Edgar Filing: APACHE CORP

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, 2015

[ ]

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

LOGO

APACHE CORPORATION

(Exact name of registrant as specified in its charter)


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

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

(Address of principal executive offices)

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

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


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

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

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

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

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

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

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

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

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


Aggregate market value of the voting and non-voting common equity held by non-affiliates of registrant as of June 30, 2015	$	21,783,122,197
Number of shares of registrant’s common stock outstanding as of January 31, 2016		378,297,784

Documents Incorporated By Reference

Portions of registrant’s proxy statement relating to registrant’s 2016 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		16
1B.	UNRESOLVED STAFF COMMENTS		26
2.	PROPERTIES		1
3.	LEGAL PROCEEDINGS		26
4.	MINE SAFETY DISCLOSURES		26

	PART II

5.	MARKET FOR THE REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES		27
6.	SELECTED FINANCIAL DATA		29
7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		30
7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		54
8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA		55
9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE		55
9A.	CONTROLS AND PROCEDURES		55
9B.	OTHER INFORMATION		56

	PART III

10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE		58
11.	EXECUTIVE COMPENSATION		58
12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS		58
13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE		58
14.	PRINCIPAL ACCOUNTING FEES AND SERVICES		58

	PART IV

15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES		59

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, 2015, 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;

•

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

•

production and reserve levels;

•

drilling risks;

•

economic and competitive conditions;

•

the availability of capital resources;

•

capital expenditure and other contractual obligations;

•

currency exchange rates;

•

weather conditions;

•

inflation rates;

•

the availability of goods and services;

•

legislative or regulatory changes;

•

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

•

the integration of acquisitions;

•

terrorism or cyber attacks;

•

occurrence of property acquisitions or divestitures;

•

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

•

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

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.

“LIBOR” means London Interbank Offered Rate.

“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. We currently have exploration and production interests in four countries: the U.S., Canada, Egypt, and the U.K. (North Sea). Apache also pursues exploration interests in other countries that may over time result in reportable discoveries and development opportunities. We treat all operations as one line of business.

Our common stock, par value $0.625 per share, has been listed on the New York Stock Exchange (NYSE) since 1969, on the Chicago Stock Exchange (CHX) since 1960, and on the NASDAQ National Market (NASDAQ) since 2004. On May 18, 2015, 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.

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

•

financial flexibility

•

optimization of returns, earnings, and cash flow

Rigorous management of our asset portfolio plays a key role in optimizing shareholder value over the long-term. In 2015, Apache completed a multi-year effort to refocus its portfolio and strengthen its financial position. As a part of this effort, the Company monetized certain capital intensive projects that were not accretive to

earnings in the near-term and other non-strategic assets. These divestitures included Apache’s interest in LNG projects in Australia and Canada, its exploration and production operations in Australia and Argentina, and mature assets offshore in the Gulf of Mexico. The proceeds were used to reduce debt levels and redeployed to upgrade our portfolio.

Preserving financial flexibility is also key to our overall business philosophy. In response to the decline in commodity prices, Apache immediately took proactive measures to reduce activity levels and focused on bringing costs into alignment with commodity prices. We reduced our capital investments by over 60 percent from 2014 levels and realized meaningful reductions in drilling, operating, and overhead costs. These steps, coupled with our strategic divestitures, enabled us to reduce debt $2.5 billion and increase cash $700 million from year-end 2014. We accomplished this in spite of a 47 percent decrease in crude oil realizations and a 44 percent decline in North American natural gas realizations.

During 2016 we will continue to focus on our cost structure and expect to realize additional reductions in overhead, operating, and capital costs. In addition, we have chosen to reduce our capital spending to a level at which we believe we can achieve “cash flow neutrality” for the year. We intend to fund our capital program and dividends through cash from operations and a limited amount of non-core asset sales, without external financing. Our 2016 capital budget is over 60 percent lower than 2015 and 80 percent lower than 2014. Our 2016 capital will be allocated on a prioritized basis as follows: (i) maintain assets and keeping them running efficiently and preserve mineral rights and leases, (ii) further optimize and build high quality inventory for the future, (iii) conduct certain medium-cycle, high-impact exploration activities, and (iv) conduct limited-scale development activities that remain economically robust at these low prices. We currently plan capital investments in 2016 in the range of $1.4 to $1.8 billion excluding noncontrolling interest: $700 million to $800 million allocated to North American onshore plays, and the balance to international and U.S. offshore regions. This budget may be adjusted, up or down, with commodity price movements throughout the year. Given the further curtailment of capital spending, we are projecting a production decline of 7 percent to 11 percent in 2016 compared to 2015 levels, after adjusting for divestitures and volumes associated with Egypt’s noncontrolling interest and tax impacts.

For a more in-depth discussion of our divestitures, strategy, 2015 results, and the Company’s capital resources and liquidity, please see Part II, Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations of this Form 10-K.

Geographic Area Overviews

We have exploration and production interests in four countries: the U.S., Canada, Egypt, and the U.K. North Sea. Apache also pursues exploration interests in other countries that may over time result in reportable discoveries and development opportunities. During 2015, the Company completed the sale of all of its operations in Australia. Results of operations and cash flows for Australia operations are reflected as discontinued operations in the Company’s financial statements and are not included in the tables below.

The following table sets out a brief comparative summary of certain key 2015 data for each of our 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		91.6		47	%	$	2,636		847		54	%		506		492
Canada		24.7		13			498		280		18			38		38

Total North America		116.3		60			3,134		1,127		72			544		530

Egypt⁽¹⁾		53.0		27			1,969		302		19			122		109
North Sea		26.0		13			1,280		135		9			26		21
Other International		–		–			–		–		–			1		–

Total International		79.0		40			3,249		437		28			149		130

Total		195.3		100	%	$	6,383		1,564		100	%		693		660

⁽¹⁾

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

North America

Apache’s North American assets are primarily located in the Permian Basin, the Anadarko basin in western Oklahoma and the Texas Panhandle, Gulf Coast and the offshore Gulf of Mexico areas of the U.S., and in Western Canada.

North America Onshore

Overview We have access to significant liquid hydrocarbons across our 10.7 million gross acres onshore in the U.S. and Canada. Approximately 55 percent of this acreage is undeveloped. Additionally, 58 percent of Apache’s worldwide equivalent 2015 production and 72 percent of our estimated year-end proved reserves were in our U.S. and Canada onshore regions. Over the past several years, Apache’s drilling activity has centered on our North America onshore assets, which delivered liquids growth of 4 percent during 2015 excluding the impacts of divestitures. To manage our development efforts across our acreage positions within North America, our onshore assets are divided into a few key regions: Permian, MidContinent/Gulf Coast, and Canada.

Permian Region Our Permian region controls over 3.3 million gross acres with exposure to numerous plays across the Permian Basin. Apache is one of the largest operators in the Permian Basin, with more than 14,300 producing wells in 163 fields, including 58 waterfloods and seven CO₂ floods. The Permian region’s year-end 2015 estimated proved reserves were 684 MMboe, representing 44 percent of the Company’s worldwide reserves. Total region production for 2015 was up 6 percent sequentially, despite operating an average rig count of 12 compared to 40 rigs in the prior year. The reduced rig count reflected the Company’s decisive action to reduce capital spending in response to rapidly declining commodity prices. During the year, we drilled or participated in drilling 378 wells, 217 of which were horizontal, with a 97 percent success rate.

In recent years, the region has been testing numerous formations and building a large inventory of horizontal opportunities in several plays across our acreage position. In 2015, we ran a streamlined capital program that focused on efficiency improvements, downspacing and other strategic tests to further delineate several plays. Production growth was driven by Wolfcamp wells in the Barnhart, Wildfire and Azalea areas of the Southern Midland Basin, the Bone Spring development program in the Delaware basin, and Yeso drilling on the Northwest shelf. In addition, the region continued to manage its completion inventory as costs continued to fall throughout the year.

Given its acreage holdings and recent seismic data acquisitions, the region’s deep portfolio of drilling inventory and opportunities allows us to focus efforts on the most economic wells and capital projects as the industry continues to adjust to current commodity price levels. Heading into 2016, we will continue to operate in a reduced capital spending program and will balance larger development programs with exploration activity in several new areas.

MidContinent/Gulf Coast Region As part of our 2015 strategic efforts to reduce our operating cost structure, we streamlined our organization by closing our regional office in Tulsa and combining our MidContinent and Gulf Coast onshore regions. Apache’s MidContinent/Gulf Coast region holds 2.8 million gross acres and includes 3,402 producing wells primarily in western Oklahoma, the Texas Panhandle, and south Texas. Total region production in 2015 was 73 Mboe/d, comprising 13 percent of Apache’s worldwide production. The region’s year-end 2015 estimated proved reserves were 154 MMboe.

In 2015, Apache drilled or participated in drilling 127 wells with a 99 percent success rate. The region focused on drilling activities in the Canyon Lime, Eagle Ford, Marmaton, and Woodford formations with consistently strong results. Apache is active in the Woodford-SCOOP play in Central Oklahoma targeting the Woodford formation, where we drilled or participated in drilling 33 wells. The region continues to work on optimizing fracture geometry and well spacing to reduce costs in this play. Apache’s prolific Canyon Lime and Woodford plays will again be a focus area for region drilling activity in 2016.

Canada Region Apache entered the Canadian market in 1995 and currently holds nearly 3.6 million gross acres across the provinces of British Columbia, Alberta, and Saskatchewan. The region’s large acreage position presents significant drilling opportunities and portfolio diversification with exposure to oil, gas, and liquids rich fairways. Our Canadian region provided approximately 13 percent of Apache’s 2015 worldwide production and held 280 MMboe of estimated proved reserves at year-end.

In 2015, Apache drilled or participated in drilling 38 wells in the region with a 100 percent success rate. Drilling operations continued in our established Swan Hills, Bluesky, and Glauconite plays, and we de-risked our Montney and Duvernay emerging growth plays. The results from the first seven-well pad in the Duvernay were encouraging. Moving to a pad development decreased costs by 40 percent from 2014. The pad commenced production during the fourth quarter, with average 30 day initial production rates of 1,632 boe/d per well. Our Montney drilling has been focused in the Karr-Simonette and Wapiti areas. The two initial wells in Karr-Simonette exceeded expectations with peak oil rates of 450 and 630 boe/d. We have also successfully tested the lower Montney in the Wapiti area. The region’s development activity in 2016 will primarily be centered on the Duvernay and Montney programs.

As part of our assessment and rationalization of the Company’s North American portfolio, in the second quarter of 2015 we divested our working interest in the Kitimat LNG development and approximately 333,000 of our net acres in the Horn River and Liard natural gas basins of British Columbia.

North America Offshore

Gulf of Mexico Region The Gulf of Mexico region comprises assets in the offshore waters of the Gulf of Mexico and onshore Louisiana. Apache’s offshore technical teams continue to focus on subsalt and other deeper exploration opportunities in water depths less than 1,000 feet, which have been relatively untested by the industry. In addition to the exploration and development of properties in shallower water, Apache continues to pursue joint venture and other monetization opportunities for its deepwater prospects, which offer exposure to significant reserve and production potential in underexplored and oil-prone areas in water depths greater than 1,000 feet. During 2015, Apache’s Gulf of Mexico region contributed 9.2 Mboe/d to the Company’s total production.

North America Marketing

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

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., our objective is to maximize the value of crude oil sold by identifying the best markets and most economical transportation routes available to move the product. Sales contracts are generally 30-day evergreen contracts that renew automatically until canceled by either party. These contracts provide for sales that are priced daily at prevailing market prices. 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, the crude is transported by pipeline or truck within Western Canada to market hubs in Alberta and Manitoba where it is sold, allowing for a more diversified group of purchasers and a higher netback price. A portion of our trucked barrels are delivered and sold at rail terminals. We evaluate our transport options monthly to maximize our 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.

International

Apache’s international assets are located in Egypt and offshore U.K. in the North Sea. In 2015, international assets contributed 40 percent of our production and 51 percent of our oil and gas revenues. Approximately 28 percent of our estimated proved reserves at year-end were located outside North America.

Egypt

Overview Our operations in Egypt are conducted pursuant to production sharing contracts (PSCs). Under the terms of the PSCs, the contractor partners bear the risk and cost of exploration, development, and production activities. In return, if exploration is successful, the contractor partners receive 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 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 our cost recovery entitlement and income taxes paid on our 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 contractors’ income taxes are paid by EGPC, the amount of the income tax has no economic impact on the contractors despite impacting our production and reserves.

Our activity in Egypt began in 1994 with our first Qarun discovery well, and today we are one of the largest acreage holders in Egypt’s Western Desert. At year-end 2015, we held 6.7 million gross acres in 24 separate concessions. Approximately 73 percent of our acreage in Egypt is undeveloped, providing us with considerable

exploration and development opportunities for the future. Development leases within concessions currently have expiration dates ranging from 4 to 24 years, with extensions possible for additional commercial discoveries or on a negotiated basis. Our estimated proved reserves in Egypt are reported under the economic interest method and exclude the host country’s share of reserves. Our operations in Egypt, including a one-third noncontrolling interest, contributed 27 percent of our 2015 production and accounted for 19 percent of our year-end estimated proved reserves and 36 percent of our estimated discounted future net cash flows. Excluding the noncontrolling interest, Egypt contributed 20 percent of our 2015 production and accounted for 14 percent of our year-end estimated proved reserves and 27 percent of our estimated discounted future net cash flows.

We have historically been one of the most active drillers in the Western Desert, however, 2015 activity was curtailed in all regions in response to reduction in commodity prices. We drilled 97 development and 25 exploration wells in 2015. Approximately 60 percent of our exploration wells were successful, further expanding our presence in the westernmost concessions and unlocking additional opportunities in existing plays. A key component of the region’s success has been the ability to acquire and evaluate 3-D seismic surveys that enable our technical teams to consistently high-grade existing prospects and identify new targets across multiple pay horizons in the Cretaceous, Jurassic, and deeper Paleozoic formations.

Following several years of political turmoil, Apache’s operations, located in remote locations in the Western Desert, continue to experience no production interruptions. We have also continued to receive development lease approvals for our drilling program. However, a deterioration in the political, economic, and social conditions or other relevant policies of the Egyptian government, such as changes in laws or regulations, export restrictions, expropriation of our assets or resource nationalization, forced renegotiation or modification of our existing contracts with EGPC, or threats or acts of terrorism by groups such as ISIS, could materially and adversely affect our business, financial condition, and results of operations. Apache purchases and maintains limited insurance covering its investments in Egypt. For information regarding such coverage, please see Part II, Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Insurance Program of this Form 10-K.

Marketing Our gas production is sold to EGPC primarily under an industry-pricing formula, a sliding scale based on Dated Brent crude oil with a minimum of $1.50 per MMBtu and a maximum of $2.65 per MMBtu, plus an upward adjustment for liquids content. The region averaged $2.92 per Mcf in 2015.

Oil from the Khalda Concession, the Qarun Concession, and other nearby Western Desert blocks is sold to third parties in the export market or to EGPC when called upon to supply domestic demand. Oil sales are exported from or sold at one of two terminals on the northern coast of Egypt. Oil production that is sold to EGPC is sold on a spot basis priced at Brent with a monthly EGPC official differential applied.

North Sea

Overview Apache entered the North Sea in 2003 after acquiring an approximate 97 percent working interest in the Forties field (Forties). Since acquiring Forties, Apache has actively invested in the region 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 field. In total, Apache has interests in approximately 1 million gross acres in the U.K. North Sea.

The North Sea region continues to play an important role in the overall Apache portfolio by providing competitive investment opportunities across multiple horizons and potential reserve upside with high-impact exploration potential. In 2015, the North Sea region contributed 13 percent of worldwide consolidated production and 9 percent of year-end estimated proved reserves. During the year, 23 development wells were drilled in the North Sea, of which 19 were productive. Apache has invested approximately $2.7 billion in infrastructure

improvements across all of its fields over the past decade resulting in significantly improved production efficiency and lower unit operating costs. With basin-wide leading production efficiency, our infrastructure and offtake capabilities have positioned the region to be allocated a higher percentage of capital dollars for drilling and production.

The Beryl field, which is a geologically complex area with multiple fields and stacked pay potential, provides for significant exploration opportunity. Following the completion of the first full-field 3-D acquisition since 1997, Apache recently announced two exceptional discoveries in the area, the K and Corona discoveries, and is moving ahead with development and additional exploration efforts. The K discovery encompasses multiple commercial zones across three distinct fault blocks, including one fault block with over 1,500 feet of net pay and is projected to begin production mid-2017. The Corona discovery logged 225 feet vertical depth net pay in reservoir-quality sandstone. Apache has 55 percent and 100 percent working interests in K and Corona, respectively. The 3-D acquisition has also indicated the potential for several future prospects similar to K and Corona on Apache acreage in the Beryl area.

In addition to the K and Corona discoveries, Apache also announced an appraisal well drilled approximately 50 miles (80 kilometers) south of the Forties complex. The Seagull discovery logged 672 feet of net oil pay over a 1,092-foot column in Triassic-age sands. Further appraisal work will continue following the recent acquisition of a multi-azimuth 3-D survey. Apache is now operator of the license and has a 35 percent working interest in the project.

Marketing We have traditionally sold our 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 2016 include continued analysis and review of our deepwater prospects in offshore Suriname.

Major Customers

In 2015, 2014, and 2013 purchases by Royal Dutch Shell plc and its subsidiaries accounted for 11 percent, 19 percent, and 24 percent, respectively, of the Company’s worldwide oil and gas production revenues.

Drilling Statistics

Worldwide in 2015 we participated in drilling 693 gross wells, with 660 (95 percent) completed as producers. Historically, our drilling activities in the U.S. have generally concentrated on exploitation and

extension of existing producing fields rather than exploration. As a general matter, our operations outside of North America focus on a mix of exploration and development wells. In addition to our completed wells, at year-end a number of wells had not yet reached completion: 41 gross (18.1 net) in the U.S., 45 gross (42.5 net) in Egypt, 7 gross (7 net) in Canada, and 3 gross (2.2 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

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

2013
United States		15.6		11.2		26.8		834.9		12.6		847.5		850.5		23.8		874.3
Canada		-		-		-		108.5		6.9		115.4		108.5		6.9		115.4
Egypt		30.5		18.7		49.2		141.9		7.3		149.2		172.4		26.0		198.4
Australia		2.2		0.4		2.6		3.4		-		3.4		5.6		0.4		6.0
North Sea		-		0.5		0.5		13.4		0.1		13.5		13.4		0.6		14.0
Argentina		2.4		-		2.4		22.0		-		22.0		24.4		-		24.4

Total		50.7		30.8		81.5		1,124.1		26.9		1,151.0		1,174.8		57.7		1,232.5

Productive Oil and Gas Wells

The number of productive oil and gas wells, operated and non-operated, in which we had an interest as of December 31, 2015, is set forth below:


	Oil				Gas				Total
	Gross		Net		Gross		Net		Gross		Net
United States		14,441		9,490		3,394		1,695		17,835		11,185
Canada		1,885		872		2,405		1,943		4,290		2,815
Egypt		1,185		1,115		115		110		1,300		1,225
North Sea		158		120		27		15		185		135

Total		17,669		11,597		5,941		3,763		23,610		15,360

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

Production, Pricing, and Lease Operating Cost Data

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


	Production						Average Lease Operating Cost per Boe		Average Sales Price
Year Ended December 31,	Oil (MMbbls)		NGLs (MMbbls)		Gas (Bcf)		Average Lease Operating Cost per Boe		Oil (Per bbl)		NGLs (Per bbl)		Gas (Per Mcf)

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⁾		31.2		0.4		128.2		10.69		50.65		30.97		2.92
North Sea		21.7		0.4		23.7		13.74		51.26		26.53		6.73

Total		103.8		22.7		412.8		10.56		48.17		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⁾		32.1		0.2		135.1		9.83		97.44		51.80		2.96
North Sea		22.2		0.5		20.5		17.30		95.53		59.42		8.29

Total		109.4		24.5		489.2		11.66		91.73		27.28		4.05


2013
United States		53.6		19.9		285.2	$	11.60	$	98.14	$	27.29	$	3.84
Canada		6.5		2.4		181.6		15.68		87.00		30.50		3.23
Egypt⁽¹⁾		32.7		–		130.1		9.42		107.94		–		2.99
North Sea		23.3		0.5		18.6		15.16		107.48		73.06		10.43

Total		116.1		22.8		615.5		12.17		102.15		28.56		3.68

⁽¹⁾

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

Gross and Net Undeveloped and Developed Acreage

The following table sets out our gross and net acreage position as of December 31, 2015, in each country where we have operations:


	Undeveloped Acreage				Developed Acreage
	Gross Acres		Net Acres		Gross Acres		Net Acres
	(in thousands)
United States		7,738		3,979		2,236		1,166
Canada		980		771		2,596		1,889
Egypt		4,913		3,568		1,805		1,698
North Sea		832		379		153		116

Total		14,463		8,697		6,790		4,869

As of December 31, 2015, Apache had 2.3 million net undeveloped acres scheduled to expire by year-end 2016 if production is not established or we take no other action to extend the terms. Additionally, Apache has 1.5 million and 700,000 net undeveloped acres set to expire in 2017 and 2018, respectively. We strive to extend the terms of many of these licenses and concession areas through operational or administrative actions, but cannot assure that such extensions can be achieved on an economic basis or otherwise on terms agreeable to both the Company and third parties, including governments.

Exploration concessions in our Egypt region comprise a significant portion of our net undeveloped acreage expiring over the next three years. We have 1.8 million and 700,000 net undeveloped acres set to expire in 2016 and 2017, respectively. Apache will continue to pursue acreage extensions in areas in which it believes exploration opportunities exist and over the past year has been successful in being awarded six-month extensions on targeted concessions. Longer term extensions are also being finalized with EGPC. There were no reserves recorded on this undeveloped acreage.

As of December 31, 2015, 25 percent of U.S. net undeveloped acreage and 42 percent of Canadian net undeveloped acreage was held by production.

Apache also holds 1.8 million net undeveloped acreage in two blocks in Suriname expiring in 2017 and 2018.

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.

The following table shows proved oil, NGL, and gas reserves as of December 31, 2015, based on average commodity prices in effect on the first day of each month in 2015, 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 (MMbbls)		NGL (MMbbls)		Gas (Bcf)		Total (MMboe)
Proved Developed:
United States		349		150		1,364		727
Canada		68		15		759		210
Egypt⁽¹⁾		144		2		776		275
North Sea		105		1		86		120

Total Proved Developed		666		168		2,985		1,332

Proved Undeveloped:
United States		60		25		209		120
Canada		38		5		163		70
Egypt⁽¹⁾		18		–		54		27
North Sea		12		–		19		15

Total Proved Undeveloped		128		30		445		232

TOTAL PROVED		794		198		3,430		1,564

⁽¹⁾

Includes total proved reserves of 101 MMboe attributable to a one-third noncontrolling interest in Egypt

As of December 31, 2015, Apache had total estimated proved reserves of 794 MMbbls of crude oil, 198 MMbbls of NGLs, and 3.4 Tcf of natural gas. Combined, these total estimated proved reserves are the volume equivalent of 1.6 billion barrels of oil or 9.4 Tcf of natural gas, of which oil represents 51 percent. As of December 31, 2015, the Company’s proved developed reserves totaled 1,332 MMboe and estimated PUD reserves totaled 232 MMboe, or approximately 15 percent of worldwide total proved reserves. Apache has elected not to disclose probable or possible reserves in this filing.

During 2015, Apache added 117 MMboe of proved reserves through exploration and development activity and 7 MMboe through purchases of minerals in-place. We sold a combined 385 MMboe through several divestiture transactions. We recognized a 368 MMboe downward revision in proved reserves, of which 339 MMboe was related to lower product prices.

The Company’s estimates of proved reserves, proved developed reserves, and PUD reserves as of December 31, 2015, 2014, and 2013, changes in estimated proved reserves during the last three years, and estimates of future net cash flows from proved reserves are contained in Note 14—Supplemental Oil and Gas Disclosures in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K. Estimated future net cash flows were calculated using a discount rate of 10 percent per annum, end of period costs, and an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months, held flat for the life of the production, except where prices are defined by contractual arrangements.

Proved Undeveloped Reserves

The Company’s total estimated PUD reserves of 232 MMboe as of December 31, 2015, decreased by 513 MMboe from 745 MMboe of PUD reserves reported at the end of 2014. During the year, Apache converted 73 MMboe of PUD reserves to proved developed reserves through development drilling activity. In North America, we converted 40 MMboe, with the remaining 33 MMboe in our international areas. We sold 240 MMboe and

acquired 7 MMboe of PUD reserves during the year. We added 56 MMboe of new PUD reserves through extensions and discoveries. We recognized a 263 MMboe downward revision in proved undeveloped reserves during the year, of which 202 MMboe was associated with lower product prices.

During the year, a total of approximately $1.4 billion was spent on projects associated with reserves that were carried as PUD reserves at the end of 2014. A portion of our costs incurred each year relate to development projects that will be converted to proved developed reserves in future years. We spent approximately $900 million on PUD reserve development activity in North America and $500 million in the international areas. As of December 31, 2015, we 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 35 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. Apache selects the properties for review by Ryder Scott based primarily on relative reserve value. We also consider other factors such as geographic location, new wells drilled during the year and reserves volume. During 2015, the properties selected for each country ranged from 82 to 100 percent of the total future net cash flows discounted at 10 percent. These properties also accounted for over 86 percent of the reserves value of our international proved reserves and 91 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 2015, 2014, and 2013, Ryder Scott’s review covered 90, 91, and 92 percent, respectively, of the Company’s worldwide estimated proved reserves value and 83, 85, and 86 percent, respectively, of the Company’s total proved reserves volume. 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.

Ryder Scott’s review of 2013 covered 84 percent of U.S., 82 percent of Canada, 63 percent of Argentina, 99 percent of Australia, 88 percent of Egypt, and 88 percent of the U.K.’s total proved reserves.

We have filed Ryder Scott’s independent report as an exhibit to this Form 10-K.

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

Employees

On December 31, 2015, we had 3,860 employees.

Offices

Our principal executive offices are located at One Post Oak Central, 2000 Post Oak Boulevard, Suite 100, Houston, Texas 77056-4400. At year-end 2015, we 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. We have 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 8—Commitments and Contingencies in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.

Title to Interests

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

Additional Information about Apache

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

Remediation Plans and Procedures

Apache and its wholly owned subsidiary, Apache Deepwater LLC (ADW), developed Oil Spill Response Plans (the Plans) for their respective Gulf of Mexico operations to ensure rapid and effective responses to spill events that may occur on such entities’ operated properties as required by the Bureau of Safety and Environmental Enforcement (BSEE). Annually, drills are conducted to measure and maintain the effectiveness of the Plans. These drills include the participation of spill response contractors, representatives of Clean Gulf Associates (CGA), and representatives of governmental agencies.

