehensive Income
COMPREHENSIVE LOSS ATTRIBUTABLE TO COMMON STOCK	$	(5,404	)	$	(2,957	)	$	(8,361	)

The following tables present the effects of the change to the successful efforts method in the statement of consolidated cash flows:

	Changes to the Statement of Consolidated Cash Flows
For the Year Ended December 31, 2016	Under Full Cost			Changes*			As Reported Under Successful Efforts
	(In millions)
Net loss including noncontrolling interest	$	(1,394	)	$	121		$	(1,273	)
Gain on divestitures, net	(17		)	(4		)	(21		)
Exploratory dry hole expense and unproved leasehold impairments	—			353			353
Depreciation, depletion, and amortization	3,570			(952		)	2,618
Impairments	677			426			1,103
Benefit from deferred income taxes	(721		)	(112		)	(833		)
Changes in operating assets and liabilities	138			15			153
Net cash provided by continuing operating activities	2,606			(153		)	2,453
Additions to oil and gas property	(1,776		)	166			(1,610		)
Net cash used in investing activities	(1,826		)	166			(1,660		)
Other	6			(13		)	(7		)
Net cash used in financing activities	(847		)	(13		)	(860		)
NET DECREASE IN CASH	(90		)	—			(90		)
BEGINNING CASH BALANCE	1,467			—			1,467
ENDING CASH BALANCE	1,377			—			1,377

	Changes to the Statement of Consolidated Cash Flows
For the Year Ended December 31, 2015	Under Full Cost			Changes*			As Reported Under Successful Efforts
	(In millions)
Net loss including noncontrolling interest	$	(23,528	)	$	12,861		$	(10,667	)
Loss (income) from discontinued operations	771			(1,263		)	(492		)
Gain on divestitures, net	(59		)	(222		)	(281		)
Exploratory dry hole expense and unproved leasehold impairments	—			2,595			2,595
Depreciation, depletion, and amortization	29,372			(26,072		)	3,300
Impairments	1,920			7,552			9,472
Other noncash items, net	161			(154		)	7
Benefit from deferred income taxes	(5,778		)	4,333			(1,445		)
Changes in operating assets and liabilities	(170		)	90			(80		)
Net cash provided by operating activities - continuing operations	2,834			(280		)	2,554
Net cash provided by operating activities - discontinued operations	150			(37		)	113
Additions to oil and gas property	(4,578		)	370			(4,208		)
Net cash used in investing activities - continuing operations	(3,659		)	370			(3,289		)
Net cash provided by investing activities - discontinued operations	4,335			37			4,372
NET INCREASE IN CASH	698			90			788
BEGINNING CASH BALANCE	769			(90		)	679
ENDING CASH BALANCE	1,467			—			1,467

	Changes to the Statement of Consolidated Cash Flows
For the Year Ended December 31, 2014	Under Full Cost			Changes*			As Reported Under Successful Efforts
	(In millions)
Net loss including noncontrolling interest	$	(5,060	)	$	(2,959	)	$	(8,019	)
Income from discontinued operations	1,588			119			1,707
Loss on divestitures, net	180			1,428			1,608
Exploratory dry hole expense and unproved leasehold impairments	—			2,294			2,294
Depreciation, depletion, and amortization	9,720			(5,194		)	4,526
Impairments	1,919			5,183			7,102
Benefit from deferred income taxes	(514		)	(1,285		)	(1,799		)
Changes in operating assets and liabilities	(239		)	(90		)	(329		)
Net cash provided by operating activities - continuing operations	7,517			(504		)	7,013
Net cash provided by operating activities - discontinued operations	944			—			944
Additions to oil and gas property	(9,022		)	414			(8,608		)
Net cash used in investing activities - continuing operations	(8,585		)	414			(8,171		)
Net cash used in investing activities - discontinued operations	(219		)	—			(219		)
NET DECREASE IN CASH	(1,137		)	(90		)	(1,227		)
BEGINNING CASH BALANCE	1,906			—			1,906
ENDING CASH BALANCE	769			(90		)	679

The following tables present the effects of the change to the successful efforts method in the consolidated balance sheet:

	Changes to the Consolidated Balance Sheet
December 31, 2016	Under Full Cost			Changes*			As Reported Under Successful Efforts
	(In millions)
PROPERTY AND EQUIPMENT:
Property and equipment - cost	$	95,371		$	(48,622	)	$	46,749
Less: Accumulated depreciation, depletion, and amortization	(83,230		)	55,348			(27,882		)
PROPERTY AND EQUIPMENT, NET	12,141			6,726			18,867
TOTAL ASSETS	15,793			6,726			22,519
Income taxes	353			1,357			1,710
Paid-in capital	12,225			139			12,364
Accumulated deficit	(8,521		)	5,136			(3,385		)
Accumulated other comprehensive loss	(109		)	(3		)	(112		)
Noncontrolling interest	1,344			97			1,441
TOTAL EQUITY	2,310			5,369			7,679

	Changes to the Consolidated Balance Sheet
December 31, 2015	Under Full Cost			Changes*			As Reported Under Successful Efforts
	(In millions)
PROPERTY AND EQUIPMENT:
Property and equipment - cost	$	93,825		$	(47,675	)	$	46,150
Less: Accumulated depreciation, depletion, and amortization	(79,706		)	54,394			(25,312		)
PROPERTY AND EQUIPMENT, NET	14,119			6,719			20,838
TOTAL ASSETS	18,781			6,719			25,500
Income taxes	1,072			1,457			2,529
Paid-in capital	12,467			152			12,619
Accumulated deficit	(7,153		)	5,173			(1,980		)
Accumulated other comprehensive loss	(116		)	(3		)	(119		)
Noncontrolling interest	1,662			(60		)	1,602
TOTAL EQUITY	4,228			5,262			9,490

*In conjunction with recasting the financial information for the adoption of the successful efforts method of accounting, the Company corrected certain immaterial errors in the North Sea pertaining to the improper calculation of deferred tax liabilities associated with capitalized interest under the full cost method.

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Acquisitions and Divestitures (Tables) - Divestiture [Member]

12 Months Ended

Dec. 31, 2016

Argentina [Member]

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

	For the Year Ended December 31,
	2016			2015		2014
	(In millions)
Revenues and other from discontinued operations	$	—		$	—	$	87
Loss from Argentina divestiture	$	(10	)	$	—	$	(654	)
Loss from operations in Argentina	—			—		(1		)
Income tax benefit	—			—		23
Loss from discontinued operations, net of tax	$	(10	)	$	—	$	(632	)

Australia [Member]

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

	For the Year Ended December 31,
	2016			2015			2014
	(In millions)
Revenues and other from discontinued operations	$	—		$	288		$	1,050
Impairment on Woodside sale	$	—		$	(49	)	$	(833	)
Loss on Woodside sale	(23		)	—			—
Loss on Consortium sale	—			(139		)	—
Income (loss) from divested Australian operations	—			28			(12		)
Income tax benefit (expense)	—			652			(231		)
Income (loss) from Australian discontinued operations, net of tax	$	(23	)	$	492		$	(1,076	)

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Capitalized Exploratory Well Costs (Tables)

12 Months Ended

Dec. 31, 2016

Extractive Industries [Abstract]

Capitalized Exploratory Well Costs, Roll Forward

The following summarizes the changes in capitalized exploratory well costs for each of the last three years ended December 31, 2016, 2015, and 2014. Additions pending the determination of proved reserves excludes amounts capitalized and subsequently charged to expense within the same year.

	2016			2015			2014
	(In millions)
Balance at January 1	$	245		$	849		$	630
Additions pending determination of proved reserves	249			382			622
Divestitures and other	—			(557		)	(54		)
Reclassifications to proved properties	(211		)	(369		)	(207		)
Charged to exploration expense	(19		)	(60		)	(142		)
Balance at December 31(1)	$	264		$	245		$	849

⁽¹⁾ Includes $49 million of assets that were held for sale in Australia at December 31, 2014.

Schedule of Aging of Capitalized Exploratory Well Costs

The following provides an aging of capitalized exploratory well costs and the number of projects for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling:

	2016		2015		2014
	(In millions)
Exploratory well costs capitalized for a period of one year or less	$	119	$	184	$	504
Exploratory well costs capitalized for a period greater than one year	145		61		345
Balance at December 31(1)	$	264	$	245	$	849
Number of projects with exploratory well costs capitalized for a period greater than one year	3		2		18

⁽¹⁾ Includes $49 million of assets that were held for sale in Australia at December 31, 2014.

Schedule of Projects with Exploratory Well Costs Capitalized for More than One Year

The following summarizes a further aging by geographic area of those exploratory well costs that have been capitalized for a period greater than one year since the completion of drilling at December 31, 2016:

							2013 and
	Total		2015		2014		Prior
North Sea	$	113	$	53	$	58	$	2
Other International	32		28		3		1
	$	145	$	81	$	61	$	3

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Derivative Instruments and Hedging Activities (Tables)

12 Months Ended

Dec. 31, 2016

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Commodity Derivative Activity Recorded in Statement of Consolidated Operations

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

	Gain (Loss) on Derivatives Recognized in Income	For the Year Ended December 31,
		2016		2015		2014
		(In millions)
Derivatives not designated as cash flow hedges:
Realized loss		$	—	$	—	$	(16	)
Unrealized gain (loss)		—		—		300
Gain (loss) on derivatives not designated as cash flow hedges	Revenues and Other: Other	$	—	$	—	$	284

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Other Current Liabilities (Tables)

12 Months Ended

Dec. 31, 2016

Payables and Accruals [Abstract]

Detail of Other Current Liabilities

The following table provides detail of the Company’s other current liabilities at December 31, 2016 and 2015:

	December 31,
	2016		2015
	(In millions)
Accrued operating expenses	$	110	$	139
Accrued exploration and development	463		637
Accrued compensation and benefits	201		166
Accrued interest	145		144
Accrued income taxes	22		47
Current asset retirement obligation	66		36
Current debt	—		1
Refundable deposits	174		—
Other	77		53
Total Other current liabilities	$	1,258	$	1,223

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Asset Retirement Obligation (Tables)

12 Months Ended

Dec. 31, 2016

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, 2016 and 2015:

	2016			2015
	(In millions)
Asset retirement obligation at beginning of year	$	2,598		$	2,952
Liabilities incurred	41			68
Liabilities divested	(7		)	(490		)
Liabilities settled	(57		)	(90		)
Accretion expense	156			158
Revisions in estimated liabilities	(233		)	—
Asset retirement obligation at end of year	2,498			2,598
Less current portion	(66		)	(36		)
Asset retirement obligation, long-term	$	2,432		$	2,562

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Debt (Tables)

12 Months Ended

Dec. 31, 2016

Debt Disclosure [Abstract]

Debt for Apache and Subsidiaries

The following table presents the carrying value of the Company’s debt at December 31, 2016 and 2015:

	December 31,
	2016			2015
	(In millions)
Commercial paper	$	—		$	—
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)	493			500
3.25% notes due 2022(1)	857			919
2.625% notes due 2023(1)	528			531
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)	1,499			1,500
5.25% notes due 2042(1)	500			500
4.75% notes due 2043(1)	1,413			1,500
4.25% notes due 2044(1)	780			800
7.375% debentures due 2047	150			150
7.625% debentures due 2096	150			150
	8,350			8,530
Subsidiary and other obligations:
Notes due in 2017	—			1
Apache Finance Canada 7.75% notes due 2029	300			300
	300			301
Debt before unamortized discount and debt issuance costs	8,650			8,831
Unamortized discount	(50		)	(53		)
Debt issuance costs	(56		)	(61		)
Total debt	8,544			8,717
Current maturities	—			(1		)
Long-term debt	$	8,544		$	8,716

(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, 2016, excluding discounts and debt issuance costs, are as follows:

	(In millions)
2017	$	—
2018	550
2019	150
2020	—
2021	493
Thereafter(1)	7,457
Total Debt(1), excluding discounts and debt issuance costs	$	8,650

(1) In January 2017, Apache purchased and canceled $69 million aggregate principal amount of senior notes (see overview above), which reduces “Thereafter” and “Total Debt” maturities to $7.4 billion and $8.6 billion, respectively, as of January 31, 2017.

Summary of Carrying Amounts and Estimated Fair Values

	December 31, 2016				December 31, 2015
	Carrying     Amount		Fair     Value		Carrying     Amount		Fair     Value
	(In millions)
Commercial paper	$	—	$	—	$	—	$	—
Notes and debentures	8,544		9,183		8,717		8,330
Total Debt	$	8,544	$	9,183	$	8,717	$	8,330

Components of Financing Costs, Net

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

	For the Year Ended December 31,
	2016			2015			2014
	(In millions)
Interest expense	$	464		$	486		$	499
Amortization of deferred loan costs	8			11			6
Capitalized interest	(48		)	(15		)	(85		)
Loss on extinguishment of debt	1			39			—
Interest income	(8		)	(10		)	(7		)
Financing costs, net	$	417		$	511		$	413

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2016

Income Tax Disclosure [Abstract]

Income (Loss) Before Income Taxes

Loss from continuing operations before income taxes is composed of the following:

	For the Year Ended December 31,
	2016			2015			2014
	(In millions)
U.S.	$	(997	)	$	(9,386	)	$	(4,807	)
Foreign	(685		)	(2,783		)	(2,023		)
Total	$	(1,682	)	$	(12,169	)	$	(6,830	)

Total Provision for Income Taxes

The total income tax provision (benefit) from continuing operations consists of the following:

	For the Year Ended December 31,
	2016			2015			2014
	(In millions)
Current income taxes:
Federal	$	(14	)	$	363		$	(10	)
State	(30		)	41			1
Foreign	435			31			1,290
	391			435			1,281
Deferred income taxes:
Federal	(257		)	(1,123		)	(671		)
State	—			(51		)	(45		)
Foreign	(576		)	(271		)	(1,083		)
	(833		)	(1,445		)	(1,799		)
Total	$	(442	)	$	(1,010	)	$	(518	)

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

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

	For the Year Ended December 31,
	2016			2015			2014
	(In millions)
Income tax expense (benefit) at U.S. statutory rate	$	(589	)	$	(4,259	)	$	(2,391	)
State income tax, less federal effect(1)	(19		)	(7		)	(28		)
Taxes related to foreign operations	303			(662		)	(147		)
Tax credits	(1		)	(6		)	—
Tax on distributed foreign earnings	80			726			311
Foreign tax credits	(136		)	(2,090		)	—
Deferred tax on undistributed foreign earnings	(31		)	1,903			560
Tax impact of goodwill adjustments	—			82			161
Change in U.K. tax rate	(238		)	(414		)	—
Net change in tax contingencies	(19		)	20			(3		)
Canadian USD functional currency election	158			—			—
Valuation allowances(1)	10			3,746			1,021
All other, net	40			(49		)	(2		)
	$	(442	)	$	(1,010	)	$	(518	)

(1) The change in state valuation allowance is included as a component of state income tax.

Net Deferred Tax Liability

The net deferred income tax liability consists of the following:

	December 31,
	2016			2015
	(In millions)
Deferred tax assets:
Deferred income	$	105		$	20
U.S. and state net operating losses	1,095			329
Foreign net operating losses	1,424			1,507
Tax credits and other tax incentives	62			82
Foreign tax credits	2,226			2,090
Accrued expenses and liabilities	153			136
Asset retirement obligation	875			1,037
Property and equipment	1,189			1,534
Total deferred tax assets	7,129			6,735
Valuation allowance	(5,401		)	(5,434		)
Net deferred tax assets	1,728			1,301
Deferred tax liabilities:
Deferred income	—			140
Investment in foreign subsidiaries	1,872			1,903
Equity investments	23			5
Property and equipment	1,533			1,773
Other	5			4
Total deferred tax liabilities	3,433			3,825
Net deferred income tax liability	$	1,705		$	2,524

Net deferred tax assets and liabilities are included in the consolidated balance sheet as follows:

	December 31,
	2016		2015
	(In millions)
Assets:
Deferred charges and other	$	5	$	5
Liabilities:
Deferred income taxes	1,710		2,529
Net deferred income tax liability	$	1,705	$	2,524

Summary of Valuation Allowance Against Certain Foreign Net Deferred Tax Assets and State Net Operating Losses

In 2016, 2015, and 2014, the Company's valuation allowance decreased by $33 million, increased by $3.9 billion, and increased by $966 million, respectively, as detailed in the table below:

	2016			2015		2014
	(In millions)
Balance at beginning of year	$	5,434		$	1,564	$	598
State(1)	(43		)	151		62
U.S.	139			2,159		—
Foreign(2)	(129		)	1,560		1,021
Discontinued operations(3)	—			—		(117		)
Balance at end of year	$	5,401		$	5,434	$	1,564

(1) Reported as a component of state income taxes.

(2) In 2015, Apache’s subsidiaries completed the sale of its interest in the Kitimat LNG project. As such, the deferred tax assets, liabilities, and valuation allowance related to the project were removed for 2015.

(3) In 2014, Apache’s subsidiaries completed the sale of all of the Company’s operations in Argentina. As such, the deferred tax assets, liabilities, and valuation allowance related to Argentina were removed for 2014.

Net Operating Losses

On December 31, 2016, the Company had net operating losses as follows:

	Amount		Expiration
	(In millions)
Net operating losses:
U.S.	$	2,452	2018 - 2037
State	4,774		Various
Canada	125		2028 - 2035

Schedule of Foreign Tax Credit Carryforward

On December 31, 2016, the Company had foreign tax credits as follows:

	Amount		Expiration
	(In millions)
Foreign tax credits	$	2,226	2025-2026

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:

	2016			2015		2014
	(In millions)
Balance at beginning of year	$	19		$	—	$	3
Additions based on tax positions related to the current year	15			19		—
Reductions for tax positions of prior years	(19		)	—		(3		)
Balance at end of year	$	15		$	19	$	—

Key Jurisdictions of Company's Earliest Open Tax Years

U.S.	2012
Canada	2012
Egypt	1998
U.K.	2014

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2016

Commitments and Contingencies Disclosure [Abstract]

Contractual Obligations

At December 31, 2016, contractual obligations for long-term operating leases, capital leases, and purchase obligations are as follows:

Net Minimum Commitments	Total		2017		2018-2019		2020-2021		2022 & Beyond
	(In millions)
Drilling rigs	$	244	$	177	$	67	$	—	$	—
Purchase obligations(1)	680		119		287		250		24
Operating lease obligations(2)	258		56		95		37		70
Capital lease obligations	$	43	$	1	$	3	$	3	$	36
Total Net Minimum Commitments	$	1,225	$	353	$	452	$	290	$	130

(1) Includes minimum commitments associated with long-term take-or-pay contracts, NGL processing agreements, drilling work program commitments, and agreements to secure capacity rights on third-party pipelines.

(2) Amounts include long-term lease payments for office space, aircraft, supply and standby vessels, gas pipeline and land leases, and equipment related to exploration, development, and production activities, such as compressors. The Company expects to receive $10 million in sublease income associated with these leases.

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Retirement and Deferred Compensation Plans (Tables)

12 Months Ended

Dec. 31, 2016

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, 2016, 2015, and 2014, 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.

	2016						2015						2014
	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	$	202		$	26		$	216		$	22		$	189		$	28
Service cost	4			2			5			2			5			3
Interest cost	7			1			8			1			9			1
Foreign currency exchange rate changes	(39		)	—			(10		)	—			(13		)	—
Actuarial losses (gains)	32			(2		)	(10		)	—			31			(9		)
Effect of curtailment and settlements	—			—			—			2			—			—
Benefits paid	(4		)	(3		)	(7		)	(2		)	(5		)	(2		)
Retiree contributions	—			2			—			1			—			1
Projected benefit obligation at end of year	202			26			202			26			216			22
Change in Plan Assets
Fair value of plan assets at beginning of year	197			—			206			—			191			—
Actual return on plan assets	46			—			1			—			25			—
Foreign currency exchange rates	(39		)	—			(10		)	—			(13		)	—
Employer contributions	6			1			7			1			8			1
Benefits paid	(4		)	(3		)	(7		)	(2		)	(5		)	(2		)
Retiree contributions	—			2			—			1			—			1
Fair value of plan assets at end of year	206			—			197			—			206			—
Funded status at end of year	$	4		$	(26	)	$	(5	)	$	(26	)	$	(10	)	$	(22	)
Amounts recognized in Consolidated Balance Sheet
Current liability	$	—		$	(2	)	$	—		$	(2	)	$	—		$	(1	)
Non-current asset (liability)	4			(24		)	(5		)	(24		)	(10		)	(21		)
	$	4		$	(26	)	$	(5	)	$	(26	)	$	(10	)	$	(22	)
Pre-tax Amounts Recognized in Accumulated Other Comprehensive Income (Loss)
Accumulated gain (loss)	$	(25	)	$	9		$	(32	)	$	9		$	(37	)	$	10
Weighted Average Assumptions used as of December 31
Discount rate	2.70		%	3.76		%	3.90		%	3.95		%	3.70		%	3.62		%
Salary increases	4.80		%	N/A			4.60		%	N/A			4.60		%	N/A
Expected return on assets	3.40		%	N/A			4.10		%	N/A			3.90		%	N/A
Healthcare cost trend
Initial	N/A			7.00		%	N/A			7.00		%	N/A			7.00		%
Ultimate in 2025	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
	2016		2016		2015
Asset Category
Equity securities:
U.K. quoted equities	14	%	14	%	14	%
Overseas quoted equities	26	%	26	%	26	%
Total equity securities	40	%	40	%	40	%
Debt securities:
U.K. Government bonds	47	%	47	%	48	%
U.K. corporate bonds	12	%	12	%	12	%
Debt securities	59	%	59	%	60	%
Cash	1	%	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, 2016 and December 31, 2015:

	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, 2016
Equity securities:
U.K. quoted equities(1)	$	28	$	—	$	—	$	28
Overseas quoted equities(2)	54		—		—		54
Total equity securities	82		—		—		82
Debt securities:
U.K. Government bonds(3)	97		—		—		97
U.K. corporate bonds(4)	25		—		—		25
Total debt securities	122		—		—		122
Cash	2		—		—		2
Fair value of plan assets	$	206	$	—	$	—	$	206
December 31, 2015
Equity securities:
U.K. quoted equities(1)	$	27	$	—	$	—	$	27
Overseas quoted equities(2)	53		—		—		53
Total equity securities	80		—		—		80
Debt securities:
U.K. Government bonds(3)	93		—		—		93
U.K. corporate bonds(4)	24		—		—		24
Total debt securities	117		—		—		117
Fair value of plan assets	$	197	$	—	$	—	$	197

(1) This category comprises U.K. passive equities, which are benchmarked against the FTSE 350 Index.

(2) This category includes overseas equities, which comprises 30 percent passive global equities benchmarked against the MSCI World (NDR) Index, 12 percent passive global equities (hedged) benchmarked against the MSCI World (NDR) Hedged Index, 30 percent fundamental indexation global equities benchmarked against the FTSE RAFI Developed 1000 index, 12 percent fundamental indexation global equities (hedged) benchmarked against the FTSE RAFI Developed 1000 Hedge Index, and 16 percent emerging markets benchmarked against the MSCI Emerging Markets (NDR) Index, which has 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, which comprises 48 percent index-linked gilts benchmarked against the FTSE Actuaries Government Securities Index-Linked Over 5 Years Index, 37 percent sterling nominal LDI bonds, and 15 percent sterling inflation linked LDI bonds, both benchmarked against ILIM Custom Benchmark index.

(4) This category comprises U.K. corporate bonds: 12 percent benchmarked against the BofAML Sterling Corporate & Collaterlised (excluding Subordinated) 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, 2016, 2015, and 2014:

	2016						2015						2014
	Pension Benefits			Postretirement Benefits			Pension Benefits			Postretirement Benefits			Pension Benefits			Postretirement Benefits
	(In millions)
Component of Net Periodic Benefit Costs
Service cost	$	4		$	2		$	5		$	2		$	5		$	3
Interest cost	7			1			8			1			9			1
Expected return on assets	(7		)	—			(8		)	—			(11		)	—
Amortization of actuarial (gain) loss	1			(1		)	2			—			1			—
Curtailment (gain) loss	—			—			—			—			—			—
Net periodic benefit cost	$	5		$	2		$	7		$	3		$	4		$	4
Weighted Average Assumptions used to determine Net Period Benefit Cost for the Years ended December 31
Discount rate	3.90		%	3.95		%	3.70		%	3.62		%	4.60		%	4.33		%
Salary increases	4.60		%	N/A			4.60		%	N/A			4.90		%	N/A
Expected return on assets	4.10		%	N/A			3.90		%	N/A			5.60		%	N/A
Healthcare cost trend
Initial	N/A			7.00		%	N/A			7.00		%	N/A			7.00		%
Ultimate in 2025	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	5		(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)
2017	$	4	$	2
2018	4		2
2019	4		2
2020	4		2
2021	4		2
Years 2022-2026	24		9

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Capital Stock (Tables)

12 Months Ended

Dec. 31, 2016

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Common Stock Outstanding

Common Stock Outstanding

	2016	2015	2014
Balance, beginning of year	378,034,175	376,504,892	395,772,908
Shares issued for stock-based compensation plans:
Treasury shares issued	11,504	17,525	17,454
Common shares issued	1,393,997	1,511,758	1,665,259
Treasury shares acquired	—	—	(20,950,729	)
Balance, end of year	379,439,676	378,034,175	376,504,892

Net Income Per Common Share

A reconciliation of the components of basic and diluted net income (loss) per common share for the years ended December 31, 2016, 2015, and 2014 is presented in the table below.

