10-K
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, 2013

or

 

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

For the transition period from              to             

Commission file number 1-4300

 

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
Preferred Stock Purchase Rights   New York Stock Exchange and Chicago Stock Exchange

Apache Finance Canada Corporation

7.75% Notes Due 2029

Irrevocably and Unconditionally

Guaranteed by Apache Corporation

  New York Stock Exchange

 

 

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

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

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

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

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

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

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

 

Large accelerated filer   x    Accelerated filer   ¨
Non-accelerated filer   ¨    Smaller reporting company   ¨

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

 

Aggregate market value of the voting and non-voting common equity held by non-affiliates of registrant as of June 30, 2013

   $  32,641,836,810   

Number of shares of registrant’s common stock outstanding as of January 31, 2014

     394,724,983   

Documents Incorporated By Reference

Portions of registrant’s proxy statement relating to registrant’s 2014 annual meeting of stockholders have been incorporated by reference in Part II and Part III of this annual report on Form 10-K.

 

 

 


Table of Contents

TABLE OF CONTENTS

DESCRIPTION

 

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

 

 

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DEFINITIONS

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

“3-D” means three-dimensional.

“4-D” means four-dimensional.

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

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

“bcf” means billion cubic feet of natural gas.

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

“boe/d” means boe per day.

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

“LIBOR” means London Interbank Offered Rate.

“LNG” means liquefied natural gas.

“Mb/d” means Mbbls per day.

“Mbbls” means thousand barrels of oil.

“Mboe” means thousand boe.

“Mboe/d” means Mboe per day.

“Mcf” means thousand cubic feet of natural gas.

“Mcf/d” means Mcf per day.

“MMbbls” means million barrels of oil.

“MMboe” means million boe.

“MMBtu” means million Btu.

“MMBtu/d” means MMBtu per day.

“MMcf” means million cubic feet of natural gas.

“MMcf/d” means MMcf per day.

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

“NYMEX” means New York Mercantile Exchange.

“oil” includes crude oil and condensate.

“PUD” means proved undeveloped.

“SEC” means United States Securities and Exchange Commission.

“Tcf” means trillion cubic feet of natural gas.

“U.K.” means United Kingdom.

“U.S.” means United States.

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

 

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PART I

 

ITEMS 1 AND 2.    BUSINESS AND PROPERTIES

This Annual Report on Form 10-K and the documents incorporated herein by reference contain forward-looking statements based on expectations, estimates, and projections as of the date of this filing. These statements by their nature are subject to risks, uncertainties, and assumptions and are influenced by various factors. As a consequence, actual results may differ materially from those expressed in the forward-looking statements. See the risk factors set forth in Item 1A of this Form 10-K and Part II, Item 7A—Quantitative and Qualitative Disclosures About Market Risk—Forward-Looking Statements and Risk of this Form 10-K.

General

Apache Corporation, a Delaware corporation formed in 1954, is an independent energy company that explores for, develops, and produces natural gas, crude oil, and natural gas liquids. We currently have exploration and production interests in six countries: the U.S., Canada, Egypt, Australia, the U.K. North Sea (North Sea), and Argentina. Apache also pursues exploration interests in other countries that may over time result in reportable discoveries and development opportunities. We treat all operations as one line of business.

Our common stock, par value $0.625 per share, has been listed on the New York Stock Exchange (NYSE) since 1969, on the Chicago Stock Exchange (CHX) since 1960, and on the NASDAQ National Market (NASDAQ) since 2004. On June 5, 2013, we filed certifications of our compliance with the listing standards of the NYSE and the NASDAQ, including our principal executive officer’s certification of compliance with the NYSE standards. Through our website, www.apachecorp.com, you can access, free of charge, electronic copies of the charters of the committees of our Board of Directors, other documents related to our corporate governance (including our Code of Business Conduct and Governance Principles), and documents we file with the SEC, including our annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, as well as any amendments to these reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934. Included in our annual and quarterly reports are the certifications of our principal executive officer and our principal financial officer that are required by applicable laws and regulations. Access to these electronic filings is available as soon as reasonably practicable after we file such material with, or furnish it to, the SEC. You may also request printed copies of our committee charters or other governance documents free of charge by writing to our corporate secretary at the address on the cover of this report. Our reports filed with the SEC are made available to read and copy at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C., 20549. You may obtain information about the Public Reference Room by contacting the SEC at 1-800-SEC-0330. Reports filed with the SEC are also made available on its website at www.sec.gov. From time to time, we also post announcements, updates, and investor information on our website in addition to copies of all recent press releases. Information on our website or any other website is not incorporated by reference into, and does not constitute a part of, this Annual Report on Form 10-K.

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

Growth Strategy

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

 

    diverse portfolio of core assets

 

    conservative capital structure

 

    rate of return focus

 

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Throughout the cycles of our industry, these strategies have underpinned our ability to deliver long-term production and reserve growth and achieve competitive returns on invested capital for the benefit of our shareholders. We have increased reserves 23 out of the last 28 years and production 32 out of the past 35 years, a testament to our consistency over the long-term.

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

 

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

 

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

 

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

 

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

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

For a more in-depth discussion of our growth strategy, 2013 results, and the Company’s capital resources and liquidity, please see Part II, Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations of this Form 10-K.

 

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Geographic Area Overviews

During 2013, we had exploration and production interests in six countries: the U.S., Canada, Egypt, Australia, the U.K. North Sea, and Argentina. Apache also pursues exploration interests in other countries that may over time result in reportable discoveries and development opportunities.

The following table sets out a brief comparative summary of certain key 2013 data for each of our operating areas. Additional data and discussion is provided in Part II, Item 7 of this Form 10-K.

 

     Production      Percentage
of Total
Production
    Production
Revenue
     Year-End
Estimated
Proved
Reserves
     Percentage
of Total
Estimated
Proved
Reserves
    Gross
Wells
Drilled
     Gross
Productive
Wells
Drilled
 
     (In MMboe)            (In millions)      (In MMboe)                      

United States

     121.1         44   $ 6,902         1,347         51     1,179         1,148   

Canada

     39.2         14        1,224         462         17        143         135   
  

 

 

    

 

 

   

 

 

    

 

 

    

 

 

   

 

 

    

 

 

 

Total North America

     160.3         58        8,126         1,809         68        1,322         1,283   
  

 

 

    

 

 

   

 

 

    

 

 

    

 

 

   

 

 

    

 

 

 

Egypt(1)

     54.4         19        3,917         271         10        210         181   

Australia

     20.6         7        1,140         326         12        12         11   

North Sea

     26.8         10        2,728         150         6        19         17   

Argentina

     15.6         6        491         90         4        28         28   
  

 

 

    

 

 

   

 

 

    

 

 

    

 

 

   

 

 

    

 

 

 

Total International

     117.4         42        8,276         837         32        269         237   
  

 

 

    

 

 

   

 

 

    

 

 

    

 

 

   

 

 

    

 

 

 

Total

     277.7         100   $ 16,402         2,646         100     1,591         1,520   
  

 

 

    

 

 

   

 

 

    

 

 

    

 

 

   

 

 

    

 

 

 

 

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

North America

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

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

United States

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

 

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

A key focus area of our activity during the year continued to be the multi-zone development of the Deadwood area. Deadwood is the most active of our plays in the Midland basin where we ran an average of nearly 10 rigs and drilled 189 wells. Our activity in the Deadwood area is primarily drilling vertical wells targeting the Wolfwood and the Fusselman zones.

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

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

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

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

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

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

 

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

Gulf Coast Regions Our Gulf Coast assets are primarily located in and along the Gulf of Mexico, in the areas onshore and offshore Texas, Louisiana, Alabama, and Mississippi. During 2013 the area was divided into three regions, which include the Gulf Coast Onshore, Gulf of Mexico Deepwater, and Gulf of Mexico Shelf. In 2014, the Gulf of Mexico Shelf region and Gulf of Mexico Deepwater region have been combined into the Gulf of Mexico region.

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

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

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

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

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

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

 

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

Canada

Overview Apache entered the Canadian market in 1995 and currently holds nearly 5.4 million gross acres across the provinces of British Columbia, Alberta, and Saskatchewan. The region’s large acreage position provides portfolio diversification as well as significant drilling opportunities. Our Canadian region provided approximately 14 percent of Apache’s 2013 worldwide production.

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

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

The Kitimat LNG project will allow us to monetize large unconventional natural gas resources in the Liard and Horn River basins in northern British Columbia. In February 2013, Apache completed a transaction with Chevron Canada Limited (Chevron Canada) under which each company became a 50 percent owner of the Kitimat LNG plant, the Pacific Trail Pipelines Limited Partnership (PTP), and 644,000 gross undeveloped acres in the Horn River and Liard basins. Chevron Canada will operate the LNG plant and pipeline while Apache Canada will continue to operate the upstream assets. The Kitimat plant has received all significant environmental approvals and a 20-year export license from the Canadian federal government. Although the project has not reached a final investment decision, we believe Chevron’s experience in developing LNG projects and marketing expertise will assist in moving the development forward. In 2014, we plan to invest approximately $1.0 billion of capital in the Kitimat project, which includes the LNG plant as well as our upstream assets in the Horn River and Liard basins. With a 50 percent project participation, Apache is actively evaluating ways to right-size its level of participation in the Kitimat LNG project.

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

Marketing Our Canadian natural gas marketing activities focus on sales to utilities, end-users, integrated major oil companies, supply aggregators, and marketers. We maintain a diverse client portfolio, which is intended to reduce the concentration of credit risk in our portfolio. To diversify our market exposure, we transport natural gas under firm transportation contracts to delivery points into the United States. We sell the majority of our Canadian gas on a monthly basis at either first-of-the-month or daily AECO index prices. Also, from time to time, the Company will enter into fixed physical sales contracts for durations of up to one-year. These physical sales volumes are typically sold at fixed prices over the term of the contract.

Canadian crude oil production is sold to integrated major companies, refiners, and marketing companies based on a WTI price, adjusted for quality, transportation, and a market-reflective differential. The crude is transported by pipeline or truck within Western Canada to market hubs in Alberta and Manitoba where it is sold, allowing for a more diversified group of purchasers and a higher netback price. A portion of our trucked barrels

 

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

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

International

Apache’s international assets are located in Egypt, Australia, offshore the U.K. in the North Sea, and Argentina. In 2013, international assets contributed 42 percent of our production and 50 percent of our oil and gas revenues. At year-end 2013, 32 percent of our estimated proved reserves were located outside North America.

Egypt

Overview Our activity in Egypt began in 1994 with our first Qarun discovery well, and today we are one of the largest acreage holders in Egypt’s Western Desert. At year-end, we held 9.8 million gross acres, with gross oil production of 198 Mb/d and gross natural gas production of 912 MMcf/d in 2013, or 90 Mb/d and 356 MMcf/d net to Apache’s consolidated holdings. Although 3.0 million gross undeveloped acres expired in January 2014, we continue to pursue longer term extensions on areas we believe provide attractive growth opportunities. Of our remaining acreage, 72 percent is undeveloped, providing us with considerable exploration and development opportunities for the future.

Our operations in Egypt are conducted pursuant to production-sharing agreements in 24 separate concessions, under which the contractor partners pay all operating and capital expenditure costs for exploration and development. Development leases within concessions currently have expiration dates ranging from 2 to 25 years, with extensions possible for additional commercial discoveries or on a negotiated basis. A percentage of the production on development leases, usually up to 40 percent, is available to the contractor partners to recover operating and capital expenditure costs, with the balance generally allocated between the contractor partners and the Egyptian General Petroleum Corporation (EGPC) on a contractually defined basis. In 2013 Apache was granted 20 new development leases, representing one of our most successful years since our entry into Egypt.

Our growth in Egypt has been driven by an ongoing drilling program, and we have historically been one of the most active drillers in the Western Desert. During 2013, we drilled 181 development and injection wells and 54 exploration wells. Approximately 60 percent of our exploration wells were successful, further expanding our presence in the westernmost concessions and unlocking additional opportunities in existing plays. A key component of the region’s success has been the ability to acquire and evaluate 3-D seismic surveys that enable our technical teams to consistently high-grade existing prospects and identify new targets across multiple pay horizons in the Cretaceous, Jurassic, and deeper Paleozoic formations.

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

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

 

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

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

Marketing Our gas production is sold to EGPC primarily under an industry-pricing formula, a sliding scale based on Dated Brent crude oil with a minimum of $1.50 per MMBtu and a maximum of $2.65 per MMBtu, plus an upward adjustment for liquids content. The region averaged $2.99 per Mcf in 2013.

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

Egypt political unrest In February 2011, former Egyptian president Hosni Mubarak stepped down, and the Egyptian Supreme Council of the Armed Forces took power, announcing that it would remain in power until presidential and parliamentary elections could be held. In June 2012, President Mohamed Morsi of the Muslim Brotherhood’s Freedom and Justice Party was elected as Egypt’s new president.

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

Apache’s operations, located in remote locations in the Western Desert, have not experienced production interruptions, and we have continued to receive development lease approvals for our drilling program. However, a further deterioration in the political, economic, and social conditions or other relevant policies of the Egyptian government, such as changes in laws or regulations, export restrictions, expropriation of our assets or resource nationalization, and/or forced renegotiation or modification of our existing contracts with EGPC could materially and adversely affect our business, financial condition, and results of operations.

Apache purchases multi-year political risk insurance from the Overseas Private Investment Corporation (OPIC) and other highly rated international insurers covering a portion of its investments in Egypt. In the aggregate, these insurance policies, subject to the policy terms and conditions, provide approximately $856 million of coverage to Apache for losses arising from confiscation, nationalization, and expropriation risks, with a $149 million sub-limit for currency inconvertibility.

In addition, Apache has a separate policy with OPIC, which provides $300 million of coverage for losses arising from (1) non-payment by EGPC of arbitral awards covering amounts owed Apache on past due invoices and (2) expropriation of exportable petroleum in the event that actions taken by the government of Egypt prevent Apache from exporting our share of production. In October 2012, the Multilateral Investment Guarantee Agency (MIGA), a member of the World Bank Group, announced that it was providing $150 million in reinsurance to OPIC for the remainder of the policy term. This provision of long-term reinsurance to OPIC will allow Apache to maintain the $300 million of insurance coverage through 2024.

Australia

Overview Apache’s holdings in Australia are focused offshore Western Australia in the Carnarvon, Exmouth, and Browse basins, with production operations in the Carnarvon and Exmouth basins. We have

 

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

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

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

The region participated in drilling 12 offshore wells during 2013, of which 4 were exploration or appraisal wells, compared to 15 wells drilled in 2012. Over the past decade, the region’s exploration activity has established a significant pipeline of projects that are expected to contribute to production growth as they are brought online in the coming years.

Development of the Coniston oil field project, which lies just north of the Van Gogh field, continued toward projected first production in 2014. The field will be produced via subsea completions tied back to the Ningaloo Vision Floating Production Storage and Offloading Vessel (FPSO) at Van Gogh. Required modifications to the FPSO and the final phase of subsea installation work is planned for the first half of 2014. Apache has a 52.5 percent working interest in the field.

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

In 2013, further advances were made on the region’s largest development effort, which is the Chevron-operated Wheatstone LNG project (Wheatstone). The first phase of the Wheatstone project will comprise two LNG processing trains with a combined capacity of approximately 8.9 million metric tons per annum (mtpa), a domestic gas plant, and associated infrastructure. Apache has a 13 percent interest in the project and expects to invest approximately $4 billion over five years for the field and LNG facility development. Apache will supply gas to Wheatstone from its operated Julimar and Brunello complex. The 65 percent interest in the Julimar development project is expected to generate average net sales to Apache of approximately 140 MMcf/d of gas (equivalent to 1.07 million mtpa of LNG) at prices pegged to world oil markets, 22 MMcf/d of sales gas into the domestic market, and 3,250 barrels of condensate per day. First production is projected for the end of 2016.

These development projects require significant capital investments above those for traditional drilling programs. During 2014, the region plans to invest approximately $800 million for drilling, recompletion projects, development projects, equipment upgrades, production enhancement projects, and seismic acquisition. Approximately $1.4 billion of additional 2014 capital will be invested in the Wheatstone development project.

Marketing Western Australia has historically had a local market for natural gas with a limited number of buyers and sellers resulting in sales under mostly long-term, fixed-price contracts, many of which contain

 

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periodic price revision clauses based on either the Australian consumer price index or a commodity linkage. As of December 31, 2013, Apache had 21 active gas contracts in Australia with expiration dates ranging from August 2014 to December 2026. Recent increases in demand and higher development costs have increased the prices required from the local market in order to support the development of new supplies. As a result, market prices negotiated on recent contracts are substantially higher than historical levels.

We directly market all of our Australian crude oil production into Australian domestic and international markets at prices generally indexed to Dated Brent benchmark crude oil prices plus premiums, which typically result in sales well above crude sold at WTI-based prices.

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

North Sea

Overview Apache entered the North Sea in 2003 after acquiring an approximate 97 percent working interest in the Forties field (Forties). Apache has actively invested in the region and has established a large inventory of drilling prospects through successful exploration programs and the interpretation of acquired 3-D and 4-D seismic data. Building upon its success in Forties, Apache in 2012 acquired Mobil North Sea Limited (Mobil North Sea), providing the region with additional exploration and development opportunities across numerous fields, including operated interests in the Beryl, Nevis, Nevis South, Skene, and Buckland fields and non-operated interests in the Maclure, Scott, and Telford fields. In total, Apache has interests in approximately 1.2 million gross acres in the U.K. North Sea.

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

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

Marketing We have traditionally sold our North Sea crude oil under both term contracts and spot cargoes. The Forties term sales are composed of a market-based index price plus a premium, which reflects the higher market value for term arrangements. The prices received for Beryl spot cargoes are market driven and can trade at a premium to the market-based index.

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

 

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Argentina

Overview We have had a continuous presence in Argentina since 2001 and have grown our holdings in the region through an active drilling program and targeted acquisitions. The region has active operations in the provinces of Neuquén, Rio Negro, and Tierra del Fuego. As of year-end 2013, Apache held interests in 31 concessions, exploration permits, and other interests totaling 3.3 million gross acres in three of the main Argentine hydrocarbon basins: Neuquén, Austral, and Cuyo. These concessions have varying expiration dates ranging from one year to over 15 years remaining, subject to potential extensions. In 2013, Argentina produced 6 percent of our worldwide consolidated production and held 4 percent of our year-end consolidated proved reserves.

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

Marketing

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

 

    Gas Plus Program: This program was instituted by the Argentine government in 2008 to encourage investments for new gas supplies through the development of conventional and unconventional (tight sands) reserves. Under this program, Apache is allowed to sell gas from qualifying projects at prices that are above the regulated rates. During 2013, the average Gas Plus volume sold by Apache was 79.9 MMcf/d at an average price of $4.90 per Mcf.

 

    Government-regulated pricing: The volumes we are required to sell at regulated prices are set by the Argentine government and vary based on seasonal factors and category. During 2013, we realized an average price of $0.78 per Mcf on government-regulated sales.

 

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

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

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

Other Exploration

New Ventures

Apache’s global New Ventures team provides exposure to new growth opportunities by looking outside of the Company’s traditional core areas and targeting higher-risk, high-reward exploration opportunities located in frontier basins as well as new plays in more mature basins. During 2014, we plan to invest approximately $75 million to further several projects and continue pursuing additional exploration opportunities.

Major Customers

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

 

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Drilling Statistics

Worldwide in 2013 we participated in drilling 1,591 gross wells, with 1,520 (96 percent) completed as producers. Historically, our drilling activities in the U.S. have generally concentrated on exploitation and extension of existing producing fields rather than exploration. As a general matter, our operations outside of the U.S. focus on a mix of exploration and development wells. In addition to our completed wells, at year-end a number of wells had not yet reached completion: 160 in the U.S. (115.4 net); 17 in Egypt (17.0 net); and 2 in Argentina (0.3 net).

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

 

     Net Exploratory      Net Development      Total Net Wells  
     Productive      Dry      Total      Productive      Dry      Total      Productive      Dry      Total  

2013

                          

United States

     15.6         11.2         26.8         834.9         12.6         847.5         850.5         23.8         874.3   

Canada

     0.0         0.0         0.0         108.5         6.9         115.4         108.5         6.9         115.4   

Egypt

     30.5         18.7         49.2         141.9         7.3         149.2         172.4         26.0         198.4   

Australia

     2.2         0.4         2.6         3.4         0.0         3.4         5.6         0.4         6.0   

North Sea

     0.0         0.5         0.5         13.4         0.1         13.5         13.4         0.6         14.0   

Argentina

     2.4         0.0         2.4         22.0         0.0         22.0         24.4         0.0         24.4   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

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

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

2012

                          

United States

     9.5         3.5         13.0         746.0         9.6         755.6         755.5         13.1         768.6   

Canada

     5.0         7.5         12.5         110.3         14.0         124.3         115.3         21.5         136.8   

Egypt

     28.0         22.5         50.5         144.4         1.0         145.4         172.4         23.5         195.9   

Australia

     1.9         2.7         4.6         1.3         0.7         2.0         3.2         3.4         6.6   

North Sea

     1.3         0.0         1.3         11.7         3.9         15.6         13.0         3.9         16.9   

Argentina

     2.0         0.0         2.0         23.0         0.0         23.0         25.0         0.0         25.0   

Other International

     0.0         0.5         0.5         0.0         0.0         0.0         0.0         0.5         0.5   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

     47.7         36.7         84.4         1,036.7         29.2         1,065.9         1,084.4         65.9         1,150.3   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

2011

                          

United States

     12.4         5.0         17.4         522.0         17.0         539.0         534.4         22.0         556.4   

Canada

     4.0         5.0         9.0         77.2         5.0         82.2         81.2         10.0         91.2   

Egypt

     28.2         19.8         48.0         112.6         6.0         118.6         140.8         25.8         166.6   

Australia

     1.0         2.3         3.3         1.0         0.0         1.0         2.0         2.3         4.3   

North Sea

     0.0         0.3         0.3         10.7         1.9         12.6         10.7         2.2         12.9   

Argentina

     4.0         1.0         5.0         29.4         0.3         29.7         33.4         1.3         34.7   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

     49.6         33.4         83.0         752.9         30.2         783.1         802.5         63.6         866.1   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Productive Oil and Gas Wells

The number of productive oil and gas wells, operated and non-operated, in which we had an interest as of December 31, 2013, is set forth below:

 

     Oil      Gas      Total  
     Gross      Net      Gross      Net      Gross      Net  

United States

     14,164         9,346         5,001         2,831         19,165         12,177   

Canada

     2,000         939         3,030         2,277         5,030         3,216   

Egypt

     1,040         992         85         80         1,125         1,072   

Australia

     49         23         16         9         65         32   

North Sea

     161         104         24         14         185         118   

Argentina

     475         396         425         389         900         785   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

     17,889         11,800         8,581         5,600         26,470         17,400   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

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

Production, Pricing, and Lease Operating Cost Data

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

 

Year Ended December 31,

   Production      Average Lease
Operating
Cost per Boe
     Average Sales Price  
   Oil
(MMbbls)
     NGLs
(MMbbls)
     Gas
(Bcf)
        Oil
(Per bbl)
     NGLs
(Per bbl)
     Gas
(Per Mcf)
 

2013

              

United States

     53.6         19.9         285.2       $ 11.60       $ 98.14       $ 27.29       $ 3.84   

Canada

     6.5         2.4         181.6         15.68         87.00         30.50         3.23   

Egypt(1)

     32.7         —           130.1         9.42         107.94         —            2.99   

Australia

     7.0         —           81.5         10.35         110.42         —           4.43   

North Sea

     23.3         0.5         18.6         15.16         107.48         73.06         10.43   

Argentina

     3.4         0.8         68.4         12.89         79.05         23.64         2.96   
  

 

 

    

 

 

    

 

 

             

Total

     126.5         23.6         765.4         12.06         101.99         28.40         3.70   
  

 

 

    

 

 

    

 

 

             

2012

              

United States

     49.1         12.3         312.6       $ 12.83       $ 94.98       $ 32.19       $ 3.74   

Canada

     5.8         2.3         219.9         13.87         84.89         34.63         3.42   

Egypt

     36.5         —           129.5         7.73         110.92         —           3.90   

Australia

     10.6         —           78.3         9.08         115.22         —           4.55   

North Sea

     23.3         0.6         21.0         12.38         107.97         77.11         8.95   

Argentina

     3.5         1.1         78.1         10.85         75.89         21.55         2.87   
  

 

 

    

 

 

    

 

 

             

Total

     128.8         16.3         839.4         11.49         102.53         33.45         3.80   
  

 

 

    

 

 

    

 

 

             

2011

              

United States

     43.6         8.1         315.6       $ 11.80       $ 95.51       $ 48.42       $ 4.91   

Canada

     5.2         2.2         230.9         13.86         93.19         45.72         4.47   

Egypt

     37.9         —           133.4         7.19         109.92         —           4.66   

Australia

     14.0         —           67.6         7.80         111.22         —           2.69   

North Sea

     19.9         —           0.8         11.61         104.09         —           22.25   

Argentina

     3.5         1.1         77.5         9.83         68.02         27.90         2.64   
  

 

 

    

 

 

    

 

 

             

Total

     124.1         11.4         825.8         10.62         102.19         45.95         4.37   
  

 

 

    

 

 

    

 

 

             

 

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

Gross and Net Undeveloped and Developed Acreage

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

 

     Undeveloped Acreage      Developed Acreage  
     Gross Acres      Net Acres      Gross Acres      Net Acres  
     (in thousands)  

United States

     8,730         4,772         2,797         1,445   

Canada

     2,329         1,712         3,078         2,151   

Egypt

     7,852         5,060         1,971         1,806   

Australia

     7,003         3,849         900         545   

North Sea

     1,092         487         160         98   

Argentina

     3,037         2,247         231         198   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

     30,043         18,127         9,137         6,243   
  

 

 

    

 

 

    

 

 

    

 

 

 

 

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As of December 31, 2013, Apache had 3.2 million net undeveloped acres scheduled to expire by year-end 2014 if production is not established or we take no other action to extend the terms. Additionally, Apache has 2.7 million and 1.9 million net undeveloped acres set to expire in 2015 and 2016, respectively. We strive to extend the terms of many of these licenses and concession areas through operational or administrative actions, but cannot assure that such extensions can be achieved on an economic basis or otherwise on terms agreeable to both the Company and third parties including governments.

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

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

Estimated Proved Reserves and Future Net Cash Flows

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

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

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

 

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The following table shows proved oil, NGL, and gas reserves as of December 31, 2013, based on average commodity prices in effect on the first day of each month in 2013, held flat for the life of the production, except where future oil and gas sales are covered by physical contract terms. This table shows reserves on a boe basis in which natural gas is converted to an equivalent barrel of oil based on a 6:1 energy equivalent ratio. This ratio is not reflective of the current price ratio between the two products.