In the event of a spill, CGA is the primary oil spill response association available to Apache and ADW. 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 the event that CGA resources are already being utilized, other resources are available to Apache. Apache is a member of Oil Spill Response Limited (OSRL), which entitles any Apache entity worldwide to access OSRL’s service. In addition, ADW is a member of Marine Spill Response Corporation (MSRC) and National Response Corporation (NRC), and their resources are available to ADW for its deepwater Gulf of Mexico operations. The equipment and resources available to MSRC and NRC change from time to time, and current information is generally available on each company’s website.

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, 2015, Apache’s investment in MWCC totals $172 million and is reflected in “Deferred charges and other” in the Company’s consolidated balance sheet.

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 countries, 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 countries in which we have producing operations to which we can reallocate capital investments in response to changes in commodity prices, local business environments, and markets. It also reduces the risk that we will be materially impacted by an event in a specific area or country.

Environmental Compliance

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

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

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 2015 ranged from a high of $61.43 per barrel to a low of $34.73 per barrel. The NYMEX daily settlement price for the prompt month natural gas contract in 2015 ranged from a high of $3.23 per MMBtu to a low of $1.76 per MMBtu. The market prices for crude oil and natural gas depend on factors beyond our control. These factors include demand for crude oil and natural gas, which fluctuates with changes in market and economic conditions, and other factors, including:

•

worldwide and domestic supplies of crude oil and natural gas;

•

actions taken by foreign oil and gas producing nations;

•

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

•

the level of global crude oil and natural gas inventories;

•

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

•

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

•

the availability of pipeline capacity and infrastructure;

•

the availability of crude oil transportation and refining capacity;

•

weather conditions;

•

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. The recent declines in oil and natural gas prices have 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 write-downs;

•

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

•

reducing the carrying value of goodwill.

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

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

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 productivity.

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.

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 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. In the future, we may 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.

If we were to enter into hedging transactions, we would be 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.

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. Further downgrades could result in additional postings of between $500 million and $1.1 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 credit markets are subject to fluctuation and are vulnerable to unpredictable shocks. We have a significant development project inventory and an extensive exploration portfolio, which will require substantial future investment. We and/or our partners may need to seek financing in order to fund these or other future activities. Our future access to capital, as well as that of our partners and contractors, could be limited if the debt or equity markets are constrained. This could significantly delay development of our property interests.

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

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

Any indentures and other financing agreements that we enter into in the future may limit our ability to pay cash dividends on our capital stock, including common stock. In addition, under Delaware law, dividends on capital stock may only be paid from “surplus,” which is 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.

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.

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.

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

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

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

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

We may incur significant costs related to environmental matters.

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

Our North American operations are subject to governmental risks that may impact our operations.

Our North American operations have been, and at times in the future may be, affected by political developments and by federal, state, provincial, and local laws and regulations such as restrictions on production, 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 is currently planning to issue a new Notice to Lessees (NTL) 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. We currently expect such 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.

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 proposed U.S. federal budget for fiscal year 2017 includes certain provisions that, if passed as originally submitted, will have an adverse effect on our financial position, results of operations, and cash flows.

On February 9, 2016, the Office of Management and Budget released a summary of the proposed U.S. federal budget for fiscal year 2017. The proposed budget repeals many tax incentives and deductions that are currently used by U.S. oil and gas companies, and includes proposals to increase royalties and lease fees on oil and gas produced from federal lands in the United States. These provisions include elimination of the ability to fully deduct intangible drilling costs in the year incurred; increases in the taxation of foreign source income; repeal of the manufacturing tax deduction for oil and natural gas companies; an increase in the geological and geophysical amortization period for independent producers; and the imposition of a $10.25 per-barrel fee on oil production to fund investments in a clean transportation system. Should some or all of these provisions become law, our taxes will increase, potentially significantly, which would have a negative impact on our net income and cash flows. This could also cause us to reduce our drilling activities in the U.S. Since none of these proposals have yet to be voted on or become law, we do not know the ultimate impact these proposed changes may have on our business.

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

Several proposals are before the U.S. Congress that, if implemented, would either prohibit or restrict the practice of hydraulic fracturing or subject the process to regulation under the Safe Drinking Water Act. Several states are considering legislation to regulate hydraulic fracturing practices that could impose more stringent permitting, transparency, and well construction requirements on hydraulic-fracturing operations or otherwise seek to ban fracturing activities altogether. 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 40 percent of our 2015 production was outside North America, and approximately 28 percent of our estimated proved oil and gas reserves on December 31, 2015, were located

outside North America. As a result, a significant portion of our production and resources are subject to the increased political and economic risks and other factors associated with international operations including, but not limited to:

•

general strikes and civil unrest;

•

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

•

import and export regulations;

•

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

•

price control;

•

transportation regulations and tariffs;

•

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

•

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

•

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

•

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

•

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

•

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

Foreign countries have occasionally asserted rights to oil and gas properties through border disputes. If a country claims superior rights to oil and gas leases or concessions granted to us by another country, our interests could decrease in value or be lost. Even our smaller international assets may affect our overall business and results of operations by distracting management’s attention from our more significant assets. 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 by groups such as ISIS 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 by groups such as ISIS, could materially and adversely affect our business, financial condition, and results of operations. Our operations in Egypt, excluding Sinopec’s one-third noncontrolling interest, contributed 20 percent of our 2015 production and accounted for 14 percent of our year-end estimated proved reserves and 27 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.

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, 2015, we did not have any unresolved comments from the SEC staff that were received 180 or more days prior to year-end.

ITEM 3.

LEGAL PROCEEDINGS

The information set forth under “Legal Matters” and “Environmental Matters” in Note 8—Commitments and Contingencies in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K is incorporated herein by reference.

ITEM 4. MINE SAFETY DISCLOSURES

None.

PART II

ITEM 5.

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

During 2015, Apache common stock, par value $0.625 per share, was traded on the New York and Chicago Stock Exchanges and the NASDAQ National Market under the symbol “APA.” The table below provides certain information regarding our common stock for 2015 and 2014. 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.


	2015								2014
	Price Range				Dividends Per Share				Price Range				Dividends Per Share
	High		Low		Declared		Paid		High		Low		Declared		Paid
First Quarter	$	68.37	$	58.46	$	0.25	$	0.25	$	87.91	$	77.31	$	0.25	$	0.20
Second Quarter		71.40		56.54		0.25		0.25		102.34		81.87		0.25		0.25
Third Quarter		56.78		36.20		0.25		0.25		104.57		92.84		0.25		0.25
Fourth Quarter		53.94		39.72		0.25		0.25		93.87		54.34		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 29, 2016 (last trading day of the month), was $42.54 per share. As of January 31, 2016, there were 378,297,784 shares of our common stock outstanding held by approximately 4,500 stockholders of record and 289,000 beneficial owners.

We have paid cash dividends on our common stock for 51 consecutive years through December 31, 2015. In the first quarter of 2014 the Board of Directors approved a 25 percent increase to $0.25 per share for the regular quarterly cash dividend on the Company’s common shares. 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 2016 annual meeting of stockholders, which is incorporated herein by reference.

The following stock price performance graph is intended to allow review of stockholder returns, expressed in terms of the appreciation of the Company’s common stock relative to two broad-based stock performance indices. The information is included for historical comparative purposes only and should not be considered indicative of future stock performance. The graph compares the yearly percentage change in the cumulative total stockholder return on the Company’s common stock with the cumulative total return of the Standard & Poor’s Composite 500 Stock Index and of the Dow Jones U.S. Exploration & Production Index (formerly Dow Jones Secondary Oil Stock Index) from December 31, 2010, through December 31, 2015. The stock performance graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall information be incorporated by reference into any future filing under the Securities Act of 1933 or Securities Exchange Act of 1934, each as amended, except to the extent that the Company specifically incorporates it by reference into such filing.

LOGO


	2010		2011		2012		2013		2014		2015
Apache Corporation	$	100.00	$	76.37	$	66.67	$	73.69	$	54.34	$	39.27
S & P’s Composite 500 Stock Index		100.00		102.11		118.45		156.82		178.29		180.75
DJ US Expl & Prod Index		100.00		95.81		101.39		133.68		119.27		90.97

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, 2015, which information has been derived from the Company’s audited financial statements. This information should be read in connection with, and is qualified in its entirety by, the more detailed information in the Company’s financial statements set forth in Part IV, Item 15 of this Form 10-K. As discussed in more detail under Item 15, 2015 numbers in the following table reflect a total of $25.5 billion ($16.6 billion net of tax) in non-cash write-downs of the carrying value of the Company’s proved oil and gas properties as a result of ceiling test limitations and impairments totaling $1.9 billion ($1.7 billion net of tax) related to gathering, transmission, and processing facilities and inventory. The 2014 numbers reflect a total of $5.0 billion ($3.1 billion net of tax) in non-cash write-downs of the carrying value of the Company’s U.S. and North Sea proved oil and gas properties as a result of ceiling test limitations and asset impairments totaling $1.9 billion ($1.8 billion net of tax) in connection with fair value assessments, including $1.3 billion for the impairment of goodwill, $604 million for the impairment of assets held for sale, and other asset impairments. The 2013 numbers reflect a total of $995 million ($541 million net of tax) in non-cash write-downs of the carrying value of the Company’s U.S. and North Sea proved oil and gas properties as a result of ceiling test limitations and a non-cash write-down related to the Company’s exit of operations in Kenya. The 2012 numbers reflect a total of $1.9 billion ($1.4 billion net of tax) in non-cash write-downs of the carrying value of the Company’s Canadian proved oil and gas properties.


	As of or for the Year Ended December 31,
	2015		2014		2013		2012		2011
	(In millions, except per share amounts)
Income Statement Data
Oil and gas production revenues	$	6,383	$	12,691	$	14,771	$	14,854	$	14,603
Net income (loss) from continuing operations attributable to common shareholders		(22,348)		(3,815)		1,880		1,258		3,738
Net income (loss) from continuing operations per share:
Basic		(59.16)		(9.93)		4.75		3.43		9.94
Diluted		(59.16)		(9.93)		4.74		3.41		9.54
Cash dividends declared per common share		1.00		1.00		0.80		0.68		0.60

Balance Sheet Data
Total assets	$	18,842	$	55,952	$	61,637	$	60,737	$	52,051
Long-term debt		8,777		11,245		9,672		11,355		6,785
Total equity		4,228		28,137		35,393		31,331		28,993
Common shares outstanding		377		377		396		392		384

For a discussion of significant acquisitions and divestitures, see Note 2—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.

ITEM 7.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 2015 Results

This year was a transitional year for Apache. We made significant progress high-grading our portfolio, reducing drilling activity, driving down costs, and proactively strengthening our financial condition.

We completed an extensive refocusing of the Company’s asset portfolio which began several years ago. Through this process, we successfully monetized both capital intensive projects and assets that were not accretive to earnings in the near-term and other non-strategic assets. These divestitures included Apache’s interest in LNG projects in Australia and Canada, its exploration and production operations in Australia and Argentina, and mature assets offshore in the Gulf of Mexico. Proceeds from divestitures were used to improve our liquidity and redeployed to upgrade our portfolio.

We also reacted swiftly to the significant decline in crude oil prices that began in the third quarter of 2014 and continued throughout 2015 and into 2016. Immediate action was taken to substantially reduce activity levels, and concrete steps were taken to cut overhead and operating costs. Apache’s intense focus on driving internal efficiencies, along with considerable downward pressure on third-party service costs, resulted in savings in both capital and operating costs. Lease operating expenses and general and administrative expenses decreased 17 percent and 16 percent, respectively, from the prior year.

During the year, we also took action to strengthen our financial and liquidity position. The Company reduced debt by $2.5 billion since year-end 2014 and exited the year with $1.5 billion of cash. Our nearest long-term debt maturity is in 2018, and only $700 million, or 8 percent of our total debt portfolio, matures prior to 2021. In June 2015, we replaced $5.3 billion in revolving credit facilities with one $3.5 billion credit facility, which matures in June 2020.

Daily production of crude oil, natural gas, and natural gas liquids averaged 535 Mboe/d during 2015. Excluding the impact of divested assets and the impact of Egypt impairments and write-downs, production for the year would have increased 3 percent from 2014, despite a reduction of over 60 percent in capital spending. Production volumes for 2015 included a nonrecurring downward adjustment of 9,649 boe/d related to Egypt taxes. In the fourth quarter of 2015, we incurred charges totaling $1.3 billion for an impairment of certain gathering, transmission, and processing (GTP) assets and a write-down of oil and gas properties in Egypt. These charges drove a significant loss in Egypt for the fourth quarter, which mostly offset tax expense and tax volumes recognized in the first three quarters of the year. For more information regarding our production-sharing contracts and taxes, please refer to the “Geographic Area Overviews” section set forth in Part I, Item 1 and 2 of this Form 10-K.

In spite of these and other operating achievements, the precipitous decline in commodity prices negatively impacted our earnings and cash flow compared to the prior year. We reported a $23.1 billion loss attributable to common stock, or $61.20 per diluted common share, compared to a loss of $5.4 billion, or $14.06 per share in 2014. Notable items impacting our earnings that were driven by the decline in commodity price and refocusing our asset portfolio include the following:


	For the Year Ended December 31,

	2015			2014
	(In millions)

Oil and gas property write-downs, net of tax⁽¹⁾	$	16,526		$	3,068
Tax adjustments and valuation allowances		4,200			1,005
Impairments, net of tax⁽¹⁾		1,362			1,752
Discontinued operations, net of tax		771			1,588
Transaction, reorganization, and separation costs, net of tax		86			44
Contract termination charges, net of tax		57			35
Loss on extinguishment of debt, net of tax		25			-
Divested non-strategic assets, net of tax		(38	)		116

⁽¹⁾

Excludes Egypt noncontrolling interest impact.

2016 Outlook

We believe our proactive actions taken in 2015 and previous years have positioned us to be flexible and rapid in our responses to the challenges faced in this difficult and unpredictable environment. We are prepared for a potentially “lower for longer” commodity price cycle, while retaining our ability to dynamically manage our activity levels as commodity price and service costs dictate. To ensure that we sustain this position, we have reduced our activity with a target of achieving “cash flow neutrality.” This means our capital program and dividends will be funded through cash from operations and a limited amount of non-core asset sales, without external financing.

We currently plan capital investments in 2016 in the range of $1.4 to $1.8 billion, a reduction of over 60 percent from 2015 levels. Approximately $700 million to $800 million will be allocated to North American onshore plays, with the balance to international and U.S. offshore regions. This budget may be adjusted with commodity price movements throughout the year. Our budgeted amounts exclude expenditures attributable to a one-third noncontrolling interest in Egypt. Our capital budget for 2016 has been, and will be, allocated on a prioritized basis as follows: (i) maintain assets and keeping them running efficiently and preserve mineral rights and leases, (ii) further optimize and build high quality inventory for the future, (iii) conduct certain medium-cycle, high impact exploration activities, and (iv) conduct limited-scale development activities that remain economically robust at these low prices. In addition, we will continue our overhead and lease operating expenses cost reduction efforts in order to position Apache for an extended low commodity price environment.

Given the further curtailment of capital spending, we are projecting a production decline of 7 percent to 11 percent in 2016 compared to 2015 production levels after adjusting for divestitures and volumes associated with Egypt’s noncontrolling interest and tax impacts. However, we believe that if commodity prices improve from current market levels, we will be able to increase our capital plan accordingly with a greater focus on growth in our onshore North America assets.

Operational Highlights

Operational highlights for the year include:

North America

•

North America onshore liquids averaged 193,483 barrels per day, with crude oil representing 69 percent of the liquids production. When adjusted for asset divestitures, this represents an increase of 4 percent compared to 2014. North America onshore liquids production represented 56 percent of our worldwide liquids production and 36 percent of our overall production.

•

The Permian region averaged 12 operated rigs during the year, drilling 378 gross wells, 241 net wells. Drilling activity in the region resulted in a production increase of 6 percent relative to the prior year. Over half of the region’s production is crude oil and 20 percent is NGLs. Combined, this represents more than a third of Apache’s total liquids production for 2015. The region averaged 168 Mboe/d during 2015.

•

The MidContinent/Gulf Coast region averaged 5 operated rigs during the year, drilling 127 gross wells, 76 net wells. The region focused its drilling activities in the Canyon Lime, Eagleford, Marmaton, and Woodford formations during 2015. Apache is active in the SCOOP play in Central Oklahoma targeting the Woodford formation, where we drilled or participated in drilling 33 wells. The region averaged 73 Mboe/d during 2015.

•

The Canada region averaged 2 operated rigs during the year, drilling 38 gross wells, 21 net wells. Canada primarily focused on advancing growth plays in the Duvernay and Montney formations, with a goal of reducing drilling and completion costs. In the Duvernay, we brought on-line our first seven-well pad under budget and at production levels that are exceeding our initial expectations. The region averaged 68 Mboe/d during 2015.

International and Offshore

•

The Egypt region significantly reduced its drilling program throughout the year, averaging 14 rigs and drilling 122 gross wells, 107 net wells. Despite the reduction, gross production, which is subject to the terms of production sharing contracts, increased 1 percent. Egypt’s net production decreased 3 percent from 2014. Development of the Ptah and Berenice oil fields continued to deliver excellent results, with nine new wells brought on-line and combined gross field production exceeding 26,000 b/d at its peak. The region averaged 145 net Mboe/d during 2015.

•

The North Sea region averaged 6 rigs, drilling 26 gross wells, 22 net wells. During the year, the region averaged production of 71 Mboe/d. Apache was able to maintain relatively flat production year over year despite a 21 percent reduction in capital expenditures. The 2015 drilling program was extremely successful and sets up excellent growth and profitability opportunities over the next five years. During the fourth quarter of 2015, Apache announced five significant wells in the North Sea: three exploration discoveries and two notable development wells.

Exploration Discoveries

•

The K discovery, in the Beryl area, is a significant oil discovery with multiple commercial zones across three distinct fault blocks, including one fault block with over 1,500 feet of net pay. Apache is the operator of this discovery with a 55 percent working interest.

•

The Corona discovery, also located in the Beryl area, logged 225 feet total vertical depth net pay in excellent reservoir-quality sandstone. Apache has a 100 percent working interest in this discovery.

•

The Seagull discovery confirmed 672 feet of net oil pay over a 1,092-foot column in Triassic-age sands. The well was flow tested with a facility-constrained rate of 8.7 Mb/d of oil and 16 million cubic feet of natural gas per day (MMcf/d) with a very low pressure drawdown. Further appraisal work will continue following the recent acquisition of a multi-azimuth 3-D survey. Apache has a 35 percent working interest in this project and is now operator of this license.

Notable Development Wells

•

Apache drilled two significant development wells in the Beryl area, which Apache operates. Apache owns a 60.55 percent working interest in both wells. The ACN development well came online in October at a test rate of 11 Mb/d of oil and 30.4 MMcf/d of natural gas. The L4S pilot well started production in July and had an initial production rate of 2 Mb/d of oil and 45 MMcf/d of natural gas.

For a more detailed discussion related to our 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, we have repeatedly demonstrated our ability to capitalize quickly and decisively on changes in our industry and economic conditions. A key component of this strategy is to continuously review and optimize our portfolio of assets in response to changes. Most recently and prior to the precipitous decline of commodity prices beginning in 2014, Apache closed, or had agreements executed, on a series of divestitures designed to monetize nonstrategic assets and enhance our portfolio. These divestments comprised primarily capital intensive projects and assets that were not accretive to earnings in the near-term, and included all of our 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 (net of $225 million in customary, post-closing adjustments for the period between the effective date, October 1, 2014, and closing). 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 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.

•

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

•

Gulf of Mexico Shelf Operations On September 30, 2013, Apache completed the sale of its Gulf of Mexico Shelf operations and properties to Fieldwood Energy LLC (Fieldwood), an affiliate of Riverstone Holdings. Under the terms of the agreement, Apache received cash consideration of $3.7 billion, and Fieldwood assumed $1.5 billion of discounted asset abandonment liabilities. In respect of such abandonment liabilities, Fieldwood has posted letters of credit in the amount of $500 million and has established a trust account funded by a net profits interest, which contains approximately $140 million as of December 31, 2015. Additionally, Apache retained 50 percent of its ownership interest in both exploration blocks and in horizons below production in developed blocks, and access to existing infrastructure. The effective date of the transaction was July 1, 2013.

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

Results of Operations

Oil and Gas Revenues

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


	For the Year Ended December 31,
	2015				2014				2013
	$ Value		% Contribution		$ Value		% Contribution		$ Value		% Contribution
	($ in millions)

Total Oil Revenues:
United States	$	2,063		41%	$	4,260		43%	$	5,262		44%
Canada		244		5%		537		5%		563		5%

North America		2,307		46%		4,797		48%		5,825		49%

Egypt ⁽³⁾		1,582		32%		3,126		31%		3,528		30%
North Sea		1,110		22%		2,117		21%		2,500		21%

International ⁽³⁾		2,692		54%		5,243		52%		6,028		51%

Total⁽¹⁾⁽³⁾	$	4,999		100%	$	10,040		100%	$	11,853		100%


Total Natural Gas Revenues:
United States	$	382		33%	$	935		47%	$	1,096		48%
Canada		242		21%		479		24%		587		26%

North America		624		54%		1,414		71%		1,683		74%

Egypt ⁽³⁾		374		32%		400		20%		389		17%
North Sea		159		14%		169		9%		194		9%

International ⁽³⁾		533		46%		569		29%		583		26%

Total⁽²⁾⁽³⁾	$	1,157		100%	$	1,983		100%	$	2,266		100%


Total NGL Revenues:
United States	$	191		84%	$	549		82%	$	544		84%
Canada		12		5%		76		12%		74		11%

North America		203		89%		625		94%		618		95%

Egypt ⁽³⁾		13		6%		13		-		-		-
North Sea		11		5%		30		4%		34		5%

International ⁽³⁾		24		11%		43		6%		34		5%

Total ⁽³⁾	$	227		100%	$	668		100%	$	652		100%


Total Oil and Gas Revenues:
United States	$	2,636		41%	$	5,744		45%	$	6,902		47%
Canada		498		8%		1,092		9%		1,224		8%

North America		3,134		49%		6,836		54%		8,126		55%

Egypt ⁽³⁾		1,969		31%		3,539		28%		3,917		27%
North Sea		1,280		20%		2,316		18%		2,728		18%

International ⁽³⁾		3,249		51%		5,855		46%		6,645		45%

Total⁽³⁾	$	6,383		100%	$	12,691		100%	$	14,771		100%


Discontinued Operations:
Oil Revenue	$	138			$	757			$	1,050
Natural Gas Revenue		140				385				563
NGL Revenue		-				3				18

Total	$	278			$	1,145			$	1,631

⁽¹⁾

Financial derivative hedging activities decreased 2014 and 2013 oil revenues by $2 million and $47 million, respectively.

⁽²⁾

Financial derivative hedging activities increased 2014 and 2013 natural gas revenues by $2 million and $31 million, respectively.

⁽³⁾

Amounts include revenue attributable to a noncontrolling interest in Egypt.

Production

The following table presents production volumes by region:


	For the Year Ended December 31,
	2015		Increase (Decrease)	2014		Increase (Decrease)	2013
Oil Volume – b/d:
United States		123,666	(7%)		133,667	(9%)		146,907
Canada		15,768	(10%)		17,593	(1%)		17,724

North America		139,434	(8%)		151,260	(8%)		164,631

Egypt⁽¹⁾⁽²⁾		85,589	(3%)		87,917	(2%)		89,561
North Sea		59,334	(2%)		60,699	(5%)		63,721

International		144,923	(2%)		148,616	(3%)		153,282

Total		284,357	(5%)		299,876	(6%)		317,913

Natural Gas Volume – Mcf/d:
United States		440,037	(26%)		591,312	(24%)		781,335
Canada		274,764	(15%)		322,783	(35%)		497,515

North America		714,801	(22%)		914,095	(29%)		1,278,850

Egypt⁽¹⁾⁽²⁾		351,341	(5%)		370,262	4%		356,454
North Sea		64,787	16%		55,964	10%		50,961

International		416,128	(2%)		426,226	5%		407,415

Total		1,130,929	(16%)		1,340,321	(21%)		1,686,265

NGL Volume – b/d:
United States		53,928	(8%)		58,807	8%		54,580
Canada		6,126	(1%)		6,180	(8%)		6,689

North America		60,054	(8%)		64,987	6%		61,269

Egypt⁽¹⁾⁽²⁾		1,064	59%		671	NM		-
North Sea		1,131	(19%)		1,392	9%		1,272

International		2,195	6%		2,063	62%		1,272

Total		62,249	(7%)		67,050	7%		62,541

BOE per day:⁽³⁾
United States		250,934	(14%)		291,027	(12%)		331,709
Canada		67,688	(13%)		77,569	(28%)		107,332

North America		318,622	(14%)		368,596	(16%)		439,041

Egypt⁽¹⁾⁽²⁾		145,210	(3%)		150,298	1%		148,970
North Sea		71,262	0%		71,419	(3%)		73,487

International		216,472	(2%)		221,717	(0%)		222,457

Total		535,094	(9%)		590,313	(11%)		661,498

Discontinued Operations:
Oil (b/d)		7,610			22,227			28,704
Natural Gas (Mcf/d)		94,114			248,837			410,823
NGL (b/d)		-			317			2,102
BOE/d		23,296			64,017			99,277

⁽¹⁾

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


	2015		2014		2013
Oil (b/d)		206,501		197,366		197,622
Natural Gas (Mcf/d)		856,950		894,802		912,478
NGL (b/d)		2,459		1,901		-

⁽²⁾

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


Oil (b/d)	28,468	29,292	3,875
Natural Gas (Mcf/d)	116,929	123,511	16,278
NGL (b/d)	363	224	-

⁽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.