	2016							2015							2014
	Loss			Shares	Per Share			Income (Loss)			Shares	Per Share			Loss			Shares	Per Share
	(In millions, except per share amounts)
Basic and Diluted:
Loss from continuing operations	$	(1,372	)	379	$	(3.62	)	$	(10,844	)	378	$	(28.70	)	$	(6,653	)	384	$	(17.32	)
Income (loss) from discontinued operations	(33		)	379	(0.09		)	492			378	1.30			(1,707		)	384	(4.44		)
Loss attributable to common stock	$	(1,405	)	379	$	(3.71	)	$	(10,352	)	378	$	(27.40	)	$	(8,360	)	384	$	(21.76	)

Description of Stock Based Compensation Plans and Related Costs

A description of the Company’s stock-based compensation plans and related costs follows:

	2016		2015		2014
	(In millions)
Stock-based compensation expensed	$	131	$	100	$	148
Stock-based compensation capitalized	40		53		62
Total stock-based compensation costs	$	171	$	153	$	210

Summary of Stock Options Activities

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

	2016
	Shares Under Option		Weighted Average Exercise Price
	(In thousands)
Outstanding, beginning of year	4,931		$	91.52
Granted	873		41.24
Exercised	—		—
Forfeited or expired	(691	)	76.99
Outstanding, end of year(1)	5,113		84.89
Expected to vest(2)	887		46.88
Exercisable, end of year(3)	4,177		93.40

(1) As of December 31, 2016, options outstanding had a weighted average remaining contractual life of 4.6 years and aggregate intrinsic value of $18 million.

(2) As of December 31, 2016, options expected to vest had a weighted average remaining contractual life of 8.7 years and aggregate intrinsic value of $17 million.

(3) As of December 31, 2016, options exercisable had a weighted average remaining contractual life of 3.7 years and aggregate intrinsic value of nil.

Schedule of Assumptions Used

	2016			2015	2014
Expected volatility	32.72		%	N/A	N/A
Expected dividend yields	2.42		%	N/A	N/A
Expected term (in years)	6			N/A	N/A
Risk-free rate	1.44		%	N/A	N/A
Weighted-average grant-date fair value	$	10.38		N/A	N/A

Schedule of Restricted Stock and Restricted Stock Units Activity

A summary of restricted stock unit activity for the year ended December 31, 2016, is presented below.

	Shares		Weighted- Average Grant- Date Fair Value
	(In thousands)
Non-vested at January 1, 2016	4,570		$	70.86
Granted	4,049		47.37
Vested	(2,081	)	72.59
Forfeited	(476	)	58.05
Non-vested at December 31, 2016	6,062		55.55

Total Shareholder Return Stock Units [Member]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Schedule of Restricted Stock and Restricted Stock Units Activity

The weighted-average remaining life of the unvested conditional restricted stock units is approximately 0.7 years.

	Shares		Weighted- Average Grant- Date Fair Value(1)
	(In thousands)
Non-vested at January 1, 2016	172		$	78.22
Granted	—		—
Vested	(34	)	76.07
Forfeited or expired	(60	)	71.20
Non-vested at December 31, 2016	78		77.10

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

Conditional Restricted Stock [Member]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Schedule of Restricted Stock and Restricted Stock Units Activity

	Shares		Weighted Average Grant- Date Fair Value(1)
	(In thousands)
Non-vested at January 1, 2016	501		$	66.53
Granted	871		34.19
Vested	—		—
Forfeited or expired	(147	)	45.65
Non-vested at December 31, 2016	1,225		45.60

(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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Accumulated Other Comprehensive Loss (Tables)

12 Months Ended

Dec. 31, 2016

Equity [Abstract]

Components of Accumulated Other Comprehensive Income (Loss)

Components of accumulated other comprehensive loss include the following:

	For the Year Ended December 31,
	2016			2015			2014
	(In millions)
Currency translation adjustment(1)	$	(109	)	$	(109	)	$	(109	)
Unfunded pension and postretirement benefit plan (Note 11)	(3		)	(10		)	(7		)
Accumulated other comprehensive loss	$	(112	)	$	(119	)	$	(116	)

(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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Business Segment Information (Tables)

12 Months Ended

Dec. 31, 2016

Segment Reporting [Abstract]

Financial Segment Information

Financial information for each area is presented below:

	United States			Canada			Egypt(1)		North Sea			Other International			Total(1)
	(In millions)
2016
Oil and gas production revenues	$	1,997		$	343		$	2,057	$	970		$	—		$	5,367
Operating Expenses:
Lease operating expenses	553			181			446		314			—			1,494
Gathering and transportation	80			68			44		8			—			200
Taxes other than income	139			20			—		(33		)	—			126
Depreciation, depletion, and amortization	1,138			183			778		519			—			2,618
Exploration	285			88			48		37			15			473
Asset retirement obligation accretion	34			47			—		75			—			156
Impairments	80			367			1		655			—			1,103
Operating Income (Loss)	$	(312	)	$	(611	)	$	740	$	(605	)	$	(15	)	(803		)
Other Income (Expense):
Gain on divestitures, net															21
Other															(34		)
General and administrative															(410		)
Transaction, reorganization, and separation															(39		)
Financing costs, net															(417		)
Net Loss From Continuing Operations Before Income Taxes															$	(1,682	)
Net Property and Equipment	$	11,168		$	1,464		$	3,362	$	2,834		$	39		$	18,867
Total Assets	$	12,403		$	1,591		$	4,893	$	3,584		$	48		$	22,519
Additions to Net Property and Equipment	$	926		$	34		$	459	$	260		$	2		$	1,681

	United States			Canada			Egypt(1)			North Sea			Other International			Total(1)
	(In millions)
2015
Oil and gas production revenues	$	2,637		$	498		$	2,095		$	1,280		$	—		$	6,510
Operating Expenses:
Lease operating expenses	739			244			522			349			—			1,854
Gathering and transportation	68			89			45			9			—			211
Taxes other than income	184			26			9			63			—			282
Depreciation, depletion, and amortization	1,558			301			927			514			—			3,300
Exploration	2,145			231			154			237			4			2,771
Asset retirement obligation accretion	28			43			—			74			—			145
Impairments	6,266			1,593			1,255			211			147			9,472
Operating Loss	$	(8,351	)	$	(2,029	)	$	(817	)	$	(177	)	$	(151	)	(11,525		)
Other Income (Expense):
Gain on divestitures, net																281
Other																98
General and administrative																(380		)
Transaction, reorganization, and separation																(132		)
Financing costs, net																(511		)
Net Loss From Continuing Operations Before Income Taxes																$	(12,169	)
Net Property and Equipment	$	11,753		$	2,074		$	3,712		$	3,263		$	36		$	20,838
Total Assets	$	12,782		$	2,225		$	6,165		$	4,280		$	48		$	25,500
Additions to Net Property and Equipment	$	2,099		$	403		$	862		$	715		$	27		$	4,106

2014
Oil and gas production revenues	$	5,744		$	1,092		$	3,643	$	2,316		$	—		$	12,795
Operating Expenses:
Lease operating expenses	921			384			499		434			—			2,238
Gathering and transportation	93			123			40		17			—			273
Taxes other than income	350			31			11		185			—			577
Depreciation, depletion, and amortization	2,408			439			872		807			—			4,526
Exploration	2,113			162			112		119			(7		)	2,499
Asset retirement obligation accretion	43			39			—		72			—			154
Impairments	2,622			2,412			173		1,895			—			7,102
Operating Income (Loss)	$	(2,806	)	$	(2,498	)	$	1,936	$	(1,213	)	$	7		(4,574		)
Other Income (Expense):
Loss on divestitures, net															(1,608		)
Other															285
General and administrative															(453		)
Transaction, reorganization, and separation															(67		)
Financing costs, net															(413		)
Net Loss From Continuing Operations Before Income Taxes															$	(6,830	)
Net Property and Equipment	$	19,507		$	4,197		$	5,141	$	3,300		$	9		$	32,154
Total Assets	$	21,487		$	4,728		$	6,926	$	4,480		$	544		$	38,165
Additions to Net Property and Equipment	$	7,006		$	1,358		$	1,293	$	1,060		$	8		$	10,725

(1) Includes a noncontrolling interest in Egypt.

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Supplemental Oil and Gas Disclosures (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2016

Extractive Industries [Abstract]

Revenue and Direct Cost Information Relating to Company's Oil and Gas Exploration and Production Activities

Apache completed the sale of its Australian LNG business and oil and gas assets, and as such the results of Australia oil and gas assets have been classified as discontinued operations.

	United States			Canada			Egypt(3)		North Sea			Other International			Total(3)(4)
	(In millions, except per boe)
2016
Oil and gas production revenues	$	1,997		$	343		$	2,057	$	970		$	—		$	5,367
Operating cost:
Depreciation, depletion, and amortization(1)	1,055			174			733		498			—			2,460
Asset retirement obligation accretion	34			47			—		75			—			156
Lease operating expenses	553			181			446		314			—			1,494
Gathering and transportation	80			68			44		8			—			200
Exploration expenses	285			88			48		37			15			473
Impairments related to oil and gas properties	61			366			—		—			—			427
Production taxes(2)	135			18			—		(33		)	—			120
Income tax	(72		)	(162		)	354		28			—			148
	2,131			780			1,625		927			15			5,478
Results of operation	$	(134	)	$	(437	)	$	432	$	43		$	(15	)	$	(111	)
2015
Oil and gas production revenues	$	2,637		$	498		$	2,095	$	1,280		$	—		$	6,510
Operating cost:
Depreciation, depletion, and amortization(1)	1,455			251			780		490			—			2,976
Asset retirement obligation accretion	28			43			—		74			—			145
Lease operating expenses	739			244			522		349			—			1,854
Gathering and transportation	68			89			45		9			—			211
Exploration expenses	2,145			231			154		237			4			2,771
Impairments related to oil and gas properties	6,154			1,031			193		11			—			7,389
Production taxes(2)	178			23			—		58			—			259
Income tax	(2,886		)	(369		)	180		26			—			(3,049		)
	7,881			1,543			1,874		1,254			4			12,556
Results of operation	$	(5,244	)	$	(1,045	)	$	221	$	26		$	(4	)	$	(6,046	)
2014
Oil and gas production revenues	$	5,744		$	1,092		$	3,643	$	2,316		$	—		$	12,795
Operating cost:
Depreciation, depletion, and amortization(1)	2,294			382			735		784			—			4,195
Asset retirement obligation accretion	43			39			—		72			—			154
Lease operating expenses	921			384			499		434			—			2,238
Gathering and transportation	93			123			40		17			—			273
Exploration expenses	2,113			162			112		119			(7		)	2,499
Impairments related to oil and gas properties	2,372			1,645			173		1,878			—			6,068
Production taxes(2)	342			27			—		177			—			546
Income tax	(864		)	(421		)	938		(723		)	—			(1,070		)
	7,314			2,341			2,497		2,758			(7		)	14,903
Results of operation	$	(1,570	)	$	(1,249	)	$	1,146	$	(442	)	$	7		$	(2,108	)

(1) This amount only reflects DD&A of capitalized costs of oil and gas properties and, therefore, does not agree with DD&A reflected on Note 15—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 15—Business Segment Information.

(3) Includes noncontrolling interest in Egypt.

(4) Prior year 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)
2016
Acquisitions:
Proved	$	—		$	1		$	6	$	—	$	38		$	—	$	—	$	45
Unproved	110			7			49		—		4			—		—		170
Exploration	278			23			67		—		84			—		18		470
Development	420			27			353		—		150			—		—		950
Costs incurred(1)	$	808		$	58		$	475	$	—	$	276		$	—	$	18	$	1,635
(1) Includes capitalized interest and asset retirement costs as follows:
Capitalized interest	$	21		$	6		$	—	$	—	$	21		$	—	$	—	$	48
Asset retirement costs	(51		)	(13		)	—		—		(128		)	—		—		(192		)
2015
Acquisitions:
Proved	$	1		$	8		$	29	$	—	$	—		$	—	$	—	$	38
Unproved	313			23			—		—		—			—		—		336
Exploration	194			51			125		32		246			—		29		677
Development	1,729			151			741		98		479			—		—		3,198
Costs incurred(1)	$	2,237		$	233		$	895	$	130	$	725		$	—	$	29	$	4,249
(1)Includes capitalized interest and asset retirement costs as follows:
Capitalized interest	$	—		$	—		$	8	$	6	$	7		$	—	$	—	$	21
Asset retirement costs	123			8			—		—		(66		)	—		—		65
2014
Acquisitions:
Proved	$	102		$	—		$	11	$	—	$	—		$	—	$	—	$	113
Unproved	1,221			141			—		16		—			—		—		1,378
Exploration	505			93			207		131		103			9		1		1,049
Development	5,078			789			1,122		990		956			6		—		8,941
Costs incurred(1)	$	6,906		$	1,023		$	1,340	$	1,137	$	1,059		$	15	$	1	$	11,481
(1) Includes capitalized interest and asset retirement costs as follows:
Capitalized interest	$	17		$	—		$	9	$	90	$	29		$	3	$	—	$	148
Asset retirement costs	43			175			—		55		34			—		—		307
(2) Includes a noncontrolling interest in Egypt.

	United States			Canada			Egypt(1)			North Sea			Other International		Total(1)
	(In millions)
2016
Proved properties	$	19,170		$	5,434		$	10,169		$	7,920		$	—	$	42,693
Unproved properties	1,465			109			76			280			39		1,969
	20,635			5,543			10,245			8,200			39		44,662
Accumulated DD&A	(10,034		)	(4,120		)	(7,287		)	(5,531		)	—		(26,972		)
	$	10,601		$	1,423		$	2,958		$	2,669		$	39	$	17,690
2015
Proved properties	$	18,692		$	5,812		$	9,798		$	7,426		$	—	$	41,728
Unproved properties	1,615			172			25			429			36		2,277
	20,307			5,984			9,823			7,855			36		44,005
Accumulated DD&A	(9,027		)	(3,958		)	(6,559		)	(4,913		)	—		(24,457		)
	$	11,280		$	2,026		$	3,264		$	2,942		$	36	$	19,548
(1) Includes a noncontrolling interest in Egypt.

Proved Reserve Data

	Crude Oil and Condensate
	(Thousands of barrels)
	United States		Canada		Egypt(1)		Australia		North Sea		Argentina		Total(1)
Proved developed reserves:
December 31, 2013	457,981		80,526		119,242		22,524		100,327		14,195		794,795
December 31, 2014	444,440		75,876		128,712		29,996		105,746		—		784,770
December 31, 2015	348,797		67,847		144,164		—		104,255		—		665,063
December 31, 2016	300,900		51,508		138,771		—		91,138		—		582,317
Proved undeveloped reserves:
December 31, 2013	195,835		56,366		16,302		36,703		29,253		2,231		336,690
December 31, 2014	170,125		59,923		14,617		25,775		19,059		—		289,499
December 31, 2015	60,505		38,326		17,856		—		11,309		—		127,996
December 31, 2016	21,088		7,906		20,187		—		10,784		—		59,965
Total proved reserves:
Balance December 31, 2013	653,816		136,892		135,544		59,227		129,580		16,426		1,131,485
Extensions, discoveries and other additions	57,011		9,657		38,074		4,254		17,386		5		126,387
Purchase of minerals in-place	15,240		—		—		—		—		—		15,240
Revisions of previous estimates	3,083		(812	)	2,645		(216	)	(7	)	—		4,693
Production	(48,789	)	(6,421	)	(32,934	)	(7,494	)	(22,154	)	(620	)	(118,412	)
Sale of properties	(65,796	)	(3,517	)	—		—		—		(15,811	)	(85,124	)
Balance December 31, 2014	614,565		135,799		143,329		55,771		124,805		—		1,074,269
Extensions, discoveries and other additions	13,903		4,550		24,524		—		16,579		—		59,556
Purchase of minerals in-place	—		1,763		—		—		—		—		1,763
Revisions of previous estimates	(173,907	)	(27,966	)	27,330		11,189		(2,255	)	—		(165,609	)
Production	(45,138	)	(5,755	)	(33,163	)	(2,778	)	(21,657	)	—		(108,491	)
Sale of properties	(121	)	(2,218	)	—		(64,182	)	(1,908	)	—		(68,429	)
Balance December 31, 2015	409,302		106,173		162,020		—		115,564		—		793,059
Extensions, discoveries and other additions	9,614		3,372		17,599		—		9,766		—		40,351
Purchase of minerals in-place	21		—		—		—		438		—		459
Revisions of previous estimates	(58,882	)	(43,282	)	17,301		—		(3,851	)	—		(88,714	)
Production	(38,000	)	(4,787	)	(37,962	)	—		(19,995	)	—		(100,744	)
Sale of properties	(67	)	(2,062	)	—		—		—		—		(2,129	)
Balance December 31, 2016	321,988		59,414		158,958		—		101,922		—		642,282

(1)    2016, 2015, 2014, and 2013 includes proved reserves of 53 MMbbls, 54 MMbbls, 48 MMbbls, and 45 MMbbls, respectively, attributable to a noncontrolling interest in Egypt.

	Natural Gas Liquids
	(Thousands of barrels)
	United States		Canada		Egypt(1)		Australia	North Sea		Argentina		Total(1)
Proved developed reserves:
December 31, 2013	184,485		26,099		—		—	2,435		4,110		217,129
December 31, 2014	183,565		17,947		1,346		—	1,770		—		204,628
December 31, 2015	150,265		15,246		1,491		—	1,784		—		168,786
December 31, 2016	155,124		13,866		1,266		—	1,627		—		171,883
Proved undeveloped reserves:
December 31, 2013	63,538		9,970		—		—	215		1,009		74,732
December 31, 2014	69,828		7,168		212		—	371		—		77,579
December 31, 2015	24,939		4,839		78		—	295		—		30,151
December 31, 2016	17,311		2,473		131		—	646		—		20,561
Total proved reserves:
Balance December 31, 2013	248,023		36,069		—		—	2,650		5,119		291,861
Extensions, discoveries and other additions	47,516		1,163		1,820		—	1		—		50,500
Purchase of minerals in-place	2,916		—		—		—	—		—		2,916
Revisions of previous estimates	2,594		116		(11	)	—	(2	)	—		2,697
Production	(21,464	)	(2,256	)	(251	)	—	(508	)	(116	)	(24,595	)
Sale of properties	(26,192	)	(9,977	)	—		—	—		(5,003	)	(41,172	)
Balance December 31, 2014	253,393		25,115		1,558		—	2,141		—		282,207
Extensions, discoveries and other additions	5,768		1,473		144		—	689		—		8,074
Purchase of minerals in-place	—		976		—		—	—		—		976
Revisions of previous estimates	(64,226	)	(4,886	)	255		—	(321	)	—		(69,178	)
Production	(19,684	)	(2,236	)	(388	)	—	(413	)	—		(22,721	)
Sale of properties	(47	)	(357	)	—		—	(17	)	—		(421	)
Balance December 31, 2015	175,204		20,085		1,569		—	2,079		—		198,937
Extensions, discoveries and other additions	10,238		755		208		—	671		—		11,872
Purchase of minerals in-place	2		—		—		—	5		—		7
Revisions of previous estimates	6,824		(1,355	)	17		—	141		—		5,627
Production	(19,824	)	(2,098	)	(397	)	—	(623	)	—		(22,942	)
Sale of properties	(9	)	(1,048	)	—		—	—		—		(1,057	)
Balance December 31, 2016	172,435		16,339		1,397		—	2,273		—		192,444

(1)    2016, 2015, and 2014 includes proved reserves of 466 Mbbls, 523 Mbbls, and 519 Mbbls, respectively, attributable to a noncontrolling interest in Egypt.

	Natural Gas
	(Millions of cubic feet)
	United States		Canada		Egypt(1)		Australia		North Sea		Argentina		Total(1)
Proved developed reserves:
December 31, 2013	2,005,966		1,294,420		621,825		626,543		88,177		289,133		4,926,064
December 31, 2014	1,616,504		990,145		637,187		640,265		87,259		—		3,971,360
December 31, 2015	1,364,174		759,321		776,263		—		85,532		—		2,985,290
December 31, 2016	1,200,379		553,724		675,559		—		86,948		—		2,516,610
Proved undeveloped reserves:
December 31, 2013	667,160		439,037		190,355		975,224		18,988		121,584		2,412,348
December 31, 2014	580,299		527,623		171,696		964,554		23,228		—		2,267,400
December 31, 2015	208,594		162,809		53,969		—		19,760		—		445,132
December 31, 2016	231,304		45,312		42,109		—		23,813		—		342,538
Total proved reserves:
Balance December 31, 2013	2,673,126		1,733,457		812,180		1,601,767		107,165		410,717		7,338,412
Extensions, discoveries and other additions	203,318		383,077		125,899		81,156		23,803		—		817,253
Purchase of minerals in-place	21,337		—		—		—		—		—		21,337
Revisions of previous estimates	35,910		(12,626	)	17,326		—		(54	)	—		40,556
Production	(215,829	)	(117,816	)	(146,522	)	(78,104	)	(20,427	)	(12,722	)	(591,420	)
Sale of properties	(521,059	)	(468,324	)	—		—		—		(397,995	)	(1,387,378	)
Balance December 31, 2014	2,196,803		1,517,768		808,883		1,604,819		110,487		—		6,238,760
Extensions, discoveries and other additions	40,901		121,216		94,777		—		41,755		—		298,649
Purchase of minerals in-place	—		24,727		—		—		—		—		24,727
Revisions of previous estimates	(503,939	)	(325,375	)	61,442		8,162		(22,373	)	—		(782,083	)
Production	(160,614	)	(100,289	)	(134,870	)	(34,352	)	(23,647	)	—		(453,772	)
Sale of properties	(383	)	(315,917	)	—		(1,578,629	)	(930	)	—		(1,895,859	)
Balance December 31, 2015	1,572,768		922,130		830,232		—		105,292		—		3,430,422
Extensions, discoveries and other additions	219,633		30,234		35,202		—		20,814		—		305,883
Purchase of minerals in-place	7		—		—		—		6,677		—		6,684
Revisions of previous estimates	(215,378	)	(242,080	)	(4,305	)	—		4,239		—		(457,524	)
Production	(145,019	)	(88,792	)	(143,461	)	—		(26,261	)	—		(403,533	)
Sale of properties	(328	)	(22,456	)	—		—		—		—		(22,784	)
Balance December 31, 2016	1,431,683		599,036		717,668		—		110,761		—		2,859,148

(1)    2016, 2015, 2014, and 2013 include proved reserves of 239 Bcf, 277 Bcf, 270 Bcf, and 271 Bcf, respectively, 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, 2013	976,795		322,362		222,880		126,948		117,457		66,494		1,832,936
December 31, 2014	897,422		258,848		236,256		136,707		122,058		—		1,651,291
December 31, 2015	726,424		209,647		275,033		—		120,293		—		1,331,397
December 31, 2016	656,087		157,662		252,630		—		107,256		—		1,173,635
Proved undeveloped reserves:
December 31, 2013	370,566		139,509		48,028		199,240		32,633		23,504		813,480
December 31, 2014	336,670		155,028		43,446		186,534		23,301		—		744,979
December 31, 2015	120,210		70,300		26,929		—		14,897		—		232,336
December 31, 2016	76,950		17,931		27,336		—		15,399		—		137,616
Total proved reserves:
Balance December 31, 2013	1,347,361		461,871		270,908		326,188		150,090		89,998		2,646,416
Extensions, discoveries and other additions	138,413		74,666		60,877		17,780		21,354		5		313,095
Purchase of minerals in-place	21,712		—		—		—		—		—		21,712
Revisions of previous estimates	11,662		(2,800	)	5,522		(216	)	(18	)	—		14,150
Production	(106,225	)	(28,313	)	(57,605	)	(20,511	)	(26,067	)	(2,856	)	(241,577	)
Sale of properties	(178,831	)	(91,548	)	—		—		—		(87,147	)	(357,526	)
Balance December 31, 2014	1,234,092		413,876		279,702		323,241		145,359		—		2,396,270
Extensions, discoveries and other additions	26,488		26,226		40,464		—		24,227		—		117,405
Purchase of minerals in-place	—		6,860		—		—		—		—		6,860
Revisions of previous estimates	(322,123	)	(87,081	)	37,825		12,549		(6,305	)	—		(365,135	)
Production	(91,591	)	(24,706	)	(56,029	)	(8,503	)	(26,011	)	—		(206,840	)
Sale of properties	(232	)	(55,228	)	—		(327,287	)	(2,080	)	—		(384,827	)
Balance December 31, 2015	846,634		279,947		301,962		—		135,190		—		1,563,733
Extensions, discoveries and other additions	56,458		9,166		23,674		—		13,906		—		103,204
Purchase of minerals in-place	24		—		—		—		1,556		—		1,580
Revisions of previous estimates	(87,954	)	(84,984	)	16,599		—		(3,002	)	—		(159,341	)
Production	(81,994	)	(21,684	)	(62,269	)	—		(24,995	)	—		(190,942	)
Sale of properties	(131	)	(6,852	)	—		—		—		—		(6,983	)
Balance December 31, 2016	733,037		175,593		279,966		—		122,655		—		1,311,251

(1)    2016, 2015, 2014, and 2013 include total proved reserves of 93 MMboe, 101 MMboe, 93 MMboe, and 90 MMboe, respectively, attributable to a noncontrolling interest in Egypt.