 

     Oil
(MMbbls)
     NGL
(MMbbls)
     Gas
(Bcf)
     Total
(MMboe)
 

Proved Developed:

           

United States

     458         184         2,006         977   

Canada

     81         26         1,294         323   

Egypt(1)

     119         —           622         223   

Australia

     23         —           627         127   

North Sea

     100         3         88         117   

Argentina

     14         4         289         66   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total Proved Developed

     795         217         4,926         1,833   

Proved Undeveloped:

           
           

United States

     196         64         667         371   

Canada

     56         10         439         139   

Egypt(1)

     16         —           190         48   

Australia

     37         —           975         199   

North Sea

     29         —           19         32   

Argentina

     2         1         122         24   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total Proved Undeveloped

     336         75         2,412         813   
  

 

 

    

 

 

    

 

 

    

 

 

 

TOTAL PROVED

     1,131         292         7,338         2,646   
  

 

 

    

 

 

    

 

 

    

 

 

 

 

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

As of December 31, 2013, Apache had total estimated proved reserves of 1,131 MMbbls of crude oil, 292 MMbbls of NGLs, and 7.3 Tcf of natural gas. Combined, these total estimated proved reserves are the energy equivalent of 2.65 billion barrels of oil or 15.9 Tcf of natural gas, of which oil represents 43 percent. As of December 31, 2013, the Company’s proved developed reserves totaled 1,833 MMboe and estimated PUD reserves totaled 813 MMboe, or approximately 31 percent of worldwide total proved reserves. Apache has elected not to disclose probable or possible reserves in this filing.

The Company’s estimates of proved reserves, proved developed reserves and PUD reserves as of December 31, 2013, 2012, and 2011, changes in estimated proved reserves during the last three years, and estimates of future net cash flows from proved reserves are contained in Note 14—Supplemental Oil and Gas Disclosures in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K. Estimated future net cash flows were calculated using a discount rate of 10 percent per annum, end of period costs, and an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months, held flat for the life of the production, except where prices are defined by contractual arrangements.

Proved Undeveloped Reserves

The Company’s total estimated PUD reserves of 813 MMboe as of December 31, 2013, decreased by 57 MMboe from 870 MMboe of PUD reserves estimated at the end of 2012. During the year, Apache converted 154 MMboe of PUD reserves to proved developed reserves through development drilling activity. In North America, we converted 124 MMboe, with the remaining 30 MMboe in our international areas. We sold 109 MMboe and acquired 1 MMboe of PUD reserves during the year. We added 205 MMboe of new PUD reserves through extensions and discoveries.

 

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During the year, a total of approximately $3.7 billion was spent on projects associated with reserves that were carried as PUD reserves at the end of 2012. A portion of our costs incurred each year relate to development projects that will be converted to proved developed reserves in future years. We spent $2.1 billion on PUD reserve development activity in North America and $1.6 billion in the international areas. Other than our Julimar/Brunello development project, which is tied to the construction schedule of the Wheatstone LNG project, with projected first production in 2016, we had no material amounts of PUD reserves that have remained undeveloped for five years or more after they were initially disclosed as PUD reserves and no material amounts of PUD reserves which are scheduled to be developed beyond five years from December 31, 2013.

Preparation of Oil and Gas Reserve Information

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

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

Apache’s Executive Vice President of Corporate Reservoir Engineering is the person primarily responsible for overseeing the preparation of our internal reserve estimates and for coordinating any reserves audits conducted by a third-party engineering firm. He has a Bachelor of Science degree in Petroleum Engineering and over 30 years of industry experience with positions of increasing responsibility within Apache’s corporate reservoir engineering department. The Executive Vice President of Corporate Reservoir Engineering reports directly to our Chairman and Chief Executive Officer.

The estimate of reserves disclosed in this Annual Report on Form 10-K is prepared by the Company’s internal staff, and the Company is responsible for the adequacy and accuracy of those estimates. However, the Company engages Ryder Scott Company, L.P. Petroleum Consultants (Ryder Scott) to review our processes and the reasonableness of our estimates of proved hydrocarbon liquid and gas reserves. Apache selects the properties for review by Ryder Scott based primarily on relative reserve value. We also consider other factors such as geographic location, new wells drilled during the year and reserves volume. During 2013, the properties selected for each country ranged from 83 to 100 percent of the total future net cash flows discounted at 10 percent. These properties also accounted for over 86 percent of the reserves value of our international proved reserves and of the new wells drilled in each country. In addition, all fields containing five percent or more of the Company’s total proved reserves volume were included in Ryder Scott’s review. The review covered 86 percent of total proved reserves, including 89 percent of proved developed reserves and 79 percent of PUD reserves.

During 2013, 2012, and 2011, Ryder Scott’s review covered 92, 88, and 81 percent, respectively, of the Company’s worldwide estimated proved reserves value and 86, 83, and 70 percent, respectively, of the Company’s total proved reserves volume. Ryder Scott’s review of 2013 covered 84 percent of U.S., 82 percent of Canada, 63 percent of Argentina, 99 percent of Australia, 88 percent of Egypt, and 88 percent of the U.K.’s total proved reserves. Ryder Scott’s review of 2012 covered 81 percent of U.S., 78 percent of Canada, 64 percent of Argentina, 99 percent of Australia, 84 percent of Egypt, and 88 percent of the U.K.’s total proved reserves. Ryder Scott’s review of 2011 covered 68 percent of U.S., 69 percent of Canada, 58 percent of Argentina, 99 percent of Australia, 62 percent of Egypt, and 61 percent of the U.K.’s total proved reserves. We have filed Ryder Scott’s independent report as an exhibit to this Form 10-K.

 

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

Employees

On December 31, 2013, we had 5,342 employees.

Offices

Our principal executive offices are located at One Post Oak Central, 2000 Post Oak Boulevard, Suite 100, Houston, Texas 77056-4400. At year-end 2013, we maintained regional exploration and/or production offices in Midland, Texas; Tulsa, Oklahoma; Houston, Texas; Calgary, Alberta; Cairo, Egypt; Perth, Western Australia; Aberdeen, Scotland; and Buenos Aires, Argentina. Apache leases all of its primary office space. The current lease on our principal executive offices runs through December 31, 2018. For information regarding the Company’s obligations under its office leases, please see Part II, Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity—Contractual Obligations and Note 8—Commitments and Contingencies in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.

Title to Interests

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

Additional Information about Apache

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

Remediation Plans and Procedures

Apache and its wholly owned subsidiary, Apache Deepwater LLC (ADW), developed Oil Spill Response Plans (the Plans) for their respective Gulf of Mexico operations to ensure rapid and effective responses to spill events that may occur on such entities’ operated properties as required by the Bureau of Safety and Environmental Enforcement (BSEE) 30 CFR 254.30. Annually, drills are conducted to measure and maintain the effectiveness of the Plans. These drills include the participation of spill response contractors, representatives of Clean Gulf Associates (CGA), and representatives of governmental agencies. In the event of a spill, CGA is the primary oil spill response association available to Apache and ADW. Apache and ADW have received approval for the Plans from BSEE. Apache and ADW personnel each review their respective Plan biennially and update where necessary.

 

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Both Apache and ADW are members of CGA, a not-for-profit association of producing and pipeline companies operating in the Gulf of Mexico. CGA was created to provide a means of effectively staging response equipment and providing immediate spill response for its member companies’ operations in the Gulf of Mexico. In the event of a spill, CGA’s equipment, which is positioned at various staging points around the Gulf, is ready to be mobilized. In addition, CGA has contracted with Airborne Support Inc. to provide aircraft and dispersant capabilities for CGA member companies. In 2013, Apache incurred charges for CGA of approximately $700,000 based on a per-member fee and annual production.

In the event that CGA resources are already being utilized, other resources are available to Apache. Apache is a member of Oil Spill Response Limited (OSRL), which entitles any Apache entity worldwide to access OSRL’s service. OSRL has access to resources from the Global Response Network, a collaboration of seven major oil industry funded spill response organizations worldwide. If necessary, OSRL’s resources may be, and have been, deployed to areas across the globe, including the Gulf of Mexico. In addition, in February 2012, ADW became a member of Marine Spill Response Corporation (MSRC) and National Response Corporation (NRC), and their resources are available to ADW for its deepwater Gulf of Mexico operations. Furthermore, the spill response resources of other organizations are also available to both Apache and ADW as non-members, albeit at a higher cost. MSRC has an extensive inventory of oil spill response equipment, independent of and in addition to CGA’s equipment. MSRC has contracts in place with over 100 environmental contractors around the country, in addition to hundreds of other companies that provide support services during spill response. In the event of a spill, MSRC will activate these contractors as necessary to provide additional resources or support services requested by its customers. NRC owns a variety of equipment, currently including shallow water portable barges, boom, high capacity skimming systems, inland workboats, vacuum transfer units, and mobile communication centers. NRC has access to hundreds of offshore vessels and supply boats worldwide. The equipment and resources available to MSRC and NRC changes from time to time, and current information is generally available on each company’s website. In 2013, Apache’s Gulf of Mexico Deepwater region incurred charges for NRC of $12,248 based on annual production and charges for MSRC of approximately $1.4 million based on annual production and total wells spud during the year.

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

Apache also participates in a number of industry-wide task forces that are studying ways to better access and control blowouts in subsea environments and increase containment and recovery methods. Two such task forces are the Subsea Well Control and Containment Task Force and the Offshore Operating Procedures Task Force.

Competitive Conditions

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

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

 

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

Environmental Compliance

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

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

 

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ITEM 1A. RISK FACTORS

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

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

The U.S. and other world economies continue to recover from the global financial crisis and recession that began in 2008. Growth has resumed but is modest and at an unsteady rate. The continuation of current global market conditions, uncertainty or further deterioration, including the economic instability in Europe and certain emerging markets, is likely to have significant long-term effects, including a future global economic growth rate that is slower than in the years leading up to the crisis, and more volatility may occur before any sustainable growth rate is achieved. Global economic growth drives demand for energy from all sources, including fossil fuels. A lower future economic growth rate could result in decreased demand growth for our crude oil and natural gas production as well as lower commodity prices, which would reduce our cash flows from operations and our profitability.

Crude oil and natural gas prices are volatile, and a substantial reduction in these prices could adversely affect our results and the price of our common stock.

Our revenues, operating results, and future rate of growth depend highly upon the prices we receive for our crude oil and natural gas production. Historically, the markets for crude oil and natural gas have been volatile and are likely to continue to be volatile in the future. For example, the NYMEX daily settlement price for the prompt month oil contract in 2013 ranged from a high of $110.53 per barrel to a low of $86.68 per barrel. The NYMEX daily settlement price for the prompt month natural gas contract in 2013 ranged from a high of $4.46 per MMBtu to a low of $3.11 per MMBtu. The market prices for crude oil and natural gas depend on factors beyond our control. These factors include demand for crude oil and natural gas, which fluctuates with changes in market and economic conditions, and other factors, including:

 

    worldwide and domestic supplies of crude oil and natural gas;

 

    actions taken by foreign oil and gas producing nations;

 

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

 

    the level of global crude oil and natural gas inventories;

 

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

 

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

 

    the availability of pipeline capacity and infrastructure;

 

    the availability of crude oil transportation and refining capacity;

 

    weather conditions;

 

    electricity generation;

 

    domestic and foreign governmental regulations and taxes; and

 

    the overall economic environment.

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

 

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

 

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

 

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

 

    reducing our revenues, operating income, and cash flows;

 

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

 

    a reduction in the carrying value of our crude oil and natural gas properties; or

 

    a reduction in the carrying value of goodwill.

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

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

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

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

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

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

 

    well blowouts, explosions, and cratering;

 

    pipeline or other facility ruptures and spills;

 

    fires;

 

    formations with abnormal pressures;

 

    equipment malfunctions;

 

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

 

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

Failure or loss of equipment as the result of equipment malfunctions, cyber attacks, or natural disasters such as hurricanes, could result in property damages, personal injury, environmental pollution and other damages for which we could be liable. Litigation arising from a catastrophic occurrence, such as a well blowout, explosion, or fire at a location where our equipment and services are used, or ground water contamination from hydraulic

 

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fracturing chemical additives may result in substantial claims for damages. Ineffective containment of a drilling well blowout or pipeline rupture, or surface spillage and surface or ground water contamination from petroleum constituents or hydraulic fracturing chemical additives could result in extensive environmental pollution and substantial remediation expenses. If a significant amount of our production is interrupted, our containment efforts prove to be ineffective or litigation arises as the result of a catastrophic occurrence, our cash flows, and, in turn, our results of operations could be materially and adversely affected.

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

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

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

The additional deepwater drilling laws and regulations, delays in the processing and approval of permits and other related developments in the Gulf of Mexico as well as our other locations resulting from the Deepwater Horizon incident could adversely affect Apache’s business.

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

Further, at this time, we cannot predict with any certainty what further impact, if any, the Deepwater Horizon incident may have on the regulation of offshore oil and gas exploration and development activity, or on the cost or availability of insurance coverage to cover the risks of such operations. The enactment of new or stricter regulations in the United States and other countries and increased liability for companies operating in this sector could adversely affect Apache’s operations in the U.S. Gulf of Mexico as well as in our other locations.

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

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

 

    our production falls short of the hedged volumes;

 

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

 

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

 

    an unexpected event materially impacts oil and natural gas prices.

The credit risk of financial institutions could adversely affect us.

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

We are exposed to counterparty credit risk as a result of our receivables.

We are exposed to risk of financial loss from trade, joint venture, joint interest billing, and other receivables. We sell our crude oil, natural gas, and NGLs to a variety of purchasers. As operator, we pay expenses and bill our non-operating partners for their respective shares of costs. Some of our purchasers and non-operating partners may experience liquidity problems and may not be able to meet their financial obligations. Nonperformance by a trade creditor or non-operating partner could result in significant financial losses.

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

We receive debt ratings from the major credit rating agencies in the United States. Factors that may impact our credit ratings include debt levels, planned asset purchases or sales, and near-term and long-term production growth opportunities. Liquidity, asset quality, cost structure, product mix, and commodity pricing levels and others are also considered by the rating agencies. A ratings downgrade could adversely impact our ability to access debt markets in the future, increase the cost of future debt, and potentially require us to post letters of credit or other forms of collateral for certain obligations.

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

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

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

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

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

 

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

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

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

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

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

 

    unexpected drilling conditions;

 

    pressure or irregularities in formations;

 

    equipment failures or accidents;

 

    fires, explosions, blowouts, and surface cratering;

 

    marine risks such as capsizing, collisions, and hurricanes;

 

    other adverse weather conditions; and

 

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

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

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

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

 

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

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

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

The BP Acquisition and/or our liabilities could be adversely affected in the event one or more of the BP entities become the subject of a bankruptcy case.

In light of the extensive costs and liabilities related to the oil spill in the Gulf of Mexico in 2010, there has been public speculation as to whether one or more of the BP entities could become the subject of a case or proceeding under Title 11 of the United States Code or any other relevant insolvency law or similar law (which we collectively refer to as Insolvency Laws). In the event that one or more of the BP entities were to become the subject of such a case or proceeding, a court may find that the three definitive purchase and sale agreements (the “BP Purchase Agreements”) we entered into in connection with our 2010 acquisition of properties from BP (the “BP Properties”) are executory contracts, in which case such BP entities may, subject to relevant Insolvency Laws, have the right to reject the agreements and refuse to perform their future obligations under them. In this event, our ability to enforce our rights under the BP Purchase Agreements could be adversely affected.

Additionally, in a case or proceeding under relevant Insolvency Laws, a court may find that the sale of the BP Properties constitutes a constructive fraudulent conveyance that should be set aside. While the tests for determining whether a transfer of assets constitutes a constructive fraudulent conveyance vary among jurisdictions, such a determination generally requires that the seller received less than a reasonably equivalent value in exchange for such transfer or obligation and the seller was insolvent at the time of the transaction, or was rendered insolvent or left with unreasonably small capital to meet its anticipated business needs as a result of the transaction. The applicable time periods for such a finding also vary among jurisdictions, but generally range from two to six years. If a court were to make such a determination in a proceeding under relevant Insolvency Laws, our rights under the BP Purchase Agreements, and our rights to the BP Properties, could be adversely affected.

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

There are numerous uncertainties inherent in estimating crude oil and natural gas reserves and their value. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact manner. Because of the high degree of judgment involved, the accuracy of any reserve estimate is inherently imprecise, and a function of the quality of available data and the engineering

 

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

 

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

 

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

 

    future operating costs and capital expenditures; and

 

    workover and remediation costs.

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

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

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

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

We may incur significant costs related to environmental matters.

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

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

Our North American operations have been, and at times in the future may be, affected by political developments and by federal, state, provincial, and local laws and regulations such as restrictions on production,

 

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changes in taxes, royalties and other amounts payable to governments or governmental agencies, price or gathering rate controls, and environmental protection laws and regulations. New political developments, laws, and regulations may adversely impact our results of operations.

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

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

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

The proposed U.S. federal budget for fiscal year 2014, when released, is expected to include certain provisions that, if passed, will have an adverse effect on our financial position, results of operations, and cash flows.

To date, the Office of Management and Budget has not released a summary of the proposed U.S. federal budget for fiscal year 2014. It is anticipated that the proposed budget may recommend the repeal of many tax incentives and deductions that are currently used by U.S. oil and gas companies. These provisions could include the elimination of the ability to fully deduct intangible drilling costs in the year incurred; increases in the taxation of foreign source income; repeal of the manufacturing tax deduction for oil and natural gas companies; and an increase in the geological and geophysical amortization period for independent producers. Should some or all of these provisions become law, our taxes will increase, potentially significantly, which would have a negative impact on our net income and cash flows. This could also cause us to reduce our drilling activities in the U.S. Since none of these proposals have been voted on or become law, we do not know the ultimate impact these proposed changes may have on our business.

Derivatives regulation included in current or proposed financial legislation and rulemaking could impede our ability to manage business and financial risks by restricting our use of derivative instruments as hedges against fluctuating commodity prices.

The Dodd-Frank Act, which was signed into law in July 2010, contains significant derivatives regulation, including a requirement that certain transactions be cleared on exchanges and a requirement to post collateral (commonly referred to as “margin”) for such transactions. The Act provides for a potential exception from these clearing and collateral requirements for commercial end-users and it includes a number of defined terms that will be used in determining how this exception applies to particular derivative transactions and the parties to those transactions. We expect to qualify as a commercial end-user. As required by the Dodd-Frank Act, the Commodities Futures and Trading Commission (CFTC) has promulgated numerous rules to define these terms. In addition, it is possible that the CFTC, in conjunction with prudential regulators, may mandate that financial counterparties entering into swap transactions with end-users must do so with credit support agreements in place, which could result in negotiated credit thresholds above which an end-user must post collateral.

We use derivative instruments with respect to a portion of our expected crude oil and natural gas production in order to reduce the impact of commodity price fluctuations and enhance the stability of cash flows to support our capital investment programs and acquisitions. Given our current investment grade status, our current derivative contracts do not require the posting of margin regardless of the size of our liability positions.

Depending on the rules and definitions adopted by the CFTC and prudential regulators, we could be required to post significant amounts of collateral with our dealer counterparties for derivative transactions. Requirements to post cash collateral could result in negative impacts on our liquidity and financial flexibility and

 

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also cause us to incur additional debt and/or reduce capital investment. In addition, the final CFTC rules may also require the counterparties to our derivative instruments to move some of their derivative activities to a separate entity, which may not be as creditworthy as the current counterparty.

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

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

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

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

In February 2011, the former Egyptian president Hosni Mubarak stepped down, and the Egyptian Supreme Council of the Armed Forces took power, announcing that it would remain in power until the presidential and parliamentary elections could be held. In June 2012, Mohamed Morsi of the Muslim Brotherhood’s Freedom and Justice Party was elected as Egypt’s new president. In July 2013, the Egyptian military removed President Morsi from power and installed Egypt’s Chief Justice, Adly Mansour, as acting president of a temporary government, which is seeking to set a schedule for new parliamentary and presidential elections in 2014. In January 2014, Egyptians voted on and overwhelmingly approved a new constitution, and Mr. Mansour announced that the presidential election will be held prior to the parliamentary elections. While the date of the presidential election has not been announced, it is expected to be held by mid-April 2014. Deterioration in the political, economic, and social conditions or other relevant policies of the Egyptian government, such as changes in laws or regulations, export restrictions, expropriation of our assets or resource nationalization, and/or forced renegotiation or modification of our existing contracts with EGPC could materially and adversely affect our business, financial condition, and results of operations. Our operations in Egypt contributed 19 percent of our 2013 production and accounted for 10 percent of our year-end estimated proved reserves. At year-end 2013, 18 percent of our estimated discounted future net cash flows and 8 percent of our net capitalized oil and gas property was attributable to Egypt. These totals reflect our consolidated interests in Egypt including Sinopec’s one-third noncontrolling interest.

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

Our operations outside North America are based primarily in Egypt, Australia, the United Kingdom, and Argentina. On a barrel equivalent basis, approximately 42 percent of our 2013 production was outside North America, and approximately 32 percent of our estimated proved oil and gas reserves on December 31, 2013 were located outside North America. As a result, a significant portion of our production and resources are subject to the increased political and economic risks and other factors associated with international operations including, but not limited to:

 

    general strikes and civil unrest;

 

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

 

    import and export regulations;

 

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

 

    price control;

 

    transportation regulations and tariffs;

 

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

 

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

 

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

 

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

 

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

 

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

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

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

Our operations are sensitive to currency rate fluctuations.

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

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

Strong competition exists in all sectors of the oil and gas exploration and production industry. We compete with major integrated and other independent oil and gas companies for acquisition of oil and gas leases, properties, and reserves, equipment, and labor required to explore, develop, and operate those properties, and

 

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

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

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

 

ITEM 1B. UNRESOLVED STAFF COMMENTS

As of December 31, 2013, we did not have any unresolved comments from the SEC staff that were received 180 or more days prior to year-end.

 

ITEM 3. LEGAL PROCEEDINGS

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

 

ITEM 4. MINE SAFETY DISCLOSURES

None.

 

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PART II

 

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

During 2013, Apache common stock, par value $0.625 per share, was traded on the New York and Chicago Stock Exchanges and the NASDAQ National Market under the symbol “APA.” The table below provides certain information regarding our common stock for 2013 and 2012. Prices were obtained from The New York Stock Exchange, Inc. Composite Transactions Reporting System. Per-share prices and quarterly dividends shown below have been rounded to the indicated decimal place.

 

     2013      2012  
     Price Range      Dividends Per Share      Price Range      Dividends Per Share  
     High      Low          Declared              Paid          High      Low          Declared              Paid      

First Quarter

   $ 86.35       $ 72.20       $ 0.20       $ 0.17       $ 112.09       $ 91.48       $ 0.17       $ 0.15   

Second Quarter

     87.57         67.91         0.20         0.20         102.13         77.93         0.17         0.17   

Third Quarter

     89.17         75.07         0.20         0.20         94.87         81.55         0.17         0.17   

Fourth Quarter

     94.84         84.15         0.20         0.20         89.08         74.50         0.17         0.17   

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

We have paid cash dividends on our common stock for 49 consecutive years through December 31, 2013. In the first quarter of 2014 the Board of Directors approved a 25 percent increase to $0.25 per share for the regular quarterly cash dividend on the Company’s common shares. This increase will apply to the dividend on common shares payable on May 22, 2014, to stockholders of record on April 22, 2014, and subsequent dividends paid. When, and if, declared by our Board of Directors, future dividend payments will depend upon our level of earnings, financial requirements, and other relevant factors.

On July 28, 2010, Apache issued 25.3 million depositary shares, each representing a 1/20th interest in a share of Apache’s 6.00-percent Mandatory Convertible Preferred Stock, Series D (Preferred Share), or 1.265 million Preferred Shares. Upon conversion of the outstanding Preferred Shares on August 1, 2013, 14.4 million Apache common shares were issued.

In 1995, under our stockholder rights plan, each of our common stockholders received a dividend of one preferred stock purchase right (a Right) for each 2.310 outstanding shares of common stock (adjusted for subsequent stock dividends and a two-for-one stock split) that the stockholder owned. These Rights were originally scheduled to expire on January 31, 2006. Effective as of that date, the Rights were reset to one right per share of common stock, and the expiration was extended to January 31, 2016.

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

For a description of the rights, please refer to Note 10—Capital Stock in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.

Information concerning securities authorized for issuance under equity compensation plans is set forth under the caption “Equity Compensation Plan Information” in the proxy statement relating to the Company’s 2014 annual meeting of stockholders, which is incorporated herein by reference.

 

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The following stock price performance graph is intended to allow review of stockholder returns, expressed in terms of the appreciation of the Company’s common stock relative to two broad-based stock performance indices. The information is included for historical comparative purposes only and should not be considered indicative of future stock performance. The graph compares the yearly percentage change in the cumulative total stockholder return on the Company’s common stock with the cumulative total return of the Standard & Poor’s Composite 500 Stock Index and of the Dow Jones U.S. Exploration & Production Index (formerly Dow Jones Secondary Oil Stock Index) from December 31, 2008, through December 31, 2013. The stock performance graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall information be incorporated by reference into any future filing under the Securities Act of 1933 or Securities Exchange Act of 1934, each as amended, except to the extent that the Company specifically incorporates it by reference into such filing.

 

LOGO

 

     2008      2009      2010      2011      2012      2013  

Apache Corporation

   $ 100.00       $ 139.51       $ 162.19       $ 123.87       $ 108.13       $ 119.51   

S & P’s Composite 500 Stock Index

     100.00         126.46         145.51         148.59         172.37         228.19   

DJ US Expl & Prod Index

     100.00         140.56         164.09         157.22         166.37         219.35   

 

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ITEM 6. SELECTED FINANCIAL DATA

The following table sets forth selected financial data of the Company and its consolidated subsidiaries over the five-year period ended December 31, 2013, which information has been derived from the Company’s audited financial statements. This information should be read in connection with, and is qualified in its entirety by, the more detailed information in the Company’s financial statements set forth in Part IV, Item 15 of this Form 10-K. As discussed in more detail under Item 15, 2013 numbers in the following table reflect a total of $1.2 billion ($613 million net of tax) in non-cash write-downs of the carrying value of the Company’s U.S., North Sea, and Argentine proved oil and gas properties as a result of ceiling test limitations and a non-cash write-down related to the Company’s exit of operations in Kenya. The 2012 numbers reflect a total of $1.9 billion ($1.4 billion net of tax) in non-cash write-downs of the carrying value of the Company’s Canadian proved oil and gas properties. The 2009 numbers reflect a $2.82 billion ($1.98 billion net of tax) non-cash write-down of the carrying value of the Company’s U.S. and Canadian proved oil and gas properties as of March 31, 2009.