– Not meaningful

Pricing

The following table presents pricing information by region:


	For the Year Ended December 31,
	2015		Increase (Decrease)	2014		Increase (Decrease)	2013
Average Oil Price - Per barrel:
United States	$	45.71	(48%)	$	87.33	(11%)	$	98.14
Canada		42.33	(49%)		83.57	(4%)		87.00
North America		45.33	(48%)		86.89	(10%)		96.94
Egypt		50.65	(48%)		97.44	(10%)		107.94
North Sea		51.26	(46%)		95.53	(11%)		107.48
International		50.90	(47%)		96.66	(10%)		107.75
Total⁽¹⁾		48.17	(47%)		91.73	(10%)		102.15

Average Natural Gas Price - Per Mcf:
United States	$	2.38	(45%)	$	4.33	13%	$	3.84
Canada		2.41	(41%)		4.07	26%		3.23
North America		2.39	(44%)		4.24	17%		3.61
Egypt		2.92	(1%)		2.96	(1%)		2.99
North Sea		6.73	(19%)		8.29	(21%)		10.43
International		3.51	(4%)		3.66	(7%)		3.92
Total⁽²⁾		2.80	(31%)		4.05	10%		3.68

Average NGL Price - Per barrel:
United States	$	9.72	(62%)	$	25.57	(6%)	$	27.29
Canada		5.52	(84%)		33.61	10%		30.50
North America		9.29	(65%)		26.33	(5%)		27.64
Egypt		30.97	(40%)		51.80	NM		-
North Sea		26.53	(55%)		59.42	(19%)		73.06
International		28.68	(50%)		56.94	(22%)		73.06
Total		9.98	(63%)		27.28	(4%)		28.56

Discontinued Operations:
Oil price ($/Bbl)	$	49.76		$	93.28		$	100.17
Natural Gas price ($/Mcf)		4.07			4.24			3.76
NGL price ($/Bbl)		-			24.57			23.64

⁽¹⁾

Reflects a per-barrel decrease of $0.02 and $0.37 in 2014 and 2013, respectively, from financial derivative hedging activities.

⁽²⁾

Reflects a per-Mcf increase of $0.04 in 2013 from financial derivative hedging activities.

NM – Not meaningful

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 2015 were down 47 percent compared to 2014, a direct result of the sharply lower benchmark oil prices over the past year.

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 tighter global range. Price movements for all types and grades of crude oil generally move in the same direction. Crude oil prices realized in 2015 averaged $48.17 per barrel.

Natural Gas Prices

Natural gas, which currently has a limited global transportation system, is subject to price variances based on local supply and demand conditions. 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 $2.39 per Mcf in 2015, down from $4.24 per Mcf in 2014.

•

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 $2.92 per Mcf in 2015, down 1 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 $6.73 per Mcf in 2015, a 19 percent decrease from an average of $8.29 per Mcf in 2014.

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

2015 vs. 2014 During 2015 crude oil revenues totaled $5.0 billion, approximately 50 percent lower than the 2014 total of $10.0 billion, driven by a 47 percent decrease in average crude oil prices and a 5 percent decrease in worldwide production. Average daily production in 2015 was 284.4 Mb/d, with prices averaging $48.17 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 $273 million.

Worldwide crude oil production from continuing operations decreased 15.5 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.

2014 vs. 2013 During 2014 crude oil revenues totaled $10.0 billion, $1.8 billion lower than the 2013 total of $11.9 billion, driven by a 6 percent decrease in worldwide production and 10 percent decrease in average realized prices. Average daily production in 2014 was 300.0 Mb/d, with prices averaging $91.73 per barrel.

Crude oil represented 79 percent of our 2014 oil and gas production revenues and 51 percent of our equivalent production, compared to 80 and 48 percent, respectively, in the prior year. Lower realized prices reduced revenues $1.2 billion, while lower production volumes reduced revenues $604 million.

Worldwide crude oil production from continuing operations decreased 18.0 Mb/d, however, when excluding production from asset divestitures during 2014 and 2013, crude oil production increased 17.0 Mb/d. This increase was driven by production growth of 20.1 Mb/d in our Permian region as a result of higher drilling and recompletion activity, partially offset by a decrease in production from the North Sea on natural decline.

Natural Gas Revenues

2015 vs. 2014 Natural gas revenues of $1.2 billion for 2015 were $826 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 209.4 MMcf/d, lowering revenues by $214 million. Realized prices in 2015 averaged $2.80 per Mcf, a decrease of $1.25 per Mcf compared to 2014, which decreased revenues by $612 million.

Worldwide gas production from continuing operations decreased 16 percent. Excluding production from asset divestitures during 2015 and 2014, gas production decreased only 1 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.

2014 vs. 2013 Natural gas revenues of $2.0 billion for 2014 were $283 million lower than 2013, the result of a 21 percent decrease in production volumes offset by a 10 percent increase in realized prices. Worldwide production decreased 345.9 MMcf/d, lowering revenues by $511.8 million. Realized prices in 2014 averaged $4.05 per Mcf, an increase of $0.37 per Mcf from 2013, which increased revenues by $229 million.

Worldwide gas production from continuing operations decreased 21 percent. However, excluding production from asset divestitures during 2015 and 2014, gas production increased 14.2 MMcf/d. This increase was driven by production growth of 28.0 MMcf/d in the Permian region as a result of higher drilling and recompletion activity. Egypt’s net production increased 13.8 MMcf/d as a result of our successful drilling program with new wells coming on-line during 2014, and production from the North Sea increased 5 MMcf/d on stronger than expected well performance.

NGL Revenues

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.

2014 vs. 2013 NGL revenues totaled $668 million in 2014, an increase of $16 million from 2013, the result of a 7 percent increase in production volumes partially offset by a 4 percent decrease in realized prices. Worldwide production from continuing operations increased 4.5 Mb/d, which added $44.9 million to revenues. This increase was primarily driven by drilling and recompletion activity in our North American onshore regions. Realized prices in 2014 averaged $27.28 per barrel, a decrease of $1.28 per barrel, which reduced revenues by $29.4 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,
	2015		2014		2013		2015		2014		2013
	(In millions)						(Per boe)
Depreciation, depletion and amortization:
Oil and gas property and equipment
Recurring	$	3,531	$	4,388	$	4,534	$	18.08	$	20.36	$	18.78
Additional		25,517		5,001		995		130.65		23.21		4.12
Other assets		324		331		337		1.66		1.54		1.40
Asset retirement obligation accretion		145		154		211		0.74		0.72		0.88
Lease operating costs		1,854		2,238		2,650		9.49		10.39		10.97
Gathering and transportation costs		211		273		288		1.07		1.27		1.19
Taxes other than income		282		577		772		1.45		2.68		3.20
Impairments		1,920		1,919		-		9.83		8.90		-
General and administrative expense		377		451		481		1.93		2.09		1.99
Transaction, reorganization, and separation costs		132		67		33		0.68		0.31		0.13
Financing costs, net		299		211		229		1.53		0.98		0.95

Total	$	34,592	$	15,610	$	10,530	$	177.11	$	72.45	$	43.61

Recurring Depreciation, Depletion and Amortization (DD&A)

2015 vs. 2014 Oil and gas property recurring DD&A expense of $3.5 billion in 2015 decreased $857 million compared to 2014. The Company’s oil and gas property recurring DD&A rate decreased $2.28 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 property carrying values resulting from significant property write-downs incurred during 2015.

2014 vs. 2013 Recurring full-cost depletion expense decreased $146 million on an absolute dollar basis: $412 million on lower volumes partially offset by an increase of $266 million from a higher average cost rate per boe. Our full-cost depletion rate increased $1.58 to $20.36 per boe reflecting increased cost for exploration and development activity over the prior years.

Additional DD&A

Under the full-cost method of accounting, the Company is required to review the carrying value of its proved oil and gas properties each quarter on a country-by-country basis. Under these rules, capitalized costs of oil and gas properties, net of accumulated DD&A and deferred income taxes, may not exceed the present value of estimated future net cash flows from proved oil and gas reserves, net of related tax effects and discounted 10 percent per annum and adjusted for cash flow hedges. Estimated future net cash flows are calculated using end-of-period costs and an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months, held flat for the life of the production, except where prices are defined by contractual arrangements.

Apache recorded non-cash after-tax write-downs of its proved oil and gas properties totaling $16.6 billion, $3.1 billion, and $541 million in 2015, 2014, and 2013, respectively. The following table reflects write-downs by country:


	For the Year Ended December 31, 2015				For the Year Ended December 31, 2014				For the Year Ended December 31, 2013
	Before tax		After tax		Before tax		After tax		Before tax		After tax
	(In millions)
U.S.	$	19,537	$	12,602	$	4,412	$	2,844	$	552	$	356
Canada		3,667		2,721		-		-		-		-
North Sea		2,032		1,016		589		224		368		139
Egypt		281		281		-		-		-		-
Other international		-		-		-		-		75		46

Total write-downs	$	25,517	$	16,620	$	5,001	$	3,068	$	995	$	541

In 2013, the Company recorded a non-cash write-down of $118 million, net of tax, in Argentina, which is reflected as discontinued operations in the Company’s consolidated financial statements.

If commodity prices do not recover significantly from current levels, the Company expects further write-downs of the carrying value of its oil and gas properties as the full cost ceiling limitation was calculated using a historical 12-month pricing average that included commodity prices from 2015. These prices were significantly higher than current commodity futures prices. To estimate the full cost ceiling limitation for 2016, had the Company utilized commodity futures prices as of December 31, 2015 in lieu of using historical commodity prices to calculate the 12-month unweighted arithmetic average price, the write-down as of December 31, 2015 would have been higher by $4.3 billion ($3.0 billion net of tax).

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 2015 production, is inherently more expensive to produce than natural gas. Repair and maintenance costs are typically higher on offshore properties.

During 2015, LOE decreased $384 million, or 17 percent, on an absolute dollar basis compared to 2014. On a per-unit basis, LOE decreased $0.90, or 9 percent compared to 2014. During 2014, LOE decreased $412 million, or 16 percent, on an absolute dollar basis compared to 2013. On a per-unit basis, LOE decreased $0.58, or 5 percent, compared to 2013. These reductions reflect our continued focus on cost reductions consistent with the current price environment.

Gathering and Transportation

We generally sell oil and natural gas under two common types of agreements, both of which include a transportation charge. One is a netback arrangement, under which we sell oil or natural gas at the wellhead and collect a lower relative price to reflect transportation costs to be incurred by the purchaser. In this case, we record sales at the netback price received from the purchaser. Alternatively, we sell oil or natural gas at a specific delivery point, pay our own transportation to a third-party carrier, and receive a price with no transportation deduction. In this case, we record the separate transportation cost as gathering and transportation costs.

In the U.S. and Canada we sell oil and natural gas under both types of arrangements. In the North Sea, we pay transportation charges to a third-party carrier. In Egypt, our oil and natural gas production is primarily sold to EGPC under netback arrangements; however, we also export crude oil under both types of arrangements.

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

2014 vs. 2013 Gathering and transportation costs decreased $15 million from 2013. Canada’s 2014 costs decreased $32 million from a decline in production primarily associated with divestitures. The U.S. costs for 2014 increased $9 million as compared to 2013 primarily as a result of increased production in the MidContinent/Gulf Coast and Permian regions from increased drilling activity partially offset by a decrease from the Gulf of Mexico asset sales. Egypt costs were down $2 million from decreases in the world scale freight rates. North Sea costs increased $10 million on increased NGL activity and oil transportation tariffs.

Taxes Other Than Income

Taxes other than income primarily consist of U.K. Petroleum Revenue Tax (PRT), severance taxes on properties onshore and in state or provincial waters off the coast of the U.S., and 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 Resources surtax. The table below presents a comparison of these expenses:


	For the Year Ended December 31,
	2015		2014		2013
	(In millions)
U.K. PRT	$	59	$	177	$	373
Severance taxes		121		259		257
Ad valorem taxes		77		104		104
Other		25		37		38

Total Taxes other than income	$	282	$	577	$	772

2015 vs. 2014 Taxes other than income 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. In 2015, the U.K. government enacted Finance Bill 2015, which provides tax relief to exploration and production (E&P) companies operating in the North Sea. Effective January 1, 2016, the U.K. PRT rate is reduced from 50 percent to 35 percent.

2014 vs. 2013 Taxes other than income were $195 million lower than 2013. U.K. PRT decreased $196 million over the comparable 2013 period based on a decrease in production revenues in the North Sea from qualifying fields during the year. Severance tax increased $2 million with increased production from the Permian region offset by higher tax credits and decreased commodity prices.

Impairments

During 2015, the Company recorded asset impairments totaling $1.9 billion in connection with fair value assessments in the current low commodity price environment, including $1.7 billion for the impairment of gathering, transmission, and processing (GTP) facilities, $148 million for the impairment of our YPHPL equity method investment sold in the fourth quarter, and $55 million for inventory write-downs. GTP impairments included $555 million ($410 million net of tax) for facilities in Canada, $102 million in the U.S. ($66 million net

of tax), 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 $1.9 billion in connection with fair value assessments, including $1.3 billion for the impairment of goodwill, $604 million for the impairment of assets held for sale, and other asset impairments. The Company had also recorded $439 million in impairments related to the sale of Australia’s assets, which are classified as discontinued operations in 2014.

General and Administrative (G&A) Expenses

2015 vs. 2014 G&A expenses decreased $74 million, or 16 percent, from 2014. On a per-unit basis, G&A expenses decreased $0.16 to $1.93 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.

2014 vs. 2013 G&A expenses decreased $30 million, or 6 percent, from 2013. On a per-unit basis, G&A expenses increased $0.10 to $2.09 per boe, with the benefit of lower costs partially offset by the impact of lower production.

Transaction, Reorganization, and Separation Costs

Apache recorded $132 million, $67 million and $33 million of expenses during 2015, 2014, and 2013, respectively, primarily related to divestiture activity and company reorganization, including separation costs, investment banking fees and other associated costs. The charges for 2015 include $53 million for employee separation cost; $42 million associated with office closings, consolidation of office space in Houston, and other reorganization efforts; and $36 million related to the Australia divestiture and other transactions.

Financing Costs, Net

Financing costs incurred during the period comprised the following:


	For the Year Ended December 31,
	2015		2014		2013
	(In millions)

Interest expense	$	486	$	499	$	560
Amortization of deferred loan costs		11		6		8
Capitalized interest		(227)		(287)		(315)
Loss (gain) on extinguishment of debt		39		-		(16)
Interest income		(10)		(7)		(8)

Total Financing costs, net	$	299	$	211	$	229

2015 vs. 2014 Net financing costs increased $88 million from 2014. The increase is primarily related to a decrease of $60 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.

2014 vs. 2013 Net financing costs decreased $18 million from 2013. The decrease is primarily related to a $61 million decrease in interest expense as a result of lower average debt balances during 2014, partially offset by a $28 million decrease in capitalized interest resulting from lower property balances and a $16 million gain on extinguishment of debt in 2013.

Provision for Income Taxes

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 $5.5 billion. The deferred tax position in the U.S. changed from a net deferred tax liability as of December 31, 2014 to a net deferred tax asset as of December 31, 2015 as a result of $19.5 billion in non-cash ceiling test write-downs and the recognition of $2.1 billion of deferred tax assets related to foreign tax credit carryforwards. The 2015 effective tax rate reflects an increase in valuation allowance against the U.S. and Canadian region’s net deferred tax assets. Separately, the U.K. government enacted Finance Bill 2015 that provides 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 $619 million related to the remeasurement of the Company’s December 31, 2014 U.K. deferred income tax liability.

The 2014 provision for income taxes from continuing operations totaled $663 million. The 2014 effective rate reflects the tax benefit from the $5.0 billion non-cash ceiling test write-down in the U.S. and North Sea. The Company’s rate is also impacted by the $560 million of deferred income tax expense recorded in 2014 for changing our position on undistributed earnings on foreign subsidiaries and $311 million of deferred income tax expense on distributed foreign earnings. In addition, the Company had approximately $1.9 billion of impairments related to non-cash write-downs of goodwill and assets held for sale which impact the effective tax rate.

For additional information regarding income taxes, please refer to Note 7—Income Taxes in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.

Capital Resources and Liquidity

Operating cash flows are the Company’s primary source of liquidity. We may also elect to utilize available 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.

Deterioration in commodity prices also impacts estimated quantities of proved reserves. During 2015, we recognized negative reserve revisions of approximately 15 percent of our year-end 2014 estimated proved reserves as a result of lower prices. If realized prices for the remainder of 2016 approximate commodity future prices as of December 31, 2015, the Company is reasonably likely to report additional negative revisions, currently estimated at eight to ten percent of year-end 2015 estimated proved reserves.

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.

commodity price movements throughout the year. Our budgeted amounts exclude expenditures attributable to a one-third non-controlling interest in Egypt. Our capital budget for 2016 has been, and will be, allocated on a prioritized basis as follows: (i) maintain assets and keeping them running efficiently and preserve mineral rights and leases, (ii) further optimize and build high quality inventory for the future, (iii) conduct certain medium-cycle, high impact exploration activities, and (iv) conduct limited-scale development activities that remain economically robust at these low prices. In addition, we will continue our overhead and LOE cost reduction efforts in order to position Apache for an extended low commodity price environment.

We believe the liquidity and capital resource alternatives available to Apache, combined with proactive measures to adjust our capital budget to reflect lower commodity prices and anticipated operating cash flows, 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.

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,
	2015		2014		2013
	(In millions)
Sources of Cash and Cash Equivalents:
Net cash provided by continuing operating activities	$	2,834	$	7,517	$	8,685
Proceeds from Australian divestitures		5,084		-		-
Net cash provided by Argentina discontinued operations		-		788		18
Proceeds from asset divestitures		1,122		3,092		4,405
Proceeds from sale of Egypt noncontrolling interest		-		-		2,948
Commercial paper and bank loan borrowings, net		-		1,568		-
Other		59		-		-

		9,099		12,965		16,056

Uses of Cash and Cash Equivalents:
Capital expenditures⁽¹⁾	$	4,811	$	9,903	$	9,127
Leasehold and property acquisitions		367		1,475		429
Net cash used by Australia discontinued operations		208		105		732
Commercial paper, credit facility and bank loan repayments, net		1,570		-		509
Payments on fixed-rate debt		939		-		2,072
Shares repurchased		-		1,864		997
Dividends paid		377		365		360
Distributions to noncontrolling interest		129		140		-
Other		-		250		84

		8,401		14,102		14,310

Increase (decrease) in cash and cash equivalents	$	698	$	(1,137)	$	1,746

⁽¹⁾

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

Net Cash Provided by Continuing Operating Activities

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

Net cash provided by continuing operating activities for 2015 totaled $2.8 billion, down $4.7 billion from 2014. The decrease primarily reflects lower commodity prices and divestitures.

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 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 and losses on disposal are classified as discontinued operations in all periods presented in this Annual Report on Form 10-K. In addition, Apache sold its 49 percent interest equity method investment in YPHPL for total cash proceeds of $391 million.

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 2015, 2014, and 2013, Apache had proceeds from divestitures totaling $1.1 billion, $3.1 billion, and $4.4 billion, respectively. For information regarding our acquisitions and divestitures, please see Note 2—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.

Egypt Noncontrolling Interest

During 2013, Apache completed the sale of a one-third minority participation in its Egypt oil and gas business to Sinopec for $2.95 billion. Apache made cash distributions totaling $129 million and $140 million to Sinopec in 2015 and 2014, respectively.

Capital Expenditures

During 2015, capital spending for exploration and development (E&D) activities totaled $4.6 billion compared to $9.0 billion in the prior year. Apache’s E&D capital spending was primarily focused on our North American onshore region, where Apache operated an average of 19 drilling rigs. Apache’s investment in gas gathering, transmission, and processing facilities totaled $233 million and $881 million during 2015 and 2014, respectively. Apache’s investment in GTP was primarily for the Kitimat LNG project, which was divested in the second quarter of 2015.

Apache also completed leasehold and property acquisitions totaling $367 million during 2015, compared with $1.5 billion in 2014. 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 2015 and is not obligated to acquire any specific number of shares.

Dividends

The Company has paid cash dividends on its common stock for 51 consecutive years through 2015. Future dividend payments will depend on the Company’s level of earnings, financial requirements, and other relevant factors. Common stock dividends paid during 2015 totaled $377 million, compared with $365 million in 2014 and $303 million in 2013. The Company paid dividends on its Series D Preferred Stock totaling $57 million in 2013. The preferred stock was converted to common stock in August 2013.

Liquidity


	At December 31,
	2015		2014
	(In millions, except percentages)
Cash and cash equivalents	$	1,467	$	769
Total debt		8,778		11,245
Equity		4,228		28,137
Available committed borrowing capacity		3,500		3,730
Floating-rate debt/total debt		0%		14%

Cash and Cash Equivalents

At December 31, 2015, we had $1.5 billion in cash and cash equivalents, of which $1.1 billion of cash was held by foreign subsidiaries, and approximately $382 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 securities with maturities of three months or less at the time of purchase.

Debt

At December 31, 2015, outstanding debt, which consisted of notes and debentures, totaled $8.8 billion. We have $550 million maturing in 2018, $150 million maturing in 2019, and the remaining $8.1 billion maturing in years 2021 through 2096. At December 31, 2015, we had $416,000 of notes due June 2016 classified as current debt on the consolidated balance sheet.

In September 2015, the Company fully redeemed its $500 million 5.625% notes due in 2017 and its $400 million 1.75% notes due in 2017. The notes were redeemed pursuant to the provisions of each respective note’s indenture. Apache paid the holders an aggregate of $939 million in cash reflecting principal and the premium to par, and an additional $8 million in accrued and unpaid interest.

Available Credit Facilities

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, 2015, aggregate available borrowing capacity under this credit facility was $3.5 billion.

At the Company’s option, the interest rate per annum for borrowings under the facility is either a base rate, as defined, plus a margin, or the London Inter-bank Offered Rate (LIBOR), plus a margin. At December 31, 2015 the margin over LIBOR was 1.0 percent. The Company also pays quarterly a facility fee at a per annum rate on total commitments, which at December 31, 2015 was 0.125 percent on the total $3.5 billion in commitments. The margins and the facility fee vary based upon the Company’s senior long-term debt rating. As a result of recent ratings downgrades, the base rate margin is 0.075 percent, the LIBOR margin is 1.075 percent, and the facility fee is 0.175 percent as of the date of filing this report.

The financial covenants of the 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, 2015, the Company’s debt-to-capital ratio as calculated under the credit facility was 34 percent.

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 $940 million as of December 31, 2015. 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.

There are no clauses in the facility that permit the lenders to accelerate payments or refuse to lend based on unspecified material adverse changes. The credit facility agreement does not have drawdown restrictions or prepayment obligations in the event of a decline in credit ratings. However, the agreement allows the lenders to accelerate payment maturity and terminate lending 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 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 the credit facility as of December 31, 2015.

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 and loans to cash collateralize letter of credit obligations 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 $3.5 billion revolving credit facility. Commissions are payable on outstanding letters of credit and borrowings bear interest (at a base rate or LIBOR), plus a margin. Letter of credit commissions, the interest margin, and the facility fee vary depending on Apache’s senior unsecured long-term debt rating. The Company has not requested any letters of credit or borrowings under this facility as of the date of this filing. This 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.

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, 2015, 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, 2015, the Company had no borrowings under its commercial paper program, bank facility, or uncommitted bank lines.

Off-Balance Sheet Arrangements

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

Contractual Obligations

The following table summarizes the Company’s contractual obligations as of December 31, 2015. For additional information regarding these obligations, please see Note 6—Debt and Note 8—Commitments and Contingencies in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.


Contractual Obligations⁽¹⁾	Note Reference		Total		2016		2017-2018		2019-2020		2021 & Beyond
	(In millions)
Debt, at face value		Note 6	$	8,831	$	1	$	550	$	150	$	8,130
Interest payments		Note 6		9,216		447		889		807		7,073
Drilling rig commitments⁽²⁾		Note 8		405		194		211		-		-
Purchase obligations⁽³⁾		Note 8		354		28		115		139		72
Firm transportation agreements⁽⁴⁾		Note 8		363		96		125		83		59
Office and related equipment		Note 8		342		43		87		72		140
Other operating lease obligations⁽⁵⁾		Note 8		64		22		35		6		1


Total Contractual Obligations			$	19,575	$	831	$	2,012	$	1,257	$	15,475

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

⁽²⁾

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

⁽³⁾

Purchase obligations represent agreements to purchase goods or services that are enforceable, are legally binding, and specify all significant terms, including fixed and minimum quantities to be purchased; fixed, minimum or variable price provisions; and the appropriate timing of the transaction. These include minimum commitments associated with take-or-pay contracts, NGL processing agreements, and drilling work program commitments.

⁽⁴⁾

Firm transportation commitments relate to contractual obligations for capacity rights on third-party pipelines.

⁽⁵⁾

Other operating lease obligations pertain to other long-term exploration, development, and production activities. The Company has work-related commitments for supply and standby vessels, gas pipeline and land 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 feels that it has adequately reserved for its contingent

obligations, including approximately $52 million for environmental remediation and approximately $29 million for various contingent legal liabilities. For a detailed discussion of the Company’s environmental and legal contingencies, please see Note 8—Commitments and Contingencies in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.

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 its 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) is currently planning to issue a new Notice to Lessees (NTL) 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. We currently expect such new NTL may require Apache to provide additional security to the 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 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.

Insurance Program

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

Our current insurance policies covering physical damage to our assets provide $1 billion in coverage per occurrence. These policies also provide sudden 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, subject to a retention that must be met prior to recovery. This coverage is in excess of any existing policies, including, but not limited to, aircraft liability and automobile liability. Our service agreements, including drilling contracts, generally indemnify Apache for injuries and death of the service provider’s employees as well as subcontractors hired by the service provider.

Apache purchases multi-year political risk insurance from the Overseas Private Investment Corporation (OPIC) and other highly rated international insurers covering a portion of its investments in Egypt 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, subject to the policy terms and conditions, provide approximately $750 million of coverage to Apache, subject to a self-insured retention of approximately $1 billion.

In addition, Apache has a separate policy with OPIC, which, subject to policy terms and conditions, provides $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.

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

Reserves are calculated using an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months, held flat for the life of the production, except where prices are defined by contractual arrangements.

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

Asset Retirement Obligation (ARO)

The Company has significant obligations to remove tangible equipment and restore land or seabed at the end of oil and gas production operations. Apache’s removal and restoration obligations are primarily associated with plugging and abandoning wells and removing and disposing of offshore oil and gas platforms 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. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property balance. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value.

Income Taxes

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

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

Purchase Price Allocation

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

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

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

Long-Lived Assets

Long-lived assets used in operations, excluding oil and gas properties accounted for under the full-cost method of accounting, 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. If there is an indication the carrying amount of an asset may not be recovered, the asset is monitored by management through an established process where 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. 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. 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 based on judgmental assessments of future production volumes, commodity prices, operating costs, and capital decisions, considering all available information at the date of review.

During 2015, there was a substantial decline in commodity prices. The resulting change in future commodity price assumptions and plan for cash 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 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.

Goodwill

As of December 31, 2015, 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^st 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.

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.

No goodwill impairment was recognized during 2015. During the fourth quarter of 2014, the Company recognized non-cash impairments of the entire amount of recorded goodwill in the U.S., North Sea, and Canada reporting units of $1.0 billion, $163 million, and $103 million, respectively.