Unaudited Information of Future Net Cash Flows For Oil and Gas Reserves, Net of Income Tax Expense

	United States			Canada			Egypt(2)			North Sea			Total(2)
	(In millions)
2016
Cash inflows	$	20,067		$	3,625		$	8,778		$	4,734		$	37,204
Production costs	(8,858		)	(2,582		)	(1,967		)	(2,255		)	(15,662		)
Development costs	(1,653		)	(1,565		)	(1,111		)	(2,410		)	(6,739		)
Income tax expense	(32		)	—			(1,775		)	(8		)	(1,815		)
Net cash flows	9,524			(522		)	3,925			61			12,988
10 percent discount rate	(5,319		)	549			(956		)	798			(4,928		)
Discounted future net cash flows(1)	$	4,205		$	27		$	2,969		$	859		$	8,060
2015
Cash inflows	$	26,610		$	7,345		$	11,124		$	6,994		$	52,073
Production costs	(12,178		)	(3,841		)	(2,185		)	(3,209		)	(21,413		)
Development costs	(2,255		)	(1,939		)	(1,515		)	(2,346		)	(8,055		)
Income tax expense	(63		)	—			(2,326		)	(691		)	(3,080		)
Net cash flows	12,114			1,565			5,098			748			19,525
10 percent discount rate	(6,876		)	(868		)	(1,330		)	143			(8,931		)
Discounted future net cash flows(1)	$	5,238		$	697		$	3,768		$	891		$	10,594

(1) Estimated future net cash flows before income tax expense, discounted at 10 percent per annum, totaled approximately $9.5 billionand$13.1 billion as of December 31, 2016 and 2015, respectively.

(2) Includes discounted future net cash flows of approximately $1.0 billionand$1.3 billion in 2016 and 2015, respectively, 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,
	2016			2015			2014
	(In millions)
Sales, net of production costs	$	(3,479	)	$	(4,056	)	$	(10,350	)
Net change in prices and production costs	(3,835		)	(21,710		)	(1,029		)
Discoveries and improved recovery, net of related costs	1,153			1,953			6,297
Change in future development costs	309			705			(1,136		)
Previously estimated development costs incurred during the period	986			1,991			4,462
Revision of quantities	(574		)	(2,292		)	256
Purchases of minerals in-place	8			22			508
Accretion of discount	1,313			3,642			4,442
Change in income taxes	1,070			7,264			836
Sales of properties	(52		)	(5,240		)	(4,780		)
Change in production rates and other	567			(3,343		)	(442		)
	$	(2,534	)	$	(21,064	)	$	(936	)

XML

Supplemental Quarterly Financial Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2016

Quarterly Financial Information Disclosure [Abstract]

Supplemental Quarterly Financial Data

	First			Second			Third			Fourth			Total
	(In millions, except per share amounts)
2016
Revenues and other	$	1,084		$	1,365		$	1,433		$	1,451		$	5,333
Gain (loss) on divestitures	(1		)	17			5			—			21
Expenses(1)	1,454			1,582			1,964			1,594			6,594
Net loss from continuing operations including noncontrolling interest	(371		)	(200		)	(526		)	(143		)	(1,240		)
Net loss from discontinued operations, net of tax	—			—			(33		)	—			(33		)
Net loss including noncontrolling interest	$	(371	)	$	(200	)	$	(559	)	$	(143	)	$	(1,273	)
Net loss attributable to common stock	$	(372	)	$	(244	)	$	(607	)	$	(182	)	$	(1,405	)
Basic and diluted net loss per common share(2):
Net loss from continuing operations	$	(0.98	)	$	(0.65	)	$	(1.51	)	$	(0.48	)	$	(3.62	)
Net loss from discontinued operations	—			—			(0.09		)	—			(0.09		)
Net loss per share	$	(0.98	)	$	(0.65	)	$	(1.60	)	$	(0.48	)	$	(3.71	)
2015
Revenues and other	$	1,653		$	2,019		$	1,531		$	1,405		$	6,608
Gain (loss) on divestitures	(18		)	227			(5		)	77			281
Expenses(1)	2,703			3,163			5,645			6,537			18,048
Net loss from continuing operations including noncontrolling interest	(1,068		)	(917		)	(4,119		)	(5,055		)	(11,159		)
Net income (loss) from discontinued operations, net of tax	(238		)	120			(17		)	627			492
Net loss including noncontrolling interest	$	(1,306	)	$	(797	)	$	(4,136	)	$	(4,428	)	$	(10,667	)
Net loss attributable to common stock	$	(1,334	)	$	(860	)	$	(4,143	)	$	(4,015	)	$	(10,352	)
Basic and diluted net income (loss) per common share(2):
Net loss from continuing operations	$	(2.91	)	$	(2.60	)	$	(10.91	)	$	(12.28	)	$	(28.70	)
Net income (loss) from discontinued operations	(0.63		)	0.32			(0.04		)	1.66			1.30
Net loss per share	$	(3.54	)	$	(2.28	)	$	(10.95	)	$	(10.62	)	$	(27.40	)

(1) Continuing operating expenses for 2016 include non-cash asset impairments totaling $42 million, $238 million, $951 million, and $144 million in the first, second, third, and fourth quarters of 2016, respectively. Continuing operating expenses for 2015 include non-cash asset impairments totaling $2.1 billion, $660 million, $4.1 billion, and $5.1 billion in the first, second, third, and fourth quarters of 2015, respectively.

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

XML

Supplemental Guarantor Information (Tables)

12 Months Ended

Dec. 31, 2016

Guarantees [Abstract]

Supplemental Condensed Consolidating Statement of Operations and Comprehensive Income

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)

For the Year Ended December 31, 2016

	Apache Corporation			Apache Finance Canada			All Other Subsidiaries of Apache Corporation			Reclassifications & Eliminations			Consolidated
	(In millions)
REVENUES AND OTHER:
Oil and gas production revenues	$	1,035		$	—		$	4,332		$	—		$	5,367
Equity in net income (loss) of affiliates	(575		)	(173		)	—			748			—
Other	15			(19		)	(29		)	(1		)	(34		)
Gain on divestiture	2			—			19			—			21
	477			(192		)	4,322			747			5,354
OPERATING EXPENSES:
Lease operating expenses	285			—			1,209			—			1,494
Gathering and transportation	33			—			167			—			200
Taxes other than income	76			—			50			—			126
Exploration	258			—			215			—			473
General and administrative	344			—			67			(1		)	410
Depreciation, depletion, and amortization	618			—			2,000			—			2,618
Asset retirement obligation accretion	18			—			138			—			156
Impairments	80			—			1,023			—			1,103
Transaction, reorganization, and separation	39			—			—			—			39
Financing costs, net	256			(27		)	188			—			417
	2,007			(27		)	5,057			(1		)	7,036
NET INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(1,530		)	(165		)	(735		)	748			(1,682		)
Provision (benefit) for income taxes	(158		)	8			(292		)	—			(442		)
NET INCOME (LOSS) FROM CONTINUING OPERATIONS INCLUDING NONCONTROLLING INTEREST	(1,372		)	(173		)	(443		)	748			(1,240		)
Net loss from discontinued operations, net of tax	(33		)	—			—			—			(33		)
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTEREST	(1,405		)	(173		)	(443		)	748			(1,273		)
Net income attributable to noncontrolling interest	—			—			132			—			132
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	(1,405	)	$	(173	)	$	(575	)	$	748		$	(1,405	)
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	(1,398	)	$	(173	)	$	(575	)	$	748		$	(1,398	)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)

For the Year Ended December 31, 2015

	Apache Corporation			Apache Finance Canada			All Other Subsidiaries of Apache Corporation			Reclassifications & Eliminations		Consolidated
	(In millions)
REVENUES AND OTHER:
Oil and gas production revenues	$	1,446		$	—		$	5,064		$	—	$	6,510
Equity in net income (loss) of affiliates	(5,254		)	(740		)	57			5,937		—
Other	(71		)	54			96			19		98
Gain on divestiture	36			—			245			—		281
	(3,843		)	(686		)	5,462			5,956		6,889
OPERATING EXPENSES:
Lease operating expenses	399			—			1,455			—		1,854
Gathering and transportation	35			—			176			—		211
Taxes other than income	103			—			179			—		282
Exploration	2,096			—			675			—		2,771
General and administrative	296			—			65			19		380
Depreciation, depletion, and amortization	966			—			2,334			—		3,300
Asset retirement obligation accretion	15			—			130			—		145
Impairments	3,885			—			5,587			—		9,472
Transaction, reorganization, and separation	132			—			—			—		132
Financing costs, net	475			(14		)	50			—		511
	8,402			(14		)	10,651			19		19,058
NET INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(12,245		)	(672		)	(5,189		)	5,937		(12,169		)
Provision (benefit) for income taxes	(2,065		)	11			1,044			—		(1,010		)
NET INCOME (LOSS) FROM CONTINUING OPERATIONS INCLUDING NONCONTROLLING INTEREST	(10,180		)	(683		)	(6,233		)	5,937		(11,159		)
Net income (loss) from discontinued operations, net of tax	(172		)	—			664			—		492
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTEREST	(10,352		)	(683		)	(5,569		)	5,937		(10,667		)
Net loss attributable to noncontrolling interest	—			—			(315		)	—		(315		)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	(10,352	)	$	(683	)	$	(5,254	)	$	5,937	$	(10,352	)
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	(10,355	)	$	(683	)	$	(5,254	)	$	5,937	$	(10,355	)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)

For the Year Ended December 31, 2014

	Apache Corporation			Apache Finance Canada			All Other Subsidiaries of Apache Corporation			Reclassifications & Eliminations		Consolidated
	(In millions)
REVENUES AND OTHER:
Oil and gas production revenues	$	3,399		$	—		$	9,396		$	—	$	12,795
Equity in net income (loss) of affiliates	(3,489		)	(1,191		)	73			4,607		—
Other	375			55			(150		)	5		285
Loss on divestiture	(1,031		)	—			(577		)	—		(1,608		)
	(746		)	(1,136		)	8,742			4,612		11,472
OPERATING EXPENSES:
Lease operating expenses	509			—			1,729			—		2,238
Gathering and transportation	58			—			215			—		273
Taxes other than income	206			—			371			—		577
Exploration	1,966			—			533			—		2,499
General and administrative	370			—			78			5		453
Depreciation, depletion, and amortization	1,493			—			3,033			—		4,526
Asset retirement obligation accretion	31			—			123			—		154
Impairments	1,626			—			5,476			—		7,102
Transaction, reorganization, and separation	67			—			—			—		67
Financing costs, net	372			(24		)	65			—		413
	6,698			(24		)	11,623			5		18,302
NET INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(7,444		)	(1,112		)	(2,881		)	4,607		(6,830		)
Provision (benefit) for income taxes	789			6			(1,313		)	—		(518		)
NET INCOME (LOSS) FROM CONTINUING OPERATIONS INCLUDING NONCONTROLLING INTEREST	(8,233		)	(1,118		)	(1,568		)	4,607		(6,312		)
Net loss from discontinued operations, net of tax	(127		)	—			(1,580		)	—		(1,707		)
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTEREST	(8,360		)	(1,118		)	(3,148		)	4,607		(8,019		)
Net income attributable to noncontrolling interest	—			—			341			—		341
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	(8,360	)	$	(1,118	)	$	(3,489	)	$	4,607	$	(8,360	)
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	(8,361	)	$	(1,118	)	$	(3,489	)	$	4,607	$	(8,361	)

Supplemental Condensed Consolidating Statement of Cash Flows

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

For the Year Ended December 31, 2016

	Apache Corporation			Apache Finance Canada			All Other Subsidiaries of Apache Corporation			Reclassifications & Eliminations			Consolidated
							(In millions)
CASH PROVIDED BY CONTINUING OPERATING ACTIVITIES	$	625		$	51		$	1,777		$	—		$	2,453
CASH USED IN DISCONTINUED OPERATIONS	—			—			(23		)	—			(23		)
CASH PROVIDED BY OPERATING ACTIVITIES	$	625		$	51		$	1,754		$	—		$	2,430
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property	(813		)	—			(797		)	—			(1,610		)
Additions to gas gathering, transmission, and processing facilities	(111		)	—			(47		)	—			(158		)
Leasehold and property acquisitions	(108		)	—			(73		)	—			(181		)
Proceeds from sale of oil and gas properties, other	88			—			46			—			134
Investment in subsidiaries, net	914			—			—			(914		)	—
Other	(77		)	—			232			—			155
NET CASH USED IN INVESTING ACTIVITIES	(107		)	—			(639		)	(914		)	(1,660		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Intercompany borrowings	—			(23		)	(891		)	914			—
Payments on fixed rate debt	(181		)	—			—			—			(181		)
Dividends paid	(379		)	—			—			—			(379		)
Common stock activity, net	—			(28		)	28			—			—
Distributions to noncontrolling interest	—			—			(293		)	—			(293		)
Other	8			—			(15		)	—			(7		)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES	(552		)	(51		)	(1,171		)	914			(860		)
NET DECREASE IN CASH AND CASH  EQUIVALENTS	(34		)	—			(56		)	—			(90		)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	378			—			1,089			—			1,467
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	344		$	—		$	1,033		$	—		$	1,377

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

For the Year Ended December 31, 2015

	Apache Corporation			Apache Finance Canada			All Other Subsidiaries of Apache Corporation			Reclassifications & Eliminations			Consolidated
							(In millions)
CASH PROVIDED BY CONTINUING OPERATING ACTIVITIES	$	98		$	18		$	2,438		$	—		$	2,554
CASH PROVIDED BY DISCONTINUED OPERATIONS	—			—			113			—			113
CASH PROVIDED BY OPERATING ACTIVITIES	98			18			2,551			—			2,667
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property	(1,500		)	—			(2,708		)	—			(4,208		)
Additions to gas gathering, transmission, and processing facilities	(156		)	—			(77		)	—			(233		)
Proceeds from sale of Kitimat LNG	—			—			854			—			854
Proceeds from sale of Yara Pilbara	—			—			391			—			391
Leasehold and property acquisitions	(313		)	—			(54		)	—			(367		)
Proceeds from sale of oil and gas properties	163			—			105			—			268
Investment in subsidiaries, net	6,363			—			—			(6,363		)	—
Other	(34		)	—			40			—			6
NET CASH PROVIDED BY (USED IN) CONTINUING INVESTING ACTIVITIES	4,523			—			(1,449		)	(6,363		)	(3,289		)
NET CASH PROVIDED BY DISCONTINUED OPERATIONS	—			—			4,372			—			4,372
NET CASH USED IN INVESTING ACTIVITIES	4,523			—			2,923			(6,363		)	1,083
CASH FLOWS FROM FINANCING ACTIVITIES:
Commercial paper, credit facility, and bank notes, net	(1,570		)	—			—			—			(1,570		)
Intercompany borrowings	(1,621		)	(18		)	(4,724		)	6,363			—
Payments on fixed rate debt	(939		)	—			—			—			(939		)
Dividends paid	(377		)	—			—			—			(377		)
Distributions to noncontrolling interest	—			—			(129		)	—			(129		)
Other	(3		)	—			56			—			53
NET CASH USED IN CONTINUING FINANCING ACTIVITIES	(4,510		)	(18		)	(4,797		)	6,363			(2,962		)
NET CASH USED IN FINANCING ACTIVITIES	(4,510		)	(18		)	(4,797		)	6,363			(2,962		)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	111			—			677			—			788
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	267			—			412			—			679
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	378		$	—		$	1,089		$	—		$	1,467

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

For the Year Ended December 31, 2014

	Apache Corporation			Apache Finance Canada			All Other Subsidiaries of Apache Corporation			Reclassifications & Eliminations			Consolidated
							(In millions)
CASH PROVIDED BY CONTINUING OPERATING ACTIVITIES	$	3,104		$	17		$	3,892		$	—		$	7,013
CASH PROVIDED BY DISCONTINUED OPERATIONS	—			—			944			—			944
CASH PROVIDED BY OPERATING ACTIVITIES	3,104			17			4,836			—			7,957
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property	(4,364		)	—			(4,244		)	—			(8,608		)
Additions to gas gathering, transmission, and processing facilities	(9		)	—			(872		)	—			(881		)
Proceeds from sale of Deepwater Gulf of Mexico assets	1,360			—			—			—			1,360
Proceeds from sale of Anadarko basin and southern Louisiana assets	1,262			—			—			—			1,262
Leasehold and property acquisitions	(1,475		)	—			—			—			(1,475		)
Proceeds from sale of oil and gas properties	15			—			455			—			470
Investment in subsidiaries, net	1,132			—			—			(1,132		)	—
Other	(186		)	—			(113		)	—			(299		)
NET CASH USED IN CONTINUING INVESTING ACTIVITIES	(2,265		)	—			(4,774		)	(1,132		)	(8,171		)
NET CASH USED IN DISCONTINUED OPERATIONS	—			—			(219		)	—			(219		)
NET CASH USED IN INVESTING ACTIVITIES	(2,265		)	—			(4,993		)	(1,132		)	(8,390		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Commercial paper, credit facility, and bank notes, net	1,570			—			(2		)	—			1,568
Intercompany borrowings	—			8			(1,152		)	1,144			—
Dividends paid	(365		)	—			—			—			(365		)
Distributions to noncontrolling interest	—			—			(140		)	—			(140		)
Shares repurchased	(1,864		)	—			—			—			(1,864		)
Other	(68		)	(28		)	157			(12		)	49
NET CASH USED IN CONTINUING FINANCING ACTIVITIES	(727		)	(20		)	(1,137		)	1,132			(752		)
NET CASH USED IN DISCONTINUED OPERATIONS	—			—			(42		)	—			(42		)
NET CASH USED IN FINANCING ACTIVITIES	(727		)	(20		)	(1,179		)	1,132			(794		)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	112			(3		)	(1,336		)	—			(1,227		)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	155			3			1,748			—			1,906
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	267		$	—		$	412		$	—		$	679

Supplemental Condensed Consolidating Balance Sheet

CONDENSED CONSOLIDATING BALANCE SHEET

December 31, 2016

	Apache Corporation			Apache Finance Canada			All Other Subsidiaries of Apache Corporation		Reclassifications & Eliminations			Consolidated
							(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	344		$	—		$	1,033	$	—		$	1,377
Receivables, net of allowance	358			—			770		—			1,128
Inventories	29			—			447		—			476
Drilling advances	4			—			77		—			81
Prepaid assets and other	134			—			45		—			179
Intercompany receivable	5,038			—			—		(5,038		)	—
	5,907			—			2,372		(5,038		)	3,241
PROPERTY AND EQUIPMENT, NET	7,014			—			11,853		—			18,867
OTHER ASSETS:
Intercompany receivable	—			—			12,152		(12,152		)	—
Equity in affiliates	15,517			(1,240		)	706		(14,983		)	—
Deferred charges and other	97			1,000			314		(1,000		)	411
	$	28,535		$	(240	)	$	27,397	$	(33,173	)	$	22,519
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable	$	371		$	(12	)	$	226	$	—		$	585
Other current liabilities	653			3			602		—			1,258
Intercompany payable	—			—			5,038		(5,038		)	—
	1,024			(9		)	5,866		(5,038		)	1,843
LONG-TERM DEBT	8,247			297			—		—			8,544
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Intercompany payable	12,152			—			—		(12,152		)	—
Income taxes	(271		)	5			1,976		—			1,710
Asset retirement obligation	257			—			2,175		—			2,432
Other	888			1			422		(1,000		)	311
	13,026			6			4,573		(13,152		)	4,453
COMMITMENTS AND CONTINGENCIES APACHE SHAREHOLDERS’ EQUITY	6,238			(534		)	15,517		(14,983		)	6,238
Noncontrolling interest	—			—			1,441		—			1,441
TOTAL EQUITY	6,238			(534		)	16,958		(14,983		)	7,679
	$	28,535		$	(240	)	$	27,397	$	(33,173	)	$	22,519

CONDENSED CONSOLIDATING BALANCE SHEET

December 31, 2015

	Apache Corporation			Apache Finance Canada			All Other Subsidiaries of Apache Corporation		Reclassifications & Eliminations			Consolidated
							(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	378		$	—		$	1,089	$	—		$	1,467
Receivables, net of allowance	314			—			939		—			1,253
Inventories	34			—			536		—			570
Drilling advances	16			—			156		—			172
Prepaid assets and other	102			—			188		—			290
Intercompany receivable	5,212			—			—		(5,212		)	—
	6,056			—			2,908		(5,212		)	3,752
PROPERTY AND EQUIPMENT, NET	6,546			—			14,292		—			20,838
OTHER ASSETS:
Intercompany receivable	—			—			10,744		(10,744		)	—
Equity in affiliates	16,092			(807		)	446		(15,731		)	—
Deferred charges and other	96			1,001			813		(1,000		)	910
	$	28,790		$	194		$	29,203	$	(32,687	)	$	25,500
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable	$	409		$	—		$	209	$	—		$	618
Other current liabilities	539			3			681		—			1,223
Intercompany payable	—			—			5,212		(5,212		)	—
	948			3			6,102		(5,212		)	1,841
LONG-TERM DEBT	8,418			298			—		—			8,716
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Intercompany payable	10,744			—			—		(10,744		)	—
Income taxes	(412		)	4			2,937		—			2,529
Asset retirement obligation	271			—			2,291		—			2,562
Other	933			250			179		(1,000		)	362
	11,536			254			5,407		(11,744		)	5,453
COMMITMENTS AND CONTINGENCIES APACHE SHAREHOLDERS’ EQUITY	7,888			(361		)	16,092		(15,731		)	7,888
Noncontrolling interest	—			—			1,602		—			1,602
TOTAL EQUITY	7,888			(361		)	17,694		(15,731		)	9,490
	$	28,790		$	194		$	29,203	$	(32,687	)	$	25,500

XML

Nature of Operations (Details)	12 Months Ended
	Dec. 31, 2016 Area
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of geographical areas	4

XML

Summary of Significant Accounting Policies - Allowance for Doubtful Accounts Roll-forward (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Accounting Policies [Abstract]
Allowance for doubtful accounts at beginning of year	$ 103	$ 98	$ 78
Additional provisions for the year	14	40	4
Uncollectible accounts written off net of recoveries	(24)	(35)	16
Allowance for doubtful accounts at end of year	$ 93	$ 103	$ 98

XML

Summary of Significant Accounting Policies - Additional Information (Detail) - USD ($)				3 Months Ended											12 Months Ended
	Jan. 01, 2016	Dec. 31, 2015		Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015		Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014		Dec. 31, 2016	Dec. 31, 2015		Dec. 31, 2014		Jan. 01, 2017	Dec. 31, 2013
Schedule Of Significant Accounting Policies [Line Items]
Total asset impairment charges															$ 1,100,000,000	$ 9,500,000,000		$ 7,100,000,000
Impairment charge of Petroleum Revenue Tax benefits, before tax															486,000,000
Inventory write-downs															55,000,000	55,000,000		32,000,000
UK Petroleum Revenue Tax (PRT) rate	0.00%	35.00%
Impairment charge of Petroleum Revenue Tax benefits, net of tax															292,000,000
Remaining recoverable Petroleum Revenue Tax benefits				$ 8,000,000											8,000,000
Goodwill impairment charges															0	163,000,000		347,000,000
Impairment of equity method investment																148,000,000
Impairment of assets held for sale and other assets																		655,000,000
Asset impairments				144,000,000	$ 951,000,000	$ 238,000,000	$ 42,000,000	$ 5,100,000,000		$ 4,100,000,000	$ 660,000,000	$ 2,100,000,000			1,103,000,000	9,472,000,000	[1],[2]	7,102,000,000	[1],[2]
Cash and cash equivalents		$ 1,467,000,000	[2],[3]	1,377,000,000				1,467,000,000	[2],[3]				$ 679,000,000	[2]	1,377,000,000	1,467,000,000	[2],[3]	679,000,000	[2]		$ 1,906,000,000	[2]
Allowance for doubtful accounts		103,000,000		93,000,000				103,000,000					98,000,000		93,000,000	103,000,000		98,000,000			$ 78,000,000
Oil and gas property, fair value		3,900,000,000		306,000,000				3,900,000,000					4,800,000,000		306,000,000	3,900,000,000		4,800,000,000
Gathering, transmission and processing facilities		1,052,000,000	[3]	976,000,000				1,052,000,000	[3]						976,000,000	1,052,000,000	[3]
Accumulated depreciation		25,312,000,000	[3]	27,882,000,000				25,312,000,000	[3]						27,882,000,000	25,312,000,000	[3]
Impairment of GTP assets															135,000,000	1,700,000,000		1,100,000,000
Fair value of GTP assets		306,000,000		142,000,000				306,000,000							142,000,000	306,000,000
Accounts payable															86,000,000	129,000,000
Net cost of third party gas															$ 159,000,000	105,000,000		70,000,000
Maximum percentage of production available to contract partners															40.00%
Other foreign currency gains and (losses)															$ (25,000,000)	(11,000,000)		8,000,000
Benefit of tax deductions in excess of recognized compensation cost															2,000,000	1,000,000		35,000
GTP Facilities [Member]
Schedule Of Significant Accounting Policies [Line Items]
Gathering, transmission and processing facilities		1,100,000,000		976,000,000				1,100,000,000							976,000,000	1,100,000,000
Accumulated depreciation		160,000,000		130,000,000				160,000,000							130,000,000	160,000,000
Gain (loss) on the sale of GTP facilities																59,000,000		(180,000,000)
Oil and Gas Properties, Proved [Member]
Schedule Of Significant Accounting Policies [Line Items]
Asset impairments for property and equipment															427,000,000	7,389,000,000		6,068,000,000
Gas Gathering, Transmission, and Processing Assets [Member]
Schedule Of Significant Accounting Policies [Line Items]
Asset impairments for property and equipment															135,000,000	1,700,000,000
Other Property and Equipment [Member]
Schedule Of Significant Accounting Policies [Line Items]
Accumulated depreciation		$ 693,000,000		$ 780,000,000				$ 693,000,000							780,000,000	693,000,000
United States [Member]
Schedule Of Significant Accounting Policies [Line Items]
Goodwill impairment charges															0	0		244,000,000
Impairment of GTP assets																103,000,000
Canada [Member]
Schedule Of Significant Accounting Policies [Line Items]
Goodwill impairment charges															0	0		103,000,000
Impairment of GTP assets																555,000,000
Egypt [Member]
Schedule Of Significant Accounting Policies [Line Items]
Goodwill impairment charges															$ 0	0		0
Impairment of GTP assets																$ 1,100,000,000
Australia [Member] | Discontinued Operations [Member]
Schedule Of Significant Accounting Policies [Line Items]
Asset impairments																		833,000,000
Australia [Member] | Oil and Gas Properties, Proved [Member] | Discontinued Operations [Member]
Schedule Of Significant Accounting Policies [Line Items]
Asset impairments																		271,000,000
Wheatstone LNG [Member]
Schedule Of Significant Accounting Policies [Line Items]
Impairment of GTP assets																		$ 430,000,000
Wheatstone LNG [Member] | Australia [Member]
Schedule Of Significant Accounting Policies [Line Items]
Asset impairments													$ 833,000,000
Minimum [Member]
Schedule Of Significant Accounting Policies [Line Items]
Voting interest required for consolidation of investments				50.00%											50.00%
Minimum [Member] | Other Property and Equipment [Member]
Schedule Of Significant Accounting Policies [Line Items]
Useful lives of gas gathering, transmission and processing facilities															3 years
Maximum [Member]
Schedule Of Significant Accounting Policies [Line Items]
Voting interest required for consolidation of investments				50.00%											50.00%
Maximum [Member] | Other Property and Equipment [Member]
Schedule Of Significant Accounting Policies [Line Items]
Useful lives of gas gathering, transmission and processing facilities															20 years
Retained Earnings (Accumulated Deficit) [Member] | Subsequent Event [Member] | Accounting Standards Update 2016-09 [Member]
Schedule Of Significant Accounting Policies [Line Items]
Cumulative effect of change on equity																				$ 11,000,000