 

     As of or for the Year Ended December 31,  
     2013      2012      2011      2010      2009  
     (In millions, except per share amounts)  

Income Statement Data

              

Total revenues

   $ 16,054       $ 17,078       $ 16,888       $ 12,092       $ 8,615   

Net income (loss) attributable to common stock

     2,188         1,925         4,508         3,000         (292

Net income (loss) per common share:

              

Basic

     5.53         4.95         11.75         8.53         (0.87

Diluted

     5.50         4.92         11.47         8.46         (0.87

Cash dividends declared per common share

     0.80         0.68         0.60         0.60         0.60   

Balance Sheet Data

              

Total assets

   $ 61,637       $ 60,737       $ 52,051       $ 43,425       $ 28,186   

Long-term debt

     9,672         11,355         6,785         8,095         4,950   

Total equity

     35,393         31,331         28,993         24,377         15,779   

Common shares outstanding

     396         392         384         382         336   

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

 

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

Apache Corporation, a Delaware corporation formed in 1954, is an independent energy company that explores for, develops, and produces natural gas, crude oil, and natural gas liquids. We currently have exploration and production interests in six countries: the U.S., Canada, Egypt, Australia, the U.K. North Sea, and Argentina. Apache also pursues exploration interests in other countries that may over time result in reportable discoveries and development opportunities.

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

Executive Overview

Strategy

Apache’s mission is to grow a profitable global exploration and production company in a safe and environmentally responsible manner for the long-term benefit of our shareholders. Our growth strategy focuses on economic growth through exploration and development drilling, supplemented by occasional strategic acquisitions and portfolio high-grading through asset divestitures.

The Company’s foundation for future growth is driven by our significant producing asset base and large undeveloped acreage positions. This allows for growth through sustainable lower-risk drilling opportunities, balanced by higher-risk, higher-reward exploration. We closely monitor drilling and acquisition cost trends in each of our core areas relative to product prices and, when appropriate, adjust our capital budgets accordingly and allocate funds to projects based on expected value. We do this through a disciplined and focused process that includes analyzing current economic conditions, projected rate of return on internally generated drilling inventories, and opportunities for tactical acquisitions or leasehold purchases that add substantial drilling prospects or, occasionally, provide access to new core areas that could enhance our portfolio.

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

We remain steadfast to the business principles that have guided Apache’s progress since our inception. Throughout the cycles of our industry, our strategic focus on growing a diverse portfolio has underpinned our ability to deliver production and reserve growth and competitive returns on invested capital for the benefit of our shareholders. Delivering successful results under this strategy is bolstered by Apache’s unique culture. A strong sense of urgency, empowerment of our employees, effective incentive systems, and an independent mindset are at the heart of how we build value.

Financial and Operating Results

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

 

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addition, approximately 65 percent of our 2013 crude oil production is priced relative to Dated Brent crudes and sweet crude from the Gulf Coast, which continue to be priced at a significant premium to WTI-based prices. After the sale of our Gulf of Mexico Shelf assets, less of our U.S. crude oil production is receiving these premium prices, which reduces our overall price realizations.

Results for the year ended December 31, 2013 include:

 

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

 

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

 

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

 

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

 

    Apache reported $2.2 billion in income attributable to common stock, or $5.50 per diluted common share, up from $1.9 billion, or $4.92 per share, in 2012. Earnings for 2013 and 2012 reflect the after-tax impact of oil and gas property write-downs totaling $659 million and $1.4 billion, respectively. For additional discussion regarding these write-downs, please refer to Note 1—Summary of Significant Accounting Policies—“Property and Equipment” in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.

 

    Apache’s adjusted earnings, which exclude certain items impacting the comparability of results, were $3.2 billion, or $7.92 per diluted common share, down from $3.8 billion, or $9.48 per share, in 2012. Adjusted earnings is not a financial measure prepared in accordance with accounting principles generally accepted in the U.S. (GAAP). For a description of adjusted earnings and a reconciliation of adjusted earnings to income attributable to common stock, the most directly comparable GAAP financial measure, please see “Non-GAAP Measures” in this Item 7.

2014 Outlook

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

We believe our core inventory of exploration and development projects offers numerous growth opportunities. Recent drilling successes and acquisitions of acreage positions across North America have built a robust drilling inventory for our Permian and Central regions that we intend to aggressively target because they are oil-prone and produce liquids-rich gas. Our plan for 2014 also includes further development of our major oil and gas discoveries and LNG projects in Australia and Canada, which, if completed, would enable us to monetize significant gas resources at prices more closely linked to crude oil.

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

 

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projects in North America, with the remaining amount allocated across our international regions. While funds have been committed for certain 2014 exploration wells, long-lead development projects, and front-end engineering and design (FEED) studies, the majority of our drilling and development projects are discretionary and subject to acceleration, deferral, or cancellation as conditions warrant. Approximately $2.4 billion of our 2014 capital will be invested in our Kitimat and Wheatstone LNG projects, reflecting our current project interests. Apache is actively evaluating ways to right-size its level of participation in the Kitimat LNG project.

We closely monitor commodity prices, service cost levels, regulatory impacts, and numerous other industry factors, and we typically review and revise our exploration and development budgets quarterly based on changes to actual and predicted operating cash flows.

Apache’s current capital budget is estimated to deliver an increase in 2014 production between 5 percent and 8 percent from full-year 2013 production levels when excluding the divested assets.

Operational Developments

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

Exploration, Exploitation, and Development Activities

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

North American Activities

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

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

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

International Activities

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

 

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

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

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

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

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

Acquisition and Divestiture Activity

2014 Activity

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

2013 Activity

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

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

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

 

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

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

2012 Activity

Cordillera Energy Partners III, LLC Acquisition On April 30, 2012, Apache completed the acquisition of Cordillera, a privately held exploration and production company, in a stock and cash transaction. Cordillera’s properties include approximately 312,000 net acres in the Granite Wash, Tonkawa, Cleveland, and Marmaton plays in western Oklahoma and the Texas Panhandle. Apache issued 6,272,667 shares of common stock and paid approximately $2.7 billion of cash to the sellers as consideration for the transaction.

Yara Pilbara Holdings Pty Acquisition On January 31, 2012, a subsidiary of Apache Energy Limited completed the acquisition of a 49 percent interest in Yara Pilbara Holdings Pty Limited (YPHPL, formerly Burrup Holdings Limited) for $439 million, including working capital adjustments. Yara Australia Pty Ltd (Yara) owns the remaining 51 percent of YPHPL and operates the plant.

 

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Results of Operations

Oil and Gas Revenues

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

 

     For the Year Ended December 31,  
     2013     2012     2011  
     $ Value      % Contribution     $ Value      % Contribution     $ Value      % Contribution  
     ($ in millions)  

Total Oil Revenues:

               

United States

   $ 5,262        41   $ 4,662        35   $ 4,163        33

Canada

     563        4     492        4     485        4
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

North America

     5,825        45     5,154        39     4,648        37
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

Egypt(3)

     3,528        27     4,050        31     4,169        33

Australia

     779        6     1,218        9     1,552        12

North Sea

     2,500        20     2,517        19     2,072        16

Argentina

     271        2     271        2     238        2
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

International(3)

     7,078        55     8,056        61     8,031        63
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

Total(1)(3)

   $ 12,903        100   $ 13,210        100   $ 12,679        100
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

Total Gas Revenues:

               

United States

   $ 1,096        38   $ 1,169        37   $ 1,550        43

Canada

     587        21     751        23     1,033        29
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

North America

     1,683        59     1,920        60     2,583        72
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

Egypt(3)

     389        14     504        16     621        17

Australia

     361        13     357        11     182        5

North Sea

     194        7     188        6     19        0

Argentina

     202        7     224        7     204        6
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

International(3)

     1,146        41     1,273        40     1,026        28
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

Total(2)(3)

   $ 2,829        100   $ 3,193        100   $ 3,609        100
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

NGL Revenues:

               

United States

   $ 544        81   $ 395        73   $ 391        75

Canada

     74        11     79        14     99        19
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

North America

     618        92     474        87     490        94
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

Egypt(3)

     —          —         —          0     1        0

North Sea

     34        5     46        8     —          —    

Argentina

     18        3     24        5     31        6
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

International(3)

     52        8     70        13     32        6
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

Total(3)

   $ 670        100   $ 544        100   $ 522        100
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

Total Oil and Gas Revenues:

               

United States

   $ 6,902        42   $ 6,226        37   $ 6,104        36

Canada

     1,224        8     1,322        8     1,617        10
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

North America

     8,126        50     7,548        45     7,721        46
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

Egypt(3)

     3,917        24     4,554        27     4,791        29

Australia

     1,140        7     1,575        9     1,734        10

North Sea

     2,728        16     2,751        16     2,091        12

Argentina

     491        3     519        3     473        3
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

International(3)

     8,276        50     9,399        55     9,089        54
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

Total(3)

   $ 16,402        100   $ 16,947        100   $ 16,810        100
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

 

(1)  Financial derivative hedging activities decreased 2013, 2012, and 2011 oil revenues $47 million, $146 million, and $379 million, respectively.
(2)  Financial derivative hedging activities increased 2013, 2012, and 2011 natural gas revenues $31 million, $414 million, and $272 million, respectively.
(3)  2013 includes revenues attributable to a noncontrolling interest in Egypt.

 

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Production

The following table presents production volumes by region:

 

     For the Year Ended December 31,  
     2013      Increase
(Decrease)
    2012      Increase
(Decrease)
    2011  

Oil Volume—b/d:

            

United States

     146,907        10     134,123        12     119,415  

Canada

     17,724        12     15,830        11     14,252  
  

 

 

      

 

 

      

 

 

 

North America

     164,631        10     149,953        12     133,667  
  

 

 

      

 

 

      

 

 

 

Egypt(1)(2)

     89,561        (10 %)      99,756        (4 %)      103,912  

Australia

     19,329        (33 %)      28,884        (24 %)      38,228  

North Sea

     63,721        0     63,692        17     54,541  

Argentina

     9,375        (4 %)      9,741        2     9,597  
  

 

 

      

 

 

      

 

 

 

International

     181,986        (10 %)      202,073        (2 %)      206,278  
  

 

 

      

 

 

      

 

 

 

Total

     346,617        (2 %)      352,026        4     339,945  
  

 

 

      

 

 

      

 

 

 

Natural Gas Volume—Mcf/d:

            

United States

     781,335        (9 %)      854,099        (1 %)      864,742  

Canada

     497,515        (17 %)      600,680        (5 %)      632,550  
  

 

 

      

 

 

      

 

 

 

North America

     1,278,850        (12 %)      1,454,779        (3 %)      1,497,292  
  

 

 

      

 

 

      

 

 

 

Egypt(1)(2)

     356,454        1     353,738        (3 %)      365,418  

Australia

     223,433        4     214,013        16     185,079  

North Sea

     50,961        (11 %)      57,457        NM        2,284  

Argentina

     187,390        (12 %)      213,464        1     212,311  
  

 

 

      

 

 

      

 

 

 

International

     818,238        (2 %)      838,672        10     765,092  
  

 

 

      

 

 

      

 

 

 

Total

     2,097,088        (9 %)      2,293,451        1     2,262,384  
  

 

 

      

 

 

      

 

 

 

NGL Volume—b/d:

            

United States

     54,580        63     33,527        52     22,111  

Canada

     6,689        7     6,258        5     5,958  
  

 

 

      

 

 

      

 

 

 

North America

     61,269        54     39,785        42     28,069  
  

 

 

      

 

 

      

 

 

 

Egypt

     —          0     —          NM        49  

North Sea

     1,272        (21 %)      1,618        NM        4  

Argentina

     2,102        (30 %)      3,008        0     3,018  
  

 

 

      

 

 

      

 

 

 

International

     3,374        (27 %)      4,626        51     3,071  
  

 

 

      

 

 

      

 

 

 

Total

     64,643        46     44,411        43     31,140  
  

 

 

      

 

 

      

 

 

 

BOE per day(3)

            

United States

     331,709        7     310,000        9     285,650  

Canada

     107,332        (12 %)      122,201        (3 %)      125,636  
  

 

 

      

 

 

      

 

 

 

North America

     439,041        2     432,201        5     411,286  
  

 

 

      

 

 

      

 

 

 

Egypt(2)

     148,970        (6 %)      158,713        (4 %)      164,864  

Australia

     56,568        (12 %)      64,552        (7 %)      69,074  

North Sea

     73,487        (2 %)      74,887        36     54,925  

Argentina

     42,709        (12 %)      48,326        1     48,000  
  

 

 

      

 

 

      

 

 

 

International

     321,734        (7 %)      346,478        3     336,863  
  

 

 

      

 

 

      

 

 

 

Total

     760,775        (2 %)      778,679        4     748,149  
  

 

 

      

 

 

      

 

 

 

 

(1)      Gross oil production and gross natural gas production in Egypt for 2013, 2012, and 2011 was as follows:

 

         

     2013      2012      2011  

Oil (b/d)

     197,622        213,112        217,207  

Gas (Mcf/d)

     912,478        899,972        865,485  

 

(2)      Includes 2013 production volumes per day attributable to a noncontrolling interest in Egypt of:

 

         

Oil (b/d)

     3,912        

Gas (Mcf/d)

       16,494        

 

(3)      The table shows production on a barrel of oil equivalent basis (boe) in which natural gas is converted to an equivalent barrel of oil based on a 6:1 energy equivalent ratio. This ratio is not reflective of the price ratio between the two products.

 

NM—Not meaningful

 

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Pricing

The following table presents pricing information by region:

 

     For the Year Ended December 31,  
     2013      Increase
(Decrease)
    2012      Increase
(Decrease)
    2011  

Average Oil Price—Per barrel

            

United States

   $ 98.14        3   $ 94.98        (1 %)    $ 95.51  

Canada

     87.00        2     84.89        (9 %)      93.19  

North America

     96.94        3     93.91        (1 %)      95.27  

Egypt

     107.94        (3 %)      110.92        1     109.92  

Australia

     110.42        (4 %)      115.22        4     111.22  

North Sea

     107.48        0     107.97        4     104.09  

Argentina

     79.05        4     75.89        12     68.02  

International

     106.55        (2 %)      108.92        2     106.67  

Total(1)

     101.99        (1 %)      102.53        0     102.19  

Average Natural Gas Price—Per Mcf:

            

United States

   $ 3.84        3   $ 3.74        (24 %)    $ 4.91  

Canada

     3.23        (6 %)      3.42        (23 %)      4.47  

North America

     3.61        0     3.61        (24 %)      4.72  

Egypt

     2.99        (23 %)      3.90        (16 %)      4.66  

Australia

     4.43        (3 %)      4.55        69     2.69  

North Sea

     10.43        17     8.95        (60 %)      22.25  

Argentina

     2.96        3     2.87        9     2.64  

International

     3.84        (7 %)      4.15        13     3.67  

Total(2)

     3.70        (3 %)      3.80        (13 %)      4.37  

Average NGL Price—Per barrel

            

United States

   $ 27.29        (15 %)    $ 32.19        (34 %)    $ 48.42  

Canada

     30.50        (12 %)      34.63        (24 %)      45.72  

North America

     27.64        (15 %)      32.57        (32 %)      47.85  

Egypt

     —          —          —          NM        66.36  

North Sea

     73.06        (5 %)      77.11        18     65.45  

Argentina

     23.64        10     21.55        (23 %)      27.90  

International

     42.27        3     40.98        43     28.56  

Total

     28.40        (15 %)      33.45        (27 %)      45.95  

 

(1)  Reflects a per-barrel decrease of $0.37, $1.13, and $3.05 in 2013, 2012, and 2011, respectively, from financial derivative hedging activities.
(2)  Reflects a per-Mcf increase of $0.04, $0.49, and $0.33 in 2013, 2012, and 2011, respectively, from financial derivative hedging activities.

NM—Not meaningful

Crude Oil Prices

A substantial portion of our oil production is sold at prevailing market prices, which fluctuate in response to many factors that are outside of the Company’s control. Average realized crude oil prices for 2013 were essentially flat compared to 2012, although prices fluctuated throughout the year.

Continued volatility in the commodity price environment reinforces the importance of our diverse portfolio. While the market price received for natural gas varies among geographic areas, crude oil tends to trade within a tighter global range. With the exception of Argentina, price movements for all types and grades of crude oil

 

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

Natural Gas Prices

Natural gas, which currently has a limited global transportation system, is subject to price variances based on local supply and demand conditions. The majority of our gas sales contracts are indexed to prevailing local market prices, highlighting the importance of a geographically balanced portfolio. Our primary markets include North America, Egypt, Australia, the U.K., and Argentina. An overview of the market conditions in our primary gas-producing regions follows.

 

    North America has a common market; most of our gas is sold on a monthly or daily basis at either monthly or daily market prices. Our North American regions averaged $3.61 per Mcf in 2013, unchanged from 2012 levels.

 

    In Egypt, our gas is sold to EGPC, primarily under an industry pricing formula indexed to Dated Brent crude oil with a maximum gas price of $2.65 per MMBtu, plus an upward adjustment for liquids content. Under a legacy oil-indexed contract, which expired at the end of 2012, there was no price cap for our gas up to 100 MMcf/d of gross production. Overall, the region averaged $2.99 per Mcf in 2013, down 23 percent from the prior year.

 

    Australia has historically had a local market with a limited number of buyers and sellers resulting in mostly long-term, fixed-price contracts that are periodically adjusted for changes in the local consumer price index. During 2013, the region averaged $4.43 per Mcf, a 3 percent decrease from 2012 levels.

 

    Natural gas from the North Sea Beryl field is processed through the SAGE gas plant operated by Apache. The gas is sold to a third party at the St. Fergus entry point of the national grid on a National Balancing Point index price basis. The region averaged $10.43 per Mcf in 2013, a 17 percent increase from an average of $8.95 per Mcf in 2012.

 

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

NGL Prices

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

Crude Oil Revenues

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

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

 

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

2012 vs. 2011 During 2012 crude oil revenues totaled $13.2 billion, $531 million higher than the 2011 total of $12.7 billion, driven by a 4 percent increase in worldwide production. Average daily production in 2012 was 352.0 Mb/d, with prices averaging $102.53 per barrel. Crude oil represented 78 percent of our 2012 oil and gas production revenues and 45 percent of our equivalent production, compared to 75 and 45 percent, respectively, in the prior year. Higher realized prices contributed $43 million to the increase in full-year revenues, while higher production volumes added another $488 million.

Worldwide oil production increased 12.1 Mb/d, driven by a 14.7 Mb/d increase in the U.S. The Permian region increased 9.2 Mb/d on increased drilling and recompletion activity. The Central region increased 7.4 Mb/d on properties added from the Cordillera acquisition and drilling and recompletion activity. North Sea production increased 9.2 Mb/d primarily on volumes from the 2011 Mobil North Sea acquisition. Australia production decreased 9.3 Mb/d as a result of natural decline from our Pyrenees and Van Gogh fields.

Natural Gas Revenues

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

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

2012 vs. 2011 Natural gas revenues for 2012 of $3.2 billion were $416 million lower than 2011, the result of a 13 percent decrease in realized prices partially offset by a 1 percent increase in production volumes. Realized prices in 2012 averaged $3.80 per Mcf, a decrease of $0.57 per Mcf, which reduced revenues by $467 million. Worldwide production rose 31.1 MMcf/d, adding $51 million to revenues.

Worldwide gas production rose 1 percent on increases in the North Sea and Australia, partially offset by decreases in North America. North Sea daily production increased 55.2 MMcf/d, primarily as a result of the 2011 Mobil North Sea acquisition. Daily gas production in Australia increased 28.9 MMcf/d on new contracts associated with the recently completed gas processing facilities at Devil Creek. Central region rose 29.6 MMcf/d on production from the Cordillera acquisition. Daily production in Canada and the Gulf of Mexico onshore and offshore regions decreased 31.9 MMcf/d and 47.9 MMcf/d, respectively, as drilling and recompletion activity shifted from dry gas to liquids-rich gas properties.

 

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NGL Revenues

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

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

Operating Expenses

The table below presents a comparison of our expenses on an absolute dollar basis and an equivalent unit of production (boe) basis. Our discussion may reference expenses on a boe basis, on an absolute dollar basis or both, depending on context. All 2013 operating expenses include costs attributable to a noncontrolling interest in Egypt.

 

     For the Year Ended December 31,  
     2013      2012      2011      2013      2012      2011  
            (In millions)                    (Per boe)         

Depreciation, depletion and amortization:

                 

Oil and gas property and equipment

                 

Recurring

   $ 5,114      $ 4,812      $ 3,814      $ 18.42      $ 16.88      $ 13.97  

Additional

     1,176        1,926        109        4.24        6.76        0.40  

Other assets

     410        371        281        1.47        1.30        1.03  

Asset retirement obligation accretion

     243        232        154        0.88        0.81        0.56  

Lease operating costs

     3,056        2,968        2,605        11.00        10.41        9.54  

Gathering and transportation costs

     297        303        296        1.06        1.08        1.08  

Taxes other than income

     832        862        899        3.00        3.02        3.29  

General and administrative expense

     503        531        459        1.81        1.86        1.68  

Acquisitions, divestitures & transition

     33        31        20        0.12        0.11        0.07  

Financing costs, net

     174        165        158        0.63        0.58        0.58  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 11,838      $ 12,201      $ 8,795      $ 42.63      $ 42.81      $ 32.20  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Recurring Depreciation, Depletion and Amortization (DD&A)

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

 

     Recurring DD&A  
     (In millions)  

2011 DD&A

   $ 3,814  

Volume change

     231  

DD&A Rate change

     767  
  

 

 

 

2012 DD&A

   $ 4,812  

Volume change

     (83

DD&A Rate change

     385  
  

 

 

 

2013 DD&A

   $ 5,114  
  

 

 

 

 

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

2012 vs. 2011 Recurring full-cost depletion expense increased $998 million on an absolute dollar basis: $767 million on higher costs and $231 million from additional production. Our full-cost depletion rate increased $2.91 to $16.88 per boe as costs to acquire, find, and develop reserves, which were significantly impacted by higher oil prices, exceeded our historical cost basis. Price related reserve revisions in North America also had a negative impact on the rate.

Additional DD&A

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

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

In 2012 we recorded a non-cash write-down on the carrying value of our proved oil and gas property balances in Canada of $1.9 billion ($1.4 billion net of tax). The Company also recorded $28 million of additional DD&A related to the write-off of the carrying value of our oil and gas properties in New Zealand upon exiting the country and $15 million of seismic costs incurred in countries where Apache is pursuing exploration opportunities but has not yet established a presence.

Lease Operating Expenses

Lease operating expenses (LOE) include several key components, such as direct operating costs, repair and maintenance, and workover costs.

Direct operating costs generally trend with commodity prices and are impacted by the type of commodity produced and the location of properties (i.e., offshore, onshore, remote locations, etc.). Fluctuations in commodity prices impact operating cost elements both directly and indirectly. They directly impact costs such as power, fuel, and chemicals, which are commodity price based. Commodity prices also affect industry activity and demand, thus indirectly impacting the cost of items such as rig rates, labor, boats, helicopters, materials, and supplies. Oil, which contributed nearly half of our 2013 production, is inherently more expensive to produce than natural gas. Repair and maintenance costs are typically higher on offshore properties in Australia, the North Sea and the U.S. Gulf of Mexico regions.

 

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

 

For the Year Ended December 31, 2013

   

For the Year Ended December 31, 2012

 
     Per boe          Per boe  

2012 LOE

   $ 10.41     2011 LOE    $ 9.54  

Divestitures(1)

     (0.12  

Repairs and maintenance

     0.39  

Power and fuel costs

     0.19    

Labor and pumper costs

     0.31  

Labor and overhead costs

     0.17    

Non-operated property costs

     0.12  

Non-operated property costs

     0.13    

Workover costs

     0.06  

Transportation

     0.12    

Other

     0.10  

Workover costs

     0.07    

Other decreased production

     0.01  

Repairs and maintenance

     0.07    

Acquisitions(1)

     (0.12

Other

     0.11       

Other increased production

     (0.15     
  

 

 

      

 

 

 

2013 LOE

   $ 11.00     2012 LOE    $ 10.41  
  

 

 

      

 

 

 

 

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

Gathering and Transportation

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

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

The following table presents gathering and transportation costs we paid directly to third-party carriers for each of the periods presented:

 

     For the Year Ended December 31,  
         2013              2012              2011      
     (In millions)  

Canada

   $ 155      $ 163      $ 166  

U.S.

     84        69        64  

Egypt

     42        39        34  

North Sea

     7        24        25  

Argentina

     9        8        7  
  

 

 

    

 

 

    

 

 

 

Total Gathering and transportation

   $ 297      $ 303      $ 296  
  

 

 

    

 

 

    

 

 

 

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

 

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2012 vs. 2011 Gathering and transportation costs increased $7 million from 2011. The U.S. costs for 2012 increased $5 million as compared to 2011 on increased production in the Central region, primarily resulting from our acquisition of Cordillera. Egypt’s costs were up $5 million on a higher number of sales cargoes, increased terminal fees, and higher vessel freight costs. Canada’s costs decreased $3 million from a decline in activity in the region.

Taxes Other Than Income

Taxes other than income primarily consist of U.K. Petroleum Revenue Tax (PRT), severance taxes on properties onshore and in state or provincial waters off the coast of the U.S., Australia, and Argentina, and ad valorem taxes on properties in the U.S. and Canada. Severance taxes are generally based on a percentage of oil and gas production revenues, while the U.K. PRT is assessed on net receipts from qualifying fields in the U.K. North Sea. We are subject to a variety of other taxes including U.S. franchise taxes, Australian Petroleum Resources Rent Tax, and various Canadian taxes, including the Freehold Mineral tax and Saskatchewan Resources surtax. The table below presents a comparison of these expenses:

 

     For the Year Ended December 31,  
       2013          2012          2011    
     (In millions)  

U.K. PRT

   $ 382      $ 451      $ 538  

Severance taxes

     254        220        212  

Ad valorem taxes

     113        104        94  

Other

     83        87        55  
  

 

 

    

 

 

    

 

 

 

Total Taxes other than income

   $ 832      $ 862      $ 899  
  

 

 

    

 

 

    

 

 

 

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

2012 vs. 2011 Taxes other than income were $37 million lower than 2011. U.K. PRT decreased $87 million over the comparable 2011 period as a result of a decrease in net receipts, primarily driven by lower revenues on qualifying fields during the year. Property acquisitions in 2011 and 2012 resulted in increases of $8 million and $10 million to severance and ad valorem tax expense, respectively.