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 2015, our average crude oil realizations decreased to $48.17 per barrel compared to $91.73 per barrel in 2014. Our average natural gas price realizations decreased 31 percent in 2015 to $2.80 per Mcf from $4.05 per Mcf in 2014.

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 2015, the Company did not have any derivative positions. In 2014, approximately 9 percent of our natural gas production from continuing operations and approximately 39 percent of our crude oil production from continuing operations was subject to financial derivative hedges.

See Note 3—Derivative Instruments and Hedging Activities in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.

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, 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, 2015, would result in a foreign currency net loss or gain, respectively, of approximately $122 million.

ITEM 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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

ITEM 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

The financial statements for the fiscal years ended December 31, 2015, 2014, and 2013, included in this report, have been audited by Ernst & Young LLP, registered public accounting firm, as stated in their audit report appearing herein. There have been no changes in or disagreements with the accountants during the periods presented.

ITEM 9A.

CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

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, 2015, 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, 2015, 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, 2015, that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

ITEM 9B.

OTHER INFORMATION

The registrant elects to disclose under this Item 9B information otherwise disclosable in a report on Form 8-K for an event which occurred on February 22, 2016. Disclosure for the event, which otherwise would be reportable on Form 8-K under “Item 1.01 Entry into a Material Definitive Agreement” and “Item 2.03 Creation of a Direct Financial Obligation or an Obligation under an Off-Balance Sheet Arrangement of a Registrant”, is as follows:

On February 22, 2016, Apache Corporation, a Delaware corporation (“Apache”), entered into a Credit Agreement among Apache, 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 (the “LC Facility”).

The LC Facility provides for a three-year letter of credit facility and aggregate commitments of 900.0 million pounds sterling (“GBP”), with rights to increase commitments up to an aggregate GBP1.075 billion. Apache may increase commitments by adding additional lenders or by allowing one or more existing lenders to increase their commitments by up to an aggregate GBP175.0 million. The facility is available for the issuance of letters of credit denominated in GBP, US Dollars, Canadian Dollars, and in any other foreign currency consented to by an issuing bank. The facility also is available for loans in GBP, US 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 aggregate undrawn amount of outstanding letters of credit, unreimbursed drawings under issued letters of credit, and borrowings outstanding at any time under the LC Facility may not exceed the total commitments thereunder at that time.

Borrowers under the LC Facility may include Apache and certain subsidiaries organized under the laws of, or domiciled in, the United States, Canada, England and Wales, the United Kingdom, or the Cayman Islands (each a “Borrower”). Each Borrower may obtain letters of credit and borrow, prepay, and reborrow loans, and Apache may obtain letters of credit for the account its subsidiaries, in each case subject to representations and warranties, covenants, and events of default that are substantially similar to those in Apache’s existing 2015 revolving credit facility.

All amounts outstanding under the LC Facility are due February 22, 2019, provided that Apache may once request that the maturity date be extended for one successive period expiring one year from the then scheduled maturity date. No lender is obligated to consent to any extension; however, effective on or before the original maturity date, Borrower may elect to replace any non-consenting lender and proceed with the extension as to remaining commitments, provided that lenders having at least 51% of the aggregate total commitments have agreed to the requested extension.

All borrowings under the LC Facility bear interest at one of the following rate options, as selected by Borrower:

•

A base rate plus a margin, with the (i) base rate being a rate per annum equal to the greatest of (a) the prime rate as announced by the Administrative Agent, (b) the federal funds rate plus 0.50%, and (c) the London Interbank Offered Rate (“LIBOR”) for a one-month interest period plus 1.0%, and (ii) margin (“Base Rate Margin”) being a rate per annum that varies from 0.0% to 0.65% based on the rating for Apache’s senior, unsecured, non-credit enhanced, long-term indebtedness for borrowed money (“Long-Term Debt Rating”); or

•

LIBOR plus a margin (“LIBOR Margin”) at a rate per annum varying from 0.69% to 1.65% based on Apache’s Long-Term Debt Rating. For LIBOR-based interest rates, Apache may select an interest period with respect to any currency of one, two, three or six months, or one week, and additionally with respect to GBP borrowings, one day.

The LC Facility also requires Borrower to pay a facility fee equal to a per annum rate that varies from 0.06% to 0.35% of the full amount of the commitments based on its Long-Term Debt Rating.

Currently, the Base Rate Margin is 0.075%, the LIBOR Margin is 1.075%, and the facility fee is 0.175%. A commission is payable quarterly to lenders on the face amount of each outstanding letter of credit at a per annum rate equal to the LIBOR Margin then in effect. Customary letter of credit fronting fees and other charges are payable to issuing banks.

The foregoing summary of the LC Facility does not purport to be complete and is subject to, and qualified in its entirety by, the full text of the LC Facility, a copy of which is filed as Exhibit 10.10 to this report and incorporated herein by reference.

The LC Facility has been filed with this report to provide investors and security holders with information regarding its terms. It is not intended to provide any other factual information about Apache. Representations, warranties, and covenants in the LC Facility were made only for purposes of the LC Facility, were solely for the benefit of the parties to the LC Facility, and may be subject to limitations agreed upon by the contracting parties, including being qualified by confidential disclosures exchanged between the parties in connection with the execution of the LC Facility. Representations and warranties in the LC Facility may have been made as of specific dates and for purposes of allocating contractual risk between the parties instead of establishing matters as facts, and may be subject to standards of materiality applicable to the contracting parties that differ from those applicable to investors. Investors are not third-party beneficiaries under the LC Facility and should not rely on the representations, warranties, and covenants or any descriptions thereof as characterizations of the actual state of facts or condition of Apache or any of its subsidiaries or affiliates. Moreover, information concerning the subject matter of the representations and warranties may change after the date of a LC Facility, which subsequent information may or may not be fully reflected in Apache’s public disclosures.

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 2016 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 January 2015. 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.

PART IV

ITEM 15.

EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a)

Documents included in this report:

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, 2015			F-4
Statement of consolidated comprehensive income (loss) for each of the three years in the period ended December 31, 2015			F-5
Statement of consolidated cash flows for each of the three years in the period ended December 31, 2015			F-6
Consolidated balance sheet as of December 31, 2015 and 2014			F-7
Statement of consolidated changes in equity for each of the three years in the period ended December 31, 2015			F-8
Notes to consolidated financial statements			F-9

Financial Statement Schedules

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

Exhibits


EXHIBIT NO.		DESCRIPTION

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

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

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

3.1	–	Restated Certificate of Incorporation of Registrant, dated September 19, 2013, as filed with the Secretary of State of Delaware on September 19, 2013 (incorporated by reference to Exhibit 3.2 to Registrant’s Current Report on Form 8-K filed September 20, 2013, SEC File No. 001-4300).

3.2	–	Certificate of 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).


EXHIBIT NO.		DESCRIPTION
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).


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

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

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

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

4.17	–	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).


EXHIBIT NO.		DESCRIPTION

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 Registrant, 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).


EXHIBIT NO.		DESCRIPTION
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).

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.

*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.

†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).


EXHIBIT NO.		DESCRIPTION
†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.

†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.

†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 2011 Omnibus Equity Compensation Plan, as amended and restated December 15, 2015.

†10.22	–	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).

†10.23	–	Apache Corporation 2003 Stock Appreciation Rights Plan, as amended and restated September 16, 2013 (incorporated by reference to Exhibit 10.2 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2013, 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, Commission 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 November 11, 2013 (incorporated by reference to Exhibit 10.23 to Registrant’s Annual Report on Form 10-K for the year ended December 31, 2013, SEC File No. 001-4300).


EXHIBIT NO.		DESCRIPTION
†10.27	–	Apache Corporation Non-Employee Directors’ Compensation Plan, as amended and restated July 16, 2014, effective July 1, 2014 (incorporated by reference to Exhibit 10.4 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2014, SEC File No. 001-4300).

†10.28	–	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).

†10.29	–	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).

†10.30	–	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).

†10.31	–	Apache Corporation Non-Employee Directors’ Restricted Stock Units Program, as amended and restated July 16, 2014, pursuant to Apache Corporation 2011 Omnibus Equity Compensation Plan (incorporated by reference to Exhibit 10.6 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2014, SEC File No. 001-4300).

†10.32	–	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).

†10.33	–	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	–	Employee Release and Settlement Agreement, dated February 11, 2014, between Registrant and Roger B. Plank (incorporated by reference to Exhibit 10.2 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014, SEC File No. 001-4300).

†10.37	–	Employee Release and Settlement Agreement, effective August 31, 2014, between Registrant and Thomas P. Chambers (incorporated by reference to Exhibit 10.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2014, SEC File No. 001-4300).


EXHIBIT NO.		DESCRIPTION
†10.38	–	Employee Resignation Agreement, effective October 13, 2014, between Registrant and Alfonso Leon (incorporated by reference to Exhibit 10.4 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2014, SEC File No. 001-4300).

†10.39	–	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).

†10.40	–	2015 Employee Release and Settlement Agreement between Registrant and Michael S. Bahorich, dated April 8, 2015 (incorporated by reference to Exhibit 10.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2015, SEC File No. 001-4300).

*†10.41	–	2016 Employee Release and Settlement Agreement between Registrant and Thomas E. Voytovich, effective November 30, 2015.

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

†10.43	–	Form of Restricted Stock Unit Award Agreement, dated February 12, 2009 (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K, dated February 12, 2009, filed February 18, 2009, SEC File No. 001-4300).

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

†10.45	–	Form of Restricted Stock Unit Grant Agreement, dated May 6, 2009 (incorporated by reference to Exhibit 10.38 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2009, SEC File No. 001-4300).

†10.46	–	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).

†10.47	–	Form of 2010 Performance Program Agreement, dated January 15, 2010 (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed January 19, 2010, SEC File No. 001-4300).

†10.48	–	Form of First Amendment, effective May 5, 2010, to 2010 Performance Program Agreement, dated January 15, 2010 (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed May 11, 2010, SEC File No. 001-4300).

†10.49	–	Form of Restricted Stock Unit Award Agreement, dated January 15, 2010 (incorporated by reference to Exhibit 10.2 to Registrant’s Current Report on Form 8-K filed January 19, 2010, SEC File No. 001-4300).

†10.50	–	Form of 2011 Performance Program Agreement, dated January 7, 2011 (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed January 13, 2011, SEC File No. 001-4300).

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


EXHIBIT NO.		DESCRIPTION
†10.52	–	Form of 2012 Performance Program Agreement, dated January 11, 2012 (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed January 13, 2012, SEC File No. 001-4300).

†10.53	–	Form of 2013 Performance Program Agreement, dated January 9, 2013 (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed January 11, 2013, SEC File No. 001-4300).

†10.54	–	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).

†10.55	–	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).

†10.56	–	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).

†10.57	–	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).

†10.58	–	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).

*†10.59	–	Form of 2016 Performance Share Program Award Notice and Agreement, dated January 7, 2016.

*†10.60	–	Form of Restricted Stock Unit Award Agreement, dated February 3, 2016.

*†10.61	–	Form of Stock Option Award Agreement, dated February 3, 2016.

†10.62	–	Amendments of Stock Option Grants (2007 and 2011 Omnibus Equity Compensation Plans), dated February 13, 2014, between Registrant and Roger B. Plank (incorporated by reference to Exhibits 10.3 and 10.4 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014, SEC File No. 001-4300).

†10.63	–	Amendment to Restricted Stock Unit Awards, dated February 13, 2014, between Registrant and Roger B. Plank (incorporated by reference to Exhibit 10.5 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014, SEC File No. 001-4300).

†10.64	–	Amendment of Stock Option Grants (2007 and 2011 Omnibus Equity Compensation Plans), effective August 31, 2014, between Registrant and Thomas P. Chambers (incorporated by reference to Exhibit 10.2 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2014, SEC File No. 001-4300).

†10.65	–	Amendment of Restricted Stock Unit Awards (2007 and 2011 Omnibus Equity Compensation Plans), effective August 31, 2014, between Registrant and Thomas P. Chambers (incorporated by reference to Exhibit 10.3 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2014, SEC File No. 001-4300).


EXHIBIT NO.		DESCRIPTION
†10.66	–	Amendment of Stock Option Grants (2007 and 2011 Omnibus Equity Compensation Plans), effective October 9, 2014, between Registrant and Alfonso Leon (incorporated by reference to Exhibit 10.5 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2014, SEC File No. 001-4300).

†10.67	–	Amendment of Restricted Stock Unit Awards (2007 and 2011 Omnibus Equity Compensation Plans), effective October 9, 2014, between Registrant and Alfonso Leon (incorporated by reference to Exhibit 10.6 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2014, SEC File No. 001-4300).

†10.68	–	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).

†10.69	–	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).

†10.70	–	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).

†10.71	–	Amendment of 2014 Performance Program (Business Performance) Award (2011 Omnibus Equity Compensation Plan), effective June 30, 2015, between Registrant and Michael S. Bahorich (incorporated by reference to Exhibit 10.2 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2015, SEC File No. 001-04300).

†10.72	–	Amendment of Restricted Stock Unit Awards (2011 Omnibus Equity Compensation Plan), effective June 30, 2015, between Registrant and Michael S. Bahorich (incorporated by reference to Exhibit 10.4 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2015, SEC File No. 001-04300).

†10.73	–	Amendment of Stock Option Grants (2011 Omnibus Equity Compensation Plan), effective June 30, 2015, between Registrant and Michael S. Bahorich (incorporated by reference to Exhibit 10.3 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2015, SEC File No. 001-04300).

*†10.74	–	Amendment of 2014 Performance Program (Business Performance) Award (2011 Omnibus Equity Compensation Plan), effective November 30, 2015, between Registrant and Thomas E. Voytovich.

*†10.75	–	Amendment of Restricted Stock Unit Awards (2011 Omnibus Equity Compensation Plan), effective November 30, 2015, between Registrant and Thomas E. Voytovich.

*†10.76	–	Amendment of Stock Option Grants (2007 and 2011 Omnibus Equity Compensation Plans), effective November 30, 2015, between Registrant and Thomas E. Voytovich.

*†10.77	–	Amendment of Stock Option Grants (2005 Stock Option Plan), effective November 30, 2015, between Registrant and Thomas E. Voytovich.


EXHIBIT NO.		DESCRIPTION
*12.1	–	Statement of Computation of Ratios of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividends.

14.1	–	Code of Business Conduct dated January 20, 2015 (incorporated by reference to Exhibit 14.1 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2015, SEC File No. 001-4300).

*21.1	–	Subsidiaries of Registrant

*23.1	–	Consent of Ernst & Young LLP

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

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

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

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

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

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

*101.INS	–	XBRL Instance Document.

*101.SCH	–	XBRL Taxonomy Schema Document.

*101.CAL	–	XBRL Calculation Linkbase Document.

*101.LAB	–	XBRL Label Linkbase Document.

*101.PRE	–	XBRL Presentation Linkbase Document.

*101.DEF	–	XBRL Definition Linkbase Document.

*	Filed herewith.

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

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

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 26, 2016

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	Director, Chief Executive Officer, and President (principal executive officer)	February 26, 2016

/s/ Stephen J. Riney Stephen J. Riney	Executive Vice President and Chief Financial Officer (principal financial officer)	February 26, 2016

/s/ Rebecca A. Hoyt Rebecca A. Hoyt	Senior Vice President, Chief Accounting Officer, and Controller (principal accounting officer)	February 26, 2016


Name	Title	Date

/s/ ANNELL R. BAY Annell R. Bay	Director	February 26, 2016

/s/ CHANSOO JOUNG Chansoo Joung	Director	February 26, 2016

/s/ GEORGE D. LAWRENCE George D. Lawrence	Director	February 26, 2016

/s/ JOHN E. LOWE John E. Lowe	Director	February 26, 2016

/s/ WILLIAM C. MONTGOMERY William C. Montgomery	Director	February 26, 2016

/s/ AMY H. NELSON Amy H. Nelson	Director	February 26, 2016

/s/ RODMAN D. PATTON Rodman D. Patton	Director	February 26, 2016

/s/ CHARLES J. PITMAN Charles J. Pitman	Director	February 26, 2016

/s/ DANIEL W. RABUN Daniel W. Rabun	Director	February 26, 2016

/s/ PETER A. RAGAUSS Peter A. Ragauss	Director	February 26, 2016

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, 2015. 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, 2015.

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 26, 2016

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Shareholders of Apache Corporation:

We have audited the accompanying consolidated balance sheets of Apache Corporation and subsidiaries as of December 31, 2015 and 2014, 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, 2015. 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, 2015 and 2014, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2015, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Apache Corporation’s internal control over financial reporting as of December 31, 2015, 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 26, 2016, expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Houston, Texas

February 26, 2016

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, 2015, 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, 2015, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Apache Corporation and subsidiaries as of December 31, 2015 and 2014, 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, 2015 of Apache Corporation and subsidiaries, and our report dated February 26, 2016, expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Houston, Texas

February 26, 2016

F-3

APACHE CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED OPERATIONS


	For the Year Ended December 31,
	2015		2014		2013
	(In millions, except per common share data)
REVENUES AND OTHER:
Oil and gas production revenues:
Oil revenues	$	4,999	$	10,040	$	11,853
Gas revenues		1,157		1,983		2,266
Natural gas liquids revenues		227		668		652

		6,383		12,691		14,771
Other		(17)		110		(333)

		6,366		12,801		14,438

OPERATING EXPENSES:
Depreciation, depletion, and amortization:
Oil and gas property and equipment
Recurring		3,531		4,388		4,534
Additional		25,517		5,001		995
Other assets		324		331		337
Asset retirement obligation accretion		145		154		211
Lease operating expenses		1,854		2,238		2,650
Gathering and transportation		211		273		288
Taxes other than income		282		577		772
Impairments		1,920		1,919		-
General and administrative		377		451		481
Transaction, reorganization, and separation		132		67		33
Financing costs, net		299		211		229

		34,592		15,610		10,530

NET INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		(28,226)		(2,809)		3,908
Current income tax provision		309		1,177		1,619
Deferred income tax provision (benefit)		(5,778)		(514)		309

NET INCOME (LOSS) FROM CONTINUING OPERATIONS
INCLUDING NONCONTROLLING INTEREST		(22,757)		(3,472)		1,980
Net income (loss) from discontinued operations, net of tax		(771)		(1,588)		308

NET INCOME (LOSS) INCLUDING NONCONTROLLING INTEREST		(23,528)		(5,060)		2,288
Preferred stock dividends		-		-		44
Net income (loss) attributable to noncontrolling interest		(409)		343		56

NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	(23,119)	$	(5,403)	$	2,188

NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS:
Net income (loss) from continuing operations attributable to common shareholders	$	(22,348)	$	(3,815)	$	1,880
Net income (loss) from discontinued operations		(771)		(1,588)		308

Net income (loss) attributable to common shareholders	$	(23,119)	$	(5,403)	$	2,188

BASIC NET INCOME (LOSS) PER COMMON SHARE:
Basic net income (loss) from continuing operations per share	$	(59.16)	$	(9.93)	$	4.75
Basic net income (loss) from discontinued operations per share		(2.04)		(4.13)		0.78

Basic net income (loss) per share	$	(61.20)	$	(14.06)	$	5.53

DILUTED NET INCOME (LOSS) PER COMMON SHARE:
Diluted net income (loss) from continuing operations per share	$	(59.16)	$	(9.93)	$	4.74
Diluted net income (loss) from discontinued operations per share		(2.04)		(4.13)		0.76

Diluted net income (loss) per share	$	(61.20)	$	(14.06)	$	5.50

WEIGHTED-AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
Basic		378		384		395
Diluted		378		384		406
DIVIDENDS DECLARED PER COMMON SHARE	$	1.00	$	1.00	$	0.80

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,
	2015		2014		2013
	(In millions)
NET INCOME (LOSS) INCLUDING NONCONTROLLING INTEREST	$	(23,528)	$	(5,060)	$	2,288
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and postretirement benefit plan, net of tax		-		-		9
Commodity cash flow hedge activity, net of tax:
Reclassification of (gain) loss on settled derivative instruments		-		-		11
Change in fair value of derivative instruments		-		(1)		(5)
Derivative hedge ineffectiveness reclassified into earnings		-		-		1

		-		(1)		16

COMPREHENSIVE INCOME (LOSS) INCLUDING NONCONTROLLING INTEREST		(23,528)		(5,061)		2,304
Preferred stock dividends		-		-		44
Comprehensive income (loss) attributable to noncontrolling interest		(409)		343		56

COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	(23,119)	$	(5,404)	$	2,204

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,
	2015		2014		2013
	(In millions)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) including noncontrolling interest	$	(23,528)	$	(5,060)	$	2,288
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Loss (income) from discontinued operations		771		1,588		(308)
Depreciation, depletion, and amortization		29,372		9,720		5,866
Impairments		1,920		1,919		-
Asset retirement obligation accretion		145		154		211
Provision for (benefit from) deferred income taxes		(5,778)		(514)		309
Other		102		(51)		300
Changes in operating assets and liabilities:
Receivables		663		757		105
Inventories		21		(31)		(65)
Drilling advances		138		107		269
Deferred charges and other		(435)		(211)		(148)
Accounts payable		(489)		(216)		286
Accrued expenses		(156)		(572)		(467)
Deferred credits and noncurrent liabilities		88		(73)		39

NET CASH PROVIDED BY CONTINUING OPERATING ACTIVITIES		2,834		7,517		8,685
NET CASH PROVIDED BY DISCONTINUED OPERATIONS		150		944		1,150

NET CASH PROVIDED BY OPERATING ACTIVITIES		2,984		8,461		9,835

CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property		(4,578)		(9,022)		(8,663)
Additions to gas gathering, transmission, and processing facilities		(233)		(881)		(464)
Leasehold and property acquisitions		(367)		(1,475)		(429)
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 Gulf of Mexico Shelf properties		-		-		3,702
Proceeds from Kitimat LNG transaction, net		-		-		396
Proceeds from sale of oil and gas properties, other		268		470		307
Other, net		6		(299)		(105)

NET CASH USED IN CONTINUING INVESTING ACTIVITIES		(3,659)		(8,585)		(5,256)
NET CASH PROVIDED BY (USED IN) DISCONTINUED OPERATIONS		4,335		(219)		(1,860)

NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES		676		(8,804)		(7,116)

CASH FLOWS FROM FINANCING ACTIVITIES:
Commercial paper, credit facilities and bank notes, net		(1,570)		1,568		(509)
Payments on fixed rate debt		(939)		-		(2,072)
Distributions to noncontrolling interest		(129)		(140)		-
Proceeds from sale of noncontrolling interest		-		-		2,948
Dividends paid		(377)		(365)		(360)
Treasury stock activity, net		-		(1,864)		(997)
Other		53		49		21

NET CASH USED IN CONTINUING FINANCING ACTIVITIES		(2,962)		(752)		(969)
NET CASH USED IN DISCONTINUED OPERATIONS		-		(42)		(4)

NET CASH USED IN FINANCING ACTIVITIES		(2,962)		(794)		(973)

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		698		(1,137)		1,746

CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR		769		1,906		160

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	1,467	$	769	$	1,906


SUPPLEMENTARY CASH FLOW DATA:
Interest paid, net of capitalized interest	$	246	$	134	$	192
Income taxes paid, net of refunds		573		1,357		1,766

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,
	2015		2014
	(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	1,467	$	769
Receivables, net of allowance		1,253		2,024
Inventories		570		708
Drilling advances		172		388
Assets held for sale		-		1,628
Deferred tax asset		-		769
Prepaid assets and other		290		129

		3,752		6,415

PROPERTY AND EQUIPMENT:
Oil and gas, on the basis of full-cost accounting:
Proved properties		89,069		89,852
Unproved properties and properties under development, not being amortized		2,611		7,014
Gathering, transmission, and processing facilities		1,052		5,440
Other		1,093		1,152

		93,825		103,458
Less: Accumulated depreciation, depletion, and amortization		(79,706)		(55,382)

		14,119		48,076

OTHER ASSETS:
Deferred charges and other		971		1,461

	$	18,842	$	55,952

LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable	$	618	$	1,210
Other current liabilities		1,223		2,454

		1,841		3,664

LONG-TERM DEBT		8,777		11,245


DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes		1,072		9,499
Asset retirement obligation		2,562		3,048
Other		362		359

		3,996		12,906

COMMITMENTS AND CONTINGENCIES (Note 8)

EQUITY:
Common stock, $0.625 par, 860,000,000 shares authorized, 411,218,105 and 409,706,347 shares issued, respectively		257		256
Paid-in capital		12,467		12,438
Retained earnings (accumulated deficit)		(7,153)		16,249
Treasury stock, at cost, 33,183,930 and 33,201,455 shares, respectively		(2,889)		(2,890)
Accumulated other comprehensive loss		(116)		(116)

APACHE SHAREHOLDERS’ EQUITY		2,566		25,937
Noncontrolling interest		1,662		2,200

TOTAL EQUITY		4,228		28,137

	$	18,842	$	55,952

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

F-7

APACHE CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED CHANGES IN EQUITY


	Series D Preferred Stock		Common Stock		Paid-In Capital		Retained Earnings (Accumulated Deficit)		Treasury Stock		Accumulated Other Comprehensive (Loss)		APACHE SHAREHOLDERS’ EQUITY		Non Controlling Interest		TOTAL EQUITY
	(In millions)
BALANCE AT DECEMBER 31, 2012	$	1,227	$	245	$	9,859	$	20,161	$	(30)	$	(131)	$	31,331	$	-	$	31,331
Net income		-		-		-		2,232		-		-		2,232		56		2,288
Postretirement, net of tax of $9		-		-		-		-		-		9		9		-		9
Commodity hedges, net of tax of $4		-		-		-		-		-		7		7		-		7
Preferred		-		-		-		(44)		-		-		(44)		-		(44)
Common ($0.80 per share)		-		-		-		(317)		-		-		(317)		-		(317)
Common stock activity, net		-		1		(22)		-		-		-		(21)		-		(21)
Treasury stock activity, net		-		-		-		-		(997)		-		(997)		-		(997)
Sale of noncontrolling interest		-		-		1,007		-		-		-		1,007		1,941		2,948
Conversion of Series D preferred stock		(1,227)		9		1,218		-		-		-		-		-		-
Compensation expense		-		-		189		-		-		-		189		-		189

BALANCE AT DECEMBER 31, 2013	$	-	$	255	$	12,251	$	22,032	$	(1,027)	$	(115)	$	33,396	$	1,997	$	35,393
Net income (loss)		-		-		-		(5,403)		-		-		(5,403)		343		(5,060)
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	$	12,438	$	16,249	$	(2,890)	$	(116)	$	25,937	$	2,200	$	28,137
Net income (loss)		-		-		-		(23,119)		-		-		(23,119)		(409)		(23,528)
Distributions to noncontrolling interest		-		-		-		-		-		-		-		(129)		(129)
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	$	12,467	$	(7,153)	$	(2,889)	$	(116)	$	2,566	$	1,662	$	4,228

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 countries: the United States (U.S.), Canada, Egypt, and the United Kingdom (U.K.) North Sea (North Sea). Apache also pursues exploration interests in other countries that may over time result in reportable discoveries and development opportunities.