[1] Financial information for 2015 and 2014 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

[2] Financial information for 2015 and 2014 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

[3] Financial information for 2015 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

XML

Summary of Significant Accounting Policies - Non-Cash Impairments of Proved and Unproved Property and Equipment (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Oil and Gas Properties, Proved [Member]
Schedule Of Significant Accounting Policies [Line Items]
Impairment of Oil and Gas properties	$ 427	$ 7,389	$ 6,068
Oil and Gas Properties, Unproved [Member]
Schedule Of Significant Accounting Policies [Line Items]
Impairment of Oil and Gas properties	$ 272	$ 2,462	$ 1,976

XML

Summary of Significant Accounting Policies Summary of Significant Accounting Policies - Schedule of Goodwill (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Goodwill [Roll Forward]
Goodwill, Beginning Balance	$ 87,000,000	$ 250,000,000	$ 737,000,000
Divested			(140,000,000)
Impairments	0	(163,000,000)	(347,000,000)
Goodwill, Ending Balance	87,000,000	87,000,000	250,000,000
United States [Member]
Goodwill [Roll Forward]
Goodwill, Beginning Balance	0	0	384,000,000
Divested			(140,000,000)
Impairments	0	0	(244,000,000)
Goodwill, Ending Balance	0	0	0
Canada [Member]
Goodwill [Roll Forward]
Goodwill, Beginning Balance	0	0	103,000,000
Divested			0
Impairments	0	0	(103,000,000)
Goodwill, Ending Balance	0	0	0
Egypt [Member]
Goodwill [Roll Forward]
Goodwill, Beginning Balance	87,000,000	87,000,000	87,000,000
Divested			0
Impairments	0	0	0
Goodwill, Ending Balance	87,000,000	87,000,000	87,000,000
North Sea [Member]
Goodwill [Roll Forward]
Goodwill, Beginning Balance	0	163,000,000	163,000,000
Divested			0
Impairments	0	(163,000,000)	0
Goodwill, Ending Balance	$ 0	$ 0	$ 163,000,000

XML

Change in Accounting Principle - Statement of Consolidated Operations (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015		Dec. 31, 2014
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Oil and gas production revenues									$ 5,367	$ 6,510	[1]	$ 12,795	[1]
Other									(34)	98	[1]	285	[1]
Gain (loss) on divestiture	$ 0	$ 5	$ 17	$ (1)	$ 77	$ (5)	$ 227	$ (18)	21	281	[1],[2]	(1,608)	[1],[2]
Exploration									473	2,771	[1]	2,499	[1]
General and administrative									410	380	[1]	453	[1]
Depreciation, depletion, and amortization									2,618	3,300	[2]	4,526	[2]
Impairments	144	951	238	42	5,100	4,100	660	2,100	1,103	9,472	[1],[2]	7,102	[1],[2]
Financing costs, net									417	511	[1]	413	[1]
Current income tax provision									391	435	[1]	1,281	[1]
Deferred income tax benefit									(833)	(1,445)	[1],[2]	(1,799)	[1],[2]
NET LOSS FROM CONTINUING OPERATIONS INCLUDING NONCONTROLLING INTEREST	(143)	(526)	(200)	(371)	(5,055)	(4,119)	(917)	(1,068)	(1,240)	(11,159)	[1]	(6,312)	[1]
Net income (loss) attributable to noncontrolling interest									132	(315)	[1]	341	[1]
Net loss from continuing operations attributable to common shareholders									(1,372)	(10,844)	[1]	(6,653)	[1]
Net loss from discontinued operations, net of tax									(33)	492	[1],[2]	(1,707)	[1],[2]
Net income (loss) attributable to common shareholders	$ (182)	$ (607)	$ (244)	$ (372)	$ (4,015)	$ (4,143)	$ (860)	$ (1,334)	$ (1,405)	$ (10,352)	[1]	$ (8,360)	[1]
Per Common Share
Basic and diluted net loss from continuing operations per share	$ (0.48)	$ (1.51)	$ (0.65)	$ (0.98)	$ (12.28)	$ (10.91)	$ (2.60)	$ (2.91)	$ (3.62)	$ (28.70)	[1]	$ (17.32)	[1]
Basic and diluted net loss from discontinued operations per share	0.00	(0.09)	0.00	0.00	1.66	(0.04)	0.32	(0.63)	(0.09)	1.30	[1]	(4.44)	[1]
Basic and diluted net loss per share	$ (0.48)	$ (1.60)	$ (0.65)	$ (0.98)	$ (10.62)	$ (10.95)	$ (2.28)	$ (3.54)	$ (3.71)	$ (27.40)	[1]	$ (21.76)	[1]
Other Comprehensive Income
Pension and postretirement benefit plan, net of tax									$ 7	$ (3)	[3],[4]	$ 0	[3]
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK									(1,398)	(10,355)	[3]	(8,361)	[3]
Under Full Cost [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Oil and gas production revenues									5,208	6,383		12,691
Other									(38)	(76)		290
Gain (loss) on divestiture									17	59		(180)
Exploration									0	0		0
General and administrative										377		451
Depreciation, depletion, and amortization									3,570	29,372		9,720
Impairments									677	1,920		1,919
Financing costs, net									365	299		211
Current income tax provision									232	309		1,177
Deferred income tax benefit									(721)	(5,778)		(514)
NET LOSS FROM CONTINUING OPERATIONS INCLUDING NONCONTROLLING INTEREST									(1,361)	(22,757)		(3,472)
Net income (loss) attributable to noncontrolling interest									(26)	(409)		343
Net loss from continuing operations attributable to common shareholders									(1,335)	(22,348)		(3,815)
Net loss from discontinued operations, net of tax									(33)	(771)		(1,588)
Net income (loss) attributable to common shareholders									$ (1,368)	$ (23,119)		$ (5,403)
Per Common Share
Basic and diluted net loss from continuing operations per share									$ (3.52)	$ (59.16)		$ (9.93)
Basic and diluted net loss from discontinued operations per share									(0.09)	(2.04)		(4.13)
Basic and diluted net loss per share									$ (3.61)	$ (61.20)		$ (14.06)
Other Comprehensive Income
Pension and postretirement benefit plan, net of tax										$ 0
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK									$ (1,361)	(23,119)		$ (5,404)
Change from Full Cost Method to Successful Efforts Method [Member] | Changes [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Oil and gas production revenues									159	127		104
Other									4	174		(5)
Gain (loss) on divestiture									4	222		(1,428)
Exploration									473	2,771		2,499
General and administrative										3		2
Depreciation, depletion, and amortization									(952)	(26,072)		(5,194)
Impairments									426	7,552		5,183
Financing costs, net									52	212		202
Current income tax provision									159	126		104
Deferred income tax benefit									(112)	4,333		(1,285)
NET LOSS FROM CONTINUING OPERATIONS INCLUDING NONCONTROLLING INTEREST									121	11,598		(2,840)
Net income (loss) attributable to noncontrolling interest									158	94		(2)
Net loss from continuing operations attributable to common shareholders									(37)	11,504		(2,838)
Net loss from discontinued operations, net of tax									0	1,263		(119)
Net income (loss) attributable to common shareholders									$ (37)	$ 12,767		$ (2,957)
Per Common Share
Basic and diluted net loss from continuing operations per share									$ (0.10)	$ 30.46		$ (7.39)
Basic and diluted net loss from discontinued operations per share									0.00	3.34		(0.31)
Basic and diluted net loss per share									$ (0.10)	$ 33.80		$ (7.70)
Other Comprehensive Income
Pension and postretirement benefit plan, net of tax										$ (3)
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK									$ (37)	12,764		$ (2,957)
Oil [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Oil and gas production revenues									4,172	5,107	[1]	10,110	[1]
Oil [Member] | Under Full Cost [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Oil and gas production revenues									3,983	4,999		10,040
Oil [Member] | Change from Full Cost Method to Successful Efforts Method [Member] | Changes [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Oil and gas production revenues									189	108		70
Natural Gas [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Oil and gas production revenues									967	1,176	[1]	2,017	[1]
Natural Gas [Member] | Under Full Cost [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Oil and gas production revenues									997	1,157		1,983
Natural Gas [Member] | Change from Full Cost Method to Successful Efforts Method [Member] | Changes [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Oil and gas production revenues									(30)	19		34
Natural Gas Liquids [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Oil and gas production revenues									228	227	[1]	668	[1]
Natural Gas Liquids [Member] | Under Full Cost [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Oil and gas production revenues									228	227		668
Natural Gas Liquids [Member] | Change from Full Cost Method to Successful Efforts Method [Member] | Changes [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Oil and gas production revenues									0	0		0
Recurring [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Depreciation, depletion, and amortization									2,460	2,976		4,195
Recurring [Member] | Under Full Cost [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Depreciation, depletion, and amortization									1,974	3,531		4,388
Recurring [Member] | Change from Full Cost Method to Successful Efforts Method [Member] | Changes [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Depreciation, depletion, and amortization									486	(555)		(193)
Additional [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Depreciation, depletion, and amortization									0	0		0
Additional [Member] | Under Full Cost [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Depreciation, depletion, and amortization									1,438	25,517		5,001
Additional [Member] | Change from Full Cost Method to Successful Efforts Method [Member] | Changes [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Depreciation, depletion, and amortization									$ (1,438)	$ (25,517)		$ (5,001)

[1] Financial information for 2015 and 2014 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

[2] Financial information for 2015 and 2014 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

[3] Financial information for 2015 and 2014 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

[4] Financial information for 2015, 2014, and 2013 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

XML

Change in Accounting Principle - Statement of Consolidated Cash Flow (Details) - USD ($) $ in Millions		3 Months Ended										12 Months Ended
		Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016		Dec. 31, 2015		Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016		Dec. 31, 2015		Dec. 31, 2014
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
NET LOSS INCLUDING NONCONTROLLING INTEREST		$ (143)	$ (559)	$ (200)	$ (371)		$ (4,428)		$ (4,136)	$ (797)	$ (1,306)	$ (1,273)		$ (10,667)	[1],[2],[3],[4]	$ (8,019)	[1],[2],[3],[4]
Loss (income) from discontinued operations												33		(492)	[2],[3]	1,707	[2],[3]
Loss (gain) on divestitures		0	(5)	(17)	1		(77)		5	(227)	18	(21)		(281)	[2],[3]	1,608	[2],[3]
Exploratory dry hole expense and unproved leasehold impairments												353		2,595	[3]	2,294	[3]
Depreciation, depletion, and amortization												2,618		3,300	[3]	4,526	[3]
Impairments		144	$ 951	$ 238	42		5,100		$ 4,100	$ 660	2,100	1,103		9,472	[2],[3]	7,102	[2],[3]
Other noncash items, net												164		7	[3]	(231)	[3]
Deferred income tax benefit												(833)		(1,445)	[2],[3]	(1,799)	[2],[3]
Changes in operating assets and liabilities												153		(80)		(329)
CASH PROVIDED BY CONTINUING OPERATING ACTIVITIES												2,453		2,554	[3]	7,013	[3]
CASH PROVIDED BY (USED IN) DISCONTINUED OPERATIONS												(23)		113	[3]	944	[3]
Additions to oil and gas property												(1,610)		(4,208)	[3]	(8,608)	[3]
Net cash provided by (used in) investing activities - continuing operations												(1,660)		(3,289)	[3]	(8,171)	[3]
NET CASH PROVIDED BY (USED IN) DISCONTINUED OPERATIONS												0		4,372	[3]	(219)	[3]
Other												(7)		53	[3]	49	[3]
Net cash used in financing activities												(860)		(2,962)	[3]	(794)	[3]
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS												(90)		788	[3]	(1,227)	[3]
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	[3]				1,467	[5]					679	1,467	[5]	679		1,906
CASH AND CASH EQUIVALENTS AT END OF PERIOD		1,377					1,467	[3],[5]				1,377		1,467	[3],[5]	679	[3]
Under Full Cost [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
NET LOSS INCLUDING NONCONTROLLING INTEREST												(1,394)		(23,528)		(5,060)
Loss (income) from discontinued operations												33		771		1,588
Loss (gain) on divestitures												(17)		(59)		180
Exploratory dry hole expense and unproved leasehold impairments												0		0		0
Depreciation, depletion, and amortization												3,570		29,372		9,720
Impairments												677		1,920		1,919
Other noncash items, net														161
Deferred income tax benefit												(721)		(5,778)		(514)
Changes in operating assets and liabilities												138		(170)		(239)
CASH PROVIDED BY CONTINUING OPERATING ACTIVITIES												2,606		2,834		7,517
CASH PROVIDED BY (USED IN) DISCONTINUED OPERATIONS														150		944
Additions to oil and gas property												(1,776)		(4,578)		(9,022)
Net cash provided by (used in) investing activities - continuing operations												(1,826)		(3,659)		(8,585)
NET CASH PROVIDED BY (USED IN) DISCONTINUED OPERATIONS														4,335		(219)
Other												6
Net cash used in financing activities												(847)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS												(90)		698		(1,137)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR					1,467						769	1,467		769		1,906
CASH AND CASH EQUIVALENTS AT END OF PERIOD		1,377					1,467					1,377		1,467		769
Change from Full Cost Method to Successful Efforts Method [Member] | Changes [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
NET LOSS INCLUDING NONCONTROLLING INTEREST												121		12,861		(2,959)
Loss (income) from discontinued operations												0		(1,263)		119
Loss (gain) on divestitures												(4)		(222)		1,428
Exploratory dry hole expense and unproved leasehold impairments												353		2,595		2,294
Depreciation, depletion, and amortization												(952)		(26,072)		(5,194)
Impairments												426		7,552		5,183
Other noncash items, net														(154)
Deferred income tax benefit												(112)		4,333		(1,285)
Changes in operating assets and liabilities												15		90		(90)
CASH PROVIDED BY CONTINUING OPERATING ACTIVITIES												(153)		(280)		(504)
CASH PROVIDED BY (USED IN) DISCONTINUED OPERATIONS														(37)		0
Additions to oil and gas property												166		370		414
Net cash provided by (used in) investing activities - continuing operations												166		370		414
NET CASH PROVIDED BY (USED IN) DISCONTINUED OPERATIONS														37		0
Other												(13)
Net cash used in financing activities												(13)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS												0		90		(90)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR					$ 0						$ (90)	0		(90)		0
CASH AND CASH EQUIVALENTS AT END OF PERIOD		$ 0					$ 0					$ 0		$ 0		$ (90)

[1] Financial information for 2015 and 2014 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

[2] Financial information for 2015 and 2014 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

[3] Financial information for 2015 and 2014 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

[4] Financial information for 2015, 2014, and 2013 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

[5] Financial information for 2015 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

XML

Change in Accounting Principle - Consolidated Balance Sheet (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015		Dec. 31, 2014		Dec. 31, 2013	[2]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Property and equipment - cost	$ 46,749	$ 46,150	[1]
Less: Accumulated depreciation, depletion, and amortization	(27,882)	(25,312)	[1]
Property and equipment, net	18,867	20,838	[1]
Total assets	22,519	25,500	[1]
Deferred income taxes	1,710	2,529	[1]
Paid-in capital	12,364	12,619	[1]
Accumulated deficit	(3,385)	(1,980)	[1]
Accumulated other comprehensive loss	(112)	(119)	[1]	$ (116)
Noncontrolling interest	1,441	1,602	[1]
TOTAL EQUITY	7,679	9,490	[1],[2]	20,541	[2]	$ 30,756
Change from Full Cost Method to Successful Efforts Method [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Property and equipment - cost	46,749	46,150
Less: Accumulated depreciation, depletion, and amortization	(27,882)	(25,312)
Property and equipment, net	18,867	20,838
Total assets	22,519	25,500
Deferred income taxes	1,710	2,529
Paid-in capital	12,364	12,619
Accumulated deficit	(3,385)	(1,980)
Accumulated other comprehensive loss	(112)	(119)
Noncontrolling interest	1,441	1,602
TOTAL EQUITY	7,679	9,490
Change from Full Cost Method to Successful Efforts Method [Member] | Under Full Cost [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Property and equipment - cost	95,371	93,825
Less: Accumulated depreciation, depletion, and amortization	(83,230)	(79,706)
Property and equipment, net	12,141	14,119
Total assets	15,793	18,781
Deferred income taxes	353	1,072
Paid-in capital	12,225	12,467
Accumulated deficit	(8,521)	(7,153)
Accumulated other comprehensive loss	(109)	(116)
Noncontrolling interest	1,344	1,662
TOTAL EQUITY	2,310	4,228
Change from Full Cost Method to Successful Efforts Method [Member] | Changes [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Property and equipment - cost	(48,622)	(47,675)
Less: Accumulated depreciation, depletion, and amortization	55,348	54,394
Property and equipment, net	6,726	6,719
Total assets	6,726	6,719
Deferred income taxes	1,357	1,457
Paid-in capital	139	152
Accumulated deficit	5,136	5,173
Accumulated other comprehensive loss	(3)	(3)
Noncontrolling interest	97	(60)
TOTAL EQUITY	5,369	5,262
Retained Earnings (Accumulated Deficit) [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
TOTAL EQUITY	$ (3,385)	$ (1,980)	[2]	$ 8,655	[2]	$ 17,395

[1] Financial information for 2015 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

[2] Financial information for 2015, 2014, and 2013 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

XML

Acquisitions and Divestitures - Additional Information - 2016 Activity (Details) - USD ($) $ in Millions	3 Months Ended		12 Months Ended
	Mar. 31, 2017	Dec. 31, 2016	Dec. 31, 2016	Dec. 31, 2015		Dec. 31, 2014
Business Acquisition [Line Items]
Proceeds from sale of certain non-core assets		$ 440
Refundable deposits		$ 174	$ 174	$ 0
Leasehold and property acquisition			181	367	[1]	$ 1,475	[1]
Proceeds from divestiture of other oil and gas properties			134	268		96
Gain (loss) on divestiture of other oil and gas properties			$ 21	$ 135		$ (216)
Scottish Area Gas Evacuation System [Member]
Business Acquisition [Line Items]
Percentage of ownership		30.28%	30.28%
Beryl Pipeline [Member]
Business Acquisition [Line Items]
Percentage of ownership		60.56%	60.56%
Scenario, Forecast [Member]
Business Acquisition [Line Items]
Gain from sale of certain non-core assets	$ 300

[1] Financial information for 2015 and 2014 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

XML

Acquisitions and Divestitures - Additional Information - 2015 Activity - Yara Pilbara Holdings Pty Limited Sale (Detail) - USD ($) $ in Millions	1 Months Ended	9 Months Ended	12 Months Ended
	Oct. 31, 2015	Sep. 30, 2015	Dec. 31, 2016	Dec. 31, 2015	[1]	Dec. 31, 2014	[1]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceed from sale of equity method investments			$ 0	$ 391		$ 0
Yara Pilbara Holdings Pty Limited [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Percentage of ownership	49.00%
Proceed from sale of equity method investments	$ 391
Impairment on equity method investment		$ 148

[1] Financial information for 2015 and 2014 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

XML

Acquisitions and Divestitures - Additional Information - 2015 Activity - Canada Divestiture (Detail) - USD ($) $ in Millions	1 Months Ended		3 Months Ended									12 Months Ended
	Jun. 30, 2015	Apr. 30, 2015	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Dec. 31, 2016	Dec. 31, 2015		Dec. 31, 2014	[1]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds form sale of operations												$ 0	$ 854	[1]	$ 0
Asset impairments			$ 144	$ 951	$ 238	$ 42	$ 5,100	$ 4,100	$ 660	$ 2,100		$ 1,103	9,472	[1],[2]	$ 7,102	[2]
Loss on sale of upstream assets	$ 139
Canada [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds form sale of operations		$ 854
Kitimat LNG [Member] | Canada [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Percentage of ownership		50.00%
Proceeds form sale of operations		$ 344
Asset impairments											$ 655
Upstream Assets [Member] | Canada [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds form sale of operations		$ 510
Loss on sale of upstream assets													$ (146)

[1] Financial information for 2015 and 2014 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

[2] Financial information for 2015 and 2014 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

XML

Acquisitions and Divestitures - Additional Information - 2015 Activity - Australia Divestiture (Detail) - USD ($) $ in Millions	1 Months Ended		3 Months Ended									12 Months Ended
	Jun. 30, 2015	Apr. 30, 2015	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Dec. 31, 2016	Dec. 31, 2015		Dec. 31, 2014
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from divestiture of other oil and gas properties												$ 134	$ 268		$ 96
Asset impairments			$ 144	$ 951	$ 238	$ 42	$ 5,100	$ 4,100	$ 660	$ 2,100		$ 1,103	$ 9,472	[1],[2]	$ 7,102	[1],[2]
Loss on sale of upstream assets	$ 139
Wheatstone LNG [Member] | Australia [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Asset impairments											$ 833
Loss on sale of upstream assets				$ 23
Wheatstone LNG [Member] | Oil and Gas Properties [Member] | Australia [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Loss on sale of upstream assets										$ 49
Woodside Sale [Member] | Australia [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from divestiture of other oil and gas properties		$ 2,800
Consortium Sale [Member] | Australia [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from divestiture of other oil and gas properties	$ 1,900
LNG Assets [Member] | Woodside Sale [Member] | Australia [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from divestiture of other oil and gas properties		1,400
Upstream Assets [Member] | Woodside Sale [Member] | Australia [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from divestiture of other oil and gas properties		$ 1,400

[1] Financial information for 2015 and 2014 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

[2] Financial information for 2015 and 2014 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

XML

Acquisitions and Divestitures - Summary of Sales and Other Operating Revenue and Loss From Discontinued Operation Related to Disposition - Australia Divestitures (Detail) - USD ($) $ in Millions	1 Months Ended	3 Months Ended								12 Months Ended
	Jun. 30, 2015	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015		Dec. 31, 2014
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Loss on sale	$ 139
Income (loss) from discontinued operations, net of tax		$ 0	$ (33)	$ 0	$ 0	$ 627	$ (17)	$ 120	$ (238)	$ (33)	$ 492	[1]	$ (1,707)	[1]
Australia [Member] | Divestiture [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Revenues and other from discontinued operations										0	288		1,050
Income (loss) from divested Australian operations										0	28		(12)
Income tax benefit (expense)										0	652		(231)
Income (loss) from discontinued operations, net of tax										(23)	492		(1,076)
Australia [Member] | Divestiture [Member] | Woodside Sale [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Impairment on Woodside sale										0	(49)		(833)
Loss on sale										(23)	0		0
Australia [Member] | Divestiture [Member] | Consortium Sale [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Loss on sale										$ 0	$ (139)		$ 0

[1] Financial information for 2015 and 2014 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

XML

Acquisitions and Divestitures - Additional Information - 2015 Activity - Other (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015		Dec. 31, 2014
Business Combinations [Abstract]
Leasehold and property acquisition	$ 181	$ 367	[1]	$ 1,475	[1]
Proceeds from Divestiture of Businesses	134	268		96
Gain (loss) on divestiture of other oil and gas properties	$ 21	$ 135		$ (216)

[1] Financial information for 2015 and 2014 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

XML

Acquisitions and Divestitures - Additional Information - 2014 Activity - Anadarko Basin and Southern Louisiana Divestitures (Detail)	1 Months Ended	12 Months Ended
	Dec. 31, 2014 USD ($) a	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)		Dec. 31, 2014 USD ($) a
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sale of oil and gas assets		$ 134,000,000	$ 268,000,000	[1]	$ 470,000,000	[1]
Loss on sale of oil and gas property		(21,000,000)	(135,000,000)		216,000,000
Goodwill impairment charges		$ 0	$ 163,000,000		$ 347,000,000
Anadarko Basin and Southern Louisiana [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sale of oil and gas assets	$ 1,300,000,000
Anadarko Basin [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Oil and gas properties sold | a	115,000				115,000
Loss on sale of oil and gas property	$ 823,000,000
Goodwill impairment charges	10,000,000
Loss on disposal of assets, before tax	$ 180,000,000
Southern Louisiana [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Oil and gas properties sold | a	90,000				90,000

[1] Financial information for 2015 and 2014 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