General and Administrative Expenses

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

2012 vs. 2011 G&A expenses increased $72 million, or 16 percent, from 2011. On a per-unit basis, G&A expenses increased 11 percent, or $0.18 per boe: $0.12 per boe primarily relates to stock-based performance plan charges and $0.14 per boe relates to growth-related increases, less $0.08 on increased production.

Acquisitions, Divestitures, and Transition Costs

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

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

 

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In 2011, the Company recognized $20 million in acquisitions, divestitures, and transition costs, reflecting additional expenses related to our 2010 BP asset acquisitions and the Mariner merger as well as costs arising from our 2011 acquisition of Mobil North Sea Limited.

Financing Costs, Net

Financing costs incurred during the period comprised the following:

 

     For the Year Ended December 31,  
       2013         2012         2011    
     (In millions)  

Interest expense

   $ 571     $ 509     $ 433  

Amortization of deferred loan costs

     8       7       5  

Capitalized interest

     (374     (334     (263

Gain on extinguishment of debt

     (16     —         —    

Interest income

     (15     (17     (17
  

 

 

   

 

 

   

 

 

 

Total Financing costs, net

   $ 174     $ 165     $ 158  
  

 

 

   

 

 

   

 

 

 

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

2012 vs. 2011 Net financing costs increased $7 million from 2011. The increase is primarily related to a $76 million increase in interest expense from debt issuances during 2012, partially offset by a $71 million increase in capitalized interest resulting from additional unproved property balances associated with the significant undeveloped acreage from the Cordillera acquisition and the U.S. New Ventures program.

Provision for Income Taxes

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

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

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

Capital Resources and Liquidity

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

 

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

Apache’s long-term operating cash flows are dependent on reserve replacement and the level of costs required for ongoing operations. Cash investments are required to fund activity necessary to offset the inherent declines in production and proved crude oil and natural gas reserves. Future success in maintaining and growing reserves and production is highly dependent on the success of our exploration and development activities and our ability to acquire additional reserves at reasonable costs.

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

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

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

 

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Sources and Uses of Cash

The following table presents the sources and uses of our cash and cash equivalents for the years presented:

 

     For the Year Ended December 31,  
     2013      2012     2011  
     (In millions)  

Sources of Cash and Cash Equivalents:

       

Net cash provided by operating activities

   $ 9,835      $ 8,504     $ 9,953  

Commercial paper and bank loan borrowings, net

     —          549       —    

Sale of Gulf of Mexico Shelf properties

     3,702        —         —    

Proceeds from sale of Egypt noncontrolling interest

     2,948        —         —    

Proceeds from Kitimat LNG transaction, net

     396        —         —    

Proceeds from sale of oil and gas properties, other

     307        27       422  

Fixed-rate debt borrowings

     —          4,978       —    

Other

     21        —         84  
  

 

 

    

 

 

   

 

 

 
     17,209        14,058       10,459  
  

 

 

    

 

 

   

 

 

 

Uses of Cash and Cash Equivalents:

       

Capital expenditures(1)

   $ 11,220      $ 9,531     $ 7,078  

Acquisitions

     215        2,918       1,813  

Equity investment in Yara Pilbara Holdings Pty Limited (YPHPL)

     —          439       —    

Commercial paper, credit facility and bank loan repayments, net

     513        —         925  

Dividends paid

     360        332       306  

Shares repurchased

     997        —         —    

Payments on fixed-rate debt

     2,072        400       —    

Other

     86        573       176  
  

 

 

    

 

 

   

 

 

 
     15,463        14,193       10,298  
  

 

 

    

 

 

   

 

 

 

Increase (decrease) in cash and cash equivalents

   $ 1,746      $ (135   $ 161  
  

 

 

    

 

 

   

 

 

 

 

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

Net Cash Provided by Operating Activities

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

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

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

 

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

During 2013 Apache completed the sale of certain properties in Canada and the U.S. for $4.4 billion. Apache also completed the sale of a one-third minority participation in its Egypt oil and gas business to Sinopec for $2.95 billion. For information regarding our acquisitions and divestitures, please see Note 2—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.

Capital Investments

We fund exploration and development (E&D) activities primarily through operating cash flows and budget capital expenditures based on projected operating cash flows. Our operating cash flows, both in the short and long term are impacted by highly volatile oil and natural gas prices, production levels, industry trends impacting operating expenses and our ability to continue to acquire and find high-margin reserves at competitive prices. As a majority of our exploration and development activity is discretionary, we routinely adjust our capital budget on a quarterly basis in response to changing market conditions and operating cash flow forecasts.

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

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

 

     For the Year Ended December 31,  
       2013          2012          2011    
     (In millions)  

Exploration and Development:

        

United States

   $ 5,473      $ 5,151      $ 2,768  

Canada

     720        590        817  
  

 

 

    

 

 

    

 

 

 

North America

     6,193        5,741        3,585  
  

 

 

    

 

 

    

 

 

 

Egypt(1)

     1,166        1,074        896  

Australia

     1,179        873        576  

North Sea

     874        886        823  

Argentina

     182        289        346  

Other International

     22        98        61  
  

 

 

    

 

 

    

 

 

 

International(1)

     3,423        3,220        2,702  
  

 

 

    

 

 

    

 

 

 

Worldwide E&D Costs(1)

     9,616        8,961        6,287  
  

 

 

    

 

 

    

 

 

 

Gathering, Transmission, and Processing Facilities (GTP):

        

United States

     169        75        27  

Canada

     135        172        148  

Egypt(1)

     82        33        111  

Australia

     745        441        345  

Argentina

     11        16        12  

North Sea

     1        1        —    
  

 

 

    

 

 

    

 

 

 

Total GTP Costs(1)

     1,143        738        643  
  

 

 

    

 

 

    

 

 

 

Asset Retirement Costs

     484        948        819  

Capitalized Interest

     374        334        263  
  

 

 

    

 

 

    

 

 

 

Capital Expenditures

   $ 11,617      $ 10,981      $ 8,012  
  

 

 

    

 

 

    

 

 

 

Acquisitions, including GTP

   $ 377      $ 3,543      $ 3,189  

Asset Retirement Costs—Acquired

     53        84        592  
  

 

 

    

 

 

    

 

 

 

Total Acquisitions

   $ 430      $ 3,627      $ 3,781  
  

 

 

    

 

 

    

 

 

 

 

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

 

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

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

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

Acquisitions We acquired $377 million of oil and gas properties and GTP in 2013 compared to $3.5 billion in 2012. Acquisition capital expenditures occur as attractive opportunities arise and, therefore, vary from year to year. For information regarding our acquisitions and divestitures, please see Note 2—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.

Payments on Fixed-Rate Debt

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

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

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

Dividends

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

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

 

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

Shares Repurchased

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

Liquidity

 

     At December 31,  
         2013             2012      
     (In millions, except percentages)  

Cash and cash equivalents

   $ 1,906     $ 160  

Total debt

     9,725       12,345  

Equity

     35,393       31,331  

Available committed borrowing capacity

     3,300       2,811  

Floating-rate debt/total debt

     1     5

Percent of total debt-to-capitalization

     22     28

Cash and Cash Equivalents

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

Debt

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

Available Credit Facilities

As of December 31, 2013, the Company had unsecured committed revolving syndicated bank credit facilities totaling $3.3 billion, of which $1.0 billion matures in August 2016 and $2.3 billion matures in June 2017. The facilities consist of a $1.7 billion facility and a $1.0 billion facility in the U.S., a $300 million facility in Australia, and a $300 million facility in Canada. In July 2013, we amended our $1.0 billion U.S. credit facility to conform certain representations, covenants, and events of default to those in our $1.7 billion U.S. credit

 

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

At the Company’s option, the interest rate for the facilities is based on a base rate, as defined, or the London Inter-bank Offered Rate (LIBOR) plus a margin determined by the Company’s senior long-term debt rating. The $1.7 billion credit facility also allows the Company to borrow under competitive auctions.

At December 31, 2013, the margin over LIBOR for committed loans was 0.875 percent on the $1.0 billion U.S. credit facility and 0.90 percent on each of the $1.7 billion U.S. credit facility, the $300 million Australian credit facility, and the $300 million Canadian credit facility. The Company also pays quarterly facility fees of 0.125 percent on the total amount of the $1.0 billion facility and 0.10 percent on the total amount of the other three facilities. The facility fees vary based upon the Company’s senior long-term debt rating.

The financial covenants of the credit facilities require the Company to maintain a debt-to-capitalization ratio of not greater than 60 percent at the end of any fiscal quarter. At December 31, 2013, the Company’s debt-to-capitalization ratio was 22 percent.

The negative covenants include restrictions on the Company’s ability to create liens and security interests on its assets, with exceptions for liens typically arising in the oil and gas industry, purchase money liens, and liens arising as a matter of law, such as tax and mechanics’ liens. The Company may incur liens on assets located in the U.S. and Canada of up to 5 percent of the Company’s consolidated assets, or approximately $3.1 billion as of December 31, 2013. There are no restrictions on incurring liens in countries other than the U.S. and Canada. There are also restrictions on Apache’s ability to merge with another entity, unless the Company is the surviving entity, and a restriction on its ability to guarantee debt of entities not within its consolidated group.

There are no clauses in the facilities that permit the lenders to accelerate payments or refuse to lend based on unspecified material adverse changes. The credit facility agreements do not have drawdown restrictions or prepayment obligations in the event of a decline in credit ratings. However, the agreements allow the lenders to accelerate payments and terminate lending commitments if Apache Corporation, or any of its U.S. or Canadian subsidiaries, defaults on any direct payment obligation in excess of the stated thresholds noted in the agreements or has any unpaid, non-appealable judgment against it in excess of the stated thresholds noted in the agreements. The Company was in compliance with the terms of the credit facilities as of December 31, 2013.

There is no assurance that the financial condition of banks with lending commitments to the Company will not deteriorate. We closely monitor the ratings of the 25 banks in our bank group. Having a large bank group allows the Company to mitigate the potential impact of any bank’s failure to honor its lending commitment.

Commercial Paper Program

The Company has available a $3.0 billion commercial paper program, which generally enables Apache to borrow funds for up to 270 days at competitive interest rates. The commercial paper program is fully supported by available borrowing capacity under committed credit facilities. Our 2013 weighted-average interest rate for commercial paper was 0.38 percent. If the Company is unable to issue commercial paper following a significant credit downgrade or dislocation in the market, the Company’s committed credit facilities, which expire in 2016 and 2017, are available as a 100 percent backstop. As of December 31, 2013, the Company had no outstanding commercial paper. At December 31, 2012, the Company had $489 million in commercial paper outstanding.

Letter of Credit Collateral

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

 

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

Total Debt-to-Capitalization

The Company’s debt-to-capitalization ratio as of December 31, 2013, was 22 percent as compared to 28 percent at December 31, 2012. The decrease in our debt-to-capitalization ratio is directly related to the 2013 payment of fixed and floating debt and repurchase of shares. Apache has historically utilized available committed borrowing capacity, access to both debt and equity capital markets, and proceeds from the occasional sale of nonstrategic assets for liquidity and capital resources needs.

Off-Balance Sheet Arrangements

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

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

Contractual Obligations

The following table summarizes the Company’s contractual obligations as of December 31, 2013. For additional information regarding these obligations, please see Note 6—Debt and Note 8—Commitments and Contingencies in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.

 

Contractual Obligations(1)

   Note
Reference
     Total      2014      2015-2016      2017-2018      2019 &
Beyond
 
     (In millions)  

Debt, at face value

     Note 6       $ 9,784      $ 53      $ 1      $ 1,450      $ 8,280  

Interest payments

     Note 6         10,234        482        965        907        7,880  

Drilling rig commitments(2)

     Note 8         974        376        429        157        12  

Purchase obligations(3)

     Note 8         1,759         1,002        533        204        20  

Firm transportation agreements

     Note 8         683        158        223        129        173  

Office and related equipment

     Note 8         391        46        101        95        149  

Other operating lease obligations(4)

     Note 8         686        190        295        193        8  
     

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Contractual Obligations

      $ 24,511       $ 2,307       $ 2,547      $ 3,135      $ 16,522  
     

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1)  This table does not include the Company’s liability for dismantlement, abandonment, and restoration costs of oil and gas properties, derivative liabilities, pension or postretirement benefit obligations, or tax reserves. For additional information regarding these liabilities, please see Notes 5, 3, 9, and 7, respectively, in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.
(2)  This represents minimum future expenditures for drilling rig services. Apache’s expenditures for drilling rig services will exceed such minimum amounts to the extent Apache utilizes the drilling rigs subject to a particular contractual commitment for a period greater than the period set forth in the governing contract.
(3) 

Purchase obligations represent agreements to purchase goods or services that are enforceable, are legally binding, and specify all significant terms, including fixed and minimum quantities to be purchased; fixed,

 

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  minimum or variable price provisions; and the appropriate timing of the transaction. These include minimum commitments associated with take-or-pay contracts, hydraulic fracturing service agreements, obtaining and processing seismic data, and contractual obligations to buy or build oil and gas plants and facilities, including LNG facilities.
(4)  Other operating lease obligations pertain to other long-term exploration, development, and production activities. The Company has work-related commitments for oil and gas operations equipment, acreage maintenance commitments, FPSOs, and aircraft, among other things.

Apache is also subject to various contingent obligations that become payable only if certain events or rulings were to occur. The inherent uncertainty surrounding the timing of and monetary impact associated with these events or rulings prevents any meaningful accurate measurement, which is necessary to assess settlements resulting from litigation. Apache’s management feels that it has adequately reserved for its contingent obligations, including approximately $93 million for environmental remediation and approximately $10 million for various contingent legal liabilities. For a detailed discussion of the Company’s environmental and legal contingencies, please see Note 8—Commitments and Contingencies in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.

The Company also had approximately $79 million accrued as of December 31, 2013, for an insurance contingency as a member of Oil Insurance Limited (OIL). This insurance co-op insures specific property, pollution liability, and other catastrophic risks of the Company. As part of its membership, the Company is contractually committed to pay a withdrawal premium if we elect to withdraw from OIL. Apache does not anticipate withdrawal from the insurance pool; however, the potential withdrawal premium is calculated annually based on past losses and the nature of our asset base.

Insurance Program

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

Our current insurance policies covering physical damage to our assets provide $1 billion in coverage per occurrence. These policies also provide sudden pollution coverage. Coverage for damage to our U.S. Gulf of Mexico assets specifically resulting from a named windstorm, however, is subject to a maximum of $250 million per named windstorm, which includes a self-insured retention of 40 percent of the losses above a $100 million deductible and is limited to an annual aggregate of $300 million.

Our current insurance policies covering general liabilities provide coverage of $660 million subject to Apache’s interest. This coverage is in excess of existing policies, including, but not limited to, aircraft liability, employer’s liability, and automobile liability. Our service agreements, including drilling contracts, generally indemnify Apache for injuries and death of the service provider’s employees as well as subcontractors hired by the service provider.

Our insurance policies generally renew in January and June of each year. Future insurance coverage for our industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable.

Apache purchases multi-year political risk insurance from the Overseas Private Investment Corporation (OPIC) and other highly rated international insurers covering its investments in Egypt. In the aggregate, these insurance policies, subject to the policy terms and conditions, provide approximately $856 million of coverage to Apache for losses arising from confiscation, nationalization, and expropriation risks, with a $149 million sub-limit for currency inconvertibility.

 

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In addition, the Company has a separate policy with OPIC, which provides $300 million of coverage for losses arising from (1) non-payment by EGPC of arbitral awards covering amounts owed Apache on past due invoices and (2) expropriation of exportable petroleum in the event that actions taken by the government of Egypt prevent Apache from exporting our share of production. In October 2012, the Multilateral Investment Guarantee Agency (MIGA), a member of the World Bank Group, announced that it was providing $150 million in reinsurance to OPIC for the remainder of the policy term. This provision of long-term reinsurance to OPIC will allow Apache to maintain the $300 million of insurance coverage through 2024.

Non-GAAP Measures

The Company makes reference to some measures in discussion of its financial and operating highlights that are not required by or presented in accordance with GAAP. Management uses these measures in assessing operating results and believes the presentation of these measures provides information useful in assessing the Company’s financial condition and results of operations. These non-GAAP measures should not be considered as alternatives to GAAP measures and may be calculated differently from, and therefore may not be comparable to, similarly titled measures used at other companies.

Adjusted Earnings

To assess the Company’s operating trends and performance, management uses Adjusted Earnings, which is net income excluding certain items that management believes affect the comparability of operating results. Management believes this presentation may be useful to investors who follow the practice of some industry analysts who adjust reported company earnings for items that may obscure underlying fundamentals and trends. The reconciling items below are the types of items management excludes and believes are frequently excluded by analysts when evaluating the operating trends and comparability of the Company’s results.

 

     For the Year Ended December 31,  
       2013         2012          2011    
     (In millions, except per share data)  

Income (Loss) Attributable to Common Stock (GAAP)

   $ 2,188     $ 1,925      $ 4,508  

Adjustments:

       

Oil & gas property write-downs, net of tax(1)

     659       1,427        60  

Deferred tax on distributed foreign earnings

     225       —          —    

Deferred tax adjustments

     58       226        (75

U.K. income tax adjustments

     —         118        218  

Commodity derivative mark-to-market, net of tax(2)

     142       51        —    

Acquisitions, divestitures, and transition, net of tax(3)

     21       19        13  

Unrealized foreign currency fluctuation impact on deferred tax expense

     (123     1        (73
  

 

 

   

 

 

    

 

 

 

Adjusted Earnings (Non-GAAP)

   $ 3,170     $ 3,767      $ 4,651  
  

 

 

   

 

 

    

 

 

 

Net Income per Common Share—Diluted (GAAP)

   $ 5.50     $ 4.92      $ 11.47  

Adjustments:

       

Oil & gas property write-downs, net of tax(1)

     1.63       3.53        0.15  

Deferred tax on distributed foreign earnings

     0.55       —          —    

Deferred tax adjustments

     0.14       0.56        (0.19

U.K. income tax adjustments

     —         0.30        0.55  

Commodity derivative mark-to-market, net of tax(2)

     0.35       0.13        —    

Acquisitions, divestitures, and transition, net of tax(3)

     0.05       0.04        0.03  

Unrealized foreign currency fluctuation impact on deferred tax expense

     (0.30     —          (0.18
  

 

 

   

 

 

    

 

 

 

Adjusted Earnings Per Share—Diluted (Non-GAAP)

   $ 7.92     $ 9.48      $ 11.83  
  

 

 

   

 

 

    

 

 

 

 

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(1)  Write-downs of our U.S., North Sea, and Argentina proved oil and gas property balances of $552 million, $368 million, and $181 million, respectively, were recorded in 2013, for which tax benefits of $196 million, $229 million, and $63 million, respectively, were recognized. Separately, a $75 million non-cash write-down was recorded related to the Company’s exit of operations in Kenya, for which a tax benefit of $29 million was recognized. A non-cash write-down on the carrying value of our proved oil and gas property balances in Canada of $1.9 billion was recorded during 2012, for which a tax benefit of $474 million was recognized. The tax effect was calculated utilizing the Canadian statutory rate currently in effect.
(2)  Commodity derivative mark-to-market losses recorded in 2013 totaled $221 million, for which a tax benefit of $79 million was recognized.
(3)  Acquisitions, divestitures, and transition costs recorded in 2013, 2012, and 2011, totaled $33 million, $31 million, and $20 million, respectively, for which tax benefits of $12 million, $12 million, and $7 million, respectively, were recognized. The tax effect was calculated utilizing the statutory rates in effect in each country where costs were incurred.

Critical Accounting Policies and Estimates

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

Reserves Estimates

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

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

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

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

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

 

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Asset Retirement Obligation (ARO)

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

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

Income Taxes

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

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

Purchase Price Allocation

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

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

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

 

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

 

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Commodity Risk

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

We periodically enter into derivative positions on a portion of our projected oil and natural gas production through a variety of financial and physical arrangements intended to manage fluctuations in cash flows resulting from changes in commodity prices. Apache typically uses futures contracts, swaps, and options to mitigate commodity price risk. In 2013 approximately 8 percent of our natural gas production and approximately 42 percent of our crude oil production was subject to financial derivative hedges, compared with 13 percent and 13 percent, respectively, in 2012.

On December 31, 2013, the Company had open natural gas derivatives in an asset position with a fair value of $3 million. A 10 percent movement in natural gas prices would move the fair value by approximately $463,000. The Company also had open oil derivatives in a liability position with a fair value of $301 million. A 10 percent increase in oil prices would increase the liability by approximately $476 million, while a 10 percent decrease in prices would move the derivatives to an asset position of $175 million. These fair value changes assume volatility based on prevailing market parameters at December 31, 2013. See Note 3—Derivative Instruments and Hedging Activities in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.

Interest Rate Risk

The Company considers its interest rate risk exposure to be minimal as a result of fixing interest rates on approximately 99.5 percent of the Company’s debt. At December 31, 2013, total debt included $53 million of floating-rate debt. As a result, Apache’s annual interest costs in 2013 will fluctuate based on short-term interest rates on approximately 0.5 percent of our total debt outstanding at December 31, 2013. A 10 percent change in floating interest rates on year-end floating debt balances would change annual interest expense by approximately $1.6 million.

Foreign Currency Risk

The Company’s cash flow stream relating to certain international operations is based on the U.S. dollar equivalent of cash flows measured in foreign currencies. In Australia, oil production is sold under U.S. dollar contracts, and gas production is sold under a mixture of fixed-price U.S. dollar and Australian dollar contracts. Approximately 40 percent of the costs incurred for Australian operations are paid in U.S. dollars. In Canada, oil

 

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

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

Forward-Looking Statements and Risk

This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical facts included or incorporated by reference in this report, including, without limitation, statements regarding our future financial position, business strategy, budgets, projected revenues, projected costs and plans, and objectives of management for future operations, are forward-looking statements. Such forward-looking statements are based on our examination of historical operating trends, the information that was used to prepare our estimate of proved reserves as of December 31, 2013, and other data in our possession or available from third parties. In addition, forward-looking statements generally can be identified by the use of forward-looking terminology such as “may,” “will,” “could,” “expect,” “intend,” “project,” “estimate,” “anticipate,” “plan,” “believe,” or “continue” or similar terminology. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to have been correct. Important factors that could cause actual results to differ materially from our expectations include, but are not limited to, our assumptions about:

 

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

 

    our commodity derivative and hedging arrangements;

 

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

 

    production and reserve levels;

 

    drilling risks;

 

    economic and competitive conditions;

 

    the availability of capital resources;

 

    capital expenditure and other contractual obligations;

 

    currency exchange rates;

 

    weather conditions;

 

    inflation rates;

 

    the availability of goods and services;

 

    legislative or regulatory changes;

 

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

 

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    the integration of acquisitions;

 

    terrorism or cyber attacks;

 

    occurrence of property acquisitions or divestitures;

 

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

 

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

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

 

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The financial statements and supplementary financial information required to be filed under this Item 8 are presented on pages F-1 through F-73 in Part IV, Item 15 of this Form 10-K and are incorporated herein by reference.

 

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

The financial statements for the fiscal years ended December 31, 2013, 2012, and 2011, included in this report, have been audited by Ernst & Young LLP, registered public accounting firm, as stated in their audit report appearing herein. There have been no changes in or disagreements with the accountants during the periods presented.

 

ITEM 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

G. Steven Farris, the Company’s Chairman and Chief Executive Officer, in his capacity as principal executive officer, and Thomas P. Chambers, the Company’s Senior Vice President, Finance, in his capacity as principal financial officer, evaluated the effectiveness of our disclosure controls and procedures as of December 31, 2013, the end of the period covered by this report. Based on that evaluation and as of the date of that evaluation, these officers concluded that the Company’s disclosure controls and procedures were effective, providing effective means to ensure that the information we are required to disclose under applicable laws and regulations is recorded, processed, summarized, and reported within the time periods specified in the Commission’s rules and forms and accumulated and communicated to our management, including our principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure. We also made no changes in internal controls over financial reporting during the quarter ending December 31, 2013, that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

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

 

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

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

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

Changes in Internal Control over Financial Reporting

There was no change in our internal controls over financial reporting during the quarter ending December 31, 2013, that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

 

ITEM 9B. OTHER INFORMATION

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

 

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PART III

 

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The information set forth under the captions “Nominees for Election as Directors,” “Continuing Directors,” “Executive Officers of the Company,” and “Securities Ownership and Principal Holders” in the proxy statement relating to the Company’s 2014 annual meeting of shareholders (the Proxy Statement) is incorporated herein by reference.

Code of Business Conduct

Pursuant to Rule 303A.10 of the NYSE and Rule 4350(n) of the NASDAQ, we are required to adopt a code of business conduct and ethics for our directors, officers, and employees. In February 2004, the Board of Directors adopted the Code of Business Conduct (Code of Conduct), and revised it in November 2013. The revised Code of Conduct also meets the requirements of a code of ethics under Item 406 of Regulation S-K. You can access the Company’s Code of Conduct on the Governance page of the Company’s website at www.apachecorp.com. Any shareholder who so requests may obtain a printed copy of the Code of Conduct by submitting a request to the Company’s corporate secretary at the address on the cover of this Form 10-K. Changes in and waivers to the Code of Conduct for the Company’s directors, chief executive officer and certain senior financial officers will be posted on the Company’s website within five business days and maintained for at least 12 months. Information on our website or any other website is not incorporated by reference into, and does not constitute a part of, this Annual Report on Form 10-K.

 

ITEM 11. EXECUTIVE COMPENSATION

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

 

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

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

 

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

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

 

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

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

 

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PART IV

 

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

 

  (a) Documents included in this report:

 

  1. Financial Statements

 

Report of management

     F-1   

Report of independent registered public accounting firm

     F-2   

Report of independent registered public accounting firm

     F-3   

Statement of consolidated operations for each of the three years in the period ended December 31, 2013

     F-4   

Statement of consolidated comprehensive income for each of the three years in the period ended December  31, 2013

     F-5   

Statement of consolidated cash flows for each of the three years in the period ended December 31, 2013

     F-6   

Consolidated balance sheet as of December 31, 2013 and 2012

     F-7   

Statement of consolidated changes in equity for each of the three years in the period ended December  31, 2013

     F-8   

Notes to consolidated financial statements

     F-9   

 

  2. Financial Statement Schedules

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

 

  3. Exhibits

 

EXHIBIT

NO.