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Accounting policies used by Apache and its subsidiaries reflect industry practices and conform to accounting principles generally accepted in the U.S. (GAAP). The Company’s financial statements for prior periods 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.

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. 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 2—Acquisitions and Divestitures), the estimate of proved oil and gas reserves and related present value estimates of future net cash flows therefrom (see Note 14—Supplemental Oil and Gas Disclosures), the assessment of asset retirement obligations (see Note 5—Asset Retirement Obligation), the estimates of fair value for long-lived assets and goodwill impairment (see “Fair Value Measurements” and “Goodwill” sections in this Note 1 below), and the estimate of income taxes (see Note 7—Income Taxes).

F-9

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Fair Value Measurements

Certain assets and liabilities are reported at fair value on a recurring basis in Apache’s consolidated balance sheet. Accounting Standards Codification (ASC) 820-10-35 provides a hierarchy that prioritizes and defines the types of inputs used to measure fair value. The fair value hierarchy gives the highest priority to Level 1 inputs, which consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived from inputs that are significant and unobservable; hence, these valuations have the lowest priority.

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

Recurring fair value measurements are presented in further detail in Note 6—Debt and Note 9—Retirement and Deferred Compensation Plans.

Apache also uses fair value measurements on a nonrecurring basis as indicated by certain qualitative assessments of its assets. For the year ended December 31, 2015, the Company recorded asset impairments totaling $1.9 billion in connection with fair value assessments in the current low commodity price environment. Impairments totaling $1.7 billion were recorded for certain gathering, transmission, and processing (GTP) facilities, which were written down to their fair values. These GTP impairments are discussed in further detail below in “Gathering, Transmission, and Processing Facilities.” Also in 2015, the Company recorded $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 2—Acquisitions and Divestitures.

For the year ended December 31, 2014, the Company recorded asset impairments totaling $1.9 billion in connection with fair value assessments, including $1.3 billion for the impairment of goodwill, $604 million for the impairment of assets held for sale, and other asset impairments. The Company also recorded $439 million in impairments related to the sale of Australia’s assets, which are classified as discontinued operations in 2014. For discussion of these impairments, see “Property and Equipment” and “Goodwill” below and Note 2—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, 2015 and 2014, Apache had $1.5 billion and $0.8 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

F-10

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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, 2015, 2014, and 2013, the Company had an allowance for doubtful accounts of $103 million, $98 million, and $78 million, respectively. During 2015, Apache’s allowance for doubtful accounts increased $5 million, reflecting additional provisions for the year of $40 million, partially offset by $35 million for uncollectible accounts written off net of recoveries.

Inventories

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

Property and Equipment

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

Oil and Gas Property

The Company follows the full-cost method of accounting for its oil and gas property. Under this method of accounting, all costs incurred for both successful and unsuccessful exploration and development activities, including salaries, benefits, and other internal costs directly identified with these activities, and oil and gas property acquisitions are capitalized. All costs related to production, general corporate overhead, and similar activities are expensed as incurred. Apache capitalized $297 million, $373 million, and $401 million of internal costs in 2015, 2014, and 2013, respectively.

Proved properties are amortized on a country-by-country basis using the units of production method (UOP). The UOP calculation multiplies the percentage of estimated proved reserves produced each quarter by the cost of those reserves. The amortization base in the UOP calculation includes the sum of proved property, net of accumulated depreciation, depletion and amortization (DD&A), estimated future development costs (future costs to access and develop proved reserves), and asset retirement costs, less related salvage value.

The cost of unproved properties and properties under development are excluded from the amortization calculation until it is determined whether or not proved reserves can be assigned to such properties or until development projects are placed in service. Geological and geophysical costs not associated with specific prospects are recorded to proved property immediately. Unproved properties and properties under development are reviewed for impairment at least quarterly and are determined through an evaluation considering, among other factors, seismic data, requirements to relinquish acreage, drilling results, remaining time in the commitment period, remaining capital plan, and political, economic, and market conditions. In countries where proved reserves exist, exploratory drilling costs associated with dry holes are transferred to proved properties immediately upon determination that a well is dry and amortized accordingly. In countries where a reserve base has not yet been established, impairments are charged to earnings.

Under the full-cost method of accounting, the net book value of oil and gas properties, less related deferred income taxes, may not exceed a calculated “ceiling.” The ceiling limitation is the estimated after-tax future net cash flows from proved oil and gas reserves, discounted at 10 percent per annum and adjusted for designated cash flow hedges. Future cash outflows associated with settling accrued asset retirement obligations are excluded from the calculation. Estimated future net cash flows are calculated using end-of-period costs and an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months, held flat for the life of the production, except where prices are defined by contractual arrangements. See Note 14—Supplemental Oil and Gas Disclosures for a discussion of the calculation of estimated future net cash flows.

F-11

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Any excess of the net book value of proved oil and gas properties, less related deferred income taxes, over the ceiling is charged to expense and reflected as additional DD&A in the accompanying statement of consolidated operations. Such limitations are imposed separately on a country-by-country basis and are tested quarterly. The following table presents non-cash write-downs of the carrying value of the Company’s proved oil and gas properties by country for 2015, 2014, and 2013:


	For the Year Ended December 31, 2015				For the Year Ended December 31, 2014				For the Year Ended December 31, 2013

	Before tax		After tax		Before tax		After tax		Before tax		After tax

	(In millions)

U.S.	$	19,537	$	12,602	$	4,412	$	2,844	$	552	$	356
Canada		3,667		2,721		-		-		-		-
North Sea		2,032		1,016		589		224		368		139
Egypt		281		281		-		-		-		-
Other international		-		-		-		-		75		46

Total write-downs	$	25,517	$	16,620	$	5,001	$	3,068	$	995	$	541

In 2013, the Company recorded a non-cash write-down of $118 million, net of tax, in Argentina, which is reflected as discontinued operations in the Company’s consolidated financial statements. Cash flow hedges did not materially affect the 2015, 2014, and 2013 calculations.

Proceeds from the sale or disposition of oil and gas properties are accounted for as a reduction to capitalized costs unless a significant portion (greater than 25 percent) of the Company’s reserve quantities in a particular country are sold, in which case a gain or loss is recognized in income. During 2015, Apache recorded a $1.3 billion and $922 million loss related to the sale of its Australia oil and gas assets and Wheatstone LNG project, respectively. During 2014, Apache recorded a $539 million loss related to the divestiture of operations in Argentina. No gain or loss was recorded on the Company’s divestitures in 2013. See Note 2—Acquisitions and Divestitures for more detail.

Gathering, Transmission, and Processing Facilities

GTP facilities totaled $1.1 billion and $5.4 billion at December 31, 2015 and 2014, respectively, with accumulated depreciation for these assets totaling $160 million and $1.7 billion 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 2015, the Company recorded impairments of $1.7 billion on certain GTP assets, which were written down to their fair values of $306 million in aggregate. The fair values of the impaired assets were determined using an income approach, which considered 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 2014, the Company recorded an impairment of $1.0 billion of its GTP assets

F-12

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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. No impairments of GTP facilities were recognized during 2013.

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 “Other” under “Revenues and Other” in the Company’s statement of consolidated operations. 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. No gain or loss on the sales of GTP facilities was recognized during 2013.

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 $693 million and $673 million at December 31, 2015 and 2014, respectively.

Asset Retirement Costs and Obligations

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

Goodwill

Goodwill represents the excess of the purchase price of an entity over the estimated fair value of the assets acquired and liabilities assumed. The Company assesses the carrying amount of goodwill by testing for impairment annually and when impairment indicators arise. The impairment test requires allocating goodwill and all other assets and liabilities to assigned reporting units. 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 in the fair value hierarchy.

F-13

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

As of December 31, 2013, goodwill totaled $1.4 billion, with approximately $1.0 billion, $163 million, $103 million, and $87 million recorded in the U.S., North Sea, Canada, and Egypt, respectively. Given the significant reduction in oil and gas commodity prices in December 2014, the Company tested goodwill for impairment as of December 31, 2014. 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. No impairment was indicated for the Company’s Egypt reporting unit. As a result of these assessments, during the fourth quarter of 2014 the Company recognized non-cash impairments of the entire amount of recorded goodwill in the U.S., North Sea, and Canada reporting units of $1.0 billion, $163 million, and $103 million, respectively. These goodwill impairments have been recorded in “Impairments” in the Company’s statement of consolidated operations. As of December 31, 2015 and 2014, total goodwill of $87 million remained recorded for the Egypt reporting unit.

Accounts Payable

Included in accounts payable at December 31, 2015 and 2014, are liabilities of approximately $129 million and $229 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 gas to fulfill sales obligations and commitments. Both the costs and sales proceeds of this third-party gas are reported on a net basis in oil and gas production revenues. The costs of third-party gas netted against the related sales proceeds totaled $37 million, $46 million, and $34 million, for 2015, 2014, and 2013, respectively.

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

F-14

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Derivative Instruments and Hedging Activities

Apache periodically enters into derivative contracts to manage its exposure to commodity price risk. These derivative contracts, which are generally placed with major financial institutions, may take the form of forward contracts, futures contracts, swaps, or options. The oil and gas reference prices upon which the commodity derivative contracts are based reflect various market indices that have a high degree of historical correlation with actual prices received by the Company for its oil and gas production. As of December 31, 2015, 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 “Derivative instrument gains (losses), net” under “Revenues and Other” in the statement of consolidated operations. Hedge accounting treatment allows unrealized gains and losses on cash flow hedges to be deferred in other comprehensive income. Realized gains and losses from the Company’s oil and gas cash flow hedges, including terminated contracts, are generally recognized in oil and gas production revenues when the forecasted transaction occurs. If at any time the likelihood of occurrence of a hedged forecasted transaction ceases to be “probable,” hedge accounting treatment will cease on a prospective basis, and all future changes in the fair value of the derivative will be recognized directly in earnings. Amounts recorded in other comprehensive income prior to the change in the likelihood of occurrence of the forecasted transaction will remain in other comprehensive income until such time as the forecasted transaction impacts earnings. If it becomes probable that the original forecasted production will not occur, then the derivative gain or loss would be reclassified from accumulated other comprehensive income into earnings immediately. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time, and any ineffectiveness is immediately reported as “Other” under “Revenues and Other” in the statement of consolidated operations.

General and Administrative Expense

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

Income Taxes

Apache records deferred tax assets and liabilities to account for the expected future tax consequences of events that have been recognized in the financial statements and tax returns. The Company routinely assesses the 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 7—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,

F-15

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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 7—Income Taxes. All other foreign currency transaction gains and losses are reflected in “Other” under “Revenues and Other” in the statement of consolidated operations. The Company’s other foreign currency gains and losses netted to a loss in 2015 of $11 million, a gain in 2014 of $8 million, and a loss in 2013 of $30 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. The diluted EPS calculations for the year ended December 31, 2013, includes weighted-average shares of common stock from the assumed conversion of Apache’s convertible preferred stock.

Stock-Based Compensation

The Company accounts for stock-based compensation under the fair value recognition provisions of ASC Topic 718, “Compensation – Stock Compensation.” The Company grants various types of stock-based awards including stock options, nonvested restricted stock units, and performance-based awards. Additionally, the Company also grants cash-based stock appreciation rights. These plans and related accounting policies are defined and described more fully in Note 10—Capital Stock. Stock compensation awards granted are valued on the date of grant and are expensed, net of estimated forfeitures, over the required service period.

ASC Topic 718 also requires that benefits of tax deductions in excess of recognized compensation cost be reported as financing cash flows rather than as operating cash flows. The Company classified $1 million, $35,000, and $1 million as financing cash inflows in 2015, 2014, and 2013, 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 September 2015, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2015-16, which eliminates the requirement that an acquirer in a business combination account for measurement-period adjustments retrospectively. Instead, an acquirer will recognize a measurement-period

F-16

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

adjustment during the period in which it determines the amount of the adjustment, including amounts it would have recorded in previous periods if the accounting had been completed at the acquisition date. ASU 2015-16 is effective for fiscal years beginning after December 15, 2016. The Company does not expect the adoption of this amendment to have a material impact on its consolidated financial statements.

In July 2015, the FASB issued ASU 2015-11, which simplifies the subsequent measurement of inventory by requiring inventory to be measured at the lower of cost and net realizable value. Entities will continue to apply their existing impairment models to inventories that are accounted for using last-in first-out and the retail inventory method. Under current guidance, net realizable value is one of several calculations an entity needs to make to measure inventory at the lower of cost or market. The guidance is effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years. The Company does not expect the adoption of this amendment to have a material impact on its consolidated financial statements.

In April 2015, the FASB issued ASU 2015-03, which simplifies the presentation of debt issuance costs. The new standard requires debt issuance costs to be presented as a direct deduction from the carrying value of the associated debt liability, whereas they are currently being presented as a component of “deferred charges and other” on the balance sheet. The new standard creates consistency in the way debt issuance costs and debt discounts are presented on the balance sheet and better aligns U.S. GAAP with International Financial Reporting Standards. ASU 2015-03 is effective for annual and interim reporting periods beginning after December 15, 2015. The Company will apply the change retrospectively and does not expect the adoption of this amendment to have a material impact 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 guidance 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. In July 2015, the FASB announced a delay in the effective date of the revenue standard by one year. The deferral results in the new revenue standard being 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 is currently evaluating the level of effort needed to implement the standard, the impact of adopting this standard on its consolidated financial statements, and whether to use the full retrospective approach or the modified retrospective approach.

2. ACQUISITIONS AND DIVESTITURES

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.

F-17

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Canada Divestiture

In April 2015, Apache completed the sale of its 50 percent interest in the Kitimat LNG project and related 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 8—Commitments and Contingencies.

The Kitimat LNG assets were impaired $604 million in the fourth quarter of 2014 and classified as held for sale on the consolidated balance sheet as of December 31, 2014. No material gain or loss was recognized for the LNG assets upon completion of the sale. No gain or loss was recognized on the sale of the upstream assets. In accordance with full cost accounting rules, sales of oil and gas properties are accounted for as adjustments of capitalized costs, with no gain or loss recognized unless such adjustment would significantly alter the relationship between capitalized costs and proved reserves.

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. For additional details related to post-closing adjustments, please see Note 8—Commitments and Contingencies.

The Wheatstone LNG assets were impaired in the fourth quarter of 2014 and classified as held for sale on the consolidated balance sheet as of December 31, 2014. No material gain or loss was recognized on the ultimate disposal of the LNG project. A loss of approximately $922 million was recognized on the sale of the Australian upstream assets.

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 $1.3 billion was recognized for the sale of AEL.

F-18

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. The carrying amounts of the major classes of consolidated assets and liabilities associated with the Australia dispositions were as follows:


	December 31,

	2014

	(In millions)
ASSETS
Current assets	$	1,992
Oil and gas assets, net		5,639
GTP and other assets, net		877

Total assets	$	8,508


LIABILITIES
Current liabilities	$	606
Asset retirement obligations		517
Non-current deferred tax liability		922
Other long-term liabilities		33

Total liabilities	$	2,078

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


	For the Year Ended December 31,
	2015		2014		2013

	(In millions)
Revenues and other from discontinued operations	$	288	$	1,050	$	1,121


Loss on Woodside sale	$	(922)	$	-	$	-
Loss on Consortium sale		(1,329)		-		-
Income (loss) from divested Australian operations		24		(97)		496
Income tax benefit (expense)		1,456		(974)		4

Income (loss) from Australian discontinued operations, net of tax	$	(771)	$	(1,071)	$	500

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’s net book value of oil and gas properties was reduced by approximately $1.2 billion of proved property costs as a result of the transactions. Approximately $72 million of proceeds were allocated to the GTP facilities, resulting in a loss on disposal of assets totaling $180 million ($116 million net of tax).

F-19

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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’s net book value of oil and gas properties was reduced by $850 million of proved property costs and $518 million of unproved property costs as a result of the transaction.

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.

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 in this Annual Report on Form 10-K.

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


	For the Year Ended December 31,
	2015		2014		2013
	(In millions)
Revenues and other from discontinued operations	$	-	$	87	$	494

Loss from Argentina divestiture		-		(539)		-
Income (loss) from operations in Argentina		-		(1)		(192)
Income tax benefit		-		23		-

Income (loss) from discontinued operations, net of tax	$	-	$	(517)	$	(192)

2013 Activity

Egypt Partnership

On November 14, 2013, Apache completed the sale of a one-third minority participation in its Egypt oil and gas business to a subsidiary of Sinopec International Petroleum Exploration and Production Corporation (Sinopec). Apache received cash consideration of $2.95 billion after customary closing adjustments. Apache continues to operate its Egypt upstream oil and gas business. Apache recorded $1.9 billion of the proceeds as a non-controlling interest, which is reflected as a separate component of equity in the Company’s consolidated balance sheet. This represents one-third of Apache’s net book value of its Egypt holdings at the time of the transaction.

F-20

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Gulf of Mexico Shelf Divestiture

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

Canada LNG Project

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

Leasehold and Property Acquisitions

Apache completed $367 million, $1.5 billion, and $429 million of leasehold and property acquisitions during 2015, 2014, and 2013, respectively, substantially increasing its drilling opportunities in key focus areas in North America including the Eagle Ford and Canyon Lime plays.

Transaction, Reorganization, and Separation

Apache recorded $132 million, $67 million, and $33 million of expenses during 2015, 2014, and 2013, respectively, primarily related to various transactions, company reorganization, and employee separation.

3. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

Objectives and Strategies

The Company is exposed to fluctuations in crude oil and natural gas prices on the majority of its worldwide production. Apache manages the variability in its cash flows by occasionally entering into derivative transactions on a portion of its crude oil and natural gas production. 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, 2015, Apache had no open commodity derivative positions.

F-21

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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,
	Gain (Loss) on Derivatives Recognized in Income		2015			2014			2013
			(In millions)
Loss on cash flow hedges reclassified from accumulated other comprehensive loss	Oil and Gas Production Revenues	$		-	$		-	$		(16)
Loss for ineffectiveness on cash flow hedges	Revenues and Other: Other	$		-	$		-	$		(1)
Derivatives not designated as cash flow hedges:
Realized loss		$		-	$		(16)	$		(178)
Unrealized gain (loss)				-			300			(221)

Gain (loss) on derivatives not designated as cash flow hedges	Revenues and Other: Other	$		-	$		284	$		(399)

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.”

4. OTHER CURRENT LIABILITIES

The following table provides detail of the Company’s other current liabilities at December 31, 2015 and 2014:


	December 31,
	2015		2014
	(In millions)
Accrued operating expenses	$	139	$	163
Accrued exploration and development		637		1,606
Accrued compensation and benefits		166		204
Accrued interest		144		160
Accrued income taxes		47		54
Current asset retirement obligation		36		37
Current debt		1		-
Other		53		230

Total Other current liabilities	$	1,223	$	2,454

F-22

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

5. ASSET RETIREMENT OBLIGATION

The following table describes changes to the Company’s asset retirement obligation (ARO) liability for the years ended December 31, 2015 and 2014:


	2015		2014
	(In millions)
Asset retirement obligation at beginning of year	$	3,085	$	3,222
Liabilities incurred		68		171
Liabilities divested		(623)		(471)
Liabilities settled		(90)		(146)
Accretion expense		158		181
Revisions in estimated liabilities		-		128

Asset retirement obligation at end of year		2,598		3,085
Less current portion		(36)		(37)

Asset retirement obligation, long-term	$	2,562	$	3,048

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 and 2014 includes discontinued operations of $13 million and $27 million, respectively, which are included in “Net income (loss) from discontinued operations, net of tax” on the statement of consolidated operations.

During 2015 and 2014, the Company recorded $68 million and $171 million, respectively, in abandonment liabilities resulting from Apache’s active exploration and development capital program. Liabilities settled primarily relate to individual properties, platforms, and facilities plugged and abandoned during the period.

6. DEBT

Overview

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

F-23

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The following table presents the carrying value of the Company’s debt at December 31, 2015 and 2014:


	December 31,
	2015		2014
	(In millions)
U.S.:
Commercial paper		-		1,570
5.625% notes due 2017⁽¹⁾		-		500
1.75% notes due 2017⁽¹⁾		-		400
6.9% notes due 2018⁽¹⁾		400		400
7.0% notes due 2018		150		150
7.625% notes due 2019		150		150
3.625% notes due 2021⁽¹⁾		500		500
3.25% notes due 2022⁽¹⁾		919		919
2.625% notes due 2023⁽¹⁾		531		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⁾		1,500		1,500
5.25% notes due 2042⁽¹⁾		500		500
4.75% notes due 2043⁽¹⁾		1,500		1,500
4.25% notes due 2044⁽¹⁾		800		800
7.375% debentures due 2047		150		150
7.625% debentures due 2096		150		150

		8,530		11,000

Subsidiary and other obligations:
Notes due in 2016 and 2017		1		1
Apache Finance Canada 7.75% notes due 2029		300		300

		301		301

Debt before unamortized discount		8,831		11,301
Unamortized discount		(53)		(56)

Total debt	$	8,778	$	11,245

Current maturities	$	(1)	$	-

Long-term debt	$	8,777	$	11,245

⁽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, 2015, excluding discounts, are as follows:


	(In millions)
2016 and 2017	$	1
2018		550
2019		150
Thereafter		8,130

Total Debt, excluding discounts	$	8,831

F-24

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Fair Value

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


	December 31, 2015				December 31, 2014
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)
Commercial paper		-		-		1,570		1,570
Notes and debentures		8,778		8,330		9,675		9,944

Total Debt	$	8,778	$	8,330	$	11,245	$	11,514

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, 2015 and 2014, 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, 2015, aggregate available borrowing capacity under this credit facility was $3.5 billion.

At the Company’s option, the interest rate per annum for borrowings under the facility is either a base rate, as defined, plus a margin or the London Inter-bank Offered Rate (LIBOR), plus a margin. At December 31, 2015, the margin over LIBOR was 1.0 percent. The Company also pays quarterly a facility fee at per annum rate on total commitments, which at December 31, 2015 was 0.125 percent of the total $3.5 billion in commitments. The margins and the facility fee vary based upon the Company’s senior long-term debt rating.

F-25

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The Company was in compliance with the terms of the credit facility as of December 31, 2015.

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, 2015, the Company had no commercial paper outstanding. As of December 31, 2014, the Company had $1.6 billion in commercial paper outstanding.

Subsidiary Notes – Apache Finance Canada

Apache Finance Canada has approximately $300 million of publicly traded notes due in 2029 that are fully and unconditionally guaranteed by Apache. For further discussion of subsidiary debt, please see Note 16—Supplemental Guarantor Information.

Financing Costs, Net

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


	For the Year Ended December 31,
	2015		2014		2013
	(In millions)
Interest expense	$	486	$	499	$	560
Amortization of deferred loan costs		11		6		8
Capitalized interest		(227)		(287)		(315)
Loss (gain) on extinguishment of debt		39		-		(16)
Interest income		(10)		(7)		(8)

Financing costs, net	$	299	$	211	$	229

F-26

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

As of December 31, 2015, the Company has $53 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 2015, 2014, and 2013.

As of December 31, 2015 and 2014, the Company had approximately $64 million and $69 million, respectively, of unamortized deferred loan costs associated with its various debt obligations. These costs are included in deferred charges and other in the accompanying consolidated balance sheet and are being charged to financing costs and expensed over the life of the related debt issuances.

7. INCOME TAXES

Income (loss) from continuing operations before income taxes is composed of the following:


	For the Year Ended December 31,
	2015		2014		2013
	(In millions)
U.S.	$	(20,415)	$	(3,888)	$	1,191
Foreign		(7,811)		1,079		2,717

Total	$	(28,226)	$	(2,809)	$	3,908

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


	For the Year Ended December 31,
	2015		2014		2013
	(In millions)
Current taxes:
Federal	$	363	$	(10)	$	(29)
State		41		1		-
Foreign		(95)		1,186		1,648

		309		1,177		1,619

Deferred taxes:
Federal		(4,157)		(130)		509
State		(90)		(43)		44
Foreign		(1,531)		(341)		(244)

		(5,778)		(514)		309

Total	$	(5,469)	$	663	$	1,928

F-27

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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


	For the Year Ended December 31,
	2015		2014		2013
	(In millions)
Income tax expense (benefit) at U.S. statutory rate	$	(9,879)	$	(983)	$	1,368
State income tax, less federal benefit		(32)		(27)		29
Taxes related to foreign operations		(696)		(154)		236
Tax credits		(6)		-		6
Tax on distributed foreign earnings		726		311		225
Foreign tax credit carryforwards		(2,090)		-		-
Deferred tax on undistributed foreign earnings		1,903		560		-
Goodwill impairment		-		483		-
Change in U.K. tax rate		(619)		-		-
Net change in tax contingencies		20		(3)		(10)
Valuation allowances		5,253		478		132
All other, net		(49)		(2)		(58)

	$	(5,469)	$	663	$	1,928

The net deferred income tax liability reflects the net tax impact of timing differences between the assets and liability amounts carried on the books 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,
	2015		2014
	(In millions)
Deferred tax assets:
Deferred income	$	20	$	-
U.S. and state net operating loss carryforwards		329		1,333
Foreign net operating loss carryforwards		1,507		366
Tax credits and other tax incentives		82		42
Foreign tax credit carryforwards		2,090		-
Accrued expenses and liabilities		136		68
Asset retirement obligation		1,037		1,202
Property and equipment		3,880		373

Total deferred tax assets		9,081		3,384
Valuation allowance		(6,530)		(1,069)

Net deferred tax assets		2,551		2,315

Deferred tax liabilities:
Other		1		19
Deferred income		140		24
Investment in foreign subsidiaries		1,903		1,654
Property and equipment		1,574		9,359

Total deferred tax liabilities		3,618		11,056

Net deferred income tax liability	$	1,067	$	8,741

F-28

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

In November 2015, the FASB issued ASU 2015-17 “Balance Sheet Classification of Deferred Taxes,” which requires all companies to classify deferred tax assets, liabilities, and related valuation allowances as noncurrent on the balance sheet effective for annual periods beginning after December 15, 2016, with early adoption allowed. Apache has elected to adopt the accounting standard for the year ended December 31, 2015 and as a result, all deferred tax assets, liabilities, and related valuation allowances are classified as noncurrent on Apache Corporation’s December 31, 2015 consolidated balance sheet. Prior consolidated balance sheets were not retrospectively adjusted.