XML

Acquisitions and Divestitures - Additional Information - 2014 Activity - Gulf of Mexico Deepwater Divestiture (Detail) - USD ($)		12 Months Ended
	Jun. 30, 2014	Dec. 31, 2016	Dec. 31, 2015		Dec. 31, 2014
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Sale of 11 primary-term deepwater exploration blocks		$ 134,000,000	$ 268,000,000	[1]	$ 470,000,000	[1]
Loss on sale of oil and gas property		(21,000,000)	(135,000,000)		216,000,000
Goodwill impairment charges		$ 0	$ 163,000,000		$ 347,000,000
Deepwater Gulf of Mexico [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Sale of 11 primary-term deepwater exploration blocks	$ 1,400,000,000
Effective date of sale	May 01, 2014
Loss on sale of oil and gas property	$ 332,000,000
Goodwill impairment charges	$ 130,000,000

[1] Financial information for 2015 and 2014 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

XML

Acquisitions and Divestitures - Additional Information - 2014 Activity - Canada Divestiture (Detail) $ in Millions		12 Months Ended
	Apr. 30, 2014 USD ($) a	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)		Dec. 31, 2014 USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sale of oil and gas assets		$ 134	$ 268	[1]	$ 470	[1]
Loss on sale of oil and gas property		$ (21)	$ (135)		$ 216
Natural Gas [Member] | Canada [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sale of oil and gas assets	$ 374
Oil and gas properties sold | a	328,400
Effective date of sale	Jan. 01, 2014
Loss on sale of oil and gas property	$ 237
Natural Gas Liquids [Member] | Canada [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Working interest percentage in Wapiti area	100.00%

[1] Financial information for 2015 and 2014 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

XML

Acquisitions and Divestitures - Additional Information - 2014 Activity - Argentina Divestiture (Detail) - USD ($) $ in Millions		12 Months Ended
	Mar. 12, 2014	Dec. 31, 2016	Dec. 31, 2015	[1]	Dec. 31, 2014	[1]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sale of oil and gas assets		$ 134	$ 268		$ 470
Argentina [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sale of oil and gas assets	$ 800
Liabilities assumed	$ 52
Debt assumed beginning date	Jun. 30, 2013

[1] Financial information for 2015 and 2014 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

XML

Acquisitions and Divestitures - Summary of Sales and Other Operating Revenue and Loss From Discontinued Operation Related to Disposition (Detail) - USD ($) $ in Millions	1 Months Ended	3 Months Ended								12 Months Ended
	Jun. 30, 2015	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015		Dec. 31, 2014
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Loss from divestiture	$ (139)
Income (loss) from discontinued operations, net of tax		$ 0	$ (33)	$ 0	$ 0	$ 627	$ (17)	$ 120	$ (238)	$ (33)	$ 492	[1]	$ (1,707)	[1]
Argentina [Member] | Divestiture [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Revenues and other from discontinued operations										0	0		87
Loss from divestiture										(10)	0		(654)
Income (loss) from operations in Argentina										0	0		(1)
Income tax benefit (expense)										0	0		23
Income (loss) from discontinued operations, net of tax										$ (10)	$ 0		$ (632)

[1] Financial information for 2015 and 2014 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

XML

Acquisitions and Divestitures - Additional Information - 2014 Activity (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015		Dec. 31, 2014
Business Combinations [Abstract]
Leasehold and property acquisition	$ 181	$ 367	[1]	$ 1,475	[1]
Proceeds from divestiture of other oil and gas properties	134	268		96
Gain (loss) on divestiture of other oil and gas properties	21	135		(216)
Transaction, reorganization, and separation expense	$ 39	$ 132	[2]	$ 67	[2]

[1] Financial information for 2015 and 2014 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

[2] Financial information for 2015 and 2014 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

XML

Capitalized Exploratory Well Costs - Capitalized Exploratory Well Costs Rollforward (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Increase (Decrease) in Capitalized Exploratory Well Costs that are Pending Determination of Proved Reserves [Roll Forward]
Capitalized exploratory well costs, Beginning Balance	$ 245	$ 849	$ 630
Additions pending determination of proved reserves	249	382	622
Divestitures and other	0	(557)	(54)
Reclassifications to proved properties	(211)	(369)	(207)
Charged to exploration expense	(19)	(60)	(142)
Capitalized exploratory well costs, Ending Balance	$ 264	$ 245	849
Australia [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Assets held for sale			$ 49

XML

Capitalized Exploratory Well Costs - Aging of Suspended Well Balances (Details) $ in Millions	Dec. 31, 2016 USD ($) Project	Dec. 31, 2015 USD ($) Project	Dec. 31, 2014 USD ($) Project	Dec. 31, 2013 USD ($)
Extractive Industries [Abstract]
Exploratory well costs capitalized for a period of one year or less	$ 119	$ 184	$ 504
Exploratory well costs capitalized for a period greater than one year	145	61	345
Capitalized exploratory well costs	$ 264	$ 245	$ 849	$ 630
Number of projects with exploratory well costs capitalized for a period greater than one year | Project	3,000,000	2,000,000	18,000,000

XML

Capitalized Exploratory Well Costs - Aging by Geographic Area of Exploratory Well Costs Capitalized Greater than One Year (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory well costs capitalized for a period greater than one year	$ 145	$ 61	$ 345
2015 [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory well costs capitalized for a period greater than one year	81
2014 [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory well costs capitalized for a period greater than one year	61
2013 and Prior [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory well costs capitalized for a period greater than one year	3
North Sea [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory well costs capitalized for a period greater than one year	113
North Sea [Member] | 2015 [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory well costs capitalized for a period greater than one year	53
North Sea [Member] | 2014 [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory well costs capitalized for a period greater than one year	58
North Sea [Member] | 2013 and Prior [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory well costs capitalized for a period greater than one year	2
Other International [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory well costs capitalized for a period greater than one year	32
Other International [Member] | 2015 [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory well costs capitalized for a period greater than one year	28
Other International [Member] | 2014 [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory well costs capitalized for a period greater than one year	3
Other International [Member] | 2013 and Prior [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory well costs capitalized for a period greater than one year	$ 1

XML

Derivative Instruments and Hedging Activities - Additional Information (Details) - Subsequent Event [Member] - Not Designated as Hedging Instrument [Member] - Crude Oil [Member] - Commodity Option [Member] $ in Millions	Jan. 01, 2017 USD ($) Boe $ / Boe
Derivative [Line Items]
Underlying, derivative mass | Boe	175,000
Weighted average strike price	50.47
Derivative premium | $	$ 100
Derivative premium per unit	3.09

XML

Derivative Instruments and Hedging Activities - Commodity Derivative Activity Recorded in Statement of Consolidated Operations (Detail) - Other Revenue [Member] - Not Designated as Hedging Instrument [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Derivative Instruments, Gain (Loss) [Line Items]
Realized loss	$ 0	$ 0	$ (16)
Unrealized gain (loss)	0	0	300
Gain (loss) on derivatives not designated as cash flow hedges	$ 0	$ 0	$ 284

XML

Other Current Liabilities - Details of Other Current Liabilities (Detail) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Payables and Accruals [Abstract]
Accrued operating expenses	$ 110	$ 139
Accrued exploration and development	463	637
Accrued compensation and benefits	201	166
Accrued interest	145	144
Accrued income taxes	22	47
Current asset retirement obligation	66	36
Current debt	0	1
Refundable deposits	174	0
Other	77	53
Total Other current liabilities	$ 1,258	$ 1,223	[1]

[1] Financial information for 2015 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

XML

Asset Retirement Obligation - Asset Retirement Obligation (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligation at beginning of year	$ 2,598	$ 2,952
Liabilities incurred	41	68
Liabilities divested	(7)	(490)
Liabilities settled	(57)	(90)
Accretion expense	156	158
Revisions in estimated liabilities	(233)	0
Asset retirement obligation at end of year	2,498	2,598
Less current portion	(66)	(36)
Asset retirement obligation, long-term	$ 2,432	$ 2,562	[1]

[1] Financial information for 2015 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

XML

Asset Retirement Obligation - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015		Dec. 31, 2014	[1],[2]
Asset Retirement Obligation [Line Items]
Asset retirement obligation accretion	$ 156	$ 145	[1],[2]	$ 154
Additional abandonment liabilities associated with its drilling and development program	41	68
Revisions in estimated liabilities	$ (233)	0
Net Income (Loss) From Discontinued Operations, Net Of Tax [Member]
Asset Retirement Obligation [Line Items]
Asset retirement obligation accretion		$ 13

[1] Financial information for 2015 and 2014 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

[2] Financial information for 2015 and 2014 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

XML

Debt - Additional Information (Detail)	1 Months Ended			3 Months Ended	12 Months Ended
	Jan. 31, 2017 USD ($)	Feb. 29, 2016 GBP (£)	Jun. 30, 2015 USD ($) Contract	Dec. 31, 2016 USD ($)	Dec. 31, 2016 USD ($) Contract	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	Dec. 31, 2016 GBP (£)	Nov. 30, 2016 USD ($)
Debt Instrument [Line Items]
Loss on extinguishment of debt					$ 1,000,000	$ 39,000,000	$ 0
Repayments of debt principal after year five				$ 7,457,000,000	7,457,000,000
Debt issuance costs				56,000,000	56,000,000	61,000,000
Line of credit outstanding				0	0
Commercial paper program				3,500,000,000	3,500,000,000
Debt before unamortized discount				8,650,000,000	8,650,000,000
Discount of debt amortization					3,000,000	3,000,000	$ 3,000,000
Senior Notes [Member]
Debt Instrument [Line Items]
Debt repurchased principle amount				181,000,000	181,000,000
Early repayment of senior notes				182,000,000
Debt premium									$ 500,000
Loss on extinguishment of debt				1,000,000
Unsecured Debt [Member]
Debt Instrument [Line Items]
Debt issuance costs				56,000,000	56,000,000	61,000,000
Debt before unamortized discount				8,650,000,000	8,650,000,000	8,831,000,000
Unamortized discount				50,000,000	50,000,000	53,000,000
Maximum [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Debt repurchased principle amount									$ 250,000,000
Subsequent Event [Member]
Debt Instrument [Line Items]
Repayments of debt principal after year five	$ 7,400,000,000
Debt before unamortized discount	8,600,000,000
Subsequent Event [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Debt repurchased principle amount	69,000,000
Early repayment of senior notes	71,000,000
Debt premium	$ 1,000,000
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Maximum potential lien on assets located in specified regions				$ 1,100,000,000	$ 1,100,000,000
Revolving Credit Facility [Member] | Maximum [Member]
Debt Instrument [Line Items]
Percentage of liens of companies consolidated asset				5.00%	5.00%			5.00%
Notes Payable, Other Payables [Member]
Debt Instrument [Line Items]
Period for borrowing funds					270 days
Commercial Paper [Member]
Debt Instrument [Line Items]
Short-term debt outstanding				$ 0	$ 0	0
2015 Credit Facility [Member] | Letter of Credit [Member]
Debt Instrument [Line Items]
Letter of credit subfacility			$ 750,000,000
2015 Credit Facility [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of credit facility term			5 years
Credit facility maturity date			Jun. 30, 2020
Line of credit facility, number of extension options | Contract			2
Credit facility, extension period for maturity			1 year
Line of credit facility maximum borrowing capacity			$ 3,500,000,000.0
Line of credit facility, amount terminated			5,300,000,000
Line of credit facility, available borrowing capacity				$ 3,500,000,000	$ 3,500,000,000
Quarterly facility fees at per annum rate					0.175%
2015 Credit Facility [Member] | Revolving Credit Facility [Member] | Maximum [Member]
Debt Instrument [Line Items]
Line of credit facility, commitment amount			$ 4,500,000,000.0
Debt-to-capital ratio				0.60	0.60			0.60
2015 Credit Facility [Member] | Revolving Credit Facility [Member] | Base Rate [Member]
Debt Instrument [Line Items]
Margin percentage					0.075%
2015 Credit Facility [Member] | Revolving Credit Facility [Member] | London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument [Line Items]
Margin percentage					1.075%
2016 Credit Facility [Member] | Letter of Credit [Member]
Debt Instrument [Line Items]
Line of credit facility term		3 years
Credit facility, extension period for maturity		1 year
Line of credit facility maximum borrowing capacity | £		£ 1,075,000,000.000
Quarterly facility fees at per annum rate					0.175%
Number of debt instrument | Contract					3
Letters of credit outstanding, amount | £								£ 147,500,000
Letter of credit facility | £		£ 900,000,000
2016 Credit Facility [Member] | Letter of Credit [Member] | Base Rate [Member]
Debt Instrument [Line Items]
Margin percentage					0.075%
2016 Credit Facility [Member] | Letter of Credit [Member] | London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument [Line Items]
Margin percentage					1.075%
Apache finance Canada 7.75% notes due 2029 [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Debt before unamortized discount				$ 300,000,000	$ 300,000,000	$ 300,000,000

XML

Debt - Schedule of Debt (Detail) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Debt before unamortized discount	$ 8,650
Debt issuance costs	56	$ 61
Total debt	8,544	8,717
Current maturities	0	(1)
Long-term debt	8,544	8,716	[1]
Commercial Paper [Member]
Debt Instrument [Line Items]
Total debt	0	0
Unsecured Debt [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	8,650	8,831
Unamortized discount	(50)	(53)
Debt issuance costs	56	61
Total debt	8,544	8,717
Current maturities	0	(1)
Long-term debt	8,544	8,716
Unsecured Debt [Member] | United States [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	8,350	8,530
Unsecured Debt [Member] | United States [Member] | Commercial Paper [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	$ 0	$ 0
Unsecured Debt [Member] | 6.9% notes due 2018 [Member]
Debt Instrument [Line Items]
Debt interest rate	6.90%	6.90%
Unsecured Debt [Member] | 6.9% notes due 2018 [Member] | United States [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	$ 400	$ 400
Unsecured Debt [Member] | 7.0% notes due 2018 [Member]
Debt Instrument [Line Items]
Debt interest rate	7.00%	7.00%
Unsecured Debt [Member] | 7.0% notes due 2018 [Member] | United States [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	$ 150	$ 150
Unsecured Debt [Member] | 7.625% notes due 2019 [Member]
Debt Instrument [Line Items]
Debt interest rate	7.625%	7.625%
Unsecured Debt [Member] | 7.625% notes due 2019 [Member] | United States [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	$ 150	$ 150
Unsecured Debt [Member] | 3.625% notes due 2021 [Member]
Debt Instrument [Line Items]
Debt interest rate	3.625%	3.625%
Unsecured Debt [Member] | 3.625% notes due 2021 [Member] | United States [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	$ 493	$ 500
Unsecured Debt [Member] | 3.25% notes due 2022 [Member]
Debt Instrument [Line Items]
Debt interest rate	3.25%	3.25%
Unsecured Debt [Member] | 3.25% notes due 2022 [Member] | United States [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	$ 857	$ 919
Unsecured Debt [Member] | 2.625% notes due 2023 [Member]
Debt Instrument [Line Items]
Debt interest rate	2.625%	2.625%
Unsecured Debt [Member] | 2.625% notes due 2023 [Member] | United States [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	$ 528	$ 531
Unsecured Debt [Member] | 7.7% notes due 2026 [Member]
Debt Instrument [Line Items]
Debt interest rate	7.70%	7.70%
Unsecured Debt [Member] | 7.7% notes due 2026 [Member] | United States [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	$ 100	$ 100
Unsecured Debt [Member] | 7.95% notes due 2026 [Member]
Debt Instrument [Line Items]
Debt interest rate	7.95%	7.95%
Unsecured Debt [Member] | 7.95% notes due 2026 [Member] | United States [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	$ 180	$ 180
Unsecured Debt [Member] | 6.0% notes due 2037 [Member]
Debt Instrument [Line Items]
Debt interest rate	6.00%	6.00%
Unsecured Debt [Member] | 6.0% notes due 2037 [Member] | United States [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	$ 1,000	$ 1,000
Unsecured Debt [Member] | 5.1% notes due 2040 [Member]
Debt Instrument [Line Items]
Debt interest rate	5.10%	5.10%
Unsecured Debt [Member] | 5.1% notes due 2040 [Member] | United States [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	$ 1,499	$ 1,500
Unsecured Debt [Member] | 5.25% notes due 2042 [Member]
Debt Instrument [Line Items]
Debt interest rate	5.25%	5.25%
Unsecured Debt [Member] | 5.25% notes due 2042 [Member] | United States [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	$ 500	$ 500
Unsecured Debt [Member] | 4.75% notes due 2043 [Member]
Debt Instrument [Line Items]
Debt interest rate	4.75%	4.75%
Unsecured Debt [Member] | 4.75% notes due 2043 [Member] | United States [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	$ 1,413	$ 1,500
Unsecured Debt [Member] | 4.25% notes due 2044 [Member]
Debt Instrument [Line Items]
Debt interest rate	4.25%	4.25%
Unsecured Debt [Member] | 4.25% notes due 2044 [Member] | United States [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	$ 780	$ 800
Unsecured Debt [Member] | 7.375% debentures due 2047 [Member]
Debt Instrument [Line Items]
Debt interest rate	7.375%	7.375%
Unsecured Debt [Member] | 7.375% debentures due 2047 [Member] | United States [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	$ 150	$ 150
Unsecured Debt [Member] | 7.625% debentures due 2096 [Member]
Debt Instrument [Line Items]
Debt interest rate	7.625%	7.625%
Unsecured Debt [Member] | 7.625% debentures due 2096 [Member] | United States [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	$ 150	$ 150
Unsecured Debt [Member] | Notes due In 2017 [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	0	1
Unsecured Debt [Member] | Apache finance Canada 7.75% notes due 2029 [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	$ 300	$ 300
Debt interest rate	7.75%	7.75%
Unsecured Debt [Member] | Subsidiary and other obligations [Member]
Debt Instrument [Line Items]
Debt before unamortized discount	$ 300	$ 301

[1] Financial information for 2015 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

XML

Debt - Schedule of Long Term Debt by Maturity (Detail) $ in Millions	Dec. 31, 2016 USD ($)
Debt Disclosure [Abstract]
2017	$ 0
2018	550
2019	150
2020	0
2021	493
Thereafter	7,457
Total Debt, excluding discounts and debt issuance costs	$ 8,650

XML

Debt - Summary of Carrying Amounts and Estimated Fair Values (Detail) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Debt, Carrying Value	$ 8,544	$ 8,717
Debt issuance costs	56	61
Debt, Fair Value	9,183	8,330
Commercial Paper [Member]
Debt Instrument [Line Items]
Debt, Carrying Value	0	0
Debt, Fair Value	0	0
Notes and Debentures [Member]
Debt Instrument [Line Items]
Debt, Carrying Value	8,544	8,717
Debt, Fair Value	$ 9,183	$ 8,330

XML

Debt - Components of Financing Costs, Net (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Debt Disclosure [Abstract]
Interest expense	$ 464	$ 486	$ 499
Amortization of deferred loan costs	8	11	6
Capitalized interest	(48)	(15)	(85)
Loss on extinguishment of debt	1	39	0
Interest income	(8)	(10)	(7)
Financing costs, net	$ 417	$ 511	$ 413

XML

Income Taxes - Income (Loss) Before Income Taxes (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015		Dec. 31, 2014
Income Tax Disclosure [Abstract]
U.S.	$ (997)	$ (9,386)		$ (4,807)
Foreign	(685)	(2,783)		(2,023)
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	$ (1,682)	$ (12,169)	[1]	$ (6,830)	[1]

[1] Financial information for 2015 and 2014 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

XML

Income Taxes - Total Provision for Income Taxes (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015		Dec. 31, 2014
Current income taxes:
Federal	$ (14)	$ 363		$ (10)
State	(30)	41		1
Foreign	435	31		1,290
Current tax, net	391	435	[1]	1,281	[1]
Deferred income taxes:
Federal	(257)	(1,123)		(671)
State	0	(51)		(45)
Foreign	(576)	(271)		(1,083)
Deferred taxes, net	(833)	(1,445)	[1],[2]	(1,799)	[1],[2]
Total	$ (442)	$ (1,010)		$ (518)

[1] Financial information for 2015 and 2014 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

[2] Financial information for 2015 and 2014 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

XML

Income Taxes - Reconciliation of Tax of Income Before Income Taxes and Total Tax Expense (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Income tax expense (benefit) at U.S. statutory rate	$ (589)	$ (4,259)	$ (2,391)
State income tax, less federal effect	(19)	(7)	(28)
Taxes related to foreign operations	303	(662)	(147)
Tax credits	(1)	(6)	0
Tax on distributed foreign earnings	80	726	311
Foreign tax credits	(136)	(2,090)	0
Deferred tax on undistributed foreign earnings	(31)	1,903	560
Tax impact of goodwill adjustments	0	82	161
Change in U.K. tax rate	(238)	(414)	0
Net change in tax contingencies	(19)	20	(3)
Canadian USD functional currency election	158	0	0
Valuation allowances	10	3,746	1,021
All other, net	40	(49)	(2)
Total	$ (442)	$ (1,010)	$ (518)

XML

Income Taxes - Net Deferred Tax Liability (Detail) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Deferred tax assets:
Deferred income	$ 105	$ 20
U.S. and state net operating losses	1,095	329
Foreign net operating losses	1,424	1,507
Tax credits and other tax incentives	62	82
Foreign tax credits	2,226	2,090
Accrued expenses and liabilities	153	136
Asset retirement obligation	875	1,037
Property and equipment	1,189	1,534
Total deferred tax assets	7,129	6,735
Valuation allowance	(5,401)	(5,434)	$ (1,564)	$ (598)
Net deferred tax assets	1,728	1,301
Deferred tax liabilities:
Deferred income	0	140
Investment in foreign subsidiaries	1,872	1,903
Equity investments	23	5
Property and equipment	1,533	1,773
Other	5	4
Total deferred tax liabilities	3,433	3,825
Net deferred income tax liability	$ 1,705	$ 2,524

XML

Income Taxes - Net Deferred Tax Assets and Liabilities (Detail) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Assets:
Deferred charges and other	$ 5	$ 5
Liabilities:
Deferred income taxes	1,710	2,529	[1]
Net deferred income tax liability	$ 1,705	$ 2,524

[1] Financial information for 2015 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

XML

Income Taxes - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax [Line Items]
Current income tax liability		$ 560
Deferred income tax liability on undistributed foreign earnings			$ 560
Deferred income tax expense on foreign undistributed earnings			311
Deferred tax benefit	$ 576	271	1,083
Increase in valuation allowances	33	3,900	966
Foreign tax credit carryforward, amount	2,226	2,090
Tax expense (benefit) recorded for interest and penalties	0	1	1
Accrued for payment of interest and penalties	0	1	$ 0
Reserve for uncertain tax positions related to the current year	4	$ (19)
Settlements	3
United States [Member]
Income Tax [Line Items]
Operating loss carryforwards	2,452
Operating loss carryforwards subject to annual limitation	197
Canada [Member]
Income Tax [Line Items]
Operating loss carryforwards	125
Capital loss carryforwards	$ 829
Her Majesty's Revenue and Customs (HMRC) [Member]
Income Tax [Line Items]
Supplementary charge, percent	10.00%	20.00%	32.00%
Deferred tax benefit	$ 238	$ 414

XML

Income Taxes - Summary of Valuation Allowance Against Certain Foreign Net Deferred Tax Assets and State Net Operating Losses (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Balance at beginning of year	$ 5,434	$ 1,564	$ 598
State	(43)	151	62
U.S.	139	2,159	0
Foreign	129	(1,560)	(1,021)
Discontinued operations	0	0	(117)
Balance at end of year	$ 5,401	$ 5,434	$ 1,564

XML

Income Taxes - Net Operating Losses (Detail) $ in Millions	Dec. 31, 2016 USD ($)
United States [Member]
Schedule Of Income Tax [Line Items]
Net operating losses	$ 2,452
State [Member]
Schedule Of Income Tax [Line Items]
Net operating losses	4,774
Canada [Member]
Schedule Of Income Tax [Line Items]
Net operating losses	$ 125

XML

Income Taxes - Schedule of Foreign Tax Credit Carryforward (Detail) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Foreign tax credits	$ 2,226	$ 2,090

XML

Income Taxes - Reconciliation of Beginning and Ending Amount of Unrecognized Tax Benefits (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
Balance at beginning of year	$ 15	$ 19	$ 0	$ 3
Additions based on tax positions related to the current year	15	19	0
Reductions for tax positions of prior years	(19)	0	(3)
Balance at end of year	$ 15	$ 19	$ 0	$ 3

XML

Income Taxes - Key Jurisdictions of Company's Earliest Open Tax Years (Detail)	12 Months Ended
	Dec. 31, 2016
United States [Member]
Schedule Of Income Tax [Line Items]
Open tax year by major tax jurisdiction	2012
Canada [Member]
Schedule Of Income Tax [Line Items]
Open tax year by major tax jurisdiction	2012
Egypt [Member]
Schedule Of Income Tax [Line Items]
Open tax year by major tax jurisdiction	1998
United Kingdom [Member]
Schedule Of Income Tax [Line Items]
Open tax year by major tax jurisdiction	2014

XML

Commitments and Contingencies - Additional Information (Detail) - USD ($)			12 Months Ended
	Mar. 21, 2016	Mar. 20, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Jun. 06, 2016	Mar. 12, 2014
Commitment And Contingencies [Line Items]
Accrued liability for legal contingencies			$ 15,000,000
Environmental tax and royalty obligations							$ 100,000,000
Retain right of obligations			67,500,000
Maximum cost considered to be recognized for additional reserve			300,000
Undiscounted reserve for environmental remediation			51,000,000
Net rental expenses			59,000,000	$ 57,000,000	$ 45,000,000
Contractual obligation cost incurred			86,000,000	$ 92,000,000	$ 89,000,000
Apollo Exploration Lawsuit [Member]
Commitment And Contingencies [Line Items]
Loss contingency damages sought value	$ 500,000,000
Minimum [Member] | Apollo Exploration Lawsuit [Member]
Commitment And Contingencies [Line Items]
Loss contingency damages sought value		$ 1,100,000,000
Maximum [Member] | Escheat Audits [Member]
Commitment And Contingencies [Line Items]
Loss contingency estimate of possible loss			$ 200,000
Australian Operations [Member] | Australian Operations Divestiture Dispute [Member]
Commitment And Contingencies [Line Items]
Loss contingency estimate of possible loss						$ 200,000,000