      

DESCRIPTION

2.1      Agreement and Plan of Merger, dated April 14, 2010, by and among Registrant, ZMZ Acquisitions LLC, and Mariner Energy, Inc. (incorporated by reference to Exhibit 2.1 to Registrant’s Current Report on Form 8-K, dated April 14, 2010, filed April 16, 2010, SEC File No. 001-4300) (the schedules and annexes have been omitted pursuant to Item 601(b)(2) of Regulation S-K).
2.2      Amendment No. 1, dated August 2, 2010, to Agreement and Plan of Merger, dated April 14, 2010, by and among Registrant, ZMZ Acquisitions LLC, and Mariner Energy, Inc. (incorporated by reference to Exhibit 2.1 to Registrant’s Current Report on Form 8-K, dated August 2, 2010, filed on August 3, 2010, SEC File No. 001-4300) (the schedules and annexes have been omitted pursuant to Item 601(b)(2) of Regulation S-K).
2.3      Purchase and Sale Agreement by and between BP America Production Company and ZPZ Delaware I LLC dated July 20, 2010 (incorporated by reference to Exhibit 2.1 to Registrant’s Current Report on Form 8-K/A, dated July 20, 2010, filed on July 21, 2010, SEC File No. 001-4300) (the exhibits and schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K).
2.4      Partnership Interest and Share Purchase and Sale Agreement by and between BP Canada Energy and Apache Canada Ltd. dated July 20, 2010 (incorporated by reference to Exhibit 2.2 to Registrant’s Current Report on Form 8-K/A, dated July 20, 2010, filed on July 21, 2010, SEC File No. 001-4300) (the exhibits have been omitted pursuant to Item 601(b)(2) of Regulation S-K).

 

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EXHIBIT

NO.

      

DESCRIPTION

2.5      Purchase and Sale Agreement by and among BP Egypt Company, BP Exploration (Delta) Limited and ZPZ Egypt Corporation LDC dated July 20, 2010 (incorporated by reference to Exhibit 2.3 to Registrant’s Current Report on Form 8-K/A, dated July 20, 2010, filed on July 21, 2010, SEC File No. 001-4300) (the exhibits and schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K).
3.1      Restated Certificate of Incorporation of Registrant, dated September 19, 2013, as filed with the Secretary of State of Delaware on September 19, 2013 (incorporated by reference to Exhibit 3.2 to Registrant’s Current Report on Form 8-K filed September 20, 2013, SEC File No. 001-4300).
3.2      Certificate of Designations of the 6.00% Mandatory Convertible Preferred Stock, Series D (incorporated by reference to Exhibit 3.3 to Registrant’s Registration Statement on Form 8-A, dated July 29, 2010, SEC File No. 001-4300).
3.3      Certificate of Elimination of Series D Preferred Stock of Registrant, dated September 18, 2013, as filed with the Secretary of State of Delaware on September 19, 2013 (incorporated by reference to Exhibit 3.1 to Registrant’s Current Report on Form 8-K filed September 19, 2013, SEC File No. 001-4300).
3.4      Bylaws of Registrant, as amended May 16, 2013 (incorporated by reference to Exhibit 3.1 to Registrant’s Current Report on Form 8-K filed May 17, 2013, SEC File No. 001-4300).
4.1      Form of Certificate for Registrant’s Common Stock (incorporated by reference to Exhibit 4.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2004, SEC File No. 001-4300).
4.2      Form of Certificate for the 6.00% Mandatory Convertible Preferred Stock, Series D (incorporated by reference to Exhibit A of Exhibit 3.3 to Registrant’s Registration Statement on Form 8-A, dated July 29, 2010, SEC File No. 001-4300).
4.3      Form of 3.625% Notes due 2021 (incorporated by reference to Exhibit 4.1 to Registrant’s Current Report on Form 8-K, dated November 30, 2010, filed on December 3, 2010, SEC File No. 001-4300).
4.4      Form of 5.250% Notes due 2042 (incorporated by reference to Exhibit 4.2 to Registrant’s Current Report on Form 8-K, dated November 30, 2010, filed on December 3, 2010, SEC File No. 001-4300).
4.5      Form of 5.100% Notes due 2040 (incorporated by reference to Exhibit 4.1 to Registrant’s Current Report on Form 8-K, dated August 17, 2010, filed on August 20, 2010, SEC File No. 001-4300).
4.6      Form of 1.75% Notes due 2017 (incorporated by reference to Exhibit 4.1 to Registrant’s Current Report on Form 8-K, dated April 3, 2012, filed on April 9, 2012, SEC File No. 001-4300).
4.7      Form of 3.25% Note due 2022 (incorporated by reference to Exhibit 4.2 to Registrant’s Current Report on Form 8-K, dated April 3, 2012, filed on April 9, 2012, SEC File No. 001-4300).
4.8      Form of 4.75% Notes due 2043 (incorporated by reference to Exhibit 4.3 to Registrant’s Current Report on Form 8-K, dated April 3, 2012, filed on April 9, 2012, SEC File No. 001-4300).
4.9      Form of 2.625% Notes due 2023 (incorporated by reference to Exhibit 4.1 to Registrant’s Current Report on Form 8-K, dated November 28, 2012, filed on December 4, 2012, SEC File No. 001-4300).
4.10      Form of 4.250% Notes due 2044 (incorporated by reference to Exhibit 4.2 to Registrant’s Current Report on Form 8-K, dated November 28, 2012, filed on December 4, 2012, SEC File No. 001-4300).

 

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EXHIBIT

NO.

      

DESCRIPTION

4.11      Rights Agreement, dated January 31, 1996, between Registrant and Wells Fargo Bank, N.A. (as successor-in-interest to Norwest Bank Minnesota, N.A.), rights agent, relating to the declaration of a rights dividend to Registrant’s common shareholders of record on January 31, 1996 (incorporated by reference to Exhibit (a) to Registrant’s Registration Statement on Form 8-A, dated January 24, 1996, SEC File No. 001-4300).
4.12      Amendment No. 1, dated as of January 31, 2006, to the Rights Agreement dated as of December 31, 1996, between Apache Corporation, a Delaware corporation, and Wells Fargo Bank, N.A. (as successor-in-interest to Norwest Bank Minnesota, N.A.) (incorporated by reference to Exhibit 4.4 to Registrant’s Amendment No. 1 to Registration Statement on Form 8-A, dated January 31, 2006, SEC File No. 001-4300).
4.13      Senior Indenture, dated February 15, 1996, between Registrant and The Bank of New York Mellon Trust Company, N.A. (formerly known as the Bank of New York Trust Company, N.A., as successor-in-interest to JPMorgan Chase Bank), formerly known as The Chase Manhattan Bank, as trustee, governing the senior debt securities and guarantees (incorporated by reference to Exhibit 4.6 to Registrant’s Registration Statement on Form S-3, dated May 23, 2003, Reg. No. 333-105536).
4.14      First Supplemental Indenture to the Senior Indenture, dated as of November 5, 1996, between Registrant and The Bank of New York Mellon Trust Company, N.A. (formerly known as the Bank of New York Trust Company, N.A., as successor-in-interest to JPMorgan Chase Bank, formerly known as The Chase Manhattan Bank), as trustee, governing the senior debt securities and guarantees (incorporated by reference to Exhibit 4.7 to Registrant’s Registration Statement on Form S-3, dated May 23, 2003, Reg. No. 333-105536).
4.15      Form of Indenture among Apache Finance Pty Ltd, Registrant and The Bank of New York Mellon Trust Company, N.A. (formerly known as the Bank of New York Trust Company, N.A., as successor-in-interest to The Chase Manhattan Bank), as trustee, governing the debt securities and guarantees (incorporated by reference to Exhibit 4.1 to Registrant’s Registration Statement on Form S-3, dated November 12, 1997, Reg. No. 333-339973).
4.16      Form of Indenture among Registrant, Apache Finance Canada Corporation and The Bank of New York Mellon Trust Company, N.A. (formerly known as the Bank of New York Trust Company, N.A., as successor-in-interest to The Chase Manhattan Bank), as trustee, governing the debt securities and guarantees (incorporated by reference to Exhibit 4.1 to Amendment No. 1 to Registrant’s Registration Statement on Form S-3, dated November 12, 1999, Reg. No. 333-90147).
4.17      Deposit Agreement, dated as of July 28, 2010, between Registrants and Wells Fargo Bank, N.A., as depositary, on behalf of all holders from time to time of the receipts issued there under (incorporated by reference to Exhibit 4.2 to Registrant’s Current Report on Form 8-K, dated July 22, 2010, filed on July 28, 2010, SEC File No. 001-4300).
4.18      Form of Depositary Receipt for the Depositary Shares (incorporated by reference to Exhibit A to Exhibit 4.2 to Registrant’s Current Report on Form 8-K, dated July 22, 2010, filed on July 28, 2010, SEC File No. 001-4300).
4.19      Senior Indenture, dated May 19, 2011, between Registrant and Wells Fargo Bank, National Association, as trustee, governing the senior debt securities of Apache Corporation (incorporated by reference to Exhibit 4.14 to Registrant’s Registration Statement on Form S-3, dated May 23, 2011, Reg. No. 333-174429).

 

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EXHIBIT

NO.

      

DESCRIPTION

  4.20      Senior Indenture, dated May 19, 2011, among Apache Finance Pty Ltd, Apache Corporation, as guarantor, and Wells Fargo Bank, National Association, as trustee, governing the senior debt securities of Apache Finance Pty Ltd and the related guarantees (incorporated by reference to Exhibit 4.16 to Registrant’s Registration Statement on Form S-3, dated May 23, 2011, Reg. No. 333-174429).
  4.21      Senior Indenture, dated May 19, 2011, among Apache Finance Canada Corporation, Apache Corporation, as guarantor, and Wells Fargo Bank, National Association, as trustee, governing the senior debt securities of Apache Finance Corporation and the related guarantees (incorporated by reference to Exhibit 4.20 to Registrant’s Registration Statement on Form S-3, dated May 23, 2011, Reg. No. 333-174429).
  4.22      Form of Apache Corporation November 10, 2010 First Non-Qualified Stock Option Agreement for Certain Employees of Apache Corporation (incorporated by reference to Exhibit 4.6 to Registrant’s Registration Statement on Form S-8 filed on November 10, 2010, Reg. No. 333-170533).
  4.23      Form of Apache Corporation November 10, 2010 Second Non-Qualified Stock Option Agreement for Certain Employees of Apache Corporation (incorporated by reference to Exhibit 4.7 to Registrant’s Registration Statement on Form S-8 filed on November 10, 2010, Reg. No. 333-170533).
  4.24      Form of Apache Corporation November 10, 2010 Non-Statutory Stock Option Agreement for Certain Employees of Apache Corporation (incorporated by reference to Exhibit 4.8 to Registrant’s Registration Statement on Form S-8 filed on November 10, 2010, Reg. No. 333-170533).
10.1      Credit Agreement, dated August 12, 2011, among Registrant, the lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, and Citibank, N.A., Bank of America, N.A., and Wells Fargo Bank, National Association, as Syndication Agents (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed August 18, 2011, SEC File No. 001-4300).
10.2      First Amendment to Credit Agreement, dated as of July 17, 2013, among Apache Corporation, the lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, and the other agents party thereto, amending Credit Agreement, dated as of August 12, 2011, among the same parties (incorporated by reference to Exhibit 10.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2013, SEC File No. 001-4300).
10.3      Credit Agreement, dated as of June 4, 2012, among Apache Corporation, the lenders party thereto, JPMorgan Chase Bank, N.A., as Global Administrative Agent, Bank of America, N.A. and Citibank, N.A., as Global Syndication Agents, and The Royal Bank of Scotland plc and Royal Bank of Canada, as Global Documentation Agents (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed June 7, 2012, SEC File No. 001-04300).
10.4      Credit Agreement, dated as of June 4, 2012, among Apache Canada Ltd., the lenders party thereto, JPMorgan Chase Bank, N.A., as Global Administrative Agent, Royal Bank of Canada, as Canadian Administrative Agent, Bank of America, N.A. and Citibank, N.A., as Global Syndication Agents, and The Royal Bank of Scotland plc and Royal Bank of Canada, as Global Documentation Agents (incorporated by reference to Exhibit 10.2 to Registrant’s Current Report on Form 8-K filed June 7, 2012, SEC File No. 001-04300)

 

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EXHIBIT

NO.

      

DESCRIPTION

   10.5      Syndicated Facility Agreement, dated as of June 4, 2012, among Apache Energy Limited (ACN 009 301 964), the lenders party thereto, JPMorgan Chase Bank, N.A., as Global Administrative Agent, Citisecurities Limited (ABN 51 008 489 610), as Australian Administrative Agent, Bank of America, N.A. and Citibank, N.A., as Global Syndication Agents, and The Royal Bank of Scotland plc and Royal Bank of Canada, as Global Documentation Agents (incorporated by reference to Exhibit 10.3 to Registrant’s Current Report on Form 8-K filed June 7, 2012, SEC File No. 001-04300).
  †10.6      Apache Corporation Corporate Incentive Compensation Plan A (Senior Officers’ Plan), dated July 16, 1998 (incorporated by reference to Exhibit 10.13 to Registrant’s Annual Report on Form 10-K for year ended December 31, 1998, SEC File No. 001-4300).
  †10.7      First Amendment to Apache Corporation Corporate Incentive Compensation Plan A, dated November 20, 2008, effective as of January 1, 2005 (incorporated by reference to Exhibit 10.17 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2008, SEC File No. 001-4300).
  †10.8      Apache Corporation Corporate Incentive Compensation Plan B (Strategic Objectives Format), dated July 16, 1998 (incorporated by reference to Exhibit 10.14 to Registrant’s Annual Report on Form 10-K for year ended December 31, 1998, SEC File No. 001-4300).
  †10.9      First Amendment to Apache Corporation Corporate Incentive Compensation Plan B, dated November 20, 2008, effective as of January 1, 2005 (incorporated by reference to Exhibit 10.19 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2008, SEC File No. 001-4300).
*†10.10      Apache Corporation 401(k) Savings Plan, as amended and restated, dated May 14, 2013, effective May 1, 2013.
  †10.11      Amendment to Apache Corporation 401(k) Savings Plan, dated October 25, 2013 (incorporated by reference to Exhibit 10.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2013, SEC File No. 001-4300).
  †10.12      Non-Qualified Retirement/Savings Plan of Apache Corporation, as amended and restated July 14, 2010, except as otherwise specified (incorporated by reference to Exhibit 10.3 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, SEC File No. 001-4300).
  †10.13      Amendment to Apache Corporation Non-Qualified Retirement/Savings Plan of Apache Corporation, dated December 19, 2011, effective January 1, 2012 (incorporated by reference to Exhibit 10.20 to Registrant’s Annual Report Form 10-K for year ended December 31, 2011, SEC File No. 001-4300).
  †10.14      Amendment to Non-Qualified Retirement/Savings Plan of Apache Corporation, dated November 8, 2012, effective January 1, 2013 (incorporated by reference to Exhibit 10.25 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2012, SEC File No. 001-4300).
  †10.15      Non-Qualified Restorative Retirement Savings Plan of Apache Corporation, dated November 7, 2011, effective January 1, 2012 (incorporated by reference to Exhibit 4.7 to Registrant’s Registration Statement on Form S-8, dated December 21, 2011, Reg. No. 333-178672).
  †10.16      Amendment to Non-Qualified Restorative Retirement Savings Plan of Apache Corporation, dated November 8, 2012, effective January 1, 2013 (incorporated by reference to Exhibit 10.27 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2012, SEC File No. 001-4300).

 

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EXHIBIT

NO.

      

DESCRIPTION

*†10.17      Apache Corporation 2011 Omnibus Equity Compensation Plan, as amended and restated February 3, 2014.
  †10.18      Apache Corporation 2007 Omnibus Equity Compensation Plan, as amended and restated May 4, 2011 (incorporated by reference to Exhibit 10.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2011, SEC File No. 001-4300).
  †10.19      Apache Corporation 2000 Stock Option Plan, as amended and restated May 5, 2011 (incorporated by reference to Exhibit 10.3 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2011, SEC File No. 001-4300).
  †10.20      Apache Corporation 2003 Stock Appreciation Rights Plan, as amended and restated September 16, 2013 (incorporated by reference to Exhibit 10.2 to Registrant’s Quarterly Report on Form 10-Q for quarter ended September 30, 2013, SEC File No. 001-4300).
  †10.21      Apache Corporation 2005 Stock Option Plan, as amended and restated September 16, 2013 (incorporated by reference to Exhibit 10.3 to Registrant’s Quarterly Report on Form 10-Q for quarter ended September 30, 2013, Commission File No. 001-4300).
  †10.22      Apache Corporation Income Continuance Plan, as amended and restated July 14, 2010, effective January 1, 2009 (incorporated by reference to Exhibit 10.5 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, SEC File No. 001-4300).
*†10.23      Apache Corporation Deferred Delivery Plan, as amended and restated November 11, 2013.
  †10.24      Apache Corporation Non-Employee Directors’ Compensation Plan, as amended and restated February 6, 2013 (incorporated by reference to Exhibit 10.39 to Registrant’s Annual Report on Form 10-K for the year ended December 31, 2012, SEC File No. 001-4300).
  †10.25      Apache Corporation Outside Directors’ Retirement Plan, as amended and restated February 6, 2013 (incorporated by reference to Exhibit 10.40 to Registrant’s Annual Report on Form 10-K for the year ended December 31, 2012, SEC File No. 001-4300).
  †10.26      Apache Corporation Equity Compensation Plan for Non-Employee Directors, as amended and restated February 8, 2007 (incorporated by reference to Exhibit 10.2 to Registrant’s Quarterly Report on Form 10-Q for quarter ended March 31, 2007, SEC File No. 001-4300).
  †10.27      Apache Corporation Non-Employee Directors’ Restricted Stock Units Program Specifications, dated May 5, 2011, pursuant to Apache Corporation 2011 Omnibus Equity Compensation Plan (incorporated by reference to Exhibit 10.6 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2011, SEC File No. 001-4300).
*†10.28      Apache Corporation Non-Employee Directors’ Restricted Stock Units Program Specifications, as amended and restated May 15, 2013, pursuant to Apache Corporation 2011 Omnibus Equity Compensation Plan.
  †10.29      Restated Employment and Consulting Agreement, dated January 15, 2009, between Registrant and Raymond Plank (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K, dated January 15, 2009, filed January 16, 2009, SEC File No. 001-4300).
  †10.30      Amended and Restated Employment Agreement, dated December 20, 1990, between Registrant and John A. Kocur (incorporated by reference to Exhibit 10.10 to Registrant’s Annual Report on Form 10-K for year ended December 31, 1990, SEC File No. 001-4300).
  †10.31      Employment Agreement between Registrant and G. Steven Farris, dated June 6, 1988, and First Amendment, dated November 20, 2008, effective as of January 1, 2005 (incorporated by reference to Exhibit 10.44 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2008, SEC File No. 001-4300).

 

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EXHIBIT

NO.

      

DESCRIPTION

†10.32      Restricted Stock Unit Award Agreement, dated May 8, 2008, between Registrant and G. Steven Farris (incorporated by reference to Exhibit 10.4 to Registrant’s Quarterly Report on Form 10-Q for quarter ended March 31, 2008, SEC File No. 001-4300).
†10.33      Form of Restricted Stock Unit Award Agreement, dated February 12, 2009, between Registrant and each of John A. Crum, Rodney J. Eichler, and Roger B. Plank (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K, dated February 12, 2009, filed February 18, 2009, SEC File No. 001-4300).
†10.34      Amendment to Restricted Stock Unit Award Agreement, dated March 7, 2011, between Registrant and John A. Crum (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report Form 8-K/A filed March 8, 2011, SEC File No. 001-4300).
†10.35      Resignation Agreement, dated March 7, 2011 between Registrant and John A. Crum (incorporated by reference to Exhibit 10.2 to Registrant’s Current Report on Form 8-K/A filed March 8, 2011, SEC File No. 001-4300).
†10.36      Form of Restricted Stock Unit Award Agreement, dated November 18, 2009, between Registrant and Michael S. Bahorich (incorporated by reference to Exhibit 10.37 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2009, SEC File No. 001-4300).
†10.37      Form of Restricted Stock Unit Grant Agreement, dated May 6, 2009, between Registrant and each of G. Steven Farris, Roger B. Plank, John A. Crum, Rodney J. Eichler, and Michael S. Bahorich (incorporated by reference to Exhibit 10.38 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2009, SEC File No. 001-4300).
†10.38      Form of Stock Option Award Agreement, dated May 6, 2009, between Registrant and each of G. Steven Farris, Roger B. Plank, John A. Crum, Rodney J. Eichler, and Michael S. Bahorich (incorporated by reference to Exhibit 10.39 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2009, SEC File No. 001-4300).
†10.39      Form of 2010 Performance Program Agreement, dated January 15, 2010, between Registrant and each of G. Steven Farris, John A. Crum, Rodney J. Eichler, and Roger B. Plank (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed January 19, 2010, SEC File No. 001-4300).
†10.40      Form of First Amendment, effective May 5, 2010, to 2010 Performance Program Agreement, dated January 15, 2010, between Registrant and each of G. Steven Farris, John A. Crum, Rodney J. Eichler, and Roger B. Plank (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed May 11, 2010, SEC File No. 001-4300).
†10.41      Form of Restricted Stock Unit Award Agreement, dated January 15, 2010, between Registrant and each of John A. Crum, Rodney J. Eichler, and Roger B. Plank (incorporated by reference to Exhibit 10.2 to Registrant’s Current Report on Form 8-K filed January 19, 2010, SEC File No. 001-4300).
†10.42      Form of 2011 Performance Program Agreement, dated January 7, 2011, between Registrant and each of G. Steven Farris, John A. Crum, Rodney J. Eichler, Roger B. Plank, Michael S. Bahorich, and Thomas P. Chambers (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed January 13, 2011, SEC File No. 001-4300).
†10.43      Restricted Stock Unit Award Agreement, dated February 9, 2011, between Registrant and Thomas P. Chambers (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed February 14, 2011, SEC File No. 001-4300).
†10.44      Form of 2012 Performance Program Agreement, dated January 11, 2012, between Registrant and each of G. Steven Farris, Rodney J. Eichler, Roger B. Plank, P. Anthony Lannie, and Thomas P. Chambers (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed January 13, 2012, SEC File No. 001-4300).

 

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EXHIBIT

NO.

      

DESCRIPTION

  †10.45      Form of 2013 Performance Program Agreement, dated January 9, 2013, between Registrant and each of G. Steven Farris, Rodney J. Eichler, Roger B. Plank, and Thomas P. Chambers (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed January 11, 2013, SEC File No. 001-4300).
  *10.46      Form of 2014 Performance Agreement (Total Shareholder Return), dated January 9, 2014, between Registrant and each of G. Steven Farris, Rodney J. Eichler, Roger B. Plank, P. Anthony Lannie, and Thomas P. Chambers.
  *10.47      Form of 2014 Performance Agreement (Business Performance), dated February 3, 2014, between Registrant and each of G. Steven Farris, Roger B. Plank, Rodney J. Eichler, P. Anthony Lannie, and Thomas P. Chambers.
  *12.1      Statement of Computation of Ratios of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividends.
  *14.1      Code of Business Conduct, as amended and restated November 13, 2013.
  *21.1      Subsidiaries of Registrant
  *23.1      Consent of Ernst & Young LLP
  *23.2      Consent of Ryder Scott Company L.P., Petroleum Consultants
  *24.1      Power of Attorney (included as a part of the signature pages to this report)
  *31.1      Certification (pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Exchange Act) by Principal Executive Officer.
  *31.2      Certification (pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Exchange Act) by Principal Financial Officer.
  *32.1      Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by Principal Executive Officer and Principal Financial Officer.
  *99.1      Report of Ryder Scott Company L.P., Petroleum Consultants
*101.INS      XBRL Instance Document.
*101.SCH      XBRL Taxonomy Schema Document.
*101.CAL      XBRL Calculation Linkbase Document.
*101.LAB      XBRL Label Linkbase Document.
*101.PRE      XBRL Presentation Linkbase Document.
*101.DEF      XBRL Definition Linkbase Document.

 

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

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

 

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SIGNATURES

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

APACHE CORPORATION

 

/s/ G. STEVEN FARRIS

G. Steven Farris
Chairman of the Board, Chief Executive Officer, and President

Dated: February 28, 2014

POWER OF ATTORNEY

The officers and directors of Apache Corporation, whose signatures appear below, hereby constitute and appoint G. Steven Farris, P. Anthony Lannie, Alfonso Leon, Thomas P. Chambers, and Rebecca A. Hoyt, and each of them (with full power to each of them to act alone), the true and lawful attorney-in-fact to sign and execute, on behalf of the undersigned, any amendment(s) to this report and each of the undersigned does hereby ratify and confirm all that said attorneys shall do or cause to be done by virtue thereof.

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

 

Name

  

Title

 

Date

/s/ G. STEVEN FARRIS

G. Steven Farris

   Chairman of the Board, Chief Executive Officer, and President (principal executive officer)   February 28, 2014

/s/ THOMAS P. CHAMBERS

Thomas P. Chambers

  

Senior Vice President, Finance

(principal financial officer)

  February 28, 2014

/s/ REBECCA A. HOYT

Rebecca A. Hoyt

  

Vice President, Chief Accounting Officer and Controller

(principal accounting officer)

  February 28, 2014

 

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Name

  

Title

 

Date

/s/ RANDOLPH M. FERLIC

Randolph M. Ferlic

  

Director

  February 28, 2014

/s/ EUGENE C. FIEDOREK

Eugene C. Fiedorek

  

Director

  February 28, 2014

/s/ A.D. FRAZIER, JR.

A. D. Frazier, Jr.

  

Director

  February 28, 2014

/s/ CHANSOO JOUNG

Chansoo Joung

  

Director

  February 28, 2014

/s/ GEORGE D. LAWRENCE

George D. Lawrence

  

Director

  February 28, 2014

/s/ JOHN E. LOWE

John E. Lowe

  

Director

  February 28, 2014

/s/ WILLIAM C. MONTGOMERY

William C. Montgomery

  

Director

  February 28, 2014

/s/ AMY H. NELSON

Amy H. Nelson

  

Director

  February 28, 2014

/s/ RODMAN D. PATTON

Rodman D. Patton

  

Director

  February 28, 2014

/s/ CHARLES J. PITMAN

Charles J. Pitman

  

Director

  February 28, 2014

 

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REPORT OF MANAGEMENT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

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

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

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

Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2013. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control — Integrated Framework (1992). Based on our assessment, management believes that the Company maintained effective internal control over financial reporting as of December 31, 2013.