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


	December 31,
	2015		2014
	(In millions)
Assets:
Deferred tax asset	$	-	$	(769)
Deferred charges and other		(5)		(17)

Liabilities
Other current liabilities		-		28
Deferred income taxes		1,072		9,499

Net deferred income tax liability	$	1,067	$	8,741

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 and $225 million of U.S. deferred income tax expense on foreign earnings that were distributed to the U.S. in 2014 and 2013, respectively. The Company’s Canadian subsidiaries do not currently have undistributed earnings.

In 2015, the U.K. government enacted Finance Bill 2015 that provides 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 $619 million related to the remeasurement of the Company’s December 31, 2014 U.K. deferred income tax liability.

In 2015, the Company recorded a valuation allowance against the U.S. region’s net deferred tax asset. The deferred tax position in the U.S. changed from a net deferred tax liability as of December 31, 2014 to a net deferred tax asset as of December 31, 2015 as a result of $19.5 billion in non-cash ceiling test write-downs and the recognition of $2.1 billion of deferred tax assets related to foreign tax credit carryforwards. The Company has assessed the potential realization of its U.S. net deferred tax asset and has concluded that it is more likely than not that the U.S. net deferred tax asset will not be realized based on current economic conditions and expectations for the future.

In addition, the Company has recorded an increase in valuation allowance against certain foreign deferred tax assets, primarily driven by non-cash ceiling test write-downs. The Company has assessed the future potential

F-29

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

realization of these deferred tax assets and has concluded that it is more likely than not that these foreign deferred tax assets will not be realized based on current economic conditions and expectations for the future.

In 2015, 2014, and 2013, the Company increased its total valuation allowance by $5.5 billion, $418 million, and $232 million, respectively, as detailed in the table below:


	2015		2014		2013
	(In millions)
Balance at beginning of year	$	1,069	$	651	$	419
State⁽¹⁾		235		57		32
U.S.		2,978		-		-
Foreign⁽²⁾		2,248		478		132
Discontinued operations⁽³⁾		-		(117)		68

Balance at end of year	$	6,530	$	1,069	$	651

⁽¹⁾

Reported as a component of state income taxes in the rate reconciliation.

⁽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, 2015, the Company had net operating losses as follows:



	Amount		Expiration
	(In millions)
Net operating losses:
U.S.	$	198	2018 - 2035
State		3,496	Various
Canada		60	2028 - 2035

The Company has a U.S. net operating loss carryforward of $198 million subject to annual limitation under Section 382 of the Internal Revenue Code. The Company also has $848 million of capital loss carryforwards in Canada, which have an indefinite carryover period. The Company has recorded a valuation allowance against the net operating losses listed above and the capital loss until there is sufficient evidence to support the reversal of all or some portion of this allowance.

On December 31, 2015, the Company had foreign tax credits as follows:



	Amount		Expiration
	(In millions)
Foreign Tax Credits	$	2,090		2025 - 2026

The Company has a $2.1 billion U.S. foreign tax credit carryforward. The Company has recorded a valuation allowance against the U.S. foreign tax credits listed above until there is sufficient evidence to support the reversal of all or some portion of this allowance.

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

F-30

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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:


	2015		2014		2013
	(In millions)
Balance at beginning of year	$	-	$	3	$	3
Additions based on tax positions related to the current year		19		-		-
Reductions for tax positions of prior years		-		(3)		-

Balance at end of year	$	19	$	-	$	3

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, 2015, 2014, and 2013 the Company recorded tax expense of $1 million, tax benefit of $1 million, and tax expense of $1 million, respectively, for interest and penalties. At December 31, 2015, 2014, and 2013 the Company had an accrued liability for interest and penalties of $1 million, $0, and $1 million, respectively.

In 2015, the Company recorded a $19 million reserve for uncertain tax positions related to the current year. 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. In 2013, the Company reached agreement with the IRS regarding an audit of the 2009 and 2010 tax years. There was no change in the Company’s unrecognized tax benefits as a result of this agreement. The resolution of unagreed tax issues in the Company’s open tax years cannot be predicted with absolute certainty, and differences between what has been recorded and the eventual outcomes may occur. The Company believes that it has adequately provided for income taxes and any related interest and penalties for all open tax years.

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

Jurisdiction


U.S.			2011
Canada			2011
Egypt			1998
U.K.			2013

8. COMMITMENTS AND CONTINGENCIES

Legal Matters

Apache is party to various legal actions arising in the ordinary course of business, including litigation and governmental and regulatory controls. The Company has an accrued liability of approximately $29 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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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 has appealed. 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

On November 8, 2013, Plaquemines Parish filed three lawsuits against Apache and various other oil and gas producers in the Parish’s 25^th 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. 61-000; and Parish of Plaquemines v. HHE Energy Company et al., Docket No. 60-983. On or about February 4, 2016, Cameron Parish filed six new lawsuits against Apache and various other oil and gas producers in the Parish’s 38^th 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. 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. On November 21, 2015, the Plaquemines Parish Council voted to drop all of that Parish’s lawsuits, and as a result Apache anticipates that the Parish’s claims will be dismissed. The Cameron Parish lawsuits are pending. While an adverse judgment against Apache might be possible, Apache intends to vigorously oppose these claims.

In a case captioned State of Louisiana and the Cameron Parish School Board v. Apache Corporation et al., Docket No. 10-18672, in the 38^th Judicial District Court, Parish of Cameron, State of Louisiana, plaintiffs alleged that defendants’ oil and gas exploration and production activities contaminated plaintiffs’ property. Plaintiffs sought damages in the range of $7 million to $96 million, plus exemplary damages, costs, and fees. Apache, a defendant in the case, acquired its interest in the oil and gas operations on plaintiffs’ property from the former operator, defendant Davis Oil Company, and subsequently sold the interest to defendant Wagner Oil Company (Wagner). Apache has settled with plaintiffs on confidential terms, including for an exchange of consideration that is not material to Apache. Apache claims indemnity from, and has reserved all of its rights against, Wagner.

Australia Gas Pipeline Force Majeure

In June 2008, Company subsidiaries reported a pipeline explosion in Western Australia that interrupted deliveries of natural gas to customers under various long-term contracts. The civil lawsuits concerning the pipeline explosion, all of which were filed in the Supreme Court of Western Australia, have been resolved fully and dismissed on confidential terms, including for an exchange of consideration that is not material to Apache. All matters relating to the Australia gas pipeline force majeure are concluded.

Apollo Exploration Lawsuit

In a case captioned Apollo Exploration, LLC, Cogent Exploration, Ltd. Co. & SellmoCo, LLC v. Apache Corporation, Cause No. CV50538 in the 385^th Judicial District Court, Midland County, Texas, in a Second Amended Petition on February 27, 2015, plaintiffs allege damages in excess of $1.1 billion relating to certain 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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), will examine Apache’s books and records and those of its subsidiaries and related entities to determine compliance with Delaware Escheat Laws. After more than five years of review, on January 13, 2016, Delaware confirmed that the Company has no liability for the disbursements property category for transaction years 2004 through 2009, which is a change in the Company’s favor from Delaware’s September 2015 assessment in the amount of $237,000. Delaware has advised the Company that Kelmar’s review for this property category is not complete for transaction years 1986 through 2003, and is still in process for other property types and years as well. While reserving all rights, the Company will continue to cooperate fully with Delaware until the review is complete. The Company’s exposure for the remainder of the Delaware audit is not currently determinable. At least 30 other states have retained their own consultants and have sent similar audit notifications. The scope of each state’s audit varies. It is possible that one or more of the audits could extend to all 50 states.

Burrup-Related Gas Supply Lawsuits

In a case captioned Pankaj Oswal v. Apache Corporation, No. WAD 389/2013, in the Federal Court of Australia, District of Western Australia, plaintiff asserted claims against the Company under the Australian Trade Practices Act alleging, among other things, that the Company induced him to make investments covering construction cost overruns on the Burrup Fertilisers ammonia plant in Western Australia (the Burrup plant), which was completed in 2006. Plaintiff sought damages in the amount of $491 million USD. On the eve of a trial that was to commence on February 9, 2015, plaintiff decided to discontinue his lawsuit. On March 18, 2015, the court entered a final order dismissing the case. The lawsuit is concluded in the Company’s favor.

The Western Australia lawsuit is one of a number of legal actions involving the Burrup plant. Pankaj Oswal’s shares, and those of his wife Radhika Oswal, together representing 65 percent of Burrup Holdings Limited (BHL, as it was then known, which owns Burrup Fertilisers), were offered for sale by externally-appointed administrators in Australia as a result of events of default on loans made to the Oswals and associated entities by the Australia and New Zealand Banking Group Ltd (ANZ). As part of the sale process, on January 31, 2012, a Company affiliate, Apache Fertilisers Pty Ltd (AFPL), acquired a 49 percent interest in BHL (now known as Yara Pilbara Holdings Pty Ltd, YPHPL), while Yara Australia Pty Ltd (Yara) increased its interest in YPHPL from 35 percent to 51 percent. On October 28, 2015, Yara and its related bodies corporate acquired all of the shares of AFPL. Yara operates the ammonia plant and is proceeding with development of a technical ammonium nitrate (TAN) plant in the Burrup Peninsula region of Western Australia to be developed by a consortium including YPHPL. The old gas sale agreement to supply natural gas to the ammonia plant, and to which a former Company subsidiary was a party, has been modified with, among other things, new pricing, delivery quantities, and term.

YPHPL share ownership and the modified gas sale agreement continue to be the subject of ongoing litigation in Australia. In cases captioned Radhika Oswal v. Australia and New Zealand Banking Group Limited & Ors, No. SCI 2011 4653, and Pankaj Oswal v. Australia and New Zealand Banking Group Limited & Ors, No. SCI 2012 01995, in the Supreme Court of Victoria, the Oswal plaintiffs seek to set aside the YPHPL share sales, void the modified gas sale agreement, and recover damages in the range of $833 million to $2.274 billion (plus interest, costs, and fees) allegedly resulting from the sale of their shares at undervalue. The cases are presently set for trial commencing May 2016. The Company is a named defendant and is also defending Apache Energy Limited (now known as Quadrant Energy Australia Limited) and Apache Northwest Pty Ltd (now known as Quadrant Northwest Pty Ltd). Yara has assumed full conduct and control of the defense of AFPL (now known as Chemical Holdings Pty Ltd). Apache believes that plaintiffs’ claims lack merit, and further that plaintiffs’ alleged damages are grossly inflated. Apache will vigorously oppose the claims.

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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, 2015, the Company had an undiscounted reserve for environmental remediation of approximately $52 million. Apache is not aware of any environmental claims existing as of December 31, 2015 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.

With respect to the leak of produced water discovered on June 1, 2013, from a below ground pipeline in the Zama Operations area in northern Alberta, the Alberta Energy Regulator completed its investigation of the incident and issued an administrative penalty to Apache Canada Ltd. (ACL) in the amount of $16,500 CAD. The June 2013 leak resulted from a pinhole feature in the outer polyethylene liner of the composite flex line.

On October 19, 2015, the Crown served ACL with a summons and information containing charges relating to a leak of produced water in the Zama area that occurred on or between October 3 and October 25, 2013. The October 2013 leak occurred following damage to a riser by an independent external force. The seven-count charge could result in the levying of a fine. On January 18, 2016, the Crown served ACL with a summons and information containing charges relating to a separate leak of produced water in the Belloy Field operating area that occurred on or about January 20, 2014. The January 2014 leak occurred following the collapse and failure of an internal polyethylene liner on a water injection pipeline. The five-count charge could result in the levying of a fine. ACL will respond to the charges in due course. While the exposure related to these incidents is not currently determinable, the Company does not expect the economic impact of these incidents to have a material effect on the Company’s financial position, results of operations, or liquidity.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

LNG Divestiture Dispute

In respect of the purchase by Woodside of the Company’s interest in the Wheatstone and Kitimat LNG projects and accompanying upstream oil and gas reserves from the Company and its subsidiaries, the base purchase price is subject to adjustment in accordance with the terms of the applicable sale and purchase agreement. Woodside has notified the Company and its subsidiaries that it seeks purchase price adjustments in the net amounts of $175 million (for working capital adjustments), which the Company and its subsidiaries believe is time-barred, and $214 million (for all other adjustments). To the extent the parties are unable to resolve their differences, the disputes will be referred to an independent accounting expert and/or court proceedings for final determination under the terms of the applicable sale and purchase agreement. The Company believes that under the terms of the sale and purchase agreements, Woodside’s requests for payment of purchase price adjustments lack merit; therefore, the Company has not recorded a liability associated with this dispute.

Contractual Obligations

At December 31, 2015, contractual obligations for drilling rigs, purchase obligations, firm transportation agreements, and long-term operating leases are as follows:


Net Minimum Commitments	Total		2016		2017-2018		2019-2020		2021 & Beyond
	(In millions)
Drilling rig commitments	$	405	$	194	$	211	$	-	$	-
Purchase obligations⁽¹⁾		354		28		115		139		72
Firm transportation agreements		363		96		125		83		59
Office and related equipment		342		43		87		72		140
Other operating lease obligations⁽²⁾		64		22		35		6		1

Total Net Minimum Commitments	$	1,528	$	383	$	573	$	300	$	272

⁽¹⁾

Includes contractual obligations under take-or-pay contracts, NGL processing agreements, and drilling work program commitments.

⁽²⁾

Includes commitments associated with supply and standby vessels, and gas pipeline and land leases.

The table above includes leases for buildings, facilities, and related equipment with varying expiration dates through 2035. Net rental expense, excluding discontinued operations in Argentina and Australia, was $57 million, $45 million, and $40 million for 2015, 2014, and 2013, respectively. Costs incurred under take-or-pay and throughput obligations were $92 million, $89 million, and $72 million for 2015, 2014, and 2013, respectively.

9. RETIREMENT AND DEFERRED COMPENSATION PLANS

Apache Corporation provides retirement benefits to its U.S. employees through the use of multiple plans: a 401(k) savings plan, a money purchase retirement plan, a non-qualified retirement/savings plan, and a non-qualified restorative retirement savings plan. The 401(k) savings plan provides participating employees the ability to elect to contribute up to 50 percent of eligible compensation, as defined, to the plan with the Company making matching contributions up to a maximum of 8 percent of each employee’s annual eligible compensation. In addition, the Company, 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

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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 $77 million, $107 million, and $123 million for 2015, 2014, and 2013, 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, 2015, 2014, and 2013, 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.


	2015				2014				2013
	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	$	216	$	23	$	189	$	28	$	177	$	35
Service cost		5		2		5		3		5		4
Interest cost		8		1		9		1		7		1
Foreign currency exchange rate changes		(10)		-		(13)		-		4		-
Actuarial losses (gains)		(10)		-		31		(9)		-		(8)
Effect of curtailment and settlements		-		1		-		-		-		(3)
Benefits paid		(7)		(2)		(5)		(2)		(4)		(2)
Retiree contributions		-		1		-		1		-		1

Projected benefit obligation at end of year		202		26		216		22		189		28

Change in Plan Assets
Fair value of plan assets at beginning of year		206		-		191		-		170		-
Actual return on plan assets		1		-		25		-		15		-
Foreign currency exchange rates		(10)		-		(13)		-		4		-
Employer contributions		7		1		8		1		6		1
Benefits paid		(7)		(2)		(5)		(2)		(4)		(2)
Retiree contributions		-		1		-		1		-		1

Fair value of plan assets at end of year		197		-		206		-		191		-

Funded status at end of year	$	(5)	$	(26)	$	(10)	$	(22)	$	2	$	(28)

Amounts recognized in Consolidated Balance Sheet
Current liability		-		(2)		-		(1)		-		(1)
Non-current asset (liability)		(5)		(24)		(10)		(21)		2		(27)

	$	(5)	$	(26)	$	(10)	$	(22)	$	2	$	(28)

Pre-tax Amounts Recognized in Accumulated Other Comprehensive Income (Loss)
Accumulated gain (loss)		(32)		9		(37)		10		(22)		1

	$	(32)	$	9	$	(37)	$	10	$	(22)	$	1

Weighted Average Assumptions used as of 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%

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

As of December 31, 2015, 2014, and 2013, the accumulated benefit obligation for the U.K. Pension Plan was $169 million, $183 million, and $160 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
	2015		2015		2014
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		48%		48%		48%
U.K. corporate bonds		12%		12%		12%

Debt securities		60%		60%		60%

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, 2015 and December 31, 2014:


	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, 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


December 31, 2014
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⁾		99		-		-		99
U.K. corporate bonds⁽⁴⁾		25		-		-		25

Total debt securities		124		-		-		124

Fair value of plan assets	$	206	$	-	$	-	$	206

⁽¹⁾

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

⁽²⁾

This category includes overseas equities, which comprises 30.3 percent passive global equities benchmarked against the MSCI World (NDR) Index, 12.1 percent passive global equities (hedged) benchmarked against the MSCI World (NDR) Hedged Index, 30.3 percent fundamental indexation global equities benchmarked against the FTSE RAFI Developed 1000 index, 12.1 percent fundamental indexation global equities (hedged) benchmarked against the FTSE RAFI Developed 1000 Hedge Index, and 15.2 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.

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The expected long-term rate of return on assets assumptions are derived relative to the yield on long-dated fixed-interest bonds issued by the U.K. government (gilts). For equities, 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, 2015, 2014, and 2013:


	2015				2014				2013
	Pension Benefits		Postretirement Benefits		Pension Benefits		Postretirement Benefits		Pension Benefits		Postretirement Benefits
	(In millions)
Component of Net Periodic Benefit Costs
Service cost	$	5	$	2	$	5	$	3	$	5	$	4
Interest cost		8		1		9		1		7		1
Expected return on assets		(8)		-		(11)		-		(8)		-
Amortization of actuarial (gain) loss		2		-		1		-		2		-
Curtailment (gain) loss		-		-		-		-		-		(3)

Net periodic benefit cost	$	7	$	3	$	4	$	4	$	6	$	2

Weighted Average Assumptions used to determine Net Period Benefit Cost for the Years ended December 31
Discount rate		3.70%		3.62%		4.60%		4.33%		4.30%		3.43%
Salary increases		4.60%		N/A		4.90%		N/A		4.60%		N/A
Expected return on assets		3.90%		N/A		5.60%		N/A		4.70%		N/A
Healthcare cost trend
Initial		N/A		7.00%		N/A		7.00%		N/A		7.25%
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		4		(3)

Apache expects to contribute approximately $7 million to its pension plan and $2 million to its postretirement benefit plan in 2016. The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:


	Pension Benefits		Postretirement Benefits
	(In millions)
2016	$	4	$	2
2017		4		2
2018		4		2
2019		4		2
2020		4		2
Years 2021-2025		22		10

F-41

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

10. CAPITAL STOCK

Common Stock Outstanding


	2015		2014		2013
Balance, beginning of year		376,504,892		395,772,908		391,640,770
Shares issued for stock-based compensation plans:
Treasury shares issued		17,525		17,454		25,214
Common shares issued		1,511,758		1,665,259		929,596
Common shares issued for conversion of preferred shares		-		-		14,399,247
Treasury shares acquired		-		(20,950,729)		(11,221,919)

Balance, end of year		378,034,175		376,504,892		395,772,908

Net Income per Common Share

A reconciliation of the components of basic and diluted net income per common share for the years ended December 31, 2015, 2014, and 2013 is presented in the table below.


	2015						2014						2013
	Loss		Shares		Per Share		Loss		Shares		Per Share		Income		Shares		Per Share
	(In millions, except per share amounts)
Basic:
Income (loss) from continuing operations	$	(22,348)		378	$	(59.16)	$	(3,815)		384	$	(9.93)	$	1,880		395	$	4.75
Income (loss) from discontinued operations		(771)		378		(2.04)		(1,588)		384		(4.13)		308		395		0.78

Income (loss) attributable to common stock	$	(23,119)		378	$	(61.20)	$	(5,403)		384	$	(14.06)	$	2,188		395	$	5.53


Effect of Dilutive Securities:
Mandatory Convertible Preferred Stock	$	-		-			$	-		-			$	44		9
Stock options and other		-		-				-		-				-		2


Diluted:
Income (loss) from continuing operations	$	(22,348)		378	$	(59.16)	$	(3,815)		384	$	(9.93)	$	1,924		406	$	4.74
Income (loss) from discontinued operations		(771)		378		(2.04)		(1,588)		384		(4.13)		308		406		0.76

Income (loss) attributable to common stock	$	(23,119)		378	$	(61.20)	$	(5,403)		384	$	(14.06)	$	2,232		406	$	5.50

The diluted EPS calculation excludes options and restricted shares that were anti-dilutive totaling 7.0 million, 4.5 million, and 4.9 million for the years ended December 31, 2015, 2014, and 2013, respectively.

Stock Repurchase Program

F-42

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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 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 2015, $0.95 per share in 2014, and $0.77 per share in 2013.

Stock Compensation Plans

The Company has several stock-based compensation plans, which include stock options, stock appreciation rights, restricted stock, and conditional restricted stock unit plans. On May 5, 2011, the Company’s shareholders approved the 2011 Omnibus Equity Compensation Plan (the 2011 Plan), which is intended to provide eligible employees with equity-based incentives. The 2011 Plan provides for the granting of Incentive Stock Options, Non-Qualified Stock Options, Performance Awards, Restricted Stock, Restricted Stock Units, Stock Appreciation Rights, or any combination of the foregoing. A total of 18.0 million shares were authorized and available for grant under the 2011 Plan as of December 31, 2015. Previously approved plans remain in effect solely for the purpose of governing grants still outstanding that were issued prior to approval of the 2011 Plan. All new grants are issued from the 2011 Plan.

For 2015, 2014, and 2013, stock-based compensation expensed was $100 million, $148 million, and $136 million ($65 million, $95 million, and $94 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:


	2015		2014		2013
	(In millions)
Stock-based compensation expensed:
General and administrative	$	64	$	107	$	89
Lease operating expenses		36		41		47
Stock-based compensation capitalized		53		62		55

	$	153	$	210	$	191

Stock Options

As of December 31, 2015, the Company had issued options to purchase shares of the Company’s common stock under one or more of the employee stock option plans adopted in 2000 and 2005 (collectively, the Stock Option Plans), as well as the 2007 Omnibus Equity Compensation Plan (the 2007 Plan), and the 2011 Plan discussed above (together, the Omnibus Plans). New shares of Company stock will be issued for employee stock option exercises; however, under the 2000 Stock Option Plan, shares of treasury stock are used for employee stock option exercises to the extent treasury stock is held. Under the Stock Option Plans and the Omnibus Plans, the exercise price of each option equals the closing price of Apache’s common stock on the date of grant. Prior to 2016, options generally become exercisable ratably over a four-year period and expire 10 years after granted. The Omnibus Plans and all of the Stock Option Plans, except for the 2000 Stock Option Plan, were submitted to and approved by the Company’s shareholders.

F-43

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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


	2015
	Shares Under Option		Weighted Average Exercise Price
	(In thousands)
Outstanding, beginning of year		6,445	$	90.34
Granted		-		-
Exercised		(280)		56.72
Forfeited or expired		(1,234)		93.28

Outstanding, end of year⁽¹⁾		4,931		91.52

Expected to vest⁽¹⁾		566		81.77

Exercisable, end of year⁽¹⁾		4,311		92.92

⁽¹⁾

As of December 31, 2015, the weighted average remaining contractual life for options outstanding, expected to vest, and exercisable is 4.5 years, 6.9 years, and 4.1 years, respectively. The aggregate intrinsic value of options outstanding, expected to vest, and exercisable at year-end was nil.

The intrinsic value of options exercised during 2015, 2014, and 2013 was approximately $3 million, $13 million and $4 million, respectively. The cash received from exercise of options during 2015 was approximately $16 million. The Company realized an additional tax benefit of approximately $973,767 for the amount of intrinsic value in excess of compensation cost recognized in 2015. As of December 31, 2015, the total compensation cost related to non-vested options not yet recognized was $5 million, which will be recognized over the remaining vesting period of the options.

In February 2016, the Company issued 872,574 options to purchase shares of the Company’s common stock to eligible employees under the 2011 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 2015, the Company awarded 2,976,562 restricted stock units at a weighted-average per-share market price of $61.65. In 2014 and 2013, the Company awarded 3,046,744 and 3,098,029 restricted stock units at a weighted-average per-share market price of $86.87 and $82.95, 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 2015, 2014, and 2013, $90 million ($58 million after tax), $93 million ($60 million after tax), and $82 million ($53 million after tax), respectively, was charged to expense. In 2015, 2014, and 2013, $48 million, $43 million, and $30 million was capitalized, respectively. As of December 31, 2015, there was $217 million of total unrecognized compensation cost related to 4,570,203 unvested restricted stock units. The weighted-average remaining life of unvested restricted stock units is approximately 1.1 years.

F-44

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The fair value of the awards vested during 2015, 2014 and 2013 was approximately $149 million, $138 million, and $88 million, respectively. A summary of restricted stock activity for the year ended December 31, 2015, is presented below.


	Shares		Weighted- Average Grant- Date Fair Value
	(In thousands)
Non-vested at January 1, 2015		4,784	$	81.96
Granted		2,976		61.65
Vested		(1,839)		81.14
Forfeited		(1,351)		78.26

Non-vested at December 31, 2015		4,570		70.12

In February 2016, the Company issued 2,881,924 shares of restricted stock units at a weighted-average per-share market price of $41.24 under the 2011 Plan to eligible employees. The total compensation cost of $119 million 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, 2015, 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 cancelled 918,016 awards under the 2013 Performance Program for nonexecutive employees. A total of 108,217 awards were outstanding at December 31, 2015, from which a minimum of zero and a maximum of 216,434 units could be awarded.

•

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. A total of 63,995 awards were outstanding at December 31, 2015, from which a minimum of zero and a maximum of 127,990 units could be awarded.

F-45

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 2015, 2014, and 2013, $648,000 ($418,000 after tax), $18 million ($11 million after tax), and $27 million ($17 million after tax), respectively, was charged to expense. During 2015, 2014, and 2013, $267,000, $7 million, and $13 million was capitalized, respectively. As of December 31, 2015, there was $4.7 million of total unrecognized compensation cost related to 172,212 unvested conditional restricted stock units. The weighted-average remaining life of the unvested conditional restricted stock units is approximately 1.8 years.


	Shares		Weighted- Average Grant- Date Fair Value⁽¹⁾
	(In thousands)
Non-vested at January 1, 2015		354	$	78.13
Granted		-		-
Vested		-		-
Forfeited or expired		(182)		72.09

Non-vested at December 31, 2015		172		78.22

⁽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

Beginning in 2015, Apache issued a new business performance program to 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 actual amount of shares awarded will be between zero and 150 percent of target. 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.