XML

Commitments and Contingencies - Contractual Obligations (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2016 USD ($)
Oil and Gas Delivery Commitments and Contracts [Line Items]
Total	$ 1,225
2017	353
2018-2019	452
2020-2021	290
2022 & Beyond	130
Sublease income	10
Drilling Rigs [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Total	244
2017	177
2018-2019	67
2020-2021	0
2022 & Beyond	0
Purchase Obligations [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Total	680
2017	119
2018-2019	287
2020-2021	250
2022 & Beyond	24
Operating Lease Obligations [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Total	258
2017	56
2018-2019	95
2020-2021	37
2022 & Beyond	70
Capital Lease Obligations [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Total	43
2017	1
2018-2019	3
2020-2021	3
2022 & Beyond	$ 36

XML

Retirement and Deferred Compensation Plans - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plan Disclosure [Line Items]
Portion of employee's salary, employee contributions under non-qualified retirement savings plan	50.00%
Maximum percentage of compensation contributed by the company	8.00%
Percentage of additional contribution to money purchase retirement plan	6.00%
Maximum percentage of eligible compensation contributed by the participating employees	50.00%
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	$ 82	$ 77	$ 107
Targeted ongoing funding level of pension plan policy, percent	100.00%
Outperformance relative to gilts for equities	3.50%
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation for pension plans	$ 181	$ 169	$ 183
Expected contribution towards pension and postretirement plan	5
Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected contribution towards pension and postretirement plan	$ 2

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	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Change in Projected Benefit Obligation
Benefits paid			$ (5)
Change in Plan Assets
Fair value of plan assets at beginning of year	$ 197
Benefits paid			(5)
Fair value of plan assets at end of year	206	$ 197
Pension Benefits [Member]
Change in Projected Benefit Obligation
Projected benefit obligation beginning of year	202	216	189
Service cost	4	5	5
Interest cost	7	8	9
Foreign currency exchange rate changes	(39)	(10)	(13)
Actuarial losses (gains)	32	(10)	31
Benefits paid	(4)	(7)	(5)
Projected benefit obligation at end of year	202	202	216
Change in Plan Assets
Fair value of plan assets at beginning of year	197	206	191
Actual return on plan assets	46	1	25
Foreign currency exchange rates	(39)	(10)	(13)
Employer contributions	6	7	8
Benefits paid	(4)	(7)	(5)
Fair value of plan assets at end of year	206	197	206
Funded status at end of year	4	(5)	(10)
Amounts recognized in Consolidated Balance Sheet
Current liability			0
Non-current asset (liability)	4	(5)	(10)
Defined Benefit Plans, Liabilities, Total	4	(5)	(10)
Pre-tax Amounts Recognized in Accumulated Other Comprehensive Income (Loss)
Accumulated gain (loss)	$ (25)	$ (32)	$ (37)
Weighted Average Assumptions used as of December 31
Discount rate	2.70%	3.90%	3.70%
Salary increases	4.80%	4.60%	4.60%
Expected return on assets	3.40%	4.10%	3.90%
Postretirement Benefits [Member]
Change in Projected Benefit Obligation
Projected benefit obligation beginning of year	$ 26	$ 22	$ 28
Service cost	2	2	3
Interest cost	1	1	1
Actuarial losses (gains)	(2)		(9)
Effect of curtailment and settlements		2
Benefits paid	(3)	(2)	(2)
Retiree contributions	2	1	1
Projected benefit obligation at end of year	26	26	22
Change in Plan Assets
Employer contributions	1	1	1
Benefits paid	(3)	(2)	(2)
Retiree contributions	2	1	1
Funded status at end of year	(26)	(26)	(22)
Amounts recognized in Consolidated Balance Sheet
Current liability	(2)	(2)	(1)
Non-current asset (liability)	(24)	(24)	(21)
Defined Benefit Plans, Liabilities, Total	(26)	(26)	(22)
Pre-tax Amounts Recognized in Accumulated Other Comprehensive Income (Loss)
Accumulated gain (loss)	$ 9	$ 9	$ 10
Weighted Average Assumptions used as of December 31
Discount rate	3.76%	3.95%	3.62%
Healthcare cost trend
Initial	7.00%	7.00%	7.00%
Ultimate in 2025	5.00%	5.00%	5.00%

XML

Retirement and Deferred Compensation Plans - Allocations for Plan Asset Holding and Target Allocation for Company's Plan Asset (Detail)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
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	1.00%
Percentage of Plan Assets at Year-End	1.00%	0.00%
Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	40.00%
Percentage of Plan Assets at Year-End	40.00%	40.00%
Equity Securities [Member] | UK Quoted Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	14.00%
Percentage of Plan Assets at Year-End	14.00%	14.00%
Equity Securities [Member] | Overseas Quoted Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	26.00%
Percentage of Plan Assets at Year-End	26.00%	26.00%
Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	59.00%
Percentage of Plan Assets at Year-End	59.00%	60.00%
Debt Securities [Member] | U.K. Government Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	47.00%
Percentage of Plan Assets at Year-End	47.00%	48.00%
Debt Securities [Member] | U.K. Corporate Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	12.00%
Percentage of Plan Assets at Year-End	12.00%	12.00%

XML

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	Dec. 31, 2016	Dec. 31, 2015
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 206	$ 197
Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	82	80
Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	122	117
Quoted Price in Active Markets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	206	197
Quoted Price in Active Markets (Level 1) [Member] | Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	82	80
Quoted Price in Active Markets (Level 1) [Member] | Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	122	117
UK Quoted Equities [Member] | Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	28	27
UK Quoted Equities [Member] | Quoted Price in Active Markets (Level 1) [Member] | Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	28	27
Overseas Quoted Equities [Member] | Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	54	53
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	54	53
U.K. Government Bonds [Member] | Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	97	93
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	97	93
U.K. Corporate Bonds [Member] | Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	25	24
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	25	$ 24
Cash [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	2
Cash [Member] | Quoted Price in Active Markets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets	$ 2

XML

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 Footnote (Detail)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
Portion of overseas equities	100.00%	100.00%
U.K. Government Bonds [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
Overseas Quoted Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Performance target over the benchmark	2.00%
Period for the portion of UK Equities, overseas equities, government bonds and corporate bonds, benchmarked against FTSE	3 years
U.K. Corporate Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Performance target over the benchmark	0.75%
Benchmarked against BofAML Sterling Corporate & Collateralised (excluding Subordinated) Index	12.00%
Index - Linked Index [Member] | U.K. Government Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Portion of debt securities government bonds and corporate bonds benchmarked against FTSE	48.00%
FTSE Actuaries Government Securities Index [Member] | U.K. Government Bonds [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
Sterling Nominal LDI Bonds [Member] | Nominal LDI Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Benchmarked against ILIM Custom Benchmark index	37.00%
Sterling Inflation Linked LDI Bonds [Member] | Inflation Linked LDI Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Benchmarked against ILIM Custom Benchmark index	15.00%
Passive Global Equities [Member] | MSCI World Index [Member]
Defined Benefit Plan Disclosure [Line Items]
Portion of overseas equities		30.00%
Passive Global Equities Hedged [Member] | MSCI World Index [Member]
Defined Benefit Plan Disclosure [Line Items]
Portion of overseas equities		12.00%
Fundamental Indexation Global Equities [Member] | FTSE RAFI Developed 1000 Index [Member]
Defined Benefit Plan Disclosure [Line Items]
Portion of overseas equities		30.00%
Fundamental Indexation Global Equities Hedged [Member] | FTSE RAFI Developed 1000 Index [Member]
Defined Benefit Plan Disclosure [Line Items]
Portion of overseas equities		12.00%
Emerging Markets [Member] | MSCI World Index [Member]
Defined Benefit Plan Disclosure [Line Items]
Portion of overseas equities		16.00%

XML

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	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Pension Benefits [Member]
Component of Net Periodic Benefit Costs
Service cost	$ 4	$ 5	$ 5
Interest cost	7	8	9
Expected return on assets	(7)	(8)	(11)
Amortization of actuarial (gain) loss	1	2	1
Net periodic benefit cost	$ 5	$ 7	$ 4
Weighted Average Assumptions used to determine Net Period Benefit Cost for the Years ended December 31
Discount rate	3.90%	3.70%	4.60%
Salary increases	4.60%	4.60%	4.90%
Expected return on assets	4.10%	3.90%	5.60%
Postretirement Benefits [Member]
Component of Net Periodic Benefit Costs
Service cost	$ 2	$ 2	$ 3
Interest cost	1	1	1
Amortization of actuarial (gain) loss	(1)
Curtailment (gain) loss			0
Net periodic benefit cost	$ 2	$ 3	$ 4
Weighted Average Assumptions used to determine Net Period Benefit Cost for the Years ended December 31
Discount rate	3.95%	3.62%	4.33%
Healthcare cost trend
Initial	7.00%	7.00%	7.00%
Ultimate in 2025	5.00%	5.00%	5.00%

XML

Retirement and Deferred Compensation Plans - Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates (Detail) - Postretirement Benefits [Member] $ in Millions	12 Months Ended
	Dec. 31, 2016 USD ($)
Defined Benefit Plan Disclosure [Line Items]
Effect on service and interest cost components, 1% Increase	$ 1
Effect on postretirement benefit obligation, 1% Increase	5
Effect on service and interest cost components, 1% Decrease	(1)
Effect on postretirement benefit obligation, 1% Decrease	$ (4)

XML

Retirement and Deferred Compensation Plans - Expected Future Benefit Payment (Detail) $ in Millions	Dec. 31, 2016 USD ($)
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
2017	$ 4
2018	4
2019	4
2020	4
2021	4
Years 2022-2026	24
Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
2017	2
2018	2
2019	2
2020	2
2021	2
Years 2022-2026	$ 9

XML

Capital Stock - Common Stock Outstanding (Detail) - shares	12 Months Ended			19 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2014
Equity [Abstract]
Balance, beginning of year (in shares)	378,034,175	376,504,892	395,772,908
Shares issued for stock-based compensation plans:
Treasury shares issued	11,504	17,525	17,454
Common shares issued	1,393,997	1,511,758	1,665,259
Treasury shares acquired	0	0	(20,950,729)	(32,200,000)
Balance, end of year (in shares)	379,439,676	378,034,175	376,504,892	376,504,892

XML

Capital Stock - Net Income Per Common Share (Detail) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015		Dec. 31, 2014
Earnings Per Share [Abstract]
Net loss from continuing operations attributable to common shareholders									$ (1,372)	$ (10,844)	[1]	$ (6,653)	[1]
Net income (loss) from discontinued operations									(33)	492	[1],[2]	(1,707)	[1],[2]
Net income (loss) attributable to common shareholders	$ (182)	$ (607)	$ (244)	$ (372)	$ (4,015)	$ (4,143)	$ (860)	$ (1,334)	$ (1,405)	$ (10,352)	[1]	$ (8,360)	[1]
Income (loss) from continuing operations, shares									379	378		384
Income (loss) from discontinued operations, shares									379	378		384
Income (loss) attributable to common stock, shares									379	378	[1]	384	[1]
Basic and diluted net loss from continuing operations per share	$ (0.48)	$ (1.51)	$ (0.65)	$ (0.98)	$ (12.28)	$ (10.91)	$ (2.60)	$ (2.91)	$ (3.62)	$ (28.70)	[1]	$ (17.32)	[1]
Basic and diluted net loss from discontinued operations per share	0.00	(0.09)	0.00	0.00	1.66	(0.04)	0.32	(0.63)	(0.09)	1.30	[1]	(4.44)	[1]
Basic and diluted net loss per share	$ (0.48)	$ (1.60)	$ (0.65)	$ (0.98)	$ (10.62)	$ (10.95)	$ (2.28)	$ (3.54)	$ (3.71)	$ (27.40)	[1]	$ (21.76)	[1]

[1] Financial information for 2015 and 2014 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

[2] Financial information for 2015 and 2014 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

XML

Capital Stock - Additional Information (Detail) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended	12 Months Ended			19 Months Ended
	Jan. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options and restricted stock, anti-dilutive		4,700,000	7,000,000	4,500,000
Common stock share purchase, shares		40,000,000
Common stock share repurchase, shares		0	0	20,950,729	32,200,000
Common stock share repurchase, per share					$ 88.96
Common stock dividends (in USD per share)		$ 1.00	$ 1	$ 0.95
Shares authorized and available for grant		22,900,000
Compensation expense		$ 131	$ 100	$ 148
Stock-based compensation expenses, after tax		$ 93	65	95
Exercised, Shares		0
Intrinsic value of options exercised			3	13
Stock-based compensation capitalized		$ 40	53	62
Employee Stock Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation cost related to non-vested awards not yet recognized		6
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense		113	90	111
Stock-based compensation expenses, after tax		73	$ 58	$ 72
Total compensation cost related to non-vested awards not yet recognized		$ 233
Granted, Shares		4,049,023	2,976,562	3,046,744
Weighted average grant date fair value per share (in USD per share)		$ 47.37	$ 61.65	$ 86.87
Stock-based compensation capitalized		$ 35	$ 48	$ 47
Weighted-average remaining life of unvested restricted stock units		1 year 3 months 6 days
Unvested restricted stock units		6,061,803
Total fair value of restricted stock awards vested		$ 151	$ 149	$ 138
Subsequent Event [Member] | Employee Stock Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Period in which stock options become exercisable	3 years
Total compensation cost related to non-vested awards not yet recognized	$ 9
Options Issued	489,773
Subsequent Event [Member] | Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Period in which stock options become exercisable	3 years
Total compensation cost related to non-vested awards not yet recognized	$ 118
Options Issued	1,866,606
Weighted average grant date fair value per share (in USD per share)	$ 63.25
Prior to 2016 [Member] | Employee Stock Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Period in which stock options become exercisable		4 years
Period in which stock options expires after grant date		10 years
In or After 2016 [Member] | Employee Stock Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Period in which stock options become exercisable		3 years
Period in which stock options expires after grant date		10 years

XML

Capital Stock - Description of Stock Based Compensation Plans and Related Costs (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Equity [Abstract]
Stock-based compensation expensed	$ 131	$ 100	$ 148
Stock-based compensation capitalized	40	53	62
Total stock-based compensation costs	$ 171	$ 153	$ 210

XML

Capital Stock - Summary of Stock Options Activities (Detail)	12 Months Ended
	Dec. 31, 2016 USD ($) $ / shares shares
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Outstanding, beginning of year, Shares | shares	4,931,000
Granted, Shares | shares	873,000
Exercised, Shares | shares	0
Forfeited or expired, Shares | shares	(691,000)
Outstanding, end of year, Shares | shares	5,113,000
Expected to vest, Shares | shares	887,000
Exercisable, end of year, Shares | shares	4,177,000
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price [Abstract]
Outstanding, beginning of year, Weighted Average exercise Price (in USD per share) | $ / shares	$ 91.52
Granted, Weighted Average Exercise Price (in USD per share) | $ / shares	41.24
Exercised, Weighted Average Exercise Price (in USD per share) | $ / shares	0.00
Forfeited or expired, Weighted Average Exercise Price (in USD per share) | $ / shares	76.99
Outstanding, end of year, Weighted Average Exercise Price (in USD per share) | $ / shares	84.89
Expected to vest, Weighted Average Exercise Price (in USD per share) | $ / shares	46.88
Exercisable, end of year, Weighted Average Exercise Price (in USD per share) | $ / shares	$ 93.40
Weighted average remaining contractual life for options outstanding	4 years 7 months
Weighted average remaining contractual life for expected to vest	8 years 8 months
Weighted average remaining contractual life for exercisable	3 years 8 months
Aggregate intrinsic value for options outstanding | $	$ 18,000,000
Aggregate intrinsic value for expected to vest | $	17,000,000
Aggregate intrinsic value for exercisable | $	$ 0

XML

Capital Stock - Schedule of Assumptions Used (Details) - Employee Stock Option [Member]	12 Months Ended
	Dec. 31, 2016 $ / shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected volatility	32.72%
Expected dividend yields	2.42%
Expected term (in years)	6 years
Risk-free rate	1.44%
Weighted-average grant-date fair value	$ 10.38

XML

Capital Stock - Schedule of Restricted Stock Activities (Detail) - Restricted Stock [Member] - $ / shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted Shares, nonvested, Beginning Balance, Shares	4,570,000
Granted, Shares	4,049,023	2,976,562	3,046,744
Vested, Shares	(2,081,000)
Forfeited, Shares	(476,000)
Restricted Shares, nonvested, Ending Balance, Shares	6,062,000	4,570,000
Non-vested at January 1, 2016, Weighted Average Grant Date Fair Value (in USD per share)	$ 70.86
Granted, Weighted Average Grant-Date Fair Value (in USD per share)	47.37	$ 61.65	$ 86.87
Vested, Weighted Average Grant-Date Fair Value (in USD per share)	72.59
Forfeited, Weighted Average Grant-Date Fair Value (in USD per share)	58.05
Non-vested at December 31, 2016, Weighted Average Grant Date Fair Value (in USD per share)	$ 55.55	$ 70.86

XML

Capital Stock - TSR Stock Units and Business Performance RSU Narrative (Detail) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended						12 Months Ended
	Jan. 31, 2017	Jan. 31, 2016	Feb. 28, 2015	Jan. 31, 2014	May 31, 2013	Jan. 31, 2013	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares authorized and available for grant							22,900,000
Compensation expense							$ 131.0	$ 100.0	$ 148.0
Stock-based compensation expenses, after tax							93.0	65.0	95.0
Stock-based compensation capitalized							40.0	53.0	62.0
Total Shareholder Return Stock Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense							0.7	0.6	18.0
Stock-based compensation expenses, after tax							0.5	0.4	11.0
Stock-based compensation capitalized							0.1	0.3	$ 7.0
Total compensation cost related to non-vested awards not yet recognized							$ 1.2
Unvested restricted stock units							77,824
Weighted-average remaining life of unvested restricted stock units							8 months 18 days
Conditional Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Nonvested shares outstanding							1,225,149
Compensation expense							$ 14.0	3.0
Stock-based compensation expenses, after tax							9.0	2.0
Stock-based compensation capitalized							2.0	$ 1.0
Total compensation cost related to non-vested awards not yet recognized							$ 37.0
Weighted-average remaining life of unvested restricted stock units							2 years 1 month 24 days
Total Shareholder Return Program [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of additional vest on succeeding anniversaries							25.00%
Total Shareholder Return Program [Member] | Total Shareholder Return Stock Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Nonvested shares outstanding							78,000	172,000
Granted, Shares							0
Weighted average grant date fair value per share (in USD per share)							$ 0.00
2013 TSR Program [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Initial conditional restricted stock unit awards granted to eligible employees						1,232,176
Forfeited, Shares					918,016
Shares paid out as percentage of target								70.00%
Total awards, outstanding							29,957
2014 TSR Program [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Initial conditional restricted stock unit awards granted to eligible employees				157,406
Shares paid out as percentage of target							100.00%
Total awards, outstanding							47,867
Business Performance Program [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares allocation percentage							50.00%
Shares vesting period							3 years
Business Performance Program [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares vesting percentage							50.00%
Remaining shares vesting percentage							50.00%
Business Performance Program [Member] | Conditional Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Nonvested shares outstanding							1,225,000	501,000
Granted, Shares							871,000
Weighted average grant date fair value per share (in USD per share)							$ 34.19
2015 Business Performance Program [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Initial conditional restricted stock unit awards granted to eligible employees			602,304
Total awards, outstanding							431,707
2015 Business Performance Program [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares authorized and available for grant							0
Percentage of shares awarded							0.00%
2015 Business Performance Program [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares authorized and available for grant							647,561
Percentage of shares awarded							150.00%
2016 Business Performance Program [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Initial conditional restricted stock unit awards granted to eligible employees		871,369
Total awards, outstanding							793,442
2016 Business Performance Program [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares authorized and available for grant							0
Percentage of shares awarded							0.00%
2016 Business Performance Program [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares authorized and available for grant							1,586,884
Percentage of shares awarded							200.00%
2017 Performance Program [Member] | Conditional Restricted Stock [Member] | Subsequent Event [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted, Shares	604,147
Weighted average grant date fair value per share (in USD per share)	$ 66.97
2017 Performance Program [Member] | Restricted Stock Units (RSUs) [Member] | Subsequent Event [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares authorized and available for grant	0
2017 Performance Program [Member] | Restricted Stock Units (RSUs) [Member] | Subsequent Event [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares authorized and available for grant	1,208,294
Non Employee Director [Member] | Total Shareholder Return Program [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted stock units, vested (Percentage)							50.00%

XML

Capital Stock - Schedule of TSR Stock Units and Business Performance RSU Activities (Detail)	12 Months Ended
	Dec. 31, 2016 $ / shares shares
Conditional Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Restricted Shares, nonvested, Beginning Balance, Shares
Restricted Shares, nonvested, Ending Balance, Shares	1,225,149
Total Shareholder Return Program [Member] | Total Shareholder Return Stock Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Restricted Shares, nonvested, Beginning Balance, Shares	172,000
Granted, Shares	0
Vested, Shares	(34,000)
Forfeited or expired, Shares	(60,000)
Restricted Shares, nonvested, Ending Balance, Shares	78,000
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Non-vested at January 1, 2016, Weighted Average Grant Date Fair Value (in USD per share) | $ / shares	$ 78.22
Granted, Weighted Average Grant-Date Fair Value (in USD per share) | $ / shares	0.00
Vested, Weighted Average Grant-Date Fair Value (in USD per share) | $ / shares	76.07
Forfeited or expired, Weighted Average Grant-Date Fair Value (in USD per share) | $ / shares	71.20
Non-vested at December 31, 2016, Weighted Average Grant Date Fair Value (in USD per share) | $ / shares	$ 77.10
Business Performance Program [Member] | Conditional Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Restricted Shares, nonvested, Beginning Balance, Shares	501,000
Granted, Shares	871,000
Forfeited or expired, Shares	(147,000)
Restricted Shares, nonvested, Ending Balance, Shares	1,225,000
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Non-vested at January 1, 2016, Weighted Average Grant Date Fair Value (in USD per share) | $ / shares	$ 66.53
Granted, Weighted Average Grant-Date Fair Value (in USD per share) | $ / shares	34.19
Forfeited or expired, Weighted Average Grant-Date Fair Value (in USD per share) | $ / shares	45.65
Non-vested at December 31, 2016, Weighted Average Grant Date Fair Value (in USD per share) | $ / shares	$ 45.60

XML

Accumulated Other Comprehensive Loss - Components of Accumulated Other Comprehensive Income (Loss) (Detail) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015		Dec. 31, 2014
Statement of Comprehensive Income [Abstract]
Currency translation adjustment	$ (109)	$ (109)		$ (109)
Unfunded pension and postretirement benefit plan	(3)	(10)		(7)
Accumulated other comprehensive loss	$ (112)	$ (119)	[1]	$ (116)

[1] Financial information for 2015 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

XML

Major Customers - Additional Information (Detail) - Customer Concentration Risk [Member] - Oil and Gas Production Revenues [Member]	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
China Petroleum & Chemical Corporation [Member]
Revenue, Major Customer [Line Items]
Entity wide revenue major customer percentage	21.00%	12.00%
Egyptian General Petroleum Company [Member]
Revenue, Major Customer [Line Items]
Entity wide revenue major customer percentage	12.00%	11.00%
Shell Plc [Member]
Revenue, Major Customer [Line Items]
Entity wide revenue major customer percentage		11.00%	19.00%

XML

Business Segment Information - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2016 Country
Segment Reporting [Abstract]
Production in number of countries	4