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

/s/ G. Steven Farris

Chairman of the Board, Chief Executive Officer, and President

(principal executive officer)

/s/ Thomas P. Chambers

Senior Vice President, Finance

(principal financial officer)

/s/ Rebecca A. Hoyt

Vice President, Chief Accounting Officer and Controller

(principal accounting officer)

Houston, Texas

February 28, 2014

 

F-1


Table of Contents

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Shareholders of Apache Corporation:

We have audited the accompanying consolidated balance sheets of Apache Corporation and subsidiaries as of December 31, 2013 and 2012, and the related consolidated statements of operations, comprehensive income, changes in equity, and cash flows for each of the three years in the period ended December 31, 2013. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Apache Corporation and subsidiaries at December 31, 2013 and 2012, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2013, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Apache Corporation’s internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 framework) and our report dated February 28, 2014, expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Houston, Texas

February 28, 2014

 

F-2


Table of Contents

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Shareholders of Apache Corporation:

We have audited Apache Corporation and subsidiaries’ internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 framework) (the COSO criteria). Apache Corporation and subsidiaries’ management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Report of Management on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.

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

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

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

In our opinion, Apache Corporation and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Apache Corporation and subsidiaries as of December 31, 2013 and 2012, and the related consolidated statements of operations, comprehensive income, changes in equity, and cash flows for each of the three years in the period ended December 31, 2013 of Apache Corporation and subsidiaries, and our report dated February 28, 2014, expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Houston, Texas

February 28, 2014

 

F-3


Table of Contents

APACHE CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED OPERATIONS

 

     For the Year Ended December 31,  
         2013                 2012                 2011        
     (In millions, except per common
share data)
 

REVENUES AND OTHER:

      

Oil and gas production revenues:

      

Oil revenues

   $ 12,903     $ 13,210     $ 12,679  

Gas revenues

     2,829       3,193       3,609  

Natural gas liquids revenues

     670       544       522  
  

 

 

   

 

 

   

 

 

 
     16,402       16,947       16,810  

Derivative instrument gains (losses), net

     (399     (79      

Other

     51       210       78  
  

 

 

   

 

 

   

 

 

 
     16,054       17,078       16,888  
  

 

 

   

 

 

   

 

 

 

OPERATING EXPENSES:

      

Depreciation, depletion, and amortization:

      

Oil and gas property and equipment

      

Recurring

     5,114       4,812       3,814  

Additional

     1,176       1,926       109  

Other assets

     410       371       281  

Asset retirement obligation accretion

     243       232       154  

Lease operating expenses

     3,056       2,968       2,605  

Gathering and transportation

     297       303       296  

Taxes other than income

     832       862       899  

General and administrative

     503       531       459  

Acquisitions, divestitures and transition

     33       31       20  

Financing costs, net

     174       165       158  
  

 

 

   

 

 

   

 

 

 
     11,838       12,201       8,795  
  

 

 

   

 

 

   

 

 

 

INCOME BEFORE INCOME TAXES

     4,216       4,877       8,093  

Current income tax provision

     1,665       2,199       2,263  

Deferred income tax provision

     263       677       1,246  
  

 

 

   

 

 

   

 

 

 

NET INCOME INCLUDING NONCONTROLLING INTEREST

     2,288       2,001       4,584  

Net income attributable to noncontrolling interest

     56              

Preferred stock dividends

     44       76       76  
  

 

 

   

 

 

   

 

 

 

NET INCOME ATTRIBUTABLE TO COMMON STOCK

   $ 2,188     $ 1,925     $ 4,508  
  

 

 

   

 

 

   

 

 

 

NET INCOME PER COMMON SHARE:

      

Basic

   $ 5.53     $ 4.95     $ 11.75  

Diluted

   $ 5.50     $ 4.92     $ 11.47  

WEIGHTED-AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:

      

Basic

     395       389       384  

Diluted

     406       391       400  

DIVIDENDS DECLARED PER COMMON SHARE

   $ 0.80     $ 0.68     $ 0.60  

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

 

F-4


Table of Contents

APACHE CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME

 

     For the Year Ended December 31,  
         2013             2012             2011      
     (In millions)  

NET INCOME INCLUDING NONCONTROLLING INTEREST

   $ 2,288     $ 2,001     $ 4,584  

OTHER COMPREHENSIVE INCOME (LOSS):

      

Pension and postretirement benefit plan, net of tax

     9       (2     (1

Commodity cash flow hedge activity, net of tax:

      

Reclassification of (gain) loss on settled derivative instruments

     11       (199     19  

Change in fair value of derivative instruments

     (5     79       115  

Derivative hedge ineffectiveness reclassified into earnings

     1             (1
  

 

 

   

 

 

   

 

 

 
     16       (122     132  
  

 

 

   

 

 

   

 

 

 

COMPREHENSIVE INCOME INCLUDING NONCONTROLLING INTEREST

     2,304       1,879       4,716  

Comprehensive income attributable to noncontrolling interest

     56              

Preferred stock dividends

     44       76       76  
  

 

 

   

 

 

   

 

 

 

COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON STOCK

   $ 2,204     $ 1,803     $ 4,640  
  

 

 

   

 

 

   

 

 

 

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

 

F-5


Table of Contents

APACHE CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED CASH FLOWS

 

     For the Year Ended  
     December 31,  
     2013     2012     2011  
     (In millions)  

CASH FLOWS FROM OPERATING ACTIVITIES:

      

Net income including noncontrolling interest

   $ 2,288     $ 2,001     $ 4,584  

Adjustments to reconcile net income to net cash provided by operating activities:

      

Depreciation, depletion, and amortization

     6,700       7,109       4,204  

Asset retirement obligation accretion

     243       232       154  

Provision for deferred income taxes

     263       677       1,246  

Other

     260       226       46  

Changes in operating assets and liabilities:

      

Receivables

     124       12       (759

Inventories

     (70     (59     (37

Drilling advances

     230       (343     26  

Deferred charges and other

     (124     61       27  

Accounts payable

     479       (100     241  

Accrued expenses

     (553     (1,142     90  

Deferred credits and noncurrent liabilities

     (5     (170     131  
  

 

 

   

 

 

   

 

 

 

NET CASH PROVIDED BY OPERATING ACTIVITIES

     9,835       8,504       9,953  
  

 

 

   

 

 

   

 

 

 

CASH FLOWS FROM INVESTING ACTIVITIES:

      

Additions to oil and gas property

     (10,019     (8,781     (6,414

Additions to gas gathering, transmission, and processing facilities

     (1,201     (750     (664

Proceeds from divestiture of Gulf of Mexico Shelf properties

     3,702               

Proceeds from Kitimat LNG transaction, net

     396                

Proceeds from sale of oil and gas properties, other

     307       27       422  

Acquisition of Cordillera Energy Partners III, LLC

            (2,666       

Acquisition of Yara Pilbara Holdings Pty Limited

            (439       

Acquisition of Mobil North Sea Limited

                   (1,246

Acquisitions, other

     (215     (252     (567

Other, net

     (86     (563     (176
  

 

 

   

 

 

   

 

 

 

NET CASH USED IN INVESTING ACTIVITIES

     (7,116     (13,424     (8,645
  

 

 

   

 

 

   

 

 

 

CASH FLOWS FROM FINANCING ACTIVITIES:

      

Commercial paper, credit facilities and bank notes, net

     (513     549       (925

Fixed rate debt borrowings

            4,978         

Payments on fixed rate debt

     (2,072     (400       

Proceeds from sale of noncontrolling interest

     2,948                

Dividends paid

     (360     (332     (306

Shares repurchased

     (997              

Other

     21       (10     84  
  

 

 

   

 

 

   

 

 

 

NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES

     (973     4,785       (1,147
  

 

 

   

 

 

   

 

 

 

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS

     1,746       (135     161  

CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR

     160       295       134  
  

 

 

   

 

 

   

 

 

 

CASH AND CASH EQUIVALENTS AT END OF PERIOD

   $ 1,906     $ 160     $ 295  
  

 

 

   

 

 

   

 

 

 

SUPPLEMENTARY CASH FLOW DATA:

      

Interest paid, net of capitalized interest

   $ 192     $ 146     $ 156  

Income taxes paid, net of refunds

     1,766       2,590       1,686  

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

 

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Table of Contents

APACHE CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET

 

     December 31,  
     2013     2012  
     (In millions)  
ASSETS     

CURRENT ASSETS:

    

Cash and cash equivalents

   $ 1,906     $ 160  

Receivables, net of allowance

     2,952       3,086  

Inventories

     891       908  

Drilling advances

     371       584  

Derivative instruments

     1       31  

Prepaid assets and other

     245       193  
  

 

 

   

 

 

 
     6,366       4,962  
  

 

 

   

 

 

 

PROPERTY AND EQUIPMENT:

    

Oil and gas, on the basis of full-cost accounting:

    

Proved properties

     83,390       78,383  

Unproved properties and properties under development, not being amortized

     8,363       8,754  

Gathering, transmission, and processing facilities

     6,995       5,955  

Other

     1,071       1,055  
  

 

 

   

 

 

 
     99,819       94,147  

Less: Accumulated depreciation, depletion, and amortization

     (47,398     (40,867
  

 

 

   

 

 

 
     52,421       53,280  
  

 

 

   

 

 

 

OTHER ASSETS:

    

Goodwill

     1,369       1,289  

Deferred charges and other

     1,481       1,206  
  

 

 

   

 

 

 
   $ 61,637     $ 60,737  
  

 

 

   

 

 

 
LIABILITIES AND EQUITY     

CURRENT LIABILITIES:

    

Accounts payable

   $ 1,616     $ 1,092  

Current debt

     53       990  

Current asset retirement obligation

     121       478  

Derivative instruments

     299       116  

Other current liabilities

     2,611       2,860  
  

 

 

   

 

 

 
     4,700       5,536  
  

 

 

   

 

 

 

LONG-TERM DEBT

     9,672       11,355  
  

 

 

   

 

 

 

DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:

    

Income taxes

     8,364       8,024  

Asset retirement obligation

     3,101       4,100  

Other

     407       391  
  

 

 

   

 

 

 
     11,872       12,515  
  

 

 

   

 

 

 

COMMITMENTS AND CONTINGENCIES (Note 8)

    

EQUITY:

    

Preferred stock, no par value, 10,000,000 shares authorized, 6% Cumulative Mandatory Convertible, Series D, $1,000 per share liquidation preference, 1,265,000 shares converted in 2013, 1,265,000 shares issued and outstanding in 2012

           1,227  

Common stock, $0.625 par, 860,000,000 shares authorized, 408,041,088 and 392,712,245 shares issued, respectively

     255       245  

Paid-in capital

     12,251       9,859  

Retained earnings

     22,032       20,161  

Treasury stock, at cost, 12,268,180 and 1,071,475 shares, respectively

     (1,027     (30

Accumulated other comprehensive loss

     (115     (131
  

 

 

   

 

 

 

APACHE SHAREHOLDERS’ EQUITY

     33,396       31,331  

Noncontrolling interest

     1,997        
  

 

 

   

 

 

 

TOTAL EQUITY

     35,393       31,331  
  

 

 

   

 

 

 
   $ 61,637     $ 60,737  
  

 

 

   

 

 

 

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

 

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Table of Contents

APACHE CORPORATION AND SUBSIDIARIES

STATEMENT OF CONSOLIDATED CHANGES IN EQUITY

 

     Series D
Preferred
Stock
    Common
Stock
     Paid-In
Capital
    Retained
Earnings
    Treasury
Stock
    Accumulated
Other
Comprehensive
(Loss)
    APACHE
SHAREHOLDERS’
EQUITY
    Non
Controlling
Interest
     TOTAL
EQUITY
 
     (In millions)  

BALANCE AT DECEMBER 31, 2010

   $ 1,227     $ 240      $ 8,864     $ 14,223     $ (36   $ (141   $ 24,377     $       $ 24,377  

Net income

                           4,584                     4,584               4,584  

Postretirement, net of tax of $7

                                         (1     (1             (1

Commodity hedges, net of tax of $66

                                         133       133               133  

Dividends:

                    

Preferred

                           (76                   (76             (76

Common ($0.60 per share)

                           (231                   (231             (231

Common stock activity, net

            1        35                            36               36  

Treasury stock activity, net

                    2              4              6               6  

Compensation expense

                    167                            167               167  

Other

                    (2                          (2             (2
  

 

 

   

 

 

    

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

BALANCE AT DECEMBER 31, 2011

   $ 1,227     $ 241      $ 9,066     $ 18,500     $ (32   $ (9   $ 28,993     $  —       $ 28,993  

Net income

                           2,001                     2,001               2,001  

Postretirement, net of tax of $5

                                         (2     (2             (2

Commodity hedges, net of tax of $35

                                         (120     (120             (120

Dividends:

                    

Preferred

                           (76                   (76             (76

Common ($0.68 per share)

                           (264                   (264             (264

Common shares issued

            3        598                            601               601  

Common stock activity, net

            1        (44                          (43             (43

Treasury stock activity, net

                    1              2              3               3  

Compensation expense

                    238                            238               238  
  

 

 

   

 

 

    

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

BALANCE AT DECEMBER 31, 2012

   $ 1,227     $ 245      $ 9,859     $ 20,161     $ (30   $ (131   $ 31,331     $  —       $ 31,331  

Net income

                           2,232                     2,232       56        2,288  

Postretirement, net of tax of $9

                                         9       9               9  

Commodity hedges, net of tax of $4

                                         7       7               7  

Dividends:

                    

Preferred

                           (44                   (44             (44

Common ($0.80 per share)

                           (317                   (317             (317

Common stock activity, net

            1        (22                          (21             (21

Treasury stock activity, net

                                  (997            (997             (997

Sale of noncontrolling interest

                    1,007                            1,007       1,941        2,948  

Conversion of Series D preferred stock

     (1,227     9        1,218                                             

Compensation expense

                    189                            189               189  
  

 

 

   

 

 

    

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

BALANCE AT DECEMBER 31, 2013

   $  —      $ 255      $ 12,251     $ 22,032     $ (1,027   $ (115   $ 33,396     $ 1,997      $ 35,393  
  

 

 

   

 

 

    

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

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

 

F-8


Table of Contents

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Nature of Operations

Apache Corporation (Apache or the Company) is an independent energy company that explores for, develops, and produces natural gas, crude oil, and natural gas liquids. The Company has exploration and production interests in six countries: the United States (U.S.), Canada, Egypt, Australia, the United Kingdom (U.K.) North Sea (North Sea), and Argentina. Apache also pursues exploration interests in other countries that may over time result in reportable discoveries and development opportunities.

1.    SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Accounting policies used by Apache and its subsidiaries reflect industry practices and conform to accounting principles generally accepted in the U.S. (GAAP). The Company’s financial statements for prior periods may include reclassifications that were made to conform to the current-year presentation. Significant policies are discussed below.

Principles of Consolidation

The accompanying consolidated financial statements include the accounts of Apache and its subsidiaries after elimination of intercompany balances and transactions. The Company’s undivided interests in oil and gas exploration and production ventures and partnerships are proportionately consolidated. The Company consolidates all other investments in which, either through direct or indirect ownership, Apache has more than a 50 percent voting interest or controls the financial and operating decisions. Noncontrolling interests represent third-party ownership in the net assets of a consolidated Apache subsidiary and are reflected separately in the Company’s financial statements. For further information, please refer to Note 2 — Acquisitions and Divestitures. Investments in which Apache holds less than 50 percent of the voting interest are typically accounted for under the equity method of accounting, with the balance recorded as a component of “Deferred charges and other” in Apache’s consolidated balance sheet and results of operations recorded as a component of “Other” under “Revenues and Other” in the Company’s statement of consolidated operations.

Use of Estimates

Preparation of financial statements in conformity with GAAP and disclosure of contingent assets and liabilities requires management to make estimates and assumptions that affect reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Company bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about carrying values of assets and liabilities that are not readily apparent from other sources. Apache evaluates its estimates and assumptions on a regular basis. Actual results may differ from these estimates and assumptions used in preparation of its financial statements and changes in these estimates are recorded when known. Significant estimates with regard to these financial statements include the fair value determination of acquired assets and liabilities (see Note 2 — Acquisitions and Divestitures), the estimate of proved oil and gas reserves and related present value estimates of future net cash flows therefrom (see Note 14 — Supplemental Oil and Gas Disclosures), the assessment of asset retirement obligations (see Note 5 — Asset Retirement Obligation), and the estimate of income taxes (see Note 7 — Income Taxes).

Fair Value Measurements

Certain assets and liabilities are reported at fair value on a recurring basis in Apache’s consolidated balance sheet. Accounting Standards Codification (ASC) 820-10-35 provides a hierarchy that prioritizes and defines the types of inputs used to measure fair value. The fair value hierarchy gives the highest priority to Level 1 inputs,

 

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Table of Contents

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

 

which consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived from inputs that are significant and unobservable; hence, these valuations have the lowest priority.

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

Fair value measurements are presented in further detail in Note 3 — Derivative Instruments and Hedging Activities, Note 6 — Debt, and Note 9 — Retirement and Deferred Compensation Plans.

Cash Equivalents

The Company considers all highly liquid short-term investments with a maturity of three months or less at the time of purchase to be cash equivalents. These investments are carried at cost, which approximates fair value. As of December 31, 2013 and 2012, Apache had $1.9 billion and $160 million, respectively, of cash and cash equivalents.

Accounts Receivable and Allowance for Doubtful Accounts

Accounts receivable are stated at the historical carrying amount net of write-offs and an allowance for uncollectible accounts. The carrying amount of Apache’s accounts receivable approximates fair value because of the short-term nature of the instruments. The Company routinely assesses the collectability of all material trade and other receivables. Many of Apache’s receivables are from joint interest owners on properties Apache operates. The Company may have the ability to withhold future revenue disbursements to recover any non-payment of these joint interest billings. The Company accrues a reserve on a receivable when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of any reserve may be reasonably estimated. As of December 31, 2013 and 2012, the Company had an allowance for doubtful accounts of $96 million and $82 million, respectively.

Inventories

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

Property and Equipment

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

Oil and Gas Property

The Company follows the full-cost method of accounting for its oil and gas property. Under this method of accounting, all costs incurred for both successful and unsuccessful exploration and development activities, including salaries, benefits, and other internal costs directly identified with these activities, and oil and gas

 

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Table of Contents

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

 

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

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

The cost of unproved properties and properties under development are excluded from the amortization calculation until it is determined whether or not proved reserves can be assigned to such properties or until development projects are placed in service. Geological and geophysical costs not associated with specific prospects are recorded to proved property immediately. Unproved properties and properties under development are reviewed for impairment at least quarterly. In countries where proved reserves exist, exploratory drilling costs associated with dry holes are transferred to proved properties immediately upon determination that a well is dry and amortized accordingly. In countries where a reserve base has not yet been established, impairments are charged to earnings and are determined through an evaluation considering, among other factors, seismic data, requirements to relinquish acreage, drilling results, remaining time in the commitment period, remaining capital plan, and political, economic, and market conditions. In 2013, Apache’s statement of consolidated operations includes additional DD&A of $75 million related to exiting operations in Kenya. In 2012, Apache recorded additional DD&A of $28 million related to exiting operations in New Zealand and $15 million of seismic costs incurred in countries where it has no established presence. In 2011, Apache recorded additional DD&A of $60 million related to exiting operations in Chile and $49 million of seismic costs incurred in countries where it has no established presence.

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

Any excess of the net book value of proved oil and gas properties, less related deferred income taxes, over the ceiling is charged to expense and reflected as additional DD&A in the accompanying statement of consolidated operations. Such limitations are imposed separately on a country-by-country basis and are tested quarterly. During 2013, Apache recorded non-cash write-downs of the carrying value of the Company’s proved oil and gas properties totaling $1.1 billion. The after-tax impact of these write-downs was $356 million in the U.S., $139 million in the North Sea, and $118 million in Argentina. Cash flow hedges did not materially affect the 2013 calculations. During 2012, the Company recorded a $1.9 billion ($1.4 billion net of tax) non-cash write-down of the carrying value of the Company’s Canadian proved oil and gas properties. Excluding the effects of cash flow hedges in calculating the ceiling limitation, the write-down for the full year would have been higher by $135 million ($101 million net of tax).

Proceeds from the sale or disposition of oil and gas properties are accounted for as a reduction to capitalized costs unless a significant portion (greater than 25 percent) of the Company’s reserve quantities in a particular country are sold, in which case a gain or loss is recognized in income. No gain or loss was recorded on the Company’s divestitures in 2013, 2012, or 2011.

 

F-11


Table of Contents

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

 

Gathering, Transmission, and Processing Facilities

Gathering, transmission, and processing facilities totaled $7.0 billion and $6.0 billion at December 31, 2013 and 2012, respectively. The Company assesses the carrying amount of its gathering, transmission, and processing facilities whenever events or changes in circumstances indicate that their carrying amount may not be recoverable. If the carrying amount of these facilities is less than the sum of the undiscounted cash flows, an impairment loss is recognized for the excess of the carrying value over its fair value. No impairment of gathering, transmission, and processing facilities was recognized during 2013, 2012, or 2011.

Gathering, transmission, and processing facilities, buildings, and equipment are depreciated on a straight-line basis over the estimated useful lives of the assets, which range from three to 25 years. Accumulated depreciation for these assets totaled $2.1 billion and $1.9 billion at December 31, 2013 and 2012, respectively.

Asset Retirement Costs and Obligations

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

Goodwill

Goodwill represents the excess of the purchase price of an entity over the estimated fair value of the assets acquired and liabilities assumed. The Company assesses the carrying amount of goodwill by testing for impairment annually and when impairment indicators arise. Goodwill totaled $1.4 billion and $1.3 billion at December 31, 2013 and 2012, respectively. As of December 31, 2013 and 2012, goodwill of $163 million and $84 million, respectively, was recorded in the North Sea. As of December 31, 2013 and 2012, goodwill of $1.0 billion, $103 million, and $86 million was recorded in the U.S., Canada, and Egypt, respectively. Each country was assessed as a reporting unit, and no impairment of goodwill was recognized during 2013, 2012, or 2011.

Accounts Payable

Included in accounts payable at December 31, 2013 and 2012, are liabilities of approximately $271 million and $255 million, respectively, representing the amount by which checks issued but not presented to the Company’s banks for collection exceeded balances in applicable bank accounts.

Commitments and Contingencies

Accruals for loss contingencies arising from claims, assessments, litigation, environmental and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. These accruals are adjusted as additional information becomes available or circumstances change.

Revenue Recognition and Imbalances

Oil and gas revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collectability of the revenue is probable. Cash received relating to future revenues is deferred and recognized when all revenue recognition criteria are met.

 

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Table of Contents

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

 

Apache uses the sales method of accounting for gas production imbalances. The volumes of gas sold may differ from the volumes to which Apache is entitled based on its interests in the properties. These differences create imbalances that are recognized as a liability only when the properties’ estimated remaining reserves net to Apache will not be sufficient to enable the under-produced owner to recoup its entitled share through production. The Company’s recorded liability is generally reflected in other non-current liabilities. No receivables are recorded for those wells where Apache has taken less than its share of production. Gas imbalances are reflected as adjustments to estimates of proved gas reserves and future cash flows in the unaudited supplemental oil and gas disclosures.

Apache markets its own U.S. natural gas production. Since the Company’s production fluctuates because of operational issues, it is occasionally necessary to purchase third-party gas to fulfill sales obligations and commitments. Both the costs and sales proceeds of this third-party gas are reported on a net basis in oil and gas production revenues. The costs of third-party gas netted against the related sales proceeds totaled $34 million, $27 million, and $28 million, for 2013, 2012, and 2011, respectively.

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

Derivative Instruments and Hedging Activities

Apache periodically enters into derivative contracts to manage its exposure to commodity price risk. These derivative contracts, which are generally placed with major financial institutions, may take the form of forward contracts, futures contracts, swaps, or options. The oil and gas reference prices upon which the commodity derivative contracts are based reflect various market indices that have a high degree of historical correlation with actual prices received by the Company for its oil and gas production.

Apache records all derivative instruments, other than those that meet the normal purchases and sales exception, on the balance sheet as either an asset or liability measured at fair value. Changes in fair value are recognized currently in earnings unless specific hedge accounting criteria are met. Gains and losses from the change in fair value of derivative instruments that do not qualify for hedge accounting are reported in current-period income as “Derivative instrument gains (losses), net” under “Revenues and Other” in the statement of consolidated operations. Hedge accounting treatment allows unrealized gains and losses on cash flow hedges to be deferred in other comprehensive income. Realized gains and losses from the Company’s oil and gas cash flow hedges, including terminated contracts, are generally recognized in oil and gas production revenues when the forecasted transaction occurs. If at any time the likelihood of occurrence of a hedged forecasted transaction ceases to be “probable,” hedge accounting treatment will cease on a prospective basis, and all future changes in the fair value of the derivative will be recognized directly in earnings. Amounts recorded in other comprehensive income prior to the change in the likelihood of occurrence of the forecasted transaction will remain in other comprehensive income until such time as the forecasted transaction impacts earnings. If it becomes probable that the original forecasted production will not occur, then the derivative gain or loss would be reclassified from accumulated other comprehensive income into earnings immediately. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time, and any ineffectiveness is immediately reported as “Other” under “Revenues and Other” in the statement of consolidated operations.

 

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Table of Contents

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

 

General and Administrative Expense

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

Income Taxes

Apache records deferred tax assets and liabilities to account for the expected future tax consequences of events that have been recognized in the financial statements and tax returns. The Company routinely assesses the realizability of its deferred tax assets. If the Company concludes that it is more likely than not that some or all of the deferred tax assets will not be realized, the tax asset is reduced by a valuation allowance. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and gas prices) and changing tax laws.

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

Foreign Currency Transaction Gains and Losses

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

Foreign currency transaction gains and losses related to current taxes payable and deferred tax assets and liabilities are recorded as components of the provision for income taxes. In 2013, Apache recorded a tax benefit of $154 million, including current and deferred taxes. In 2012 and 2011, the Company recorded tax expense of $16 million and a tax benefit of $66 million, respectively. For further discussion, please refer to Note 7 — Income Taxes. All other foreign currency transaction gains and losses are reflected in “Other” under Revenues and Other in the statement of consolidated operations. The Company’s other foreign currency gains and losses netted to a loss in 2013 of $30 million and gains in 2012 and 2011 of $24 million and $4 million, respectively.

Insurance Coverage

The Company recognizes an insurance receivable when collection of the receivable is deemed probable. Any recognition of an insurance receivable is recorded by crediting and offsetting the original charge. Any differential arising between insurance recoveries and insurance receivables is recorded as a capitalized cost or as an expense, consistent with its original treatment.