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. A total of 500,972 units were outstanding as of December 31, 2015, from which a minimum of zero and a maximum of 751,458 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 2015, $3.4 million ($2.2 million after tax) and $1.4 million were charged to expense and capitalized, respectively. As of December 31, 2015, there was $29 million of total unrecognized compensation cost related to 500,972 unvested conditional restricted stock units. The weighted-average remaining life of the unvested conditional restricted stock units is approximately 2.4 years.

F-46

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


	Shares		Weighted Average Grant- Date Fair Value⁽¹⁾
	(In thousands)
Non-vested at January 1, 2015		-	$	-
Granted		602		66.63
Vested		-		-
Forfeited or expired		(101)		66.63

Non-vested at December 31, 2015		501		66.63

⁽¹⁾

In January 2016, the Company’s Board of Directors approved the 2016 Performance Program, pursuant to the 2011 Plan, with terms similar to the 2015 Performance Program described above. Eligible employees received the initial conditional restricted stock unit totaling 855,263, with the ultimate number of restricted stock units to be awarded ranging from zero to a maximum of 1,710,526 units. The grant date fair value per award was $36.55.

11. ACCUMULATED OTHER COMPREHENSIVE LOSS

Components of accumulated other comprehensive loss include the following:


	For the Year Ended December 31,
	2015		2014		2013
	(In millions)
Currency translation adjustment⁽¹⁾	$	(109)	$	(109)	$	(109)
Unrealized gain (loss) on derivatives (Note 3)		-		-		1
Unfunded pension and postretirement benefit plan (Note 9)		(7)		(7)		(7)

Accumulated other comprehensive loss	$	(116)	$	(116)	$	(115)

⁽¹⁾

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

12. MAJOR CUSTOMERS

In 2015, 2014, and 2013, purchases by Royal Dutch Shell plc and its subsidiaries accounted for 11 percent, 19 percent, and 24 percent, respectively, of the Company’s worldwide oil and gas production revenues.

F-47

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

13. BUSINESS SEGMENT INFORMATION

Apache is engaged in a single line of business. Both domestically and internationally, the Company explores for, develops, and produces natural gas, crude oil and natural gas liquids. At December 31, 2015, the Company had production in four countries: the United States, Canada, Egypt, and the U.K. North Sea. Apache also pursues exploration interests in other countries that may over time result in reportable discoveries and development opportunities. Financial information for each country is presented below:


	United States		Canada		Egypt⁽¹⁾		North Sea		Other International		Total⁽¹⁾
	(In millions)
2015
Oil and gas production revenues	$	2,637	$	498	$	1,968	$	1,280	$	-	$	6,383
Operating Expenses:
Depreciation, depletion, and amortization:
Recurring		1,522		312		1,275		746		-		3,855
Additional		19,537		3,667		281		2,032		-		25,517
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
Taxes other than income		184		26		9		63		-		282

Operating Income (Loss)	$	(19,441)	$	(3,883)	$	(164)	$	(1,993)	$	-		(25,481)


Other Income (Expense):
Other												(17)
Impairments												(1,920)
General and administrative												(377)
Transaction, reorganization, and separation												(132)
Financing costs, net												(299)

Net Loss From Continuing Operations Before Income Taxes											$	(28,226)

Net Property and Equipment	$	5,826	$	1,314	$	3,998	$	2,929	$	52	$	14,119

Total Assets	$	7,113	$	1,465	$	6,249	$	3,951	$	64	$	18,842

Additions to Net Property and Equipment	$	2,454	$	324	$	915	$	733	$	28	$	4,454

F-48

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


	United States		Canada		Egypt⁽¹⁾		North Sea		Other International		Total⁽¹⁾
	(In millions)
2014
Oil and gas production revenues⁽²⁾	$	5,744	$	1,092	$	3,539	$	2,316	$	-	$	12,691
Operating Expenses:
Depreciation, depletion, and amortization:
Recurring		2,170		400		1,151		998		-		4,719
Additional		4,412		-		-		589		-		5,001
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
Taxes other than income		350		31		11		185		-		577

Operating Income (Loss)⁽²⁾	$	(2,245)	$	115	$	1,838	$	21	$	-		(271)

Other Income (Expense):
Other												110
Impairments												(1,919)
General and administrative												(451)
Transaction, reorganization, and separation												(67)
Financing costs, net												(211)

Net Income From Continuing Operations Before Income Taxes⁽²⁾											$	(2,809)

Net Property and Equipment⁽²⁾	$	24,627	$	6,107	$	5,700	$	5,103	$	23	$	41,560

Total Assets⁽²⁾	$	26,853	$	6,640	$	7,292	$	6,101	$	46	$	46,932

Additions to Net Property and Equipment⁽²⁾	$	7,294	$	963	$	1,397	$	1,071	$	(28)	$	10,697

2013
Oil and gas production revenues⁽²⁾	$	6,902	$	1,224	$	3,917	$	2,728	$	-	$	14,771
Operating Expenses:
Depreciation, depletion, and amortization:
Recurring		2,338		505		1,005		1,022		1		4,871
Additional		552		-		-		367		76		995
Asset retirement obligation accretion		94		49		-		68		-		211
Lease operating expenses		1,320		459		471		400		-		2,650
Gathering and transportation		84		155		42		7		-		288
Taxes other than income		335		45		8		384		-		772

Operating Income (Loss)⁽²⁾	$	2,179	$	11	$	2,391	$	480	$	(77)		4,984


Other Income (Expense):
Other												(333)
General and administrative												(481)
Transaction, reorganization, and separation												(33)
Financing costs, net												(229)

Net Income From Continuing Operations Before Income Taxes⁽²⁾											$	3,908

Net Property and Equipment⁽²⁾	$	27,010	$	6,058	$	5,454	$	5,622	$	23	$	44,167

Total Assets⁽²⁾	$	29,940	$	6,952	$	8,121	$	6,902	$	51	$	51,966

Additions to Net Property and Equipment⁽²⁾	$	6,404	$	1,082	$	1,309	$	1,084	$	24	$	9,903

⁽¹⁾

Includes a noncontrolling interest in Egypt.

⁽²⁾

Prior year amounts have been recast to exclude discontinued operations.

F-49

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

14. SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited)

Oil and Gas Operations

The following table sets forth revenue and direct cost information relating to the Company’s oil and gas exploration and production activities. Apache has no long-term agreements to purchase oil or gas production from foreign governments or authorities. 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)
2015
Oil and gas production revenues	$	2,637	$	498	$	1,968	$	1,280	$	-	$	6,383

Operating cost:
Depreciation, depletion, and amortization
Recurring⁽¹⁾		1,419		262		1,128		722		-		3,531
Additional		19,537		3,667		281		2,032		-		25,517
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
Production taxes⁽²⁾		178		23		-		58		-		259
Income tax		(6,863)		(1,000)		(4)		(982)		-		(8,849)

		15,106		3,328		1,972		2,262		-		22,668

Results of operation	$	(12,469)	$	(2,830)	$	(4)	$	(982)	$	-	$	(16,285)

Amortization rate per boe	$	15.49	$	10.61	$	21.29	$	27.77	$	-	$	18.08


2014
Oil and gas production revenues	$	5,744	$	1,092	$	3,539	$	2,316	$	-	$	12,691

Operating cost:
Depreciation, depletion, and amortization
Recurring⁽¹⁾		2,056		343		1,014		975		-		4,388
Additional		4,412		-		-		589		-		5,001
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
Production taxes⁽²⁾		342		27		-		177		-		546
Income tax		(754)		44		914		32		-		236

		7,113		960		2,467		2,296		-		12,836

Results of operation	$	(1,369)	$	132	$	1,072	$	20	$	-	$	(145)

Amortization rate per boe	$	19.35	$	12.11	$	18.48	$	37.41	$	-	$	20.36

F-50

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


	United States		Canada		Egypt⁽³⁾		North Sea		Other International		Total⁽³⁾⁽⁴⁾
	(In millions, except per boe)

2013
Oil and gas production revenues	$	6,902	$	1,224	$	3,917	$	2,728	$	-	$	14,771

Operating cost:
Depreciation, depletion, and amortization
Recurring⁽¹⁾		2,227		426		881		999		-		4,533
Additional		552		-		-		367		76		995
Asset retirement obligation accretion		94		49		-		68		-		211
Lease operating expenses		1,320		459		471		400		-		2,650
Gathering and transportation		84		155		42		7		-		288
Production taxes⁽²⁾		324		40		-		382		-		746
Income tax		817		24		1,161		313		-		2,315

		5,418		1,153		2,555		2,536		76		11,738

Results of operation	$	1,484	$	71	$	1,362	$	192	$	(76)	$	3,033

Amortization rate per boe	$	18.39	$	10.89	$	16.21	$	37.25	$	-	$	18.77

⁽¹⁾

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

⁽²⁾

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

⁽³⁾

Includes noncontrolling interest in Egypt.

⁽⁴⁾

Prior year amounts have been recast to exclude discontinued operations.

F-51

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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


	United States		Canada		Egypt⁽²⁾		Australia		North Sea		Argentina		Other International		Total⁽²⁾
	(In millions)
2015
Acquisitions:
Proved	$	1	$	8	$	25	$	1	$	-	$	-	$	-	$	35
Unproved		313		23		4		-		-		-		-		340
Exploration		131		41		110		31		111		-		29		453
Development		1,957		193		764		101		623		-		-		3,638

Costs incurred⁽¹⁾	$	2,402	$	265	$	903	$	133	$	734	$	-	$	29	$	4,466

⁽¹⁾ Includes capitalized interest and asset retirement costs as follows:
Capitalized interest	$	169	$	25	$	17	$	9	$	16	$	-	$	-	$	236
Asset retirement costs		123		8		-		-		(66)		-		-		65

2014
Acquisitions:
Proved	$	102	$	-	$	1	$	1	$	-	$	-	$	-	$	104
Unproved		1,221		141		10		16		-		-		-		1,388
Exploration		467		82		193		137		84		9		1		973
Development		5,301		846		1,142		914		971		6		-		9,180

Costs incurred⁽¹⁾	$	7,091	$	1,069	$	1,346	$	1,068	$	1,055	$	15	$	1	$	11,645

⁽¹⁾ Includes capitalized interest and asset retirement costs as follows:
Capitalized interest	$	209	$	38	$	15	$	20	$	25	$	3	$	-	$	310
Asset retirement costs		43		175		-		55		34		-		-		307

2013
Acquisitions:
Proved	$	17	$	-	$	35	$	-	$	125	$	-	$	-	$	177
Unproved		195		151		15		(10)		17		11		-		379
Exploration		562		36		559		179		278		42		22		1,678
Development		5,435		722		618		996		635		142		-		8,548

Costs incurred⁽¹⁾	$	6,209	$	909	$	1,227	$	1,165	$	1,055	$	195	$	22	$	10,782

⁽¹⁾Includes capitalized interest and asset retirement costs as follows:
Capitalized interest	$	239	$	35	$	15	$	16	$	25	$	10	$	-	$	340
Asset retirement costs		480		17		-		(30)		67		3		-		537

⁽²⁾ Includes a noncontrolling interest in Egypt.

F-52

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Capitalized Costs

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


	United States			Canada			Egypt⁽¹⁾			Australia			North Sea			Other International			Total⁽¹⁾
	(In millions)
2015
Proved properties	$	51,693		$	14,613		$	11,296		$	-		$	11,266		$	201		$	89,069
Unproved properties		1,824			234			30			-			471			52			2,611

		53,517			14,847			11,326			-			11,737			253			91,680
Accumulated DD&A		(48,161	)		(13,582	)		(7,779	)		-			(9,129	)		(201	)		(78,852	)

	$	5,356		$	1,265		$	3,547		$	-		$	2,608		$	52		$	12,828


2014
Proved properties	$	47,001		$	14,003		$	9,895		$	8,289		$	10,463		$	201		$	89,852
Unproved properties		4,151			1,090			529			549			672			23			7,014

		51,152			15,093			10,424			8,838			11,135			224			96,866
Accumulated DD&A		(27,205	)		(9,653	)		(6,369	)		(3,198	)		(6,375	)		(201	)		(53,001	)

	$	23,947		$	5,440		$	4,055		$	5,640		$	4,760		$	23		$	43,865

⁽¹⁾ Includes a noncontrolling interest in Egypt.

Costs Not Being Amortized

The following table sets forth a summary of oil and gas property costs not being amortized at December 31, 2015, by the year in which such costs were incurred. There are no individually significant properties or significant development projects included in costs not being amortized. The majority of the evaluation activities are expected to be completed within five to ten years.


	Total		2015		2014		2013		2012 and Prior
	(In millions)
Property acquisition costs	$	1,960	$	316	$	1,311	$	210	$	123
Exploration and development		586		569		15		1		1
Capitalized interest		65		16		13		4		32

Total	$	2,611	$	901	$	1,339	$	215	$	156

Oil and Gas Reserve Information

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

F-53

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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

F-54

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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


	Crude Oil and Condensate
	(Thousands of barrels)
	United States		Canada		Egypt⁽¹⁾		Australia		North Sea		Argentina		Total⁽¹⁾
Proved developed reserves:
December 31, 2012		474,837		79,695		106,746		29,053		119,635		15,845		825,811
December 31, 2013		457,981		80,526		119,242		22,524		100,327		14,195		794,795
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
Proved undeveloped reserves:
December 31, 2012		203,068		70,650		17,288		34,808		28,019		2,981		356,814
December 31, 2013		195,835		56,366		16,302		36,703		29,253		2,231		336,690
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
Total proved reserves:
Balance December 31, 2012		677,905		150,345		124,034		63,861		147,654		18,826		1,182,625
Extensions, discoveries and other additions		133,227		10,177		43,738		2,539		1,543		998		192,222
Purchase of minerals in-place		85		-		5		-		3,623		-		3,713
Revisions of previous estimates		1,683		(531)		457		(118)		18		24		1,533
Production		(53,621)		(6,469)		(32,690)		(7,055)		(23,258)		(3,422)		(126,515)
Sale of properties		(105,463)		(16,630)		-		-		-		-		(122,093)

Balance December 31, 2013		653,816		136,892		135,544		59,227		129,580		16,426		1,131,485
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)		1,801		(216)		(7)		-		3,849
Production		(48,789)		(6,421)		(32,090)		(7,494)		(22,154)		(620)		(117,568)
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)		25,407		11,189		(2,255)		-		(167,532)
Production		(45,138)		(5,755)		(31,240)		(2,778)		(21,657)		-		(106,568)
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

⁽¹⁾ 2015, 2014, and 2013 includes proved reserves of 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, 2012		154,508		21,996		-		-		2,438		5,007		183,949
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
Proved undeveloped reserves:
December 31, 2012		60,889		12,258		-		-		380		876		74,403
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
Total proved reserves:
Balance December 31, 2012		215,397		34,254		-		-		2,818		5,883		258,352
Extensions, discoveries and other additions		69,231		4,014		-		-		-		-		73,245
Purchase of minerals in-place		45		-		-		-		295		-		340
Revisions of previous estimates		1,591		546		-		-		1		3		2,141
Production		(19,922)		(2,442)		-		-		(464)		(767)		(23,595)
Sale of properties		(18,319)		(303)		-		-		-		-		(18,622)

Balance December 31, 2013		248,023		36,069		-		-		2,650		5,119		291,861
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		(17)		-		(2)		-		2,691
Production		(21,464)		(2,256)		(245)		-		(508)		(116)		(24,589)
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

⁽¹⁾ 2015 and 2014 includes proved reserves of 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, 2012		2,353,587		1,734,657		690,436		596,052		93,319		365,054		5,833,105
December 31, 2013		2,005,966		1,294,420		621,825		626,543		88,177		289,133		4,926,064
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
Proved undeveloped reserves:
December 31, 2012		832,320		403,227		205,055		1,074,018		18,985		97,496		2,631,101
December 31, 2013		667,160		439,037		190,355		975,224		18,988		121,584		2,412,348
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
Total proved reserves:
Balance December 31, 2012		3,185,907		2,137,884		895,491		1,670,070		112,304		462,550		8,464,206
Extensions, discoveries and other additions		306,721		359,493		44,382		13,351		2,750		16,515		743,212
Purchase of minerals in-place		855		-		-		-		10,680		-		11,535
Revisions of previous estimates		61,247		109,551		2,413		(101)		32		49		173,191
Production		(285,187)		(181,593)		(130,106)		(81,553)		(18,601)		(68,397)		(765,437)

Sale of properties		(596,417)		(691,878)		-		-		-		-		(1,288,295)

Balance December 31, 2013		2,673,126		1,733,457		812,180		1,601,767		107,165		410,717		7,338,412
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)		5,949		-		(54)		-		29,179
Production		(215,829)		(117,816)		(135,145)		(78,104)		(20,427)		(12,722)		(580,043)
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)		54,811		8,162		(22,373)		-		(788,714)
Production		(160,614)		(100,289)		(128,239)		(34,352)		(23,647)		-		(447,141)

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

⁽¹⁾ 2015, 2014, and 2013 include proved reserves of 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, 2012		1,021,610		390,800		221,819		128,395		137,626		81,695		1,981,945
December 31, 2013		976,795		322,362		222,880		126,948		117,457		66,494		1,832,936
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
Proved undeveloped reserves:
December 31, 2012		402,677		150,113		51,464		213,811		31,563		20,106		869,734
December 31, 2013		370,566		139,509		48,028		199,240		32,633		23,504		813,480
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
Total proved reserves:
Balance December 31, 2012		1,424,287		540,913		273,283		342,206		169,189		101,801		2,851,679
Extensions, discoveries and other additions		253,578		74,107		51,135		4,764		2,001		3,751		389,336
Purchase of minerals in-place		273		-		5		-		5,698		-		5,976
Revisions of previous estimates		13,482		18,274		859		(135)		24		35		32,539
Production		(121,074)		(39,177)		(54,374)		(20,647)		(26,822)		(15,589)		(277,683)
Sale of properties		(223,185)		(132,246)		-		-		-		-		(355,431)

Balance December 31, 2013		1,347,361		461,871		270,908		326,188		150,090		89,998		2,646,416
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)		2,776		(216)		(18)		-		11,404
Production		(106,225)		(28,313)		(54,859)		(20,511)		(26,067)		(2,856)		(238,831)
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)		34,797		12,549		(6,305)		-		(368,163)
Production		(91,591)		(24,706)		(53,001)		(8,503)		(26,011)		-		(203,812)
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

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

F-58

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

During 2015, Apache sold a combined 385 MMboe through several divestiture transactions: 55 MMboe in Canada, 328 MMboe in Australia, and 2 MMboe in the North Sea. The Company added 7 MMboe of estimated proved reserves through purchases of minerals in-place and 117 MMboe from extensions, discoveries, and other additions. The Company recorded 53 MMboe in North America, primarily associated with our drilling programs in the Canadian liquid-rich gas targets of Duvernay and Montney formations and Permian Basin drilling for Wolfcamp, Yeso, Lower Spraberry, and Bone Spring formations. The Company also had additional drilling success in the Woodford, Canyon Lime, Marmaton, and Eagle Ford formations in the MidContinent/Gulf Coast region.

The international regions contributed 64 MMboe of exploration and development adds with Egypt contributing 40 MMboe from onshore exploration and appraisal activity in the West Kalabsha, Shushan, and Khalda concessions. Egypt also continued development of the Ptah, Berenice, and Razzak fields during 2015. The North Sea offshore region contributed 24 MMboe from exploration success in the Callater discovery and continued development in the Beryl, Forties, and Nevis fields.

During 2015, Apache also had combined downward revisions of previously estimated reserves of 368 MMboe. Changes in product prices accounted for 339 MMboe, lease ownership changes accounted for 16 MMboe, and engineering and performance revisions totaled 13 MMboe.

Approximately 9 percent of Apache’s year-end 2015 estimated proved developed reserves are classified as proved not producing. These reserves relate to zones that are either behind pipe, or that have been completed but not yet produced, or zones that have been produced in the past, but are not now producing because of mechanical reasons. These reserves are considered to be a lower tier of reserves than producing reserves because they are frequently based on volumetric calculations rather than performance data. Future production associated with behind pipe reserves is scheduled to follow depletion of the currently producing zones in the same wellbores. Additional capital may have to be spent to access these reserves. The capital and economic impact of production timing are reflected in this Note 14, under “Future Net Cash Flows.”

Future Net Cash Flows

Future cash inflows as of December 31, 2015 and 2014 were calculated using an unweighted arithmetic average of oil and gas prices in effect on the first day of each month in the respective year, except where prices are defined by contractual arrangements. Operating costs, production and ad valorem taxes and future development costs are based on current costs with no escalation.

F-59

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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


	United States		Canada		Egypt⁽²⁾		Australia		North Sea		Total⁽²⁾
	(In millions)
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


2014
Cash inflows	$	73,859	$	18,966	$	16,802	$	19,391	$	13,916	$	142,934
Production costs		(25,875)		(7,537)		(2,924)		(4,105)		(7,121)		(47,562)
Development costs		(4,422)		(2,453)		(1,683)		(1,173)		(2,776)		(12,507)
Income tax expense		(10,657)		(1,070)		(4,091)		(3,202)		(2,445)		(21,465)

Net cash flows		32,905		7,906		8,104		10,911		1,574		61,400
10 percent discount rate		(17,639)		(3,983)		(2,099)		(5,875)		(146)		(29,742)

Discounted future net cash flows⁽¹⁾	$	15,266	$	3,923	$	6,005	$	5,036	$	1,428	$	31,658

⁽¹⁾

Estimated future net cash flows before income tax expense, discounted at 10 percent per annum, totaled approximately $13.1 billion and $43.0 billion as of December 31, 2015 and 2014, respectively.

⁽²⁾

Includes discounted future net cash flows of approximately $1.3 billion and $2.0 billion in 2015 and 2014, respectively, attributable to a noncontrolling interest in Egypt.

F-60

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,
	2015		2014		2013
	(In millions)
Sales, net of production costs	$	(4,056)	$	(10,350)	$	(12,271)
Net change in prices and production costs		(21,710)		(1,029)		1,438
Discoveries and improved recovery, net of related costs		1,953		6,297		6,892
Change in future development costs		705		(1,136)		(2,017)
Previously estimated development costs incurred during the period		1,991		4,462		4,654
Revision of quantities		(2,292)		256		500
Purchases of minerals in-place		22		508		227
Accretion of discount		3,642		4,442		4,823
Change in income taxes		7,264		836		855
Sales of properties		(5,240)		(4,780)		(6,232)
Change in production rates and other		(3,343)		(442)		(828)

	$	(21,064)	$	(936)	$	(1,959)

F-61

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

15. SUPPLEMENTAL QUARTERLY FINANCIAL DATA (Unaudited)


	First		Second		Third		Fourth		Total
	(In millions, except per share amounts)
2015
Revenues and other	$	1,630	$	1,977	$	1,496	$	1,263	$	6,366
Expenses⁽²⁾⁽³⁾		6,134		6,809		7,047		9,133		29,123

Net income (loss) from continuing operations including noncontrolling interest		(4,504)		(4,832)		(5,551)		(7,870)		(22,757)
Net income (loss) from discontinued operations, net of tax		(132)		(732)		(95)		188		(771)

Net income (loss) including noncontrolling interest	$	(4,636)	$	(5,564)	$	(5,646)	$	(7,682)	$	(23,528)

Net income (loss) attributable to common stock	$	(4,651)	$	(5,600)	$	(5,655)	$	(7,213)	$	(23,119)

Basic net income (loss) per common share⁽¹⁾:
Net income (loss) from continuing operations	$	(11.99)	$	(12.89)	$	(14.70)	$	(19.57)	$	(59.16)
Net income (loss) from discontinued operations		(0.35)		(1.94)		(0.25)		0.50		(2.04)

Net income (loss) per share	$	(12.34)	$	(14.83)	$	(14.95)	$	(19.07)	$	(61.20)

Diluted net income (loss) per common share⁽¹⁾:
Net income (loss) from continuing operations	$	(11.99)	$	(12.89)	$	(14.70)	$	(19.57)	$	(59.16)
Net income (loss) from discontinued operations		(0.35)		(1.94)		(0.25)		0.50		(2.04)

Net income (loss) per share	$	(12.34)	$	(14.83)	$	(14.95)	$	(19.07)	$	(61.20)

2014
Revenues and other	$	3,388	$	3,289	$	3,441	$	2,683	$	12,801
Expenses⁽²⁾⁽³⁾		2,638		2,732		4,526		6,377		16,273

Net income (loss) from continuing operations including noncontrolling interest		750		557		(1,085)		(3,694)		(3,472)
Net income (loss) from discontinued operations, net of tax		(416)		56		(156)		(1,072)		(1,588)

Net income (loss) including noncontrolling interest	$	334	$	613	$	(1,241)	$	(4,766)	$	(5,060)

Net income (loss) attributable to common stock	$	236	$	505	$	(1,330)	$	(4,814)	$	(5,403)

Basic net income (loss) per common share⁽¹⁾:
Net income (loss) from continuing operations	$	1.66	$	1.17	$	(3.08)	$	(9.93)	$	(9.93)
Net income (loss) from discontinued operations		(1.06)		0.14		(0.42)		(2.85)		(4.13)

Net income (loss) per share	$	0.60	$	1.31	$	(3.50)	$	(12.78)	$	(14.06)

Diluted net income (loss) per common share⁽¹⁾:
Net income (loss) from continuing operations	$	1.65	$	1.17	$	(3.08)	$	(9.93)	$	(9.93)
Net income (loss) from discontinued operations		(1.05)		0.14		(0.42)		(2.85)		(4.13)

Net income (loss) per share	$	0.60	$	1.31	$	(3.50)	$	(12.78)	$	(14.06)

⁽¹⁾

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.

⁽²⁾

In 2015, continuing operating expenses include non-cash write-downs of the Company’s oil and gas properties totaling $16.6 billion, net of tax, in the U.S., Canada, North Sea, and Egypt regions. In 2014, operating expenses include non-cash write-downs of the Company’s oil and gas properties totaling $3.1 billion, net of tax, in the U.S. and North Sea regions.

F-62

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

⁽³⁾

In 2015, continuing operating expenses include non-cash asset impairments totaling $1.9 billion, including $1.7 billion for impairment of GTP assets, $148 million for impairment in an equity method investment, and $55 million for inventory write-downs. In 2014, operating expenses include non-cash asset impairments totaling $1.9 billion, including $1.3 billion for the impairment of goodwill, $604 million for the impairment of assets held for sale, and other asset impairments.

16. SUPPLEMENTAL GUARANTOR INFORMATION

In December 1999, Apache Finance Canada issued approximately $300 million of publicly-traded notes due in 2029, which are fully and unconditionally guaranteed by Apache. The following condensed consolidating financial statements are provided as an alternative to filing separate financial statements.

