Apache Corporation
APACHE CORP (Form: 10-K, Received: 02/26/2016 16:55:44)
Table of Contents

 

 

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

or

 

[   ]

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

For the transition period from                  to                 

Commission file number 1-4300

 

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

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   

 

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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.

 

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DEFINITIONS

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

“3-D” means three-dimensional.

“4-D” means four-dimensional.

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

“bbl” or “bbls” means barrel or barrels of oil 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.

 

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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

 

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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.

 

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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 CO 2 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.

 

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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.

 

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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

 

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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

 

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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

 

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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.

 

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Production, Pricing, and Lease Operating Cost Data

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

 

    Production         Average Lease
Operating
  Cost per Boe  
        Average Sales Price  

Year Ended December 31,

  Oil
  (MMbbls)  
        NGLs
  (MMbbls)  
        Gas
  (Bcf)  
              Oil
  (Per bbl)  
        NGLs
  (Per bbl)  
        Gas
  (Per Mcf)  
 

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.

 

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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.

 

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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                    776           275    

North Sea

    105                    86           120    
 

 

 

     

 

 

     

 

 

     

 

 

 

Total Proved Developed

    666           168           2,985           1,332    

Proved Undeveloped:

             

United States

    60           25           209           120    

Canada

    38                    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

 

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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.

 

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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.

 

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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.

 

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

 

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ITEM 1A.      RISK FACTORS

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

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

Our revenues, operating results, and future rate of growth depend highly upon the prices we receive for our crude oil and natural gas production. Historically, the markets for crude oil and natural gas have been volatile and are likely to continue to be volatile in the future. For example, the NYMEX daily settlement price for the prompt month oil contract in 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;

 

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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

 

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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.

 

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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.

 

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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;

 

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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

 

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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.

 

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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.

 

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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

 

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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

 

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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.

 

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PART II

 

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

During 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.

 

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The following stock price performance graph is intended to allow review of stockholder returns, expressed in terms of the appreciation of the Company’s common stock relative to two broad-based stock performance indices. The information is included for historical comparative purposes only and should not be considered indicative of future stock performance. The graph compares the yearly percentage change in the cumulative total stockholder return on the Company’s common stock with the cumulative total return of the Standard & Poor’s Composite 500 Stock Index and of the Dow Jones U.S. Exploration & Production Index (formerly Dow Jones Secondary Oil Stock Index) from December 31, 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    

 

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ITEM 6.      SELECTED FINANCIAL DATA

The following table sets forth selected financial data of the Company and its consolidated subsidiaries over the five-year period ended December 31, 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.

 

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

Apache Corporation, a Delaware corporation formed in 1954, is an independent energy company that explores for, develops, and produces natural gas, crude oil, and natural gas liquids. We currently have exploration and production interests in 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, 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.

 

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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.

 

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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.

 

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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.

 

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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.

 

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Table of Contents

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

                            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.

 

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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.

 

  NM

– Not meaningful

 

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Table of Contents

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

 

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Table of Contents

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.

 

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Table of Contents

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.

 

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Operating Expenses

The table below presents a comparison of our expenses on an absolute dollar basis and an equivalent unit of production (boe) basis. Our discussion may reference expenses on a boe basis, on an absolute dollar basis or both, depending on context. 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.

 

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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.

 

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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

 

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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                 

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.

 

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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.

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

 

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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.

 

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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.

 

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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

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

 

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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

 

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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.

C ontractual 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

 

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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.

 

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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.

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

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

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

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

Asset Retirement Obligation (ARO)

The Company has significant obligations to remove tangible equipment and restore land or seabed at the end of oil and gas production operations. Apache’s removal and restoration obligations are primarily associated with plugging and abandoning wells and removing and disposing of offshore oil and gas platforms 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.

 

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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

 

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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.

 

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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.

 

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The financial statements and supplementary financial information required to be filed under this Item 8 are presented on pages F-1 through F-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.

 

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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.

 

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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.

 

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PART III

 

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The information set forth under the captions “Nominees for Election as Directors,” “Continuing Directors,” “Executive Officers of the Company,” and “Securities Ownership and Principal Holders” in the proxy statement relating to the Company’s 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.

 

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PART IV

 

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

 

  (a)

Documents included in this report:

 

  1.

Financial Statements

 

Report of management on internal control over financial reporting

     F-1   

Report of independent registered public accounting firm

     F-2   

Report of independent registered public accounting firm

     F-3   

Statement of consolidated operations for each of the three years in the period ended December 31,  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   

 

  2.

Financial Statement Schedules

      

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

 

  3.

Exhibits

 

EXHIBIT
NO.

 

       

DESCRIPTION

 

    2.1      

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).

 

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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).

 

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EXHIBIT
NO.

 

       

DESCRIPTION

 

  4.13      

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

  4.14      

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

  4.15      

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

  4.16      

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

  4.17      

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).

 

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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).

 

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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).

 

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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).

 

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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).

 

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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).

 

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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).

 

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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.

 

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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.

 

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SIGNATURES

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