Earnings Per Share

The Company’s basic earnings per share (EPS) amounts have been computed based on the weighted-average number of shares of common stock outstanding for the period. Diluted EPS reflects the potential dilution, using the treasury stock method, which assumes that options were exercised and restricted stock was

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

 

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

Stock-Based Compensation

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

ASC Topic 718 also requires that benefits of tax deductions in excess of recognized compensation cost be reported as financing cash flows rather than as operating cash flows. The Company classified $1 million, $4 million, and $32 million as financing cash inflows in 2013, 2012, and 2011, respectively.

Treasury Stock

The Company follows the weighted-average-cost method of accounting for treasury stock transactions.

New Pronouncements Issued But Not Yet Adopted

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

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

2.     ACQUISITIONS AND DIVESTITURES

2014 Activity

Argentina Divestiture

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

 

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

 

2013 Activity

Egypt Partnership

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

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

Gulf of Mexico Shelf Divestiture

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

Canada LNG Project

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

Other Activity

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

2012 Activity

Cordillera Energy Partners III, LLC Acquisition

On April 30, 2012, Apache completed the acquisition of Cordillera Energy Partners III, LLC (Cordillera), a privately-held exploration and production company, in a stock and cash transaction. Cordillera’s properties included approximately 312,000 net acres in the Granite Wash, Tonkawa, Cleveland, and Marmaton plays in western Oklahoma and the Texas Panhandle.

Apache issued 6,272,667 shares of common stock and paid approximately $2.7 billion of cash to the sellers as consideration for the transaction. The transaction was accounted for using the acquisition method of

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

 

accounting, which requires, among other things, that assets acquired and liabilities assumed be recognized at their fair values as of the acquisition date. The following table summarizes the final estimates of the assets acquired and liabilities assumed in the acquisition.

 

     (In millions)  

Current assets

   $ 39  

Proved properties

     1,040  

Unproved properties

     2,299  

Gathering, transmission, and processing facilities

     1  

Goodwill(1)

     173  

Deferred tax asset

     64  
  

 

 

 

Total assets acquired

   $ 3,616  
  

 

 

 

Current liabilities

     88  

Deferred income tax liabilities

     237  

Other long-term obligations

     5  
  

 

 

 

Total liabilities assumed

   $ 330  
  

 

 

 

Net assets acquired

   $ 3,286  
  

 

 

 

 

 

(1)

Goodwill was the excess of the consideration transferred over the net assets recognized and represents the future economic benefits arising from assets acquired that could not be individually identified and separately recognized. Goodwill is not deductible for tax purposes.

Yara Pilbara Holdings Pty Limited Acquisition

On January 31, 2012, a subsidiary of Apache Energy Limited completed the acquisition of a 49 percent interest in Yara Pilbara Holdings Pty Limited (YPHPL, formerly Burrup Holdings Limited) for $439 million, including working capital adjustments. The transaction was funded with debt. Yara Australia Pty Ltd (Yara) owns the remaining 51 percent of YPHPL and operates the plant. The investment in YPHPL is accounted for under the equity method of accounting, with the balance recorded as a component of “Deferred charges and other” in Apache’s consolidated balance sheet and results of operations recorded as a component of “Other” under “Revenues and other” in the Company’s statement of consolidated operations.

2011 Activity

Mobil North Sea Limited Acquisition

On December 30, 2011, Apache completed the acquisition of Mobil North Sea Limited (Mobil North Sea). The assets acquired include: operated interests in the Beryl, Nevis, Nevis South, Skene, and Buckland fields; operated interest in the Beryl/Brae gas pipeline and the SAGE gas plant; non-operated interests in the Maclure, Scott, and Telford fields; and Benbecula (west of Shetlands) exploration acreage. This acquisition was funded with existing cash on hand.

 

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

 

The transaction was accounted for using the acquisition method of accounting. The following table summarizes the final estimates of the assets acquired and liabilities assumed in the acquisition.

 

     (In millions)  

Current assets

   $ 219  

Proved properties

     2,341  

Unproved properties

     476  

Gathering, transmission, and processing facilities

     338  

Goodwill(1)

     84  
  

 

 

 

Total assets acquired

   $ 3,458  
  

 

 

 

Current liabilities

     148  

Asset retirement obligation

     517  

Deferred income tax liabilities

     1,546  

Other long-term obligations

     1  
  

 

 

 

Total liabilities assumed

   $ 2,212  
  

 

 

 

Net assets acquired

   $ 1,246  
  

 

 

 

 

(1)

Goodwill was the excess of the consideration transferred over the net assets recognized and represents the future economic benefits arising from assets acquired that could not be individually identified and separately recognized. Goodwill is not deductible for tax purposes.

Acquisitions, Divestitures, and Transition Expenses

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

3.     DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

Objectives and Strategies

The Company is exposed to fluctuations in crude oil and natural gas prices on the majority of its worldwide production. Apache manages the variability in its cash flows by occasionally entering into derivative transactions on a portion of its crude oil and natural gas production. The Company utilizes various types of derivative financial instruments, including swaps and options, to manage fluctuations in cash flows resulting from changes in commodity prices.

Counterparty Risk

The use of derivative instruments exposes the Company to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments. To reduce the concentration of exposure to any individual counterparty, Apache utilizes a diversified group of investment-grade rated counterparties, primarily financial institutions, for its derivative transactions. As of December 31, 2013, Apache had derivative positions with 14 counterparties. The Company monitors counterparty creditworthiness on an ongoing basis; however, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, Apache may not realize the benefit of some of its derivative instruments resulting from lower commodity prices.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

 

The Company executes commodity derivative transactions under master agreements that have netting provisions that provide for offsetting payables against receivables. In general, if a party to a derivative transaction incurs a material deterioration in its credit ratings, as defined in the applicable agreement, the other party has the right to demand the posting of collateral, demand a transfer, or terminate the arrangement. The Company’s net derivative liability position at December 31, 2013, represents the aggregate fair value of all derivative instruments with credit-risk-related contingent features that are in a net liability position. The Company has not provided any collateral to any of its counterparties as of December 31, 2013.

Derivative Instruments

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

 

          Fixed-Price Swaps  

Production Period

  

Settlement Index

   Mbbls      Weighted
Average
Fixed Price
 

2014

  

NYMEX WTI

     22,889      $ 90.77  

2014

  

Dated Brent

     22,812        100.05  

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

 

          Fixed-Price Swaps  

Production Period

  

Settlement Index

   MMBtu
(in 000’s)
     Weighted
Average
Fixed Price
 

2014

  

NYMEX Henry Hub

     1,295      $ 6.72  

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

Fair Value Measurements

Apache’s commodity derivative instruments consist of variable-to-fixed price commodity swaps and options. The fair values of the Company’s derivative instruments are not actively quoted in the open market. The Company uses a market approach to estimate the fair values of its derivative instruments, utilizing commodity futures price strips for the underlying commodities provided by a reputable third party. These valuations are Level 2 inputs.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

 

The following table presents the Company’s derivative assets and liabilities measured at fair value on a recurring basis:

 

     Fair Value Measurements Using                      
     Quoted Price
in Active
Markets
(Level 1)
     Significant
Other
Inputs
(Level 2)
     Significant
Unobservable
Inputs
(Level 3)
     Total
Fair
Value
     Netting(1)     Carrying
Amount
 
     (In millions)        

December 31, 2013

                

Assets:

                

Derivatives designated as cash flow hedges

   $   —      $ 3      $   —      $ 3      $ (2   $ 1  

Liabilities:

                

Derivatives designated as cash flow hedges

   $      $ 1      $      $ 1       

Derivatives not designated as cash flow hedges

             300                300       
  

 

 

    

 

 

    

 

 

    

 

 

      

Total Derivative liabilities

   $      $ 301      $      $ 301      $ (2   $ 299  

December 31, 2012

                

Assets:

                

Derivatives designated as cash flow hedges

   $      $ 48      $      $ 48      $ (15   $ 33  

Liabilities:

                

Derivatives designated as cash flow hedges

   $      $ 51      $      $ 51       

Derivatives not designated as cash flow hedges

             80                80       
  

 

 

    

 

 

    

 

 

    

 

 

      

Total Derivative liabilities

   $      $ 131      $      $ 131      $ (15   $ 116  

 

(1)

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

All derivative instruments are reflected as either assets or liabilities at fair value in the consolidated balance sheet. These fair values are recorded by netting asset and liability positions where counterparty master netting arrangements contain provisions for net settlement. The fair market value of the Company’s derivative assets and liabilities and their locations on the consolidated balance sheet are as follows:

 

     December 31,
2013
     December 31,
2012
 
     (In millions)  

Current Assets: Derivative instruments

   $ 1      $ 31  

Other Assets: Deferred charges and other

             2  
  

 

 

    

 

 

 

Total Assets

   $ 1      $ 33  
  

 

 

    

 

 

 

Current Liabilities: Derivative instruments

   $ 299      $ 116  
  

 

 

    

 

 

 

Total Liabilities

   $ 299      $ 116  
  

 

 

    

 

 

 

 

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

 

Derivative Activity Recorded in Statement of Consolidated Operations

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

 

     Gain (Loss) on Derivatives   For the Year Ended December 31,  
    

Recognized in Income

    2013         2012         2011    
         (In millions)  

Gain (loss) on cash flow hedges reclassified from accumulated other comprehensive loss

  

Oil and Gas Production Revenues

  $ (16   $ 268     $ (13

Gain (loss) for ineffectiveness on cash flow hedges

  

Revenues and Other: Other

  $ (1   $     $ 2  

Loss on derivatives not designated as cash flow hedges

  

Derivative instrument gains (losses), net

  $ (399   $ (79   $  

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

Derivative Activity in Accumulated Other Comprehensive Income (Loss)

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

 

     For the Year Ended December 31,  
     2013     2012     2011  
     Before     After     Before     After     Before     After  
     tax     tax     tax     tax     tax     tax  
     (In millions)  

Unrealized gain (loss) on derivatives at beginning of year

   $ (10   $ (6   $ 145     $ 114     $ (54   $ (19

Realized amounts reclassified into earnings

     16       11       (268     (199     13       19  

Net change in derivative fair value

     (6     (5     113       79       188       115  

Ineffectiveness reclassified into earnings

     1       1                   (2     (1
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Unrealized gain (loss) on derivatives at end of period

   $ 1     $ 1     $ (10   $ (6   $ 145     $ 114  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

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

 

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

 

4.     OTHER CURRENT LIABILITIES

The following table provides detail of the Company’s other current liabilities at December 31, 2013 and 2012:

 

     December 31,      December 31,  
     2013      2012  
     (In millions)  

Accrued operating expenses

   $ 190      $ 211  

Accrued exploration and development

     1,582        1,792  

Accrued compensation and benefits

     242        198  

Accrued interest

     161        160  

Accrued income taxes

     248        297  

Accrued U.K. Petroleum Revenue Tax

     9        53  

Other

     179        149  
  

 

 

    

 

 

 

Total Other current liabilities

   $ 2,611      $ 2,860  
  

 

 

    

 

 

 

5.     ASSET RETIREMENT OBLIGATION

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

 

     2013     2012  
     (In millions)  

Asset retirement obligation at beginning of year

   $ 4,578     $ 3,887  

Liabilities incurred

     481       592  

Liabilities acquired

     53       72  

Liabilities divested

     (1,692      

Liabilities settled

     (497     (550

Accretion expense

     243       232  

Revisions in estimated liabilities

     56       345  
  

 

 

   

 

 

 

Asset retirement obligation at end of year

     3,222       4,578  

Less current portion

     (121     (478
  

 

 

   

 

 

 

Asset retirement obligation, long-term

   $ 3,101     $ 4,100  
  

 

 

   

 

 

 

The ARO liability reflects the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with Apache’s oil and gas properties. The Company utilizes current retirement costs to estimate the expected cash outflows for retirement obligations. The Company estimates the ultimate productive life of the properties, a risk-adjusted discount rate, and an inflation factor in order to determine the current present value of this obligation. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property balance.

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

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

 

6.     DEBT

Overview

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

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

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

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

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

 

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

 

The following table presents the carrying value of the Company’s debt at December 31, 2013 and 2012:

 

     December 31,  
     2013     2012  
     (In millions)  

U.S.:

    

Money market lines of credit

   $     $ 13  

Commercial paper

           489  

5.25% notes due 2013(1)

           500  

6.0% notes due 2013(1)

           400  

5.625% notes due 2017(1)

     500       500  

1.75% notes due 2017(1)

     400       400  

6.9% notes due 2018(1)

     400       400  

7.0% notes due 2018

     150       150  

7.625% notes due 2019

     150       150  

3.625% notes due 2021(1)

     500       500  

3.25% notes due 2022(1)

     919       1,100  

2.625% notes due 2023(1)

     531       1,200  

7.7% notes due 2026

     100       100  

7.95% notes due 2026

     180       180  

6.0% notes due 2037(1)

     1,000       1,000  

5.1% notes due 2040(1)

     1,500       1,500  

5.25% notes due 2042(1)

     500       500  

4.75% notes due 2043(1)

     1,500       1,500  

4.25% notes due 2044(1)

     800       800  

7.375% debentures due 2047

     150       150  

7.625% debentures due 2096

     150       150  
  

 

 

   

 

 

 
     9,430       11,682  
  

 

 

   

 

 

 

Subsidiary and other obligations:

    

Argentina overdraft lines of credit

     51       69  

Canada lines of credit

     2       9  

Apache Finance Canada 4.375% notes due 2015(1)

           350  

Notes due in 2016 and 2017

     1       1  

Apache Finance Canada 7.75% notes due 2029

     300       300  
  

 

 

   

 

 

 
     354       729  
  

 

 

   

 

 

 

Debt before unamortized discount

     9,784       12,411  

Unamortized discount

     (59     (66
  

 

 

   

 

 

 

Total debt

   $ 9,725     $ 12,345  
  

 

 

   

 

 

 

Current maturities

   $ (53   $ (990
  

 

 

   

 

 

 

Long-term debt

   $ 9,672     $ 11,355  
  

 

 

   

 

 

 

 

 

(1)

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

 

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

 

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

 

     (In millions)  

2014

   $ 53  

2015

      

2016

     1  

2017

     900  

2018

     550  

Thereafter

     8,280  
  

 

 

 

Total Debt, excluding discounts

   $ 9,784  
  

 

 

 

Fair Value

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

 

     December 31, 2013      December 31, 2012  
     Carrying
Amount
     Fair
Value
     Carrying
Amount
     Fair
Value
 
     (In millions)  

Money market lines of credit

   $ 53      $ 53      $ 91      $ 91  

Commercial paper

                   489        489  

Notes and debentures

     9,672        10,247        11,765        13,340  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total Debt

   $ 9,725      $ 10,300      $ 12,345      $ 13,920  
  

 

 

    

 

 

    

 

 

    

 

 

 

Money Market and Overdraft Lines of Credit

The Company has certain uncommitted money market and overdraft lines of credit that are used from time to time for working capital purposes. As of December 31, 2013, a total of $53 million was drawn on facilities in Argentina and Canada. As of December 31, 2012, a total of $91 million was drawn on facilities in the U.S., Argentina, and Canada.

Unsecured Committed Bank Credit Facilities

As of December 31, 2013, the Company had unsecured committed revolving syndicated bank credit facilities totaling $3.3 billion, of which $1.0 billion matures in August 2016 and $2.3 billion matures in June 2017. The facilities consist of a $1.7 billion facility and a $1.0 billion facility for the U.S., a $300 million facility in Australia, and a $300 million facility in Canada. In July 2013, we amended our $1.0 billion U.S. credit facility to conform certain representations, covenants, and events of default to those in our $1.7 billion U.S. credit facility. The amendments did not affect the amount or repayment terms of the $1.0 billion U.S. facility. As of December 31, 2013, aggregate available borrowing capacity under the Company’s credit facilities was $3.3 billion. The committed credit facilities are used to support Apache’s commercial paper program.

At the Company’s option, the interest rate for the facilities is based on a base rate, as defined, or the London Inter-bank Offered Rate (LIBOR) plus a margin determined by the Company’s senior long-term debt rating. The $1.7 billion credit facility also allows the Company to borrow under competitive auctions.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

 

At December 31, 2013, the margin over LIBOR for committed loans was 0.875 percent on the $1.0 billion U.S. credit facility and 0.90 percent on each of the $1.7 billion U.S. credit facility, the $300 million Australian credit facility, and the $300 million Canadian credit facility. The Company also pays quarterly facility fees of 0.125 percent on the total amount of the $1.0 billion U.S. facility and 0.10 percent on the total amount of the other three facilities. The facility fees vary based upon the Company’s senior long-term debt rating.

The financial covenants of the credit facilities require the Company to maintain a debt-to-capitalization ratio of not greater than 60 percent at the end of any fiscal quarter. At December 31, 2013, the Company’s debt-to-capitalization ratio was 22 percent.

The negative covenants include restrictions on the Company’s ability to create liens and security interests on its assets, with exceptions for liens typically arising in the oil and gas industry, purchase money liens, and liens arising as a matter of law, such as tax and mechanics’ liens. The Company may incur liens on assets located in the U.S. and Canada of up to 5 percent of the Company’s consolidated assets, or approximately $3.1 billion as of December 31, 2013. There are no restrictions on incurring liens in countries other than the U.S. and Canada. There are also restrictions on Apache’s ability to merge with another entity, unless the Company is the surviving entity, and a restriction on its ability to guarantee debt of entities not within its consolidated group.

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

The Company was in compliance with the terms of the credit facilities as of December 31, 2013.

Commercial Paper Program

The Company has available a $3.0 billion commercial paper program, which generally enables Apache to borrow funds for up to 270 days at competitive interest rates. The commercial paper program is fully supported by available borrowing capacity under committed credit facilities. Our 2013 weighted-average interest rate for commercial paper was 0.38 percent. If the Company is unable to issue commercial paper following a significant credit downgrade or dislocation in the market, the Company’s committed credit facilities, which expire in 2016 and 2017, are available as a 100 percent backstop. The Company used proceeds from divestitures to repay commercial paper and at year end had no outstanding balance. At December 31, 2012, the Company had $489 million in commercial paper outstanding.

Subsidiary Notes – Apache Finance Canada

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

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

 

Financing Costs, Net

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

 

     For the Year Ended December 31,  
       2013         2012         2011    
     (In millions)  

Interest expense

   $ 571     $ 509     $ 433  

Amortization of deferred loan costs

     8       7       5  

Capitalized interest

     (374     (334     (263

Gain on extinguishment of debt

     (16            

Interest income

     (15     (17     (17
  

 

 

   

 

 

   

 

 

 

Financing costs, net

   $ 174     $ 165     $ 158  
  

 

 

   

 

 

   

 

 

 

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

As of December 31, 2013 and 2012, the Company had approximately $73 million and $70 million, respectively, of unamortized deferred loan costs associated with its various debt obligations. These costs are included in deferred charges and other in the accompanying consolidated balance sheet and are being charged to financing costs and expensed over the life of the related debt issuances.

7.     INCOME TAXES

Income before income taxes is composed of the following:

 

     For the Year Ended December 31,  
         2013              2012              2011      
     (In millions)  

U.S.

   $ 1,191      $ 1,605      $ 2,373  

Foreign

     3,025        3,272        5,720  
  

 

 

    

 

 

    

 

 

 

Total

   $ 4,216      $ 4,877      $ 8,093  
  

 

 

    

 

 

    

 

 

 

The total provision for income taxes consists of the following:

 

     For the Year Ended December 31,  
         2013             2012             2011      
     (In millions)  

Current taxes:

      

Federal

   $ (29   $ (150   $ 64  

State

                 2  

Foreign

     1,694       2,349       2,197  
  

 

 

   

 

 

   

 

 

 
     1,665       2,199       2,263  
  

 

 

   

 

 

   

 

 

 

Deferred taxes:

      

Federal

     509       596       656  

State

     44       10       17  

Foreign

     (290     71       573  
  

 

 

   

 

 

   

 

 

 
     263       677       1,246  
  

 

 

   

 

 

   

 

 

 

Total

   $ 1,928     $ 2,876     $ 3,509  
  

 

 

   

 

 

   

 

 

 

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

 

A reconciliation of the tax on the Company’s income before income taxes and total tax expense is shown below:

 

     For the Year Ended December 31,  
         2013             2012             2011      
     (In millions)  

Income tax expense at U.S. statutory rate

   $ 1,476     $ 1,707     $ 2,833  

State income tax, less federal benefit

     29       6       12  

Taxes related to foreign operations

     200       773       568  

Tax credits

     6       (4     (15

Deferred tax on distributed foreign earnings

     225              

Current and deferred taxes related to currency fluctuations

     (154     16       (66

Change in U.K. tax rate

           118       218  

Net change in tax contingencies

     (10     (115     (6

Valuation allowances

     199       355       8  

All other, net

     (43     20       (43
  

 

 

   

 

 

   

 

 

 
   $ 1,928     $ 2,876     $ 3,509  
  

 

 

   

 

 

   

 

 

 

The net deferred tax liability consists of the following:

 

     December 31,  
     2013     2012  
     (In millions)  

Deferred tax assets:

    

Deferred income

   $ 153     $ 33  

Federal and state net operating loss carryforwards

     900       932  

Foreign net operating loss carryforwards

     156       61  

Tax credits

     66       78  

Accrued expenses and liabilities

     162       2  

Asset retirement obligation

     1,231       1,677  
  

 

 

   

 

 

 

Total deferred tax assets

     2,668       2,783  

Valuation allowance

     (651     (419
  

 

 

   

 

 

 

Net deferred tax assets

     2,017       2,364  
  

 

 

   

 

 

 

Deferred tax liabilities:

    

Other

     29       23  

Depreciation, depletion and amortization

     10,224       10,213  
  

 

 

   

 

 

 

Total deferred tax liabilities

     10,253       10,236  
  

 

 

   

 

 

 

Net deferred income tax liability

   $ 8,236     $ 7,872  
  

 

 

   

 

 

 

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

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

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

 

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

The Company considers the undistributed earnings of its foreign subsidiaries to be permanently reinvested, as it has no current intention to repatriate these earnings. As such, deferred income taxes are not provided for temporary differences of approximately $17 billion at December 31, 2013, representing unremitted earnings of subsidiaries outside the United States intended to be permanently reinvested. Upon an actual or deemed distribution of these earnings in the form of dividends or otherwise, the Company may be subject to U.S. income taxes and foreign withholding taxes. It is not practicable, however, to estimate the amount of taxes that may be payable on the eventual remittance of these earnings after consideration of available foreign tax credits. Presently, limited foreign tax credits are available to reduce the U.S. taxes on such amounts if repatriated.

On December 31, 2013, the Company had net operating losses as follows:

 

     December 31, 2013  
     Amount      Expiration  
     (In millions)         

Net operating losses:

     

U.S. — Federal

   $ 1,558        2032 - 2034   

U.S. — Federal (Mariner IRC §382 limited)

     520        2018 - 2030   

U.S. — Federal (Cordillera IRC §382 limited)

     183        2026 - 2032   

U.S. — State

     2,242        Various   

Canada

     5        2014  

Australia

     59        Indefinite   

Argentina

     299        2014  

The Company has a federal net operating loss carryforward of $2.3 billion. Included in the federal net operating loss carryforward is $520 million of federal net operating losses related to the 2010 merger with Mariner and $183 million of federal net operating losses related to the Cordillera acquisition. The Mariner and Cordillera net operating loss carryforwards are subject to annual limitations under Section 382 of the Internal Revenue Code. The Company also has $186 million of capital loss carryforwards in Canada, which have an indefinite carryover period.

The tax benefits of carryforwards are recorded as assets to the extent that management assesses the utilization of such carryforwards to be “more likely than not.” When the future utilization of some portion of the carryforwards is determined to not meet the “more likely than not” standard, a valuation allowance is provided to reduce the tax benefits from such assets. As discussed above, the Company does not believe the utilization of the Argentine net operating losses, Canadian capital losses, and certain state net operating losses to be “more likely than not.” As such, a valuation allowance was provided against these deferred tax assets.

 

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The Company accounts for income taxes in accordance with ASC Topic 740, “Income Taxes,” which prescribes a minimum recognition threshold a tax position must meet before being recognized in the financial statements. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:

 

     2013      2012     2011  
     (In millions)  

Balance at beginning of year

   $ 3      $ 97     $ 110  

Additions based on tax positions related to the current year

            4       13  

Reductions for tax positions of prior years

            (33     (4

Settlements

            (65     (22
  

 

 

    

 

 

   

 

 

 

Balance at end of year

   $ 3      $ 3     $ 97  
  

 

 

    

 

 

   

 

 

 

The Company records interest and penalties related to unrecognized tax benefits as a component of income tax expense. Each quarter the Company assesses the amounts provided for and, as a result, may increase (expense) or reduce (benefit) the amount of interest and penalties. During the years ended December 31, 2013, 2012, and 2011 the Company recorded tax expense of $1 million, $5 million, and $6 million, respectively, for interest and penalties. As of December 31, 2013 and 2012, the Company had approximately $1 million and $5 million, respectively, accrued for payment of interest and penalties.

The Company is under IRS audit for 2011 and 2012 and under audit in various states as well as in most of the Company’s foreign jurisdictions as part of its normal course of business. In 2013, the Company reached an agreement with the IRS regarding an audit of the 2009 and 2010 tax years. There was no change in the Company’s unrecognized tax benefit as a result of the 2009 and 2010 IRS settlement. In 2012, the Company reached an agreement with the IRS Administrative Appeals office regarding the audits of tax years 2004 through 2008. As a result of this agreement, the Company reduced its 2012 unrecognized tax benefit by $65 million. The resolution of unagreed tax issues in the Company’s open tax years cannot be predicted with absolute certainty, and differences between what has been recorded and the eventual outcomes may occur. The Company believes that it has adequately provided for income taxes and any related interest and penalties for all open tax years.

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

 

Jurisdiction

      

U.S.

     2010  

Canada

     2009  

Egypt

     1998  

Australia

     2009  

U.K.

     2011  

Argentina

     2006  

8.     COMMITMENTS AND CONTINGENCIES

Legal Matters

Apache is party to various legal actions arising in the ordinary course of business, including litigation and governmental and regulatory controls. The Company has an accrued liability of approximately $10 million for all

 

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legal contingencies that are deemed to be probable of occurring and can be reasonably estimated. Apache’s estimates are based on information known about the matters and its experience in contesting, litigating, and settling similar matters. Although actual amounts could differ from management’s estimate, none of the actions are believed by management to involve future amounts that would be material to Apache’s financial position, results of operations, or liquidity after consideration of recorded accruals. For material matters that Apache believes an unfavorable outcome is reasonably possible, the Company has disclosed the nature of the matter and a range of potential exposure, unless an estimate cannot be made at this time. It is management’s opinion that the loss for any other litigation matters and claims that are reasonably possible to occur will not have a material adverse effect on the Company’s financial position, results of operations, or liquidity.