XML

Business Segment Information - Financial Segment Information (Detail) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015		Dec. 31, 2014
Segment Reporting Information [Line Items]
Oil and gas production revenues									$ 5,367	$ 6,510	[1]	$ 12,795	[1]
Lease operating expenses									1,494	1,854	[1]	2,238	[1]
Gathering and transportation									200	211	[1]	273	[1]
Taxes other than income									126	282	[1]	577	[1]
Depreciation, depletion, and amortization									2,618	3,300	[2]	4,526	[2]
Exploration									473	2,771	[1]	2,499	[1]
Asset retirement obligation accretion									156	145	[1],[2]	154	[1],[2]
Impairments									1,103	9,472		7,102
Operating Income (Loss)									(803)	(11,525)		(4,574)
Other Income (Expense):
Gain (loss) on divestiture	$ 0	$ 5	$ 17	$ (1)	$ 77	$ (5)	$ 227	$ (18)	21	281	[1],[2]	(1,608)	[1],[2]
Other									(34)	98		285
General and administrative									(410)	(380)	[1]	(453)	[1]
Transaction, reorganization, and separation									(39)	(132)	[1]	(67)	[1]
Financing costs, net									(417)	(511)	[1]	(413)	[1]
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAXES									(1,682)	(12,169)	[1]	(6,830)	[1]
Net property and equipment	18,867				20,838				18,867	20,838		32,154
Total Assets	22,519				25,500				22,519	25,500		38,165
Additions to Net Property and Equipment	1,681				4,106				1,681	4,106		10,725
Operating Segments [Member] | United States [Member]
Segment Reporting Information [Line Items]
Oil and gas production revenues									1,997	2,637		5,744
Lease operating expenses									553	739		921
Gathering and transportation									80	68		93
Taxes other than income									139	184		350
Depreciation, depletion, and amortization									1,138	1,558		2,408
Exploration									285	2,145		2,113
Asset retirement obligation accretion									34	28		43
Impairments									80	6,266		2,622
Operating Income (Loss)									(312)	(8,351)		(2,806)
Other Income (Expense):
Net property and equipment	11,168				11,753				11,168	11,753		19,507
Total Assets	12,403				12,782				12,403	12,782		21,487
Additions to Net Property and Equipment	926				2,099				926	2,099		7,006
Operating Segments [Member] | Canada [Member]
Segment Reporting Information [Line Items]
Oil and gas production revenues									343	498		1,092
Lease operating expenses									181	244		384
Gathering and transportation									68	89		123
Taxes other than income									20	26		31
Depreciation, depletion, and amortization									183	301		439
Exploration									88	231		162
Asset retirement obligation accretion									47	43		39
Impairments									367	1,593		2,412
Operating Income (Loss)									(611)	(2,029)		(2,498)
Other Income (Expense):
Net property and equipment	1,464				2,074				1,464	2,074		4,197
Total Assets	1,591				2,225				1,591	2,225		4,728
Additions to Net Property and Equipment	34				403				34	403		1,358
Operating Segments [Member] | Egypt [Member]
Segment Reporting Information [Line Items]
Oil and gas production revenues									2,057	2,095		3,643
Lease operating expenses									446	522		499
Gathering and transportation									44	45		40
Taxes other than income									0	9		11
Depreciation, depletion, and amortization									778	927		872
Exploration									48	154		112
Impairments									1	1,255		173
Operating Income (Loss)									740	(817)		1,936
Other Income (Expense):
Net property and equipment	3,362				3,712				3,362	3,712		5,141
Total Assets	4,893				6,165				4,893	6,165		6,926
Additions to Net Property and Equipment	459				862				459	862		1,293
Operating Segments [Member] | North Sea [Member]
Segment Reporting Information [Line Items]
Oil and gas production revenues									970	1,280		2,316
Lease operating expenses									314	349		434
Gathering and transportation									8	9		17
Taxes other than income									(33)	63		185
Depreciation, depletion, and amortization									519	514		807
Exploration									37	237		119
Asset retirement obligation accretion									75	74		72
Impairments									655	211		1,895
Operating Income (Loss)									(605)	(177)		(1,213)
Other Income (Expense):
Net property and equipment	2,834				3,263				2,834	3,263		3,300
Total Assets	3,584				4,280				3,584	4,280		4,480
Additions to Net Property and Equipment	260				715				260	715		1,060
Corporate, Non-Segment [Member]
Segment Reporting Information [Line Items]
Depreciation, depletion, and amortization												0
Exploration									15	4		(7)
Impairments									0	147
Operating Income (Loss)									(15)	(151)		7
Other Income (Expense):
Net property and equipment	39				36				39	36		9
Total Assets	48				48				48	48		544
Additions to Net Property and Equipment	$ 2				$ 27				$ 2	$ 27		$ 8

[1] Financial information for 2015 and 2014 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

[2] Financial information for 2015 and 2014 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

XML

Supplemental Oil and Gas Disclosures (Unaudited) - Revenue and Direct Cost Information Relating to Company's Oil and Gas Exploration and Production Activities (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015		Dec. 31, 2014
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Oil and gas production revenues	$ 5,367	$ 6,510	[1]	$ 12,795	[1]
Depreciation, depletion, and amortization	2,460	2,976		4,195
Asset retirement obligation accretion	156	145	[1],[2]	154	[1],[2]
Lease operating expenses	1,494	1,854	[1]	2,238	[1]
Gathering and transportation	200	211	[1]	273	[1]
Exploration expenses	473	2,771		2,499
Impairments related to oil and gas properties	427	7,389		6,068
Production taxes	120	259		546
Income tax	148	(3,049)		(1,070)
Oil and gas properties production expense	5,478	12,556		14,903
Results of operation	(111)	(6,046)		(2,108)
United States [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Oil and gas production revenues	1,997	2,637		5,744
Depreciation, depletion, and amortization	1,055	1,455		2,294
Asset retirement obligation accretion	34	28		43
Lease operating expenses	553	739		921
Gathering and transportation	80	68		93
Exploration expenses	285	2,145		2,113
Impairments related to oil and gas properties	61	6,154		2,372
Production taxes	135	178		342
Income tax	(72)	(2,886)		(864)
Oil and gas properties production expense	2,131	7,881		7,314
Results of operation	(134)	(5,244)		(1,570)
Canada [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Oil and gas production revenues	343	498		1,092
Depreciation, depletion, and amortization	174	251		382
Asset retirement obligation accretion	47	43		39
Lease operating expenses	181	244		384
Gathering and transportation	68	89		123
Exploration expenses	88	231		162
Impairments related to oil and gas properties	366	1,031		1,645
Production taxes	18	23		27
Income tax	(162)	(369)		(421)
Oil and gas properties production expense	780	1,543		2,341
Results of operation	(437)	(1,045)		(1,249)
Egypt [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Oil and gas production revenues	2,057	2,095		3,643
Depreciation, depletion, and amortization	733	780		735
Lease operating expenses	446	522		499
Gathering and transportation	44	45		40
Exploration expenses	48	154		112
Impairments related to oil and gas properties	0	193		173
Income tax	354	180		938
Oil and gas properties production expense	1,625	1,874		2,497
Results of operation	432	221		1,146
North Sea [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Oil and gas production revenues	970	1,280		2,316
Depreciation, depletion, and amortization	498	490		784
Asset retirement obligation accretion	75	74		72
Lease operating expenses	314	349		434
Gathering and transportation	8	9		17
Exploration expenses	37	237		119
Impairments related to oil and gas properties	0	11		1,878
Production taxes	(33)	58		177
Income tax	28	26		(723)
Oil and gas properties production expense	927	1,254		2,758
Results of operation	43	26		(442)
Other International [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Exploration expenses	15	4		(7)
Oil and gas properties production expense	15	4		(7)
Results of operation	$ (15)	$ (4)		$ 7

[1] Financial information for 2015 and 2014 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

[2] Financial information for 2015 and 2014 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

XML

Supplemental Oil and Gas Disclosures (Unaudited) - Costs Incurred in Oil and Gas Property Acquisitions, Exploration and Development Activities (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved	$ 45	$ 38	$ 113
Unproved	170	336	1,378
Exploration	470	677	1,049
Development	950	3,198	8,941
Costs incurred	1,635	4,249	11,481
Capitalized interest	48	21	148
Asset retirement costs	(192)	65	307
United States [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved	0	1	102
Unproved	110	313	1,221
Exploration	278	194	505
Development	420	1,729	5,078
Costs incurred	808	2,237	6,906
Capitalized interest	21	0	17
Asset retirement costs	(51)	123	43
Canada [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved	1	8
Unproved	7	23	141
Exploration	23	51	93
Development	27	151	789
Costs incurred	58	233	1,023
Capitalized interest	6
Asset retirement costs	(13)	8	175
Egypt [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved	6	29	11
Unproved	49	0	0
Exploration	67	125	207
Development	353	741	1,122
Costs incurred	475	895	1,340
Capitalized interest	0	8	9
Australia [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved	0	0
Unproved		0	16
Exploration	0	32	131
Development	0	98	990
Costs incurred	0	130	1,137
Capitalized interest	0	6	90
Asset retirement costs		0	55
North Sea [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved	38		0
Unproved	4		0
Exploration	84	246	103
Development	150	479	956
Costs incurred	276	725	1,059
Capitalized interest	21	7	29
Asset retirement costs	(128)	(66)	34
Argentina [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Unproved			0
Exploration		0	9
Development		0	6
Costs incurred		0	15
Capitalized interest		0	3
Asset retirement costs			0
Other International [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Exploration	18	29	1
Costs incurred	$ 18	$ 29	$ 1

XML

Supplemental Oil and Gas Disclosures (Unaudited) - Capitalized Costs (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Reserve Quantities [Line Items]
Proved properties	$ 42,693	$ 41,728	[1]
Unproved properties	1,969	2,277	[1]
Capitalized costs, gross	44,662	44,005
Accumulated DD&A	(26,972)	(24,457)
Capitalized costs, net	17,690	19,548
United States [Member]
Reserve Quantities [Line Items]
Proved properties	19,170	18,692
Unproved properties	1,465	1,615
Capitalized costs, gross	20,635	20,307
Accumulated DD&A	(10,034)	(9,027)
Capitalized costs, net	10,601	11,280
Canada [Member]
Reserve Quantities [Line Items]
Proved properties	5,434	5,812
Unproved properties	109	172
Capitalized costs, gross	5,543	5,984
Accumulated DD&A	(4,120)	(3,958)
Capitalized costs, net	1,423	2,026
Egypt [Member]
Reserve Quantities [Line Items]
Proved properties	10,169	9,798
Unproved properties	76	25
Capitalized costs, gross	10,245	9,823
Accumulated DD&A	(7,287)	(6,559)
Capitalized costs, net	2,958	3,264
North Sea [Member]
Reserve Quantities [Line Items]
Proved properties	7,920	7,426
Unproved properties	280	429
Capitalized costs, gross	8,200	7,855
Accumulated DD&A	(5,531)	(4,913)
Capitalized costs, net	2,669	2,942
Other International [Member]
Reserve Quantities [Line Items]
Proved properties	0	0
Unproved properties	39	36
Capitalized costs, gross	39	36
Accumulated DD&A	0	0
Capitalized costs, net	$ 39	$ 36

[1] Financial information for 2015 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

XML

Supplemental Oil and Gas Disclosures (Unaudited) - Oil and Gas Reserve Information (Detail)	12 Months Ended
	Dec. 31, 2016 MBoe MMcf MBbls	Dec. 31, 2015 MBoe MMcf MBbls	Dec. 31, 2014 MBoe MMcf MBbls	Dec. 31, 2013 MBoe MMcf MBbls
Reserve Quantities [Line Items]
Proved developed reserves	1,173,635	1,331,397	1,651,291	1,832,936
Proved undeveloped reserves	137,616	232,336	744,979	813,480
Beginning balance	1,563,733	2,396,270	2,646,416
Extensions, discoveries and other additions	103,204	117,405	313,095
Purchase of minerals in-place	1,580	6,860	21,712
Revisions of previous estimates	(159,341)	(365,135)	14,150
Production	(190,942)	(206,840)	(241,577)
Sale of properties	(6,983)	(384,827)	(357,526)
Ending balance	1,311,251	1,563,733	2,396,270
Egypt [Member]
Reserve Quantities [Line Items]
Proved developed reserves	252,630	275,033	236,256	222,880
Proved undeveloped reserves	27,336	26,929	43,446	48,028
Beginning balance	301,962	279,702	270,908
Extensions, discoveries and other additions	23,674	40,464	60,877
Revisions of previous estimates	16,599	37,825	5,522
Production	(62,269)	(56,029)	(57,605)
Ending balance	279,966	301,962	279,702
United States [Member]
Reserve Quantities [Line Items]
Proved developed reserves	656,087	726,424	897,422	976,795
Proved undeveloped reserves	76,950	120,210	336,670	370,566
Beginning balance	846,634	1,234,092	1,347,361
Extensions, discoveries and other additions	56,458	26,488	138,413
Purchase of minerals in-place	24		21,712
Revisions of previous estimates	(87,954)	(322,123)	11,662
Production	(81,994)	(91,591)	(106,225)
Sale of properties	(131)	(232)	(178,831)
Ending balance	733,037	846,634	1,234,092
Canada [Member]
Reserve Quantities [Line Items]
Proved developed reserves	157,662	209,647	258,848	322,362
Proved undeveloped reserves	17,931	70,300	155,028	139,509
Beginning balance	279,947	413,876	461,871
Extensions, discoveries and other additions	9,166	26,226	74,666
Purchase of minerals in-place		6,860
Revisions of previous estimates	(84,984)	(87,081)	(2,800)
Production	(21,684)	(24,706)	(28,313)
Sale of properties	(6,852)	(55,228)	(91,548)
Ending balance	175,593	279,947	413,876
Australia [Member]
Reserve Quantities [Line Items]
Proved developed reserves			136,707	126,948
Proved undeveloped reserves			186,534	199,240
Beginning balance	0	323,241	326,188
Extensions, discoveries and other additions			17,780
Revisions of previous estimates	0	12,549	(216)
Production	0	(8,503)	(20,511)
Sale of properties	0	(327,287)
Ending balance		0	323,241
North Sea [Member]
Reserve Quantities [Line Items]
Proved developed reserves	107,256	120,293	122,058	117,457
Proved undeveloped reserves	15,399	14,897	23,301	32,633
Beginning balance	135,190	145,359	150,090
Extensions, discoveries and other additions	13,906	24,227	21,354
Purchase of minerals in-place	1,556
Revisions of previous estimates	(3,002)	(6,305)	(18)
Production	(24,995)	(26,011)	(26,067)
Sale of properties	0	(2,080)
Ending balance	122,655	135,190	145,359
Argentina [Member]
Reserve Quantities [Line Items]
Proved developed reserves				66,494
Proved undeveloped reserves				23,504
Beginning balance			89,998
Extensions, discoveries and other additions			5
Revisions of previous estimates			0
Production			(2,856)
Sale of properties			(87,147)
Crude Oil and Condensate [Member]
Reserve Quantities [Line Items]
Proved developed reserves	582,317	665,063	784,770	794,795
Proved undeveloped reserves	59,965	127,996	289,499	336,690
Beginning balance	793,059	1,074,269	1,131,485
Extensions, discoveries and other additions	40,351	59,556	126,387
Purchase of minerals in-place	459	1,763	15,240
Revisions of previous estimates	(88,714)	(165,609)	4,693
Production	(100,744)	(108,491)	(118,412)
Sale of properties	(2,129)	(68,429)	(85,124)
Ending balance	642,282	793,059	1,074,269
Crude Oil and Condensate [Member] | Egypt [Member]
Reserve Quantities [Line Items]
Proved developed reserves	138,771	144,164	128,712	119,242
Proved undeveloped reserves	20,187	17,856	14,617	16,302
Beginning balance	162,020	143,329	135,544
Extensions, discoveries and other additions	17,599	24,524	38,074
Revisions of previous estimates	17,301	27,330	2,645
Production	(37,962)	(33,163)	(32,934)
Ending balance	158,958	162,020	143,329
Crude Oil and Condensate [Member] | United States [Member]
Reserve Quantities [Line Items]
Proved developed reserves	300,900	348,797	444,440	457,981
Proved undeveloped reserves	21,088	60,505	170,125	195,835
Beginning balance	409,302	614,565	653,816
Extensions, discoveries and other additions	9,614	13,903	57,011
Purchase of minerals in-place	21		15,240
Revisions of previous estimates	(58,882)	(173,907)	3,083
Production	(38,000)	(45,138)	(48,789)
Sale of properties	(67)	(121)	(65,796)
Ending balance	321,988	409,302	614,565
Crude Oil and Condensate [Member] | Canada [Member]
Reserve Quantities [Line Items]
Proved developed reserves	51,508	67,847	75,876	80,526
Proved undeveloped reserves	7,906	38,326	59,923	56,366
Beginning balance	106,173	135,799	136,892
Extensions, discoveries and other additions	3,372	4,550	9,657
Purchase of minerals in-place		1,763
Revisions of previous estimates	(43,282)	(27,966)	(812)
Production	(4,787)	(5,755)	(6,421)
Sale of properties	(2,062)	(2,218)	(3,517)
Ending balance	59,414	106,173	135,799
Crude Oil and Condensate [Member] | Australia [Member]
Reserve Quantities [Line Items]
Proved developed reserves			29,996	22,524
Proved undeveloped reserves			25,775	36,703
Beginning balance		55,771	59,227
Extensions, discoveries and other additions		0	4,254
Revisions of previous estimates		11,189	(216)
Production		(2,778)	(7,494)
Sale of properties		(64,182)
Ending balance			55,771
Crude Oil and Condensate [Member] | North Sea [Member]
Reserve Quantities [Line Items]
Proved developed reserves	91,138	104,255	105,746	100,327
Proved undeveloped reserves	10,784	11,309	19,059	29,253
Beginning balance	115,564	124,805	129,580
Extensions, discoveries and other additions	9,766	16,579	17,386
Purchase of minerals in-place	438
Revisions of previous estimates	(3,851)	(2,255)	(7)
Production	(19,995)	(21,657)	(22,154)
Sale of properties		(1,908)
Ending balance	101,922	115,564	124,805
Crude Oil and Condensate [Member] | Argentina [Member]
Reserve Quantities [Line Items]
Proved developed reserves				14,195
Proved undeveloped reserves				2,231
Beginning balance			16,426
Extensions, discoveries and other additions			5
Production			(620)
Sale of properties			(15,811)
Natural Gas Liquids [Member]
Reserve Quantities [Line Items]
Proved developed reserves	171,883	168,786	204,628	217,129
Proved undeveloped reserves	20,561	30,151	77,579	74,732
Beginning balance	198,937	282,207	291,861
Extensions, discoveries and other additions	11,872	8,074	50,500
Purchase of minerals in-place	7	976	2,916
Revisions of previous estimates	5,627	(69,178)	2,697
Production	(22,942)	(22,721)	(24,595)
Sale of properties	(1,057)	(421)	(41,172)
Ending balance	192,444	198,937	282,207
Natural Gas Liquids [Member] | Egypt [Member]
Reserve Quantities [Line Items]
Proved developed reserves	1,266	1,491	1,346
Proved undeveloped reserves	131	78	212
Beginning balance	1,569	1,558
Extensions, discoveries and other additions	208	144	1,820
Revisions of previous estimates	17	255	(11)
Production	(397)	(388)	(251)
Ending balance	1,397	1,569	1,558
Natural Gas Liquids [Member] | United States [Member]
Reserve Quantities [Line Items]
Proved developed reserves	155,124	150,265	183,565	184,485
Proved undeveloped reserves	17,311	24,939	69,828	63,538
Beginning balance	175,204	253,393	248,023
Extensions, discoveries and other additions	10,238	5,768	47,516
Purchase of minerals in-place	2		2,916
Revisions of previous estimates	6,824	(64,226)	2,594
Production	(19,824)	(19,684)	(21,464)
Sale of properties	(9)	(47)	(26,192)
Ending balance	172,435	175,204	253,393
Natural Gas Liquids [Member] | Canada [Member]
Reserve Quantities [Line Items]
Proved developed reserves	13,866	15,246	17,947	26,099
Proved undeveloped reserves	2,473	4,839	7,168	9,970
Beginning balance	20,085	25,115	36,069
Extensions, discoveries and other additions	755	1,473	1,163
Purchase of minerals in-place		976
Revisions of previous estimates	(1,355)	(4,886)	116
Production	(2,098)	(2,236)	(2,256)
Sale of properties	(1,048)	(357)	(9,977)
Ending balance	16,339	20,085	25,115
Natural Gas Liquids [Member] | North Sea [Member]
Reserve Quantities [Line Items]
Proved developed reserves	1,627	1,784	1,770	2,435
Proved undeveloped reserves	646	295	371	215
Beginning balance	2,079	2,141	2,650
Extensions, discoveries and other additions	671	689	1
Purchase of minerals in-place	5
Revisions of previous estimates	141	(321)	(2)
Production	(623)	(413)	(508)
Sale of properties		(17)
Ending balance	2,273	2,079	2,141
Natural Gas Liquids [Member] | Argentina [Member]
Reserve Quantities [Line Items]
Proved developed reserves				4,110
Proved undeveloped reserves				1,009
Beginning balance			5,119
Production			(116)
Sale of properties			(5,003)
Natural Gas [Member]
Reserve Quantities [Line Items]
Proved developed reserves | MMcf	2,516,610	2,985,290	3,971,360	4,926,064
Proved undeveloped reserves | MMcf	342,538	445,132	2,267,400	2,412,348
Beginning balance | MMcf	3,430,422	6,238,760	7,338,412
Extensions, discoveries and other additions | MMcf	305,883	298,649	817,253
Purchase of minerals in-place | MMcf	6,684	24,727	21,337
Revisions of previous estimates | MMcf	(457,524)	(782,083)	40,556
Production | MMcf	(403,533)	(453,772)	(591,420)
Sale of properties | MMcf	(22,784)	(1,895,859)	(1,387,378)
Ending balance | MMcf	2,859,148	3,430,422	6,238,760
Natural Gas [Member] | Egypt [Member]
Reserve Quantities [Line Items]
Proved developed reserves | MMcf	675,559	776,263	637,187	621,825
Proved undeveloped reserves | MMcf	42,109	53,969	171,696	190,355
Beginning balance | MMcf	830,232	808,883	812,180
Extensions, discoveries and other additions | MMcf	35,202	94,777	125,899
Revisions of previous estimates | MMcf	(4,305)	61,442	17,326
Production | MMcf	(143,461)	(134,870)	(146,522)
Ending balance | MMcf	717,668	830,232	808,883
Natural Gas [Member] | United States [Member]
Reserve Quantities [Line Items]
Proved developed reserves | MMcf	1,200,379	1,364,174	1,616,504	2,005,966
Proved undeveloped reserves | MMcf	231,304	208,594	580,299	667,160
Beginning balance | MMcf	1,572,768	2,196,803	2,673,126
Extensions, discoveries and other additions | MMcf	219,633	40,901	203,318
Purchase of minerals in-place | MMcf	7		21,337
Revisions of previous estimates | MMcf	(215,378)	(503,939)	35,910
Production | MMcf	(145,019)	(160,614)	(215,829)
Sale of properties | MMcf	(328)	(383)	(521,059)
Ending balance | MMcf	1,431,683	1,572,768	2,196,803
Natural Gas [Member] | Canada [Member]
Reserve Quantities [Line Items]
Proved developed reserves | MMcf	553,724	759,321	990,145	1,294,420
Proved undeveloped reserves | MMcf	45,312	162,809	527,623	439,037
Beginning balance | MMcf	922,130	1,517,768	1,733,457
Extensions, discoveries and other additions | MMcf	30,234	121,216	383,077
Purchase of minerals in-place | MMcf		24,727
Revisions of previous estimates | MMcf	(242,080)	(325,375)	(12,626)
Production | MMcf	(88,792)	(100,289)	(117,816)
Sale of properties | MMcf	(22,456)	(315,917)	(468,324)
Ending balance | MMcf	599,036	922,130	1,517,768
Natural Gas [Member] | Australia [Member]
Reserve Quantities [Line Items]
Proved developed reserves | MMcf			640,265	626,543
Proved undeveloped reserves | MMcf			964,554	975,224
Beginning balance | MMcf		1,604,819	1,601,767
Extensions, discoveries and other additions | MMcf			81,156
Revisions of previous estimates | MMcf		8,162
Production | MMcf		(34,352)	(78,104)
Sale of properties | MMcf		(1,578,629)
Ending balance | MMcf			1,604,819
Natural Gas [Member] | North Sea [Member]
Reserve Quantities [Line Items]
Proved developed reserves | MMcf	86,948	85,532	87,259	88,177
Proved undeveloped reserves | MMcf	23,813	19,760	23,228	18,988
Beginning balance | MMcf	105,292	110,487	107,165
Extensions, discoveries and other additions | MMcf	20,814	41,755	23,803
Purchase of minerals in-place | MMcf	6,677
Revisions of previous estimates | MMcf	4,239	(22,373)	(54)
Production | MMcf	(26,261)	(23,647)	(20,427)
Sale of properties | MMcf		(930)
Ending balance | MMcf	110,761	105,292	110,487
Natural Gas [Member] | Argentina [Member]
Reserve Quantities [Line Items]
Proved developed reserves | MMcf				289,133
Proved undeveloped reserves | MMcf				121,584
Beginning balance | MMcf			410,717
Production | MMcf			(12,722)
Sale of properties | MMcf			(397,995)
Noncontrolling Interest [Member] | Egypt [Member]
Reserve Quantities [Line Items]
Proved developed reserves (Energy) | MBoe	93,322	101,000	93,000	90,000
Noncontrolling Interest [Member] | Crude Oil and Condensate [Member] | Egypt [Member]
Reserve Quantities [Line Items]
Proved developed reserves	52,986	54,007	47,776	45,181
Noncontrolling Interest [Member] | Natural Gas Liquids [Member] | Egypt [Member]
Reserve Quantities [Line Items]
Proved developed reserves	466	523	519
Noncontrolling Interest [Member] | Natural Gas [Member] | Egypt [Member]
Reserve Quantities [Line Items]
Proved developed reserves | MMcf	239,223	277	270	271

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Supplemental Oil and Gas Disclosures (Unaudited) - Future Net Cash Flows (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Cash inflows	$ 37,204	$ 52,073
Production costs	(15,662)	(21,413)
Development costs	(6,739)	(8,055)
Income tax expense	(1,815)	(3,080)
Net cash flows	12,988	19,525
10 percent discount rate	(4,928)	(8,931)
Discounted future net cash flows	$ 8,060	10,594
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	$ 9,500	13,100
Egypt [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Cash inflows	8,778	11,124
Production costs	(1,967)	(2,185)
Development costs	(1,111)	(1,515)
Income tax expense	(1,775)	(2,326)
Net cash flows	3,925	5,098
10 percent discount rate	(956)	(1,330)
Discounted future net cash flows	2,969	3,768
United States [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Cash inflows	20,067	26,610
Production costs	(8,858)	(12,178)
Development costs	(1,653)	(2,255)
Income tax expense	(32)	(63)
Net cash flows	9,524	12,114
10 percent discount rate	(5,319)	(6,876)
Discounted future net cash flows	4,205	5,238
Canada [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Cash inflows	3,625	7,345
Production costs	(2,582)	(3,841)
Development costs	(1,565)	(1,939)
Net cash flows	(522)	1,565
10 percent discount rate	549	(868)
Discounted future net cash flows	27	697
North Sea [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Cash inflows	4,734	6,994
Production costs	(2,255)	(3,209)
Development costs	(2,410)	(2,346)
Income tax expense	(8)	(691)
Net cash flows	61	748
10 percent discount rate	798	143
Discounted future net cash flows	859	891
Noncontrolling Interest [Member] | Egypt [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Discounted future net cash flows	$ 1,000	$ 1,300