Apache Finance Canada 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-63

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME

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	$	-	$	4,937	$	-	$	6,383
Equity in net income (loss) of affiliates		(7,685)		(1,958)		57		9,586		-
Other		(18)		54		(72)		19		(17)

		(6,257)		(1,904)		4,922		9,605		6,366


OPERATING EXPENSES:
Depreciation, depletion, and amortization		19,496		-		9,876		-		29,372
Asset retirement obligation accretion		15		-		130		-		145
Lease operating expenses		399		-		1,455		-		1,854
Gathering and transportation		35		-		176		-		211
Taxes other than income		103		-		179		-		282
Impairments		112		-		1,808		-		1,920
General and administrative		300		-		58		19		377
Transaction, reorganization, and separation		132		-		-		-		132
Financing costs, net		288		(14)		25		-		299

		20,880		(14)		13,707		19		34,592


NET INCOME (LOSS) FROM CONTINUING OPERATIONS
BEFORE INCOME TAXES		(27,137)		(1,890)		(8,785)		9,586		(28,226)
Provision for income taxes		(4,188)		11		(1,292)		-		(5,469)

NET INCOME (LOSS) FROM CONTINUING OPERATIONS
INCLUDING NONCONTROLLING INTEREST		(22,949)		(1,901)		(7,493)		9,586		(22,757)
Net loss from discontinued operations, net of tax		(172)		-		(599)		-		(771)

NET INCOME (LOSS) INCLUDING
NONCONTROLLING INTEREST		(23,121)		(1,901)		(8,092)		9,586		(23,528)
Net income attributable to noncontrolling interest		-		-		(409)		-		(409)

NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	(23,121)	$	(1,901)	$	(7,683)	$	9,586	$	(23,119)

COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	(23,121)	$	(1,901)	$	(7,683)	$	9,586	$	(23,119)

F-64

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME

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	$	-	$	9,292	$	-	$	12,691
Equity in net income (loss) of affiliates		25		(209)		73		111		-
Other		195		55		(145)		5		110

		3,619		(154)		9,220		116		12,801


OPERATING EXPENSES:
Depreciation, depletion, and amortization		5,845		-		3,875		-		9,720
Asset retirement obligation accretion		31		-		123		-		154
Lease operating expenses		509		-		1,729		-		2,238
Gathering and transportation		58		-		215		-		273
Taxes other than income		206		-		371		-		577
Impairments		175		-		1,744		-		1,919
General and administrative		377		-		69		5		451
Transaction, reorganization, and separation		67		-		-		-		67
Financing costs, net		158		(24)		77		-		211

		7,426		(24)		8,203		5		15,610


NET INCOME (LOSS) FROM CONTINUING OPERATIONS
BEFORE INCOME TAXES		(3,807)		(130)		1,017		111		(2,809)
Provision for income taxes		1,472		6		(815)		-		663

NET INCOME (LOSS) FROM CONTINUING OPERATIONS
INCLUDING NONCONTROLLING INTEREST		(5,279)		(136)		1,832		111		(3,472)
Net income from discontinued operations, net of tax		(127)		-		(1,461)		-		(1,588)

NET INCOME (LOSS) INCLUDING
NONCONTROLLING INTEREST		(5,406)		(136)		371		111		(5,060)
Net income attributable to noncontrolling interest		-		-		343		-		343

NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	(5,406)	$	(136)	$	28	$	111	$	(5,403)

COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	(5,407)	$	(136)	$	28	$	111	$	(5,404)

F-65

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME

For the Year Ended December 31, 2013


	Apache Corporation		Apache Finance Canada		All Other Subsidiaries of Apache Corporation		Reclassifications & Eliminations		Consolidated
	(In millions)
REVENUES AND OTHER:
Oil and gas production revenues	$	4,585	$	-	$	10,186	$	-	$	14,771
Equity in net income (loss) of affiliates		2,313		17		36		(2,366)		-
Other		(399)		61		9		(4)		(333)

		6,499		78		10,231		(2,370)		14,438


OPERATING EXPENSES:
Depreciation, depletion, and amortization		2,250		-		3,616		-		5,866
Asset retirement obligation accretion		67		-		144		-		211
Lease operating expenses		939		-		1,711		-		2,650
Gathering and transportation		61		-		227		-		288
Taxes other than income		190		-		582		-		772
General and administrative		408		-		77		(4)		481
Acquisition, divestiture, and separation costs		33		-		-		-		33
Financing costs, net		97		5		127		-		229

		4,045		5		6,484		(4)		10,530

NET INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		2,454		73		3,747		(2,366)		3,908
Provision (benefit) for income taxes		222		20		1,686		-		1,928

NET INCOME (LOSS) FROM CONTINUING OPERATIONS INCLUDING NONCONTROLLING INTEREST		2,232		53		2,061		(2,366)		1,980
Net income from discontinued operations, net of tax		-		-		308		-		308

NET INCOME (LOSS) INCLUDING NONCONTROLLING INTEREST		2,232		53		2,369		(2,366)		2,288
Preferred stock dividends		44		-		-		-		44
Net income attributable to noncontrolling interest		-		-		56		-		56

NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	2,188	$	53	$	2,313	$	(2,366)	$	2,188

COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	2,204	$	53	$	2,313	$	(2,366)	$	2,204

F-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	$	395	$	18	$	2,421	$	-	$	2,834
CASH PROVIDED BY DISCONTINUED OPERATIONS		-		-		150		-		150

CASH PROVIDED BY OPERATING ACTIVITIES		395		18		2,571		-		2,984
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property		(1,779)		-		(2,799)		-		(4,578)
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, other		163		-		105		-		268
Investment in subsidiaries, net		6,363		-		-		(6,363)		-
Other		(34)		-		40		-		6

NET CASH USED IN CONTINUING INVESTING ACTIVITIES		4,244		-		(1,540)		(6,363)		(3,659)
NET CASH PROVIDED BY DISCONTINUED OPERATIONS		-		-		4,335		-		4,335

NET CASH USED IN INVESTING ACTIVITIES		4,244		-		2,795		(6,363)		676

CASH FLOWS FROM FINANCING ACTIVITIES:
Commercial paper, credit facility, and bank notes, net		(1,570)		-		-		-		(1,570)
Intercompany borrowings		(1,639)		(10)		(4,714)		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		(4,528)		(10)		(4,787)		6,363		(2,962)

NET CASH USED IN FINANCING ACTIVITIES		(4,528)		(10)		(4,787)		6,363		(2,962)
NET INCREASE IN CASH AND CASH
EQUIVALENTS		111		8		579		-		698
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR		267		-		502		-		769

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	378	$	8	$	1,081	$	-	$	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	$	6,691	$	17	$	809	$	-	$	7,517
CASH PROVIDED BY DISCONTINUED OPERATIONS		-		-		944		-		944

CASH PROVIDED BY OPERATING ACTIVITIES		6,691		17		1,753		-		8,461

CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property		(8,997)		-		(25)		-		(9,022)
Additions to gas gathering, transmission, and processing facilities		49		-		(930)		-		(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		(1,087)		-		(388)		-		(1,475)
Proceeds from sale of oil and gas properties		15		-		455		-		470
Investment in subsidiaries, net		1,459		-		-		(1,459)		-
Other		(278)		-		(21)		-		(299)

NET CASH USED IN CONTINUING INVESTING ACTIVITIES		(6,217)		-		(909)		(1,459)		(8,585)
NET CASH PROVIDED BY DISCONTINUED OPERATIONS		-		-		(219)		-		(219)

NET CASH USED IN INVESTING ACTIVITIES		(6,217)		-		(1,128)		(1,459)		(8,804)

CASH FLOWS FROM FINANCING ACTIVITIES:
Commercial paper, credit facility, and bank notes, net		1,570		-		(2)		-		1,568
Intercompany borrowings		-		8		(1,479)		1,471		-
Dividends paid		(365)		-		-		-		(365)
Distributions to noncontrolling interest		-		-		(140)		-		(140)
Treasury stock activity, net		(1,864)		-		-		-		(1,864)
Other		(5)		(28)		94		(12)		49

NET CASH USED IN CONTINUING FINANCING ACTIVITIES		(664)		(20)		(1,527)		1,459		(752)
NET CASH USED IN DISCONTINUED OPERATIONS		-		-		(42)		-		(42)

NET CASH USED IN FINANCING ACTIVITIES		(664)		(20)		(1,569)		1,459		(794)

NET INCREASE (DECREASE) IN CASH AND CASH
EQUIVALENTS		(190)		(3)		(944)		-		(1,137)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR		155		3		1,748		-		1,906

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	(35)	$	-	$	804	$	-	$	769

F-68

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

For the Year Ended December 31, 2013


	Apache Corporation		Apache Finance Canada		All Other Subsidiaries of Apache Corporation		Reclassifications & Eliminations		Consolidated
					(In millions)

CASH PROVIDED BY CONTINUING OPERATING ACTIVITIES	$	1,421	$	315	$	6,949	$	-	$	8,685
CASH PROVIDED BY DISCONTINUED OPERATIONS		-		-		1,150		-		1,150

CASH PROVIDED BY OPERATING ACTIVITIES		1,421		315		8,099		-		9,835

CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property		(4,096)		-		(4,567)		-		(8,663)
Additions to gas gathering, transmission, and processing facilities		(124)		-		(340)		-		(464)
Proceeds from divestiture of Gulf of Mexico Shelf properties		3,702		-		-		-		3,702
Leasehold and property acquisitions		(195)		-		(234)		-		(429)
Proceeds from Kitimat LNG transaction, net		-		-		396		-		396
Proceeds from sale of oil and gas properties		-		-		307		-		307
Other		(58)		-		(47)		-		(105)

NET CASH USED IN CONTINUING INVESTING ACTIVITIES		(771)		-		(4,485)		-		(5,256)
NET CASH USED IN DISCONTINUED OPERATIONS		-		-		(1,860)		-		(1,860)

NET CASH USED IN INVESTING ACTIVITIES		(771)		-		(6,345)		-		(7,116)

CASH FLOWS FROM FINANCING ACTIVITIES:
Commercial paper, credit facility, and bank notes, net		(501)		-		(8)		-		(509)
Intercompany borrowings		3,056		1		(3,057)		-		-
Payments on fixed rate debt		(1,722)		(350)		-		-		(2,072)
Dividends paid		(360)		-		-		-		(360)
Proceeds from sale of noncontrolling interest		-		-		2,948		-		2,948
Shares repurchased		(997)		-		-		-		(997)
Other		29		37		(45)		-		21

NET CASH USED IN CONTINUING FINANCING ACTIVITIES		(495)		(312)		(162)		-		(969)
NET CASH USED IN DISCONTINUED OPERATIONS		-		-		(4)		-		(4)

NET CASH USED IN FINANCING ACTIVITIES		(495)		(312)		(166)		-		(973)

NET INCREASE IN CASH AND CASH EQUIVALENTS		155		3		1,588		-		1,746
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR		-		-		160		-		160

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	155	$	3	$	1,748	$	-	$	1,906

F-69

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

CONDENSED CONSOLIDATING 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		-		-		14,119		-		14,119

OTHER ASSETS:
Intercompany receivable		-		-		10,744		(10,744)		-
Equity in affiliates		16,443		(1,154)		446		(15,735)		-
Deferred charges and other		157		1,001		813		(1,000)		971

	$	22,656	$	153	$	29,030	$	(32,691)	$	18,842

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		8,479		298		-		-		8,777

DEFERRED CREDITS AND OTHER
NONCURRENT LIABILITIES:
Intercompany payable		10,744		-		-		(10,744)		-
Income taxes		(1,285)		4		2,353		-		1,072
Asset retirement obligation		271		-		2,291		-		2,562
Other		933		250		179		(1,000)		362

		10,663		254		4,823		(11,744)		3,996

COMMITMENTS AND CONTINGENCIES APACHE SHAREHOLDERS’ EQUITY		2,566		(708)		16,443		(15,735)		2,566
Noncontrolling interest		-		-		1,662		-		1,662

TOTAL EQUITY		2,566		(708)		18,105		(15,735)		4,228

	$	22,656	$	(153)	$	29,030	$	(32,691)	$	18,842

F-70

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

CONDENSED CONSOLIDATING BALANCE SHEET

December 31, 2014


	Apache Corporation		Apache Finance Canada		All Other Subsidiaries of Apache Corporation		Reclassifications & Eliminations		Consolidated
					(In millions)

ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	267	$	-	$	502	$	-	$	769
Receivables, net of allowance		837		-		1,187		-		2,024
Inventories		24		-		684		-		708
Drilling advances		34		1		353		-		388
Assets held for sale		-		-		1,628		-		1,628
Deferred tax asset		612		-		157		-		769
Prepaid assets and other		32		-		97		-		129
Intercompany receivable		4,939		-		-		(4,939)		-

		6,745		1		4,608		(4,939)		6,415

PROPERTY AND EQUIPMENT, NET		13,940		-		34,136		-		48,076

OTHER ASSETS:
Intercompany receivable		-		-		608		(608)		-
Equity in affiliates		25,791		869		444		(27,104)		-
Deferred charges and other		175		1,002		1,284		(1,000)		1,461

	$	46,651	$	1,872	$	41,080	$	(33,651)	$	55,952

LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable	$	748	$	10	$	452	$	-	$	1,210
Other current liabilities		1,042		1		1,411		-		2,454
Intercompany payable		-		-		4,939		(4,939)		-

		1,790		11		6,802		(4,939)		3,664

LONG-TERM DEBT		10,947		298		-		-		11,245

DEFERRED CREDITS AND OTHER
NONCURRENT LIABILITIES:
Intercompany payable		608		-		-		(608)		-
Income taxes		5,076		-		4,423		-		9,499
Asset retirement obligation		211		-		2,837		-		3,048
Other		2,082		250		(973)		(1,000)		359

		7,977		250		6,287		(1,608)		12,906

COMMITMENTS AND CONTINGENCIES APACHE SHAREHOLDERS’ EQUITY		25,937		1,313		25,791		(27,104)		25,937
Noncontrolling interest		-		-		2,200		-		2,200

TOTAL EQUITY		25,937		1,313		27,991		(27,104)		28,137

	$	46,651	$	1,872	$	41,080	$	(33,651)	$	55,952

F-71

Board of Directors

Annell R. Bay ^{(2) (3)}

Former Vice President – Global Exploration

Marathon Oil Corporation

John J. Christmann IV

Chief Executive Officer and President

Apache Corporation

Chansoo Joung ^(1)
(2)

Former Partner,

Warburg Pincus LLC

George D. Lawrence⁽¹⁾

Private Investor; Former Chief Executive Officer,

The Phoenix Resource Companies, Inc.

John E. Lowe

Chairman of the Board, Apache Corporation

Former Executive Vice President,

ConocoPhillips

William C. Montgomery^(2)
(3)

Managing Director, Quantum Energy Partners

Amy H. Nelson⁽¹⁾

President and Founder, Greenridge Advisors, LLC

Rodman D. Patton⁽¹⁾

Former Managing Director,

Merrill Lynch Energy Group

Charles J. Pitman^(2)
(3)

Former Regional President – Middle East/

Caspian/Egypt/India, BP Amoco plc

Daniel W. Rabun⁽³⁾

Former Chairman, Ensco plc

Peter A. Ragauss⁽¹⁾

Former Senior Vice President and Chief Financial Officer

Baker Hughes Incorporated

Officers

John J. Christmann IV

Chief Executive Officer and President

Stephen J. Riney

Executive Vice President and Chief Financial Officer

Margery M. Harris

Executive Vice President – Human Resources

P. Anthony Lannie

Executive Vice President and General Counsel

W. Kregg Olson

Executive Vice President – Corporate Reservoir Engineering

Timothy J. Sullivan

Executive Vice President – Operations Support

Rebecca A. Hoyt

Senior Vice President – Chief Accounting Officer and Controller

Gary T. Clark

Vice President – Investor Relations

(1)	Audit Committee

(2)	Corporate Governance and Nominating Committee

(3)	Management Development and Compensation Committee

Shareholder Information

Stock Data


	Price Range				Dividends per Share
	High		Low		Declared		Paid
2015
First Quarter	$	68.37	$	58.46	$	0.25	$	0.25
Second Quarter		71.40		56.54		0.25		0.25
Third Quarter		56.78		36.20		0.25		0.25
Fourth Quarter		53.94		39.72		0.25		0.25
2014
First Quarter	$	87.91	$	77.31	$	0.25	$	0.20
Second Quarter		102.34		81.87		0.25		0.25
Third Quarter		104.57		92.84		0.25		0.25
Fourth Quarter		93.87		54.34		0.25		0.25

The Company has paid cash dividends on its common stock for 51 consecutive years through December 31, 2015. Future dividend payments will depend upon the Company’s level of earnings, financial requirements and other relevant factors.

Apache common stock is listed on the New York and Chicago stock exchanges and the NASDAQ National Market (symbol APA). At January 31, 2016, the Company’s shares of common stock outstanding were held by approximately 4,500 shareholders of record and 289,000 beneficial owners. Also listed on the New York Stock Exchange are Apache Finance Canada’s 7.75% notes, due 2029 (symbol APA/29).

Corporate Offices

One Post Oak Central

2000 Post Oak Boulevard

Suite 100

Houston, Texas 77056-4400

(713) 296-6000

Independent Public Accountants

Ernst & Young LLP

Five Houston Center

1401 McKinney Street, Suite 1200

Houston, Texas 77010-2007

Stock Transfer Agent and Registrar

Wells Fargo Bank, N.A.

Attn: Shareowner Services

P.O. Box 64854

South St. Paul, Minnesota 55164-0854

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

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

Dividend Reinvestment Plan

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

Direct Registration

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

Annual Meeting

Apache will hold its annual meeting of shareholders on Thursday, May 12, 2016, at 10:00 a.m. in the Ballroom, Hilton Houston Post Oak, 2001 Post Oak Boulevard, Houston, Texas. Apache plans to web cast the annual meeting live; connect through the Apache web site: www.apachecorp.com

Stock Held in “Street Name”

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

Form 10-K Request

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

Investor Relations

Shareholders, brokers, securities analysts, or portfolio managers seeking information about the Company are welcome to contact Gary T. Clark., Vice President of Investor Relations, at (281) 302-2286.

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

Web site: www.apachecorp.com

INDEX TO EXHIBITS


EXHIBIT NO.		DESCRIPTION

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

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

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

3.1	–	Restated Certificate of Incorporation of Registrant, dated September 19, 2013, as filed with the Secretary of State of Delaware on September 19, 2013 (incorporated by reference to Exhibit 3.2 to Registrant’s Current Report on Form 8-K filed September 20, 2013, SEC File No. 001-4300).

3.2	–	Certificate of 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).


EXHIBIT NO.		DESCRIPTION
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).


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

4.17	–	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).


EXHIBIT NO.		DESCRIPTION
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 Registrant, 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).

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).


EXHIBIT NO.		DESCRIPTION
*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.

*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.

†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.

†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.

†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).


EXHIBIT NO.		DESCRIPTION
†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 2011 Omnibus Equity Compensation Plan, as amended and restated December 15, 2015.

†10.22	–	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).

†10.23	–	Apache Corporation 2003 Stock Appreciation Rights Plan, as amended and restated September 16, 2013 (incorporated by reference to Exhibit 10.2 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2013, 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, Commission 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 November 11, 2013 (incorporated by reference to Exhibit 10.23 to Registrant’s Annual Report on Form 10-K for the year ended December 31, 2013, SEC File No. 001-4300).

†10.27	–	Apache Corporation Non-Employee Directors’ Compensation Plan, as amended and restated July 16, 2014, effective July 1, 2014 (incorporated by reference to Exhibit 10.4 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2014, SEC File No. 001-4300).

†10.28	–	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).

†10.29	–	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).

†10.30	–	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).

†10.31	–	Apache Corporation Non-Employee Directors’ Restricted Stock Units Program, as amended and restated July 16, 2014, pursuant to Apache Corporation 2011 Omnibus Equity Compensation Plan (incorporated by reference to Exhibit 10.6 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2014, SEC File No. 001-4300).


EXHIBIT NO.		DESCRIPTION
†10.32	–	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).

†10.33	–	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	–	Employee Release and Settlement Agreement, dated February 11, 2014, between Registrant and Roger B. Plank (incorporated by reference to Exhibit 10.2 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014, SEC File No. 001-4300).

†10.37	–	Employee Release and Settlement Agreement, effective August 31, 2014, between Registrant and Thomas P. Chambers (incorporated by reference to Exhibit 10.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2014, SEC File No. 001-4300).

†10.38	–	Employee Resignation Agreement, effective October 13, 2014, between Registrant and Alfonso Leon (incorporated by reference to Exhibit 10.4 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2014, SEC File No. 001-4300).

†10.39	–	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).

†10.40	–	2015 Employee Release and Settlement Agreement between Registrant and Michael S. Bahorich, dated April 8, 2015 (incorporated by reference to Exhibit 10.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2015, SEC File No. 001-4300).

*†10.41	–	2016 Employee Release and Settlement Agreement between Registrant and Thomas E. Voytovich, effective November 30, 2015.

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

†10.43	–	Form of Restricted Stock Unit Award Agreement, dated February 12, 2009 (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K, dated February 12, 2009, filed February 18, 2009, SEC File No. 001-4300).


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

†10.45	–	Form of Restricted Stock Unit Grant Agreement, dated May 6, 2009 (incorporated by reference to Exhibit 10.38 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2009, SEC File No. 001-4300).

†10.46	–	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).

†10.47	–	Form of 2010 Performance Program Agreement, dated January 15, 2010 (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed January 19, 2010, SEC File No. 001-4300).

†10.48	–	Form of First Amendment, effective May 5, 2010, to 2010 Performance Program Agreement, dated January 15, 2010 (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed May 11, 2010, SEC File No. 001-4300).

†10.49	–	Form of Restricted Stock Unit Award Agreement, dated January 15, 2010 (incorporated by reference to Exhibit 10.2 to Registrant’s Current Report on Form 8-K filed January 19, 2010, SEC File No. 001-4300).

†10.50	–	Form of 2011 Performance Program Agreement, dated January 7, 2011 (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed January 13, 2011, SEC File No. 001-4300).

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

†10.52	–	Form of 2012 Performance Program Agreement, dated January 11, 2012 (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed January 13, 2012, SEC File No. 001-4300).

†10.53	–	Form of 2013 Performance Program Agreement, dated January 9, 2013 (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed January 11, 2013, SEC File No. 001-4300).

†10.54	–	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).

†10.55	–	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).

†10.56	–	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).

†10.57	–	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).


EXHIBIT NO.		DESCRIPTION
†10.58	–	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).

*†10.59	–	Form of 2016 Performance Share Program Award Notice and Agreement, dated January 7, 2016.

*†10.60	–	Form of Restricted Stock Unit Award Agreement, dated February 3, 2016.

*†10.61	–	Form of Stock Option Award Agreement, dated February 3, 2016.

†10.62	–	Amendments of Stock Option Grants (2007 and 2011 Omnibus Equity Compensation Plans), dated February 13, 2014, between Registrant and Roger B. Plank (incorporated by reference to Exhibits 10.3 and 10.4 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014, SEC File No. 001-4300).

†10.63	–	Amendment to Restricted Stock Unit Awards, dated February 13, 2014, between Registrant and Roger B. Plank (incorporated by reference to Exhibit 10.5 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014, SEC File No. 001-4300).

†10.64	–	Amendment of Stock Option Grants (2007 and 2011 Omnibus Equity Compensation Plans), effective August 31, 2014, between Registrant and Thomas P. Chambers (incorporated by reference to Exhibit 10.2 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2014, SEC File No. 001-4300).

†10.65	–	Amendment of Restricted Stock Unit Awards (2007 and 2011 Omnibus Equity Compensation Plans), effective August 31, 2014, between Registrant and Thomas P. Chambers (incorporated by reference to Exhibit 10.3 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2014, SEC File No. 001-4300).

†10.66	–	Amendment of Stock Option Grants (2007 and 2011 Omnibus Equity Compensation Plans), effective October 9, 2014, between Registrant and Alfonso Leon (incorporated by reference to Exhibit 10.5 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2014, SEC File No. 001-4300).

†10.67	–	Amendment of Restricted Stock Unit Awards (2007 and 2011 Omnibus Equity Compensation Plans), effective October 9, 2014, between Registrant and Alfonso Leon (incorporated by reference to Exhibit 10.6 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2014, SEC File No. 001-4300).

†10.68	–	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).

†10.69	–	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).


EXHIBIT NO.		DESCRIPTION
†10.70	–	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).

†10.71	–	Amendment of 2014 Performance Program (Business Performance) Award (2011 Omnibus Equity Compensation Plan), effective June 30, 2015, between Registrant and Michael S. Bahorich (incorporated by reference to Exhibit 10.2 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2015, SEC File No. 001-04300).

†10.72	–	Amendment of Restricted Stock Unit Awards (2011 Omnibus Equity Compensation Plan), effective June 30, 2015, between Registrant and Michael S. Bahorich (incorporated by reference to Exhibit 10.4 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2015, SEC File No. 001-04300).

†10.73	–	Amendment of Stock Option Grants (2011 Omnibus Equity Compensation Plan), effective June 30, 2015, between Registrant and Michael S. Bahorich (incorporated by reference to Exhibit 10.3 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2015, SEC File No. 001-04300).

*†10.74	–	Amendment of 2014 Performance Program (Business Performance) Award (2011 Omnibus Equity Compensation Plan), effective November 30, 2015, between Registrant and Thomas E. Voytovich.

*†10.75	–	Amendment of Restricted Stock Unit Awards (2011 Omnibus Equity Compensation Plan), effective November 30, 2015, between Registrant and Thomas E. Voytovich.

*†10.76	–	Amendment of Stock Option Grants (2007 and 2011 Omnibus Equity Compensation Plans), effective November 30, 2015, between Registrant and Thomas E. Voytovich.

*†10.77	–	Amendment of Stock Option Grants (2005 Stock Option Plan), effective November 30, 2015, between Registrant and Thomas E. Voytovich.

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

14.1	–	Code of Business Conduct dated January 20, 2015 (incorporated by reference to Exhibit 14.1 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2015, SEC File No. 001-4300).

*21.1	–	Subsidiaries of Registrant

*23.1	–	Consent of Ernst & Young LLP

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

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

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

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


EXHIBIT NO.		DESCRIPTION
*32.1	–	Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by Principal Executive Officer and Principal Financial Officer.

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

*101.INS	–	XBRL Instance Document.

*101.SCH	–	XBRL Taxonomy Schema Document.

*101.CAL	–	XBRL Calculation Linkbase Document.

*101.LAB	–	XBRL Label Linkbase Document.

*101.PRE	–	XBRL Presentation Linkbase Document.

*101.DEF	–	XBRL Definition Linkbase Document.

*	Filed herewith.

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