Argentine Environmental Claims 

In connection with the acquisition from Pioneer Natural Resources (Pioneer) in 2006, the Company acquired a subsidiary of Pioneer in Argentina (PNRA) that is involved in various administrative proceedings with environmental authorities in the Neuquén Province relating to permits for and discharges from operations in that province. In addition, PNRA was named in a lawsuit initiated against oil companies operating in the Neuquén basin entitled Asociación de Superficiarios de la Patagonia v YPF S.A., et. al., originally filed on August 21, 2003, in the Argentine National Supreme Court of Justice. The plaintiffs, a private group of landowners known as ASSUPA, have also named the national government and several provinces as third parties. The lawsuit alleges injury to the environment generally by the oil and gas industry. The plaintiffs principally seek from all defendants, jointly, (i) the remediation of contaminated sites, of the superficial and underground waters, and of soil that allegedly was degraded as a result of deforestation, (ii) if the remediation is not possible, payment of an indemnification for the material and moral damages claimed from defendants operating in the Neuquén basin, of which PNRA is a small portion, (iii) adoption of all the necessary measures to prevent future environmental damages, and (iv) the creation of a private restoration fund to provide coverage for remediation of potential future environmental damages. Much of the alleged damage relates to operations by the Argentine state oil company, which conducted oil and gas operations throughout Argentina prior to its privatization, which began in 1990. ASSUPA in 2012 asserted similar lawsuits and claims against numerous oil and gas producers relating to other geographic areas of Argentina, including claims against a Company subsidiary relating to the Austral basin. While the plaintiffs will seek to make all oil and gas companies jointly liable for each other’s actions in each of these lawsuits, Company subsidiaries will defend on an individual basis and attempt to require the plaintiffs to delineate damages by company. Company subsidiaries intend to defend each case vigorously. It is not certain exactly what the courts will do in these matters as the lawsuit relating to the Neuquén basin is the first of its kind. While it is possible Company subsidiaries may incur liabilities related to the environmental claims, no reasonable prediction can be made as the Company subsidiaries’ exposure related to these lawsuits is not currently determinable.

Argentine Tariff 

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

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

 

U.S. Royalty Litigation

In Foster v. Apache Corporation, Civil Action No. CIV-10-0573-HE, in the United States District Court for the Western District of Oklahoma, on August 20, 2012, the United States District Court for the Western District of Oklahoma denied plaintiff’s motion for class certification. The plaintiff filed a motion for reconsideration, which was also denied, and petitioned the United States Court of Appeals for the Tenth Circuit to accept an appeal of the District Court’s ruling denying class certification. The plaintiff withdrew the petition to appeal following decisions on July 8, 2013, by the United States Court of Appeals for the Tenth Circuit to vacate District Court class certification orders in two unrelated lawsuits — Wallace B. Roderick Revocable Living Trust v. XTO Energy, Inc., No. 12-3176, and Chieftain Royalty Company v. XTO Energy, Inc., No. 12-7047. The plaintiff and Apache recently filed a joint stipulation to dismiss the Foster lawsuit with prejudice, which concludes the matter.

Louisiana Restoration 

Numerous surface owners have filed claims or sent demand letters to various oil and gas companies, including Apache, claiming that, under either expressed or implied lease terms or Louisiana law, they are liable for damage measured by the cost of restoration of leased premises to their original condition as well as damages from contamination and cleanup, regardless of the value of the underlying property. Because the Company has continuing operations in Louisiana, from time-to-time restoration lawsuits and claims are resolved by the Company for amounts that are not material to the Company while new lawsuits and claims are asserted against the Company. With respect to each of the pending lawsuits and claims, the amount claimed is not currently determinable or is not material, except that in a lawsuit captioned Ardoin Limited Partnership et al. v. Meridian Resources & Exploration et al., Case No.10-18692, in the District Court of Cameron Parish, Louisiana, the plaintiffs’ expert opined that the cost to restore plaintiffs’ property would be approximately $61 million. Prior to trial the court granted Apache’s motions to dismiss the plaintiffs’ claims against Apache. Plaintiffs then settled with the other defendant in the case, BP America, Inc. (BP). BP has demanded that Apache indemnify it for the amount of its settlement with plaintiffs, which is not material to Apache. Apache has rejected BP’s indemnity claim and, further, Apache has demanded that Wagner Oil Company (which purchased Apache’s interest in the subject property) indemnify Apache from and against BP’s claim.

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

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

 

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

The overall exposure related to these lawsuits and claims is not currently determinable. While an adverse judgment against Apache is possible, Apache intends to actively defend the cases.

Hurricane-Related Litigation

On May 27, 2011, a lawsuit captioned Comer et al. v. Murphy Oil USA, Inc. et al., Case No. 1:11-cv-220 HS0-JMR, in the United States District Court for the Southern District of Mississippi, was filed in which certain named residents of Mississippi, as plaintiffs, alleged that the oil, coal, and chemical industries are responsible for global warming, which they claim caused or increased the effect of Hurricane Katrina, allegedly resulting among other things in economic losses and increased insurance premiums. Plaintiffs sought class certification, damages for losses sustained, a declaration that state law tort claims are not pre-empted by federal law, and punitive and exemplary damages. Apache was one of numerous defendants. The District Court granted defendants’ motion to dismiss plaintiffs’ claims. Plaintiffs appealed the decision to the United States Court of Appeals for the Fifth Circuit, which affirmed dismissal of the suit. Plaintiffs did not appeal further, thus concluding the matter. A similar action filed by Comer et al. was previously dismissed in 2011.

Australia Gas Pipeline Force Majeure 

In June 2008, Company subsidiaries reported a pipeline explosion that interrupted deliveries of natural gas to customers under various long-term contracts. Company subsidiaries believe that the event was a force majeure, and as a result, the subsidiaries and their joint venture participants declared force majeure under those contracts.

On December 16, 2009, a natural gas customer, Burrup Fertilisers Pty Ltd (Burrup Fertilisers), filed a lawsuit on behalf of itself and certain of its underwriters at Lloyd’s of London and other insurers, against the Company and its subsidiaries in Texas state court, in a case captioned Burrup Fertilisers Pty Ltd v. Apache Corporation, Apache Energy Limited, and Apache Northwest Pty Ltd, Cause No. 2009-79834, in the District Court of Harris County, Texas. The lawsuit concerned the interruption of deliveries of natural gas to Burrup Fertilisers following the pipeline explosion. Burrup Fertilisers and its underwriters asserted claims for negligence, breach of contract, alter ego, single business enterprise, res ipsa loquitur, and gross negligence/exemplary damages, and sought to recover unspecified actual damages, cost of repair and replacement, exemplary damages, lost profits, loss of business goodwill, value of the gas lost under the Gas Supply and Purchase Agreement (GSA), interest, and court costs. On March 22, 2013, Burrup Fertilisers agreed to dismiss its

 

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

On March 24, 2011, another natural gas customer, Alcoa of Australia Limited (“Alcoa”) filed a lawsuit captioned Alcoa of Australia Limited vs. Apache Energy Limited, Apache Northwest Pty Ltd, Tap (Harriet) Pty Ltd, and Kufpec Australia Pty Ltd, Civ. 1481 of 2011, in the Supreme Court of Western Australia. The lawsuit concerns the interruption of deliveries of natural gas to Alcoa under two long-term contracts. Alcoa challenges the declaration of force majeure and the validity of the liquidated damages provisions in the contracts. Alcoa asserts claims based on breach of contract, statutory duties, and duty of care. Alcoa seeks approximately $158 million AUD in general damages or, alternatively, approximately $5.7 million AUD in liquidated damages. On June 20, 2012, the Supreme Court struck out Alcoa’s claim that the liquidated damages provisions under two long-term contracts are unenforceable as a penalty and also struck out Alcoa’s claim for damages for breach of statutory duty. On September 17, 2013, the Western Australia Court of Appeal dismissed the Company subsidiaries’ appeal concerning Alcoa’s remaining tort claim for economic loss. On October 15, 2013, the Company subsidiaries applied to the High Court of Australia for leave to appeal. The applications for leave to appeal are pending. If the High Court does not grant leave to appeal at this time, all of the Company subsidiaries’ defenses remain intact for further proceedings at the trial court level.

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

The Company and its subsidiaries do not believe that the Burrup Fertilisers, Alcoa, and Barrick claims have merit and will vigorously pursue their defenses against such claims.

Other customers have threatened to file suit challenging the declaration of force majeure under their contracts. At least one third party that is not a customer has also threatened to file suit. Contract prices under customer contracts are significantly below current prices for natural gas in Australia. In the event it is determined that the pipeline explosion was not a force majeure, Company subsidiaries believe that liquidated damages should be the extent of the damages under those long-term contracts with such provisions. Approximately 90 percent of the natural gas volumes sold by Company subsidiaries under long-term contracts have liquidated damages provisions. Contractual liquidated damages under the long-term contracts with such provisions would not be expected to exceed $50 million AUD exclusive of interest. This is a reduction from the previous estimate of $200 million AUD. No assurance can be given that customers would not assert claims in excess of contractual liquidated damages, and exposure related to such claims (or any claims by non-customers) is not currently determinable. While an adverse judgment against Company subsidiaries (and the Company, in the case of Burrup Fertilisers) is possible, the Company and Company subsidiaries do not believe any such claims would have merit and plan to vigorously pursue their defenses against any such claims.

In December 2008, the Senate Economics Committee of the Parliament of Australia released its findings from public hearings concerning the economic impact of the gas shortage following the explosion on Varanus Island and the government’s response. The Committee concluded, among other things, that the macroeconomic impact to Western Australia will never be precisely known, but cited to a range of estimates from $300 million

 

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AUD to $2.5 billion AUD consisting in part of losses alleged by some parties who have long-term contracts with Company subsidiaries (as described above), but also losses alleged by third parties who do not have contracts with Company subsidiaries (but who may have purchased gas that was re-sold by customers or who may have paid more for energy following the explosion or who lost wages or sales due to the inability to obtain energy or the increased price of energy). A timber industry group, whose members do not have a contract with Company subsidiaries, has announced that it intends to seek compensation for its members and their subcontractors from Company subsidiaries for $20 million AUD in losses allegedly incurred as a result of the gas supply shortage following the explosion. In Johnson Tiles Pty Ltd v. Esso Australia Pty Ltd [2003] VSC 27 (Supreme Court of Victoria, Gillard J presiding), which concerned a 1998 explosion at an Esso natural gas processing plant at Longford in East Gippsland, Victoria, the Court held that Esso was not liable for $1.3 billion AUD of pure economic losses suffered by claimants that had no contract with Esso, but was liable to such claimants for reasonably foreseeable property damage which Esso settled for $32.5 million AUD plus costs. In reaching this decision the Court held that third-party claimants should have protected themselves from pure economic losses, through the purchase of insurance or the installation of adequate backup measures, in case of an interruption in their gas supply from Esso. While an adverse judgment against Company subsidiaries is possible if litigation is filed, Company subsidiaries do not believe any such claims would have merit and plan to vigorously pursue their defenses against any such claims. Exposure related to any such potential claims is not currently determinable.

On October 10, 2008, the Australia National Offshore Petroleum Safety Authority (NOPSA) released a self-titled “Final Report” of the findings of its investigation into the pipeline explosion, prepared at the request of the Western Australian Department of Industry and Resources (DoIR). NOPSA concluded in its report that the evidence gathered to date indicates that the main causal factors in the incident were: (1) ineffective anti-corrosion coating at the beach crossing section of the 12-inch sales gas pipeline, due to damage and/or dis-bondment from the pipeline; (2) ineffective cathodic protection of the wet-dry transition zone of the beach crossing section of the 12-inch sales gas pipeline; and (3) ineffective inspection and monitoring by Company subsidiaries of the beach crossing and shallow water section of the 12-inch sales gas pipeline. NOPSA further concluded that the investigation identified that Apache Northwest Pty Ltd and its co-licensees may have committed offenses under the Petroleum Pipelines Act 1969, Sections 36A & 38(b) and the Petroleum Pipelines Regulations 1970, Regulation 10, and that some findings may also constitute non-compliance with pipeline license conditions.

On May 28, 2009, the Department of Mines and Petroleum (DMP) filed a prosecution notice in the Magistrates Court of Western Australia, charging Apache Northwest Pty Ltd and its co-licensees with failure to maintain a pipeline in good condition and repair under the Petroleum Pipelines Act 1969, Section 38(b). The maximum fine associated with the alleged offense was $50,000 AUD. The Company subsidiary did not believe that the charge had merit and vigorously pursued its defenses, resulting in the dismissal of the prosecution notice by the Magistrates Court of Western Australia on March 29, 2012.

NOPSA stated in its report that an application for renewal of the pipeline license (the “pipeline license”) covering the area of the Varanus Island facility was granted in May 1985 with 21 years validity, and an application for renewal of the pipeline license was submitted to DoIR by Company subsidiaries in December 2005 and remained pending at the time NOPSA issued its report. The application by Apache Northwest, Kufpec Australia Pty Ltd, and Tap (Harriet) Pty Ltd for renewal and variation of the pipeline license covering the area of the Varanus Island facility was granted on April 19, 2011, by the DMP. The period of the pipeline license is 21 years commencing April 20, 2011.

Company subsidiaries disagree with NOPSA’s conclusions and believe that the NOPSA report was premature, based on an incomplete investigation, and misleading. In a July 17, 2008, media statement, DoIR acknowledged, “The pipelines and Varanus Island facilities have been the subject of an independent validation

 

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report [by Lloyd’s Register] which was received in August 2007. NOPSA has also undertaken a number of inspections between 2005 and the present.” These and numerous other inspections, audits and reviews conducted by top international consultants and regulators did not identify any warnings that the pipeline had a corrosion problem or other issues that could lead to its failure. Company subsidiaries believe that the explosion was not reasonably foreseeable, and was not within the reasonable control of Company’s subsidiaries or able to be reasonably prevented by Company subsidiaries.

On January 9, 2009, the governments of Western Australia and the Commonwealth of Australia announced a joint inquiry to consider the effectiveness of the regulatory regime for occupational health and safety and integrity that applied to operations and facilities at Varanus Island and the role of DoIR, NOPSA, and the Western Australian Department of Consumer and Employment Protection. The joint inquiry’s report was published in June 2009.

On May 8, 2009, the government of Western Australia announced that the DMP would carry out “the final stage of investigations into the Varanus Island gas explosion.” Inspectors were appointed under the Petroleum Pipelines Act to coordinate the final stage of the investigations. That report, prepared by the inspectors in June 2009, was made public by the State government on May 24, 2012. Company subsidiaries disagree with the inspectors’ June 2009 conclusions. Two other government reports were not published by the State and were not referenced by the inspectors. The Magistrates Court of Western Australia subsequently ordered that both such reports could be released on the basis that the inspectors’ June 2009 report “came with some limitations” and the two other government reports “together were part and parcel if not the main reason or the only reason…certainly a significant contribution to the reason for the matter not proceeding to prosecution and trial.” In the first such report, the State’s senior investigator said in February 2009 that the prospects of a successful prosecution of Apache for failing to maintain the pipeline “would be slight.” In the second such report, the State’s lead corrosion expert concluded in July 2011 that Apache “had reasonable grounds to believe that the pipeline was in good repair” prior to the explosion.

Breton Lawsuit

On October 4, 2011, plaintiffs filed suit in Breton Energy, L.L.C. et al. v. Mariner Energy Resources, Inc., et al., Case 4:11-cv-03561, in the United States District Court for the Southern District of Texas, Houston Division, seeking compensation from defendants for allegedly depriving plaintiffs of rights to hydrocarbons in a reservoir described by plaintiffs as a common reservoir in West Cameron Blocks 171 and 172 offshore Louisiana in the Gulf of Mexico. In their original petition plaintiffs named, among others, Mariner Energy, Inc. and certain of its affiliates as defendants. On December 12, 2011, plaintiffs filed an amended petition to add as defendants Apache Corporation and Apache Shelf, Inc. as successors to the Mariner interests. On September 27, 2012, the court dismissed plaintiffs’ claims on various grounds, including for failure to state a claim upon which relief may be granted, while granting plaintiffs leave to amend their complaint within 30 days. On October 29, 2012, the plaintiffs filed an amended complaint. On May 28, 2013, the United States District Court for the Southern District of Texas dismissed the plaintiffs’ claims and entered judgment in favor of the defendants. On June 3, 2013, the plaintiffs filed a notice of appeal in the United States Court of Appeals for the Fifth Circuit. The appeal is pending. The exposure related to the re-filed lawsuit is not currently determinable. While an adverse judgment against Apache is possible, Apache intends to vigorously defend the case.

Escheat Audits

The State of Delaware, Department of Finance, Division of Revenue (Unclaimed Property), has notified numerous companies, including Apache Corporation, that the State will examine its books and records and those of its subsidiaries and related entities to determine compliance with the Delaware Escheat Laws. The review is

 

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being conducted by Kelmar Associates on behalf of the State of Delaware. At least 30 other states have retained their own consultants and have sent similar notifications. The scope of each state’s audit varies. The State of Delaware advises, for example, that the scope of its examination will be for the period 1981 through the present. It is possible that one or more of the audits could extend to all 50 states. The exposure related to the audits is not currently determinable.

Burrup-Related Gas Supply Lawsuits

On May 19, 2011, a lawsuit captioned Pankaj Oswal et al. v. Apache Corporation, Cause No. 2011-30302, in the District Court of Harris County, Texas, was filed in which plaintiffs asserted claims against the Company under the Australian Trade Practices Act. Following a hearing on March 22, 2013, the District Court on April 5, 2013, granted Apache Corporation’s motion to dismiss on the ground of forum non conveniens and entered an order dismissing the Texas lawsuit. On or about October 11, 2013, a statement of claim captioned Pankaj Oswal v. Apache Corporation, No. WAD 389/2013, in the Federal Court of Australia, District of Western Australia, General Division, was filed in which plaintiff Oswal once again asserts claims against the Company under the Australian Trade Practices Act. The Western Australia lawsuit is one of a number of legal actions involving the Burrup Fertilisers ammonia plant in Western Australia (the Burrup plant) founded by Oswal. Oswal’s shares, and those of his wife, together representing 65 percent of Burrup Holdings Limited (BHL, which owns Burrup Fertilisers), were offered for sale by externally-appointed administrators in Australia as a result of events of default on loans made to the Oswals by the Australia and New Zealand Banking Group Ltd (ANZ). In the Western Australia lawsuit, plaintiff Oswal alleges, among other things, that the Company induced him to make investments covering construction cost overruns on the ammonia plant that was completed in 2006. Plaintiff Oswal seeks damages in the amount of $491 million USD. The Company believes that the claims are without merit and intends to vigorously defend against them.

The Texas and Western Australia lawsuits relate to a pending action filed by Tap (Harriet) Pty Ltd (Tap) against Burrup Fertilisers Pty Ltd et al., Civ. 2329 of 2009, in the Supreme Court of Western Australia (the “Tap action”), seeking a declaratory judgment regarding its contractual rights and obligations under a gas sales agreement between Burrup Fertilisers and the Harriet Joint Venture (comprised of a Company subsidiary and two joint venture partners, Tap and Kufpec Australia Pty Ltd).

As part of the sale process described above, on January 31, 2012, a Company affiliate acquired a 49 percent interest in YPHPL, while Yara Australia Pty Ltd (Yara) increased its interest in YPHPL from 35 percent to 51 percent. Yara operates the ammonia plant and is proceeding with development of a technical ammonium nitrate (TAN) plant in the Burrup Peninsula region of Western Australia to be developed by a consortium including YPHPL. A Company affiliate’s existing agreement to supply gas to the ammonia plant has been modified (with, among other things, new pricing, delivery quantities, and term). YPHPL share ownership, and the modified gas supply agreement, continues to be the subject of ongoing litigation in Australia with third parties, including Pankaj and Radhika Oswal. Two such cases directly involve the Company or certain of its subsidiaries. In a case captioned Radhika Oswal v. Australia and New Zealand Banking Group Limited (ANZ) et al., No. SCI 2011 4653, in the Supreme Court of Victoria, the defendants include a Company affiliate. The Court has denied plaintiff’s application seeking to amend her statement of claim in order to add parties as defendants to the proceedings, including the Company and certain of its other subsidiaries. Similarly, in a companion case captioned Pankaj Oswal v. Australia and New Zealand Banking Group Limited (ANZ) et al., No. SCI 2012 01995, in the Supreme Court of Victoria, the Court has also denied plaintiff’s application seeking to amend his statement of claim in order to add parties as defendants to the proceedings, including the Company and certain of its subsidiaries. The plaintiffs, either in their original claims or in their proposed amended claims, seek to set aside the YPHPL share sale, void the modified gas sale agreement, and recover unspecified damages. The plaintiffs’ in both cases have sought leave to appeal the Court’s denial of their applications. The new gas supply

 

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agreement resolves counterclaims by Burrup Fertilisers against Apache and its affiliate in the Tap action. A Company subsidiary purchased Tap, which then modified its agreement to supply gas to the ammonia plant and resolved both Tap’s claims against Burrup Fertilisers and Burrup Fertilisers’ counterclaims against Tap in the Tap action. If Kufpec does not settle the remaining claims in the Tap action, it is expected that the trial court in the Tap action will issue its ruling in respect of phase 1 of those proceedings, which was tried in September 2011 and concerned construction of the original gas supply agreement.

Environmental Matters

The Company, as an owner or lessee and operator of oil and gas properties, is subject to various federal, provincial, state, local, and foreign country laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution clean-up resulting from operations and subject the lessee to liability for pollution damages. In some instances, the Company may be directed to suspend or cease operations in the affected area. We maintain insurance coverage, which we believe is customary in the industry, although we are not fully insured against all environmental risks.

Apache manages its exposure to environmental liabilities on properties to be acquired by identifying existing problems and assessing the potential liability. The Company also conducts periodic reviews, on a Company-wide basis, to identify changes in its environmental risk profile. These reviews evaluate whether there is a probable liability, the amount, and the likelihood that the liability will be incurred. The amount of any potential liability is determined by considering, among other matters, incremental direct costs of any likely remediation and the proportionate cost of employees who are expected to devote a significant amount of time directly to any possible remediation effort. As it relates to evaluations of purchased properties, depending on the extent of an identified environmental problem, the Company may exclude a property from the acquisition, require the seller to remediate the property to Apache’s satisfaction, or agree to assume liability for the remediation of the property. The Company’s general policy is to limit any reserve additions to any incidents or sites that are considered probable to result in an expected remediation cost exceeding $300,000. Any environmental costs and liabilities that are not reserved for are treated as an expense when actually incurred. In Apache’s estimation, neither these expenses nor expenses related to training and compliance programs are likely to have a material impact on its financial condition.

As of December 31, 2013, the Company had an undiscounted reserve for environmental remediation of approximately $93 million. Apache is not aware of any environmental claims existing as of December 31, 2013 that have not been provided for or would otherwise have a material impact on its financial position or results of operations. There can be no assurance however, that current regulatory requirements will not change or past non-compliance with environmental laws will not be discovered on the Company’s properties.

On May 25, 2011, a panel of the Bureau of Ocean Energy Management (BOEMRE, as it was then known) published a report dated May 23, 2011, and titled “OCS G-2580, Vermilion Block 380 Platform A, Incidents of Noncompliance.” The report concerned the BOEMRE’s investigation of a fire on the Vermilion 380 A platform located in the Gulf of Mexico. At the time of the incident, Mariner operated the platform. A small amount of hydrocarbons spilled from the platform into the surrounding water as a result of the incident, and 13 workers were rescued after evacuating the platform. The BOEMRE concluded in its investigation that the fire was caused by Mariner’s failure to adequately maintain or operate the platform’s heater-treater in a safe condition. The BOEMRE also identified other safety deficiencies on the platform. On December 27, 2011, the Bureau of Safety and Environmental Enforcement (BSEE, successor to BOEMRE) issued several Incidents of Non-Compliance, which may provide the basis for the assessment of civil penalties against Mariner. The Company’s subsidiary

 

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Apache Deepwater LLC, which acquired Mariner effective November 10, 2010, filed an appeal on August 31, 2012, contesting several of the Incidents of Non-Compliance. It is management’s opinion that any loss arising from this matter will not have a material adverse effect on the Company’s financial position, results of operations, or liquidity.

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

Contractual Obligations

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

 

                                 2019 &  

Net Minimum Commitments

   Total      2014      2015-2016      2017-2018      Beyond  
     (In millions)  

Drilling rig commitments(1)

   $ 974      $ 376      $ 429      $ 157      $ 12  

Purchase obligations(2)

     1,759         1,002         533        204        20  

Firm transportation agreements(3)

     683        158        223        129        173  

Office and related equipment(4)

     391        46        101        95        149  

Other operating lease obligations(5)

     686        190        295        193        8  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Net Minimum Commitments

   $ 4,493       $ 1,772       $ 1,581       $ 778      $ 362  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1)

Includes day-rate and other contractual agreements with third party service providers for use of drilling, completion, and workover rigs.

 

(2)

Includes contractual obligations to buy or build oil and gas plants and facilities, LNG facilities, seismic and drilling work program commitments, take-or-pay contracts, and hydraulic fracturing services agreements.

 

(3)

Relates to contractual obligations for capacity rights on third-party pipelines.

 

(4)

Includes office and other building rentals and related equipment leases.

 

(5)

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

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

 

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9.     RETIREMENT AND DEFERRED COMPENSATION PLANS

Apache Corporation provides retirement benefits to its U.S. employees through the use of multiple plans: a 401(k) savings plan, a money purchase retirement plan, a non-qualified retirement/savings plan, and a non-qualified restorative retirement savings plan. The 401(k) savings plan provides participating employees the ability to elect to contribute up to 50 percent of eligible compensation, as defined, to the plan with the Company making matching contributions up to a maximum of 8 percent of each employee’s annual eligible compensation. In addition, the Company annually contributes 6 percent of each participating employee’s annual eligible compensation to a money purchase retirement plan. The 401(k) savings plan and the money purchase retirement plan are subject to certain annually-adjusted, government-mandated restrictions that limit the amount of employee and Company contributions. For certain eligible employees, the Company also provides a non-qualified retirement/savings plan or a non-qualified restorative retirement savings plan. These plans allow the deferral of