XML

Supplemental Oil and Gas Disclosures (Unaudited) - Principal Sources of Change In Discounted Future Net Cash Flows (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Extractive Industries [Abstract]
Sales, net of production costs	$ (3,479)	$ (4,056)	$ (10,350)
Net change in prices and production costs	(3,835)	(21,710)	(1,029)
Discoveries and improved recovery, net of related costs	1,153	1,953	6,297
Change in future development costs	309	705	(1,136)
Previously estimated development costs incurred during the period	986	1,991	4,462
Revision of quantities	(574)	(2,292)	256
Purchases of minerals in-place	8	22	508
Accretion of discount	1,313	3,642	4,442
Change in income taxes	1,070	7,264	836
Sales of properties	(52)	(5,240)	(4,780)
Change in production rates and other	567	(3,343)	(442)
Change in the discounted future net cash flows, Total	$ (2,534)	$ (21,064)	$ (936)

XML

Supplemental Oil and Gas Disclosures (Unaudited) - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2016 MMBoe MBbls	Dec. 31, 2015 MBbls	Dec. 31, 2014 MBbls
Reserve Quantities [Line Items]
Purchases of minerals in-place	2
Sale of minerals in-place through divestiture transactions	7
Extensions, discoveries and other additions | MMBoe	103
Combined downward revisions of previously estimated reserves	159
Changes in reserves accounted	(159,341)	(365,135)	14,150
Percentage of estimated proved developed reserves classified as proved not producing	9.00%
North America [Member]
Reserve Quantities [Line Items]
Extensions, discoveries and other additions | MMBoe	66
Premian Basin [Member]
Reserve Quantities [Line Items]
Extensions, discoveries and other additions | MMBoe	49
Canada [Member]
Reserve Quantities [Line Items]
Extensions, discoveries and other additions | MMBoe	9
Changes in reserves accounted	(84,984)	(87,081)	(2,800)
MidContinent Region [Member]
Reserve Quantities [Line Items]
Extensions, discoveries and other additions | MMBoe	8
Egypt [Member]
Reserve Quantities [Line Items]
Extensions, discoveries and other additions | MMBoe	23
Changes in reserves accounted	16,599	37,825	5,522
North Sea [Member]
Reserve Quantities [Line Items]
Extensions, discoveries and other additions | MMBoe	14
Changes in reserves accounted	(3,002)	(6,305)	(18)
Australia [Member]
Reserve Quantities [Line Items]
Changes in reserves accounted	0	12,549	(216)
International Regions [Member]
Reserve Quantities [Line Items]
Extensions, discoveries and other additions | MMBoe	37
Changes in Product Prices [Member]
Reserve Quantities [Line Items]
Changes in reserves accounted	172
Changes in Lease Ownership [Member]
Reserve Quantities [Line Items]
Changes in reserves accounted	6
Changes in Engineering and Performance [Member]
Reserve Quantities [Line Items]
Changes in reserves accounted	19

XML

Supplemental Quarterly Financial Data (Unaudited) - Supplemental Quarterly Financial Data (Detail) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015		Dec. 31, 2014	[1]
Quarterly Financial Information Disclosure [Abstract]
Revenues and other	$ 1,451	$ 1,433	$ 1,365	$ 1,084	$ 1,405	$ 1,531	$ 2,019	$ 1,653	$ 5,333	$ 6,608
Gain (loss) on divestiture	0	5	17	(1)	77	(5)	227	(18)	21	281	[1],[2]	$ (1,608)	[2]
Expenses	1,594	1,964	1,582	1,454	6,537	5,645	3,163	2,703	6,594	18,048
Net loss from continuing operations including noncontrolling interest	(143)	(526)	(200)	(371)	(5,055)	(4,119)	(917)	(1,068)	(1,240)	(11,159)	[1]	(6,312)
Net income (loss) from discontinued operations, net of tax	0	(33)	0	0	627	(17)	120	(238)	(33)	492	[1]	(1,707)
NET LOSS INCLUDING NONCONTROLLING INTEREST	(143)	(559)	(200)	(371)	(4,428)	(4,136)	(797)	(1,306)	(1,273)	(10,667)	[1],[2],[3],[4]	(8,019)	[2],[3],[4]
Net income (loss) attributable to common stock	$ (182)	$ (607)	$ (244)	$ (372)	$ (4,015)	$ (4,143)	$ (860)	$ (1,334)	$ (1,405)	$ (10,352)	[1]	$ (8,360)
Basic and diluted net loss per common share:
Basic and diluted net loss from continuing operations per share	$ (0.48)	$ (1.51)	$ (0.65)	$ (0.98)	$ (12.28)	$ (10.91)	$ (2.60)	$ (2.91)	$ (3.62)	$ (28.70)	[1]	$ (17.32)
Basic and diluted net income (loss) from discontinued operations per share	0.00	(0.09)	0.00	0.00	1.66	(0.04)	0.32	(0.63)	(0.09)	1.30	[1]	(4.44)
Basic and diluted net loss per share	$ (0.48)	$ (1.60)	$ (0.65)	$ (0.98)	$ (10.62)	$ (10.95)	$ (2.28)	$ (3.54)	$ (3.71)	$ (27.40)	[1]	$ (21.76)
Asset impairments	$ 144	$ 951	$ 238	$ 42	$ 5,100	$ 4,100	$ 660	$ 2,100	$ 1,103	$ 9,472	[1],[2]	$ 7,102	[2]

[1] Financial information for 2015 and 2014 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

[2] Financial information for 2015 and 2014 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

[3] Financial information for 2015 and 2014 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

[4] Financial information for 2015, 2014, and 2013 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

XML

Supplemental Guarantor Information - Additional Information (Detail) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 1999
Condensed Financial Statements, Captions [Line Items]
Equity ownership percentage	100.00%
Notes Due 2029 [Member]
Condensed Financial Statements, Captions [Line Items]
Publicly traded notes		$ 300

XML

Supplemental Guarantor Information - Supplemental Condensed Consolidating Statement of Operations and Comprehensive Income (Detail) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015		Dec. 31, 2014
REVENUES AND OTHER:
Oil and gas production revenues									$ 5,367	$ 6,510	[1]	$ 12,795	[1]
Other									(34)	98	[1]	285	[1]
Gain (loss) on divestiture	$ 0	$ 5	$ 17	$ (1)	$ 77	$ (5)	$ 227	$ (18)	21	281	[1],[2]	(1,608)	[1],[2]
Total revenues and other									5,354	6,889	[1]	11,472	[1]
OPERATING EXPENSES:
Lease operating expenses									1,494	1,854	[1]	2,238	[1]
Gathering and transportation									200	211	[1]	273	[1]
Taxes other than income									126	282	[1]	577	[1]
Exploration									473	2,771	[1]	2,499	[1]
General and administrative									410	380	[1]	453	[1]
Depreciation, depletion, and amortization									2,618	3,300	[2]	4,526	[2]
Asset retirement obligation accretion									156	145	[1],[2]	154	[1],[2]
Asset impairments	144	951	238	42	5,100	4,100	660	2,100	1,103	9,472	[1],[2]	7,102	[1],[2]
Transaction, reorganization, and separation									39	132	[1]	67	[1]
Financing costs, net									417	511		413
Total operating expenses									7,036	19,058		18,302
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAXES									(1,682)	(12,169)	[1]	(6,830)	[1]
Provision (benefit) for income taxes									(442)	(1,010)		(518)
Net loss from continuing operations including noncontrolling interest	(143)	(526)	(200)	(371)	(5,055)	(4,119)	(917)	(1,068)	(1,240)	(11,159)	[1]	(6,312)	[1]
Net income (loss) from discontinued operations, net of tax	0	(33)	0	0	627	(17)	120	(238)	(33)	492	[1]	(1,707)	[1]
NET LOSS INCLUDING NONCONTROLLING INTEREST	(143)	(559)	(200)	(371)	(4,428)	(4,136)	(797)	(1,306)	(1,273)	(10,667)	[1],[2],[3],[4]	(8,019)	[1],[2],[3],[4]
Net income attributable to noncontrolling interest									132	(315)	[1]	341	[1]
Net income (loss) attributable to common shareholders	$ (182)	$ (607)	$ (244)	$ (372)	$ (4,015)	$ (4,143)	$ (860)	$ (1,334)	(1,405)	(10,352)	[1]	(8,360)	[1]
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK									(1,398)	(10,355)	[3]	(8,361)	[3]
Reclassifications & Eliminations [Member]
REVENUES AND OTHER:
Equity in net income (loss) of affiliates									748	5,937		4,607
Other									(1)	19		5
Total revenues and other									747	5,956		4,612
OPERATING EXPENSES:
General and administrative									(1)	19		5
Total operating expenses									(1)	19		5
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAXES									748	5,937		4,607
Net loss from continuing operations including noncontrolling interest									748	5,937		4,607
NET LOSS INCLUDING NONCONTROLLING INTEREST									748	5,937		4,607
Net income (loss) attributable to common shareholders									748	5,937		4,607
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK									748	5,937		4,607
Apache Corporation [Member]
REVENUES AND OTHER:
Oil and gas production revenues									1,035	1,446		3,399
Equity in net income (loss) of affiliates									(575)	(5,254)		(3,489)
Other									15	(71)		375
Gain (loss) on divestiture									2	36		(1,031)
Total revenues and other									477	(3,843)		(746)
OPERATING EXPENSES:
Lease operating expenses									285	399		509
Gathering and transportation									33	35		58
Taxes other than income									76	103		206
Exploration									258	2,096		1,966
General and administrative									344	296		370
Depreciation, depletion, and amortization									618	966		1,493
Asset retirement obligation accretion									18	15		31
Asset impairments									80	3,885		1,626
Transaction, reorganization, and separation									39	132		67
Financing costs, net									256	475		372
Total operating expenses									2,007	8,402		6,698
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAXES									(1,530)	(12,245)		(7,444)
Provision (benefit) for income taxes									(158)	(2,065)		789
Net loss from continuing operations including noncontrolling interest									(1,372)	(10,180)		(8,233)
Net income (loss) from discontinued operations, net of tax									(33)	(172)		(127)
NET LOSS INCLUDING NONCONTROLLING INTEREST									(1,405)	(10,352)		(8,360)
Net income (loss) attributable to common shareholders									(1,405)	(10,352)		(8,360)
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK									(1,398)	(10,355)		(8,361)
Apache Finance Canada [Member]
REVENUES AND OTHER:
Equity in net income (loss) of affiliates									(173)	(740)		(1,191)
Other									(19)	54		55
Total revenues and other									(192)	(686)		(1,136)
OPERATING EXPENSES:
Financing costs, net									(27)	(14)		(24)
Total operating expenses									(27)	(14)		(24)
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAXES									(165)	(672)		(1,112)
Provision (benefit) for income taxes									8	11		6
Net loss from continuing operations including noncontrolling interest									(173)	(683)		(1,118)
NET LOSS INCLUDING NONCONTROLLING INTEREST									(173)	(683)		(1,118)
Net income (loss) attributable to common shareholders									(173)	(683)		(1,118)
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK									(173)	(683)		(1,118)
All Other Subsidiaries of Apache Corporation [Member]
REVENUES AND OTHER:
Oil and gas production revenues									4,332	5,064		9,396
Equity in net income (loss) of affiliates									0	57		73
Other									(29)	96		(150)
Gain (loss) on divestiture									19	245		(577)
Total revenues and other									4,322	5,462		8,742
OPERATING EXPENSES:
Lease operating expenses									1,209	1,455		1,729
Gathering and transportation									167	176		215
Taxes other than income									50	179		371
Exploration									215	675		533
General and administrative									67	65		78
Depreciation, depletion, and amortization									2,000	2,334		3,033
Asset retirement obligation accretion									138	130		123
Asset impairments									1,023	5,587		5,476
Financing costs, net									188	50		65
Total operating expenses									5,057	10,651		11,623
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAXES									(735)	(5,189)		(2,881)
Provision (benefit) for income taxes									(292)	1,044		(1,313)
Net loss from continuing operations including noncontrolling interest									(443)	(6,233)		(1,568)
Net income (loss) from discontinued operations, net of tax									0	664		(1,580)
NET LOSS INCLUDING NONCONTROLLING INTEREST									(443)	(5,569)		(3,148)
Net income attributable to noncontrolling interest									132	(315)		341
Net income (loss) attributable to common shareholders									(575)	(5,254)		(3,489)
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK									$ (575)	$ (5,254)		$ (3,489)

[1] Financial information for 2015 and 2014 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

[2] Financial information for 2015 and 2014 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

[3] Financial information for 2015 and 2014 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

[4] Financial information for 2015, 2014, and 2013 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

XML

Supplemental Guarantor Information - Supplemental Condensed Consolidating Statement of Cash Flows (Detail) - USD ($) $ in Millions			1 Months Ended		12 Months Ended
		Jun. 30, 2014	Dec. 31, 2014		Dec. 31, 2016		Dec. 31, 2015		Dec. 31, 2014
Condensed Financial Statements, Captions [Line Items]
CASH PROVIDED BY CONTINUING OPERATING ACTIVITIES					$ 2,453		$ 2,554	[1]	$ 7,013	[1]
CASH PROVIDED BY (USED IN) DISCONTINUED OPERATIONS					(23)		113	[1]	944	[1]
CASH PROVIDED BY OPERATING ACTIVITIES					2,430		2,667	[1]	7,957	[1]
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property					(1,610)		(4,208)		(8,608)
Additions to gas gathering, transmission, and processing facilities					(158)		(233)		(881)
Proceeds from sale of Kitimat LNG					0		854	[1]	0	[1]
Proceeds from sale of Yara Pilbara					0		391	[1]	0	[1]
Leasehold and property acquisitions					(181)		(367)	[1]	(1,475)	[1]
Proceeds from sale of oil and gas assets					134		268	[1]	470	[1]
Other					155		6	[1]	(299)	[1]
NET CASH USED IN CONTINUING INVESTING ACTIVITIES					(1,660)		(3,289)	[1]	(8,171)	[1]
NET CASH PROVIDED BY DISCONTINUED OPERATIONS					0		4,372	[1]	(219)	[1]
NET CASH USED IN INVESTING ACTIVITIES					(1,660)		1,083	[1]	(8,390)	[1]
CASH FLOWS FROM FINANCING ACTIVITIES:
Commercial paper, credit facility, and bank notes, net					0		(1,570)	[1]	1,568	[1]
Payments on fixed rate debt					(181)		(939)	[1]	0	[1]
Dividends paid					(379)		(377)	[1]	(365)	[1]
Distributions to noncontrolling interest					(293)		(129)	[1]	(140)	[1]
Shares repurchased					0		0	[1]	(1,864)	[1]
Other					(7)		53	[1]	49	[1]
NET CASH USED IN CONTINUING FINANCING ACTIVITIES					(860)		(2,962)	[1]	(752)	[1]
NET CASH USED IN DISCONTINUED OPERATIONS					0		0	[1]	(42)	[1]
NET CASH USED IN FINANCING ACTIVITIES					(860)		(2,962)	[1]	(794)	[1]
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS					(90)		788	[1]	(1,227)	[1]
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	[1]				1,467	[2]	679		1,906
CASH AND CASH EQUIVALENTS AT END OF PERIOD			$ 679	[1]	1,377		1,467	[1],[2]	679	[1]
Reclassifications & Eliminations [Member]
CASH FLOWS FROM INVESTING ACTIVITIES:
Investment in subsidiaries, net					(914)		(6,363)		(1,132)
NET CASH USED IN CONTINUING INVESTING ACTIVITIES							(6,363)		(1,132)
NET CASH USED IN INVESTING ACTIVITIES					(914)		(6,363)		(1,132)
CASH FLOWS FROM FINANCING ACTIVITIES:
Intercompany borrowings					914		6,363		1,144
Other							0		(12)
NET CASH USED IN CONTINUING FINANCING ACTIVITIES							6,363		1,132
NET CASH USED IN FINANCING ACTIVITIES					914		6,363		1,132
Apache Corporation [Member]
Condensed Financial Statements, Captions [Line Items]
CASH PROVIDED BY CONTINUING OPERATING ACTIVITIES					625		98		3,104
CASH PROVIDED BY OPERATING ACTIVITIES					625		98		3,104
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property					(813)		(1,500)		(4,364)
Additions to gas gathering, transmission, and processing facilities					(111)		(156)		(9)
Leasehold and property acquisitions					(108)		(313)		(1,475)
Proceeds from sale of oil and gas assets					88		163		15
Investment in subsidiaries, net					914		6,363		1,132
Other					(77)		(34)		(186)
NET CASH USED IN CONTINUING INVESTING ACTIVITIES							4,523		(2,265)
NET CASH USED IN INVESTING ACTIVITIES					(107)		4,523		(2,265)
CASH FLOWS FROM FINANCING ACTIVITIES:
Commercial paper, credit facility, and bank notes, net							(1,570)		1,570
Intercompany borrowings					0		(1,621)
Payments on fixed rate debt					(181)		(939)
Dividends paid					(379)		(377)		(365)
Shares repurchased									(1,864)
Other					8		(3)		(68)
NET CASH USED IN CONTINUING FINANCING ACTIVITIES							(4,510)		(727)
NET CASH USED IN FINANCING ACTIVITIES					(552)		(4,510)		(727)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS					(34)		111		112
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR					378		267		155
CASH AND CASH EQUIVALENTS AT END OF PERIOD			267		344		378		267
Apache Finance Canada [Member]
Condensed Financial Statements, Captions [Line Items]
CASH PROVIDED BY CONTINUING OPERATING ACTIVITIES					51		18		17
CASH PROVIDED BY OPERATING ACTIVITIES					51		18		17
CASH FLOWS FROM FINANCING ACTIVITIES:
Intercompany borrowings					(23)		(18)		8
Common stock activity, net					(28)
Other							0		(28)
NET CASH USED IN CONTINUING FINANCING ACTIVITIES							(18)		(20)
NET CASH USED IN FINANCING ACTIVITIES					(51)		(18)		(20)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS					0		0		(3)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR							0		3
CASH AND CASH EQUIVALENTS AT END OF PERIOD			0		0				0
All Other Subsidiaries of Apache Corporation [Member]
Condensed Financial Statements, Captions [Line Items]
CASH PROVIDED BY CONTINUING OPERATING ACTIVITIES					1,777		2,438		3,892
CASH PROVIDED BY (USED IN) DISCONTINUED OPERATIONS					(23)		113		944
CASH PROVIDED BY OPERATING ACTIVITIES					1,754		2,551		4,836
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property					(797)		(2,708)		(4,244)
Additions to gas gathering, transmission, and processing facilities					(47)		(77)		(872)
Proceeds from sale of Kitimat LNG							854
Proceeds from sale of Yara Pilbara							391
Leasehold and property acquisitions					(73)		(54)		0
Proceeds from sale of oil and gas assets					46		105		455
Other					232		40		(113)
NET CASH USED IN CONTINUING INVESTING ACTIVITIES							(1,449)		(4,774)
NET CASH PROVIDED BY DISCONTINUED OPERATIONS							4,372		(219)
NET CASH USED IN INVESTING ACTIVITIES					(639)		2,923		(4,993)
CASH FLOWS FROM FINANCING ACTIVITIES:
Commercial paper, credit facility, and bank notes, net							0		(2)
Intercompany borrowings					(891)		(4,724)		(1,152)
Distributions to noncontrolling interest					(293)		(129)		(140)
Common stock activity, net					28
Other					(15)		56		157
NET CASH USED IN CONTINUING FINANCING ACTIVITIES							(4,797)		(1,137)
NET CASH USED IN DISCONTINUED OPERATIONS									(42)
NET CASH USED IN FINANCING ACTIVITIES					(1,171)		(4,797)		(1,179)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS					(56)		677		(1,336)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR					1,089		412		1,748
CASH AND CASH EQUIVALENTS AT END OF PERIOD			412		1,033		1,089		412
Anadarko Basin and Southern Louisiana [Member]
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from sale of productive assets					0		0	[1]	1,262	[1]
Proceeds from sale of oil and gas assets			$ 1,300
Anadarko Basin and Southern Louisiana [Member] | Apache Corporation [Member]
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from sale of productive assets									1,262
Deepwater Gulf of Mexico [Member]
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from sale of productive assets					$ 0		$ 0	[1]	1,360	[1]
Proceeds from sale of oil and gas assets		$ 1,400
Deepwater Gulf of Mexico [Member] | Apache Corporation [Member]
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from sale of productive assets									$ 1,360

[1] Financial information for 2015 and 2014 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

[2] Financial information for 2015 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

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Supplemental Guarantor Information - Supplemental Condensed Consolidating Balance Sheet (Detail) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015		Dec. 31, 2014		Dec. 31, 2013
CURRENT ASSETS:
Cash and cash equivalents	$ 1,377	$ 1,467	[1],[2]	$ 679	[1]	$ 1,906	[1]
Receivables, net of allowance	1,128	1,253	[2]
Inventories	476	570	[2]
Drilling advances	81	172	[2]
Prepaid assets and other	179	290	[2]
Total current assets	3,241	3,752	[2]
PROPERTY AND EQUIPMENT, NET	18,867	20,838	[2]
OTHER ASSETS:
Deferred charges and other	411	910	[2]
Total assets	22,519	25,500	[2]
CURRENT LIABILITIES:
Accounts payable	585	618	[2]
Other current liabilities	1,258	1,223	[2]
Total current liabilities	1,843	1,841	[2]
Long-term debt	8,544	8,716	[2]
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes	1,710	2,529	[2]
Asset retirement obligation, non current	2,432	2,562	[2]
Other	311	362	[2]
Total deferred credits and other noncurrent liabilities	4,453	5,453	[2]
APACHE SHAREHOLDERS' EQUITY	6,238	7,888	[2]
Noncontrolling interest	1,441	1,602	[2]
TOTAL EQUITY	7,679	9,490	[2],[3]	20,541	[3]	30,756	[3]
Total liabilities and shareholders' equity	22,519	25,500	[2]
Reclassifications & Eliminations [Member]
CURRENT ASSETS:
Intercompany receivable	(5,038)	(5,212)
Total current assets	(5,038)	(5,212)
OTHER ASSETS:
Intercompany receivable	(12,152)	(10,744)
Equity in affiliates	(14,983)	(15,731)
Deferred charges and other	(1,000)	(1,000)
Total assets	(33,173)	(32,687)
CURRENT LIABILITIES:
Intercompany payable	(5,038)	(5,212)
Total current liabilities	(5,038)	(5,212)
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Intercompany payable	(12,152)	(10,744)
Other	(1,000)	(1,000)
Total deferred credits and other noncurrent liabilities	(13,152)	(11,744)
APACHE SHAREHOLDERS' EQUITY	(14,983)	(15,731)
TOTAL EQUITY	(14,983)	(15,731)
Total liabilities and shareholders' equity	(33,173)	(32,687)
Apache Corporation [Member]
CURRENT ASSETS:
Cash and cash equivalents	344	378		267		155
Receivables, net of allowance	358	314
Inventories	29	34
Drilling advances	4	16
Prepaid assets and other	134	102
Intercompany receivable	5,038	5,212
Total current assets	5,907	6,056
PROPERTY AND EQUIPMENT, NET	7,014	6,546
OTHER ASSETS:
Equity in affiliates	15,517	16,092
Deferred charges and other	97	96
Total assets	28,535	28,790
CURRENT LIABILITIES:
Accounts payable	371	409
Other current liabilities	653	539
Total current liabilities	1,024	948
Long-term debt	8,247	8,418
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Intercompany payable	12,152	10,744
Income taxes	(271)	(412)
Asset retirement obligation, non current	257	271
Other	888	933
Total deferred credits and other noncurrent liabilities	13,026	11,536
APACHE SHAREHOLDERS' EQUITY	6,238	7,888
TOTAL EQUITY	6,238	7,888
Total liabilities and shareholders' equity	28,535	28,790
Apache Finance Canada [Member]
CURRENT ASSETS:
Cash and cash equivalents	0			0		3
OTHER ASSETS:
Equity in affiliates	(1,240)	(807)
Deferred charges and other	1,000	1,001
Total assets	(240)	194
CURRENT LIABILITIES:
Accounts payable	(12)
Other current liabilities	3	3
Total current liabilities	(9)	3
Long-term debt	297	298
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes	5	4
Other	1	250
Total deferred credits and other noncurrent liabilities	6	254
APACHE SHAREHOLDERS' EQUITY	(534)	(361)
TOTAL EQUITY	(534)	(361)
Total liabilities and shareholders' equity	(240)	194
All Other Subsidiaries of Apache Corporation [Member]
CURRENT ASSETS:
Cash and cash equivalents	1,033	1,089		$ 412		$ 1,748
Receivables, net of allowance	770	939
Inventories	447	536
Drilling advances	77	156
Prepaid assets and other	45	188
Total current assets	2,372	2,908
PROPERTY AND EQUIPMENT, NET	11,853	14,292
OTHER ASSETS:
Intercompany receivable	12,152	10,744
Equity in affiliates	706	446
Deferred charges and other	314	813
Total assets	27,397	29,203
CURRENT LIABILITIES:
Accounts payable	226	209
Other current liabilities	602	681
Intercompany payable	5,038	5,212
Total current liabilities	5,866	6,102
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes	1,976	2,937
Asset retirement obligation, non current	2,175	2,291
Other	422	179
Total deferred credits and other noncurrent liabilities	4,573	5,407
APACHE SHAREHOLDERS' EQUITY	15,517	16,092
Noncontrolling interest	1,441	1,602
TOTAL EQUITY	16,958	17,694
Total liabilities and shareholders' equity	$ 27,397	$ 29,203

[1] Financial information for 2015 and 2014 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

[2] Financial information for 2015 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.

[3] Financial information for 2015, 2014, and 2013 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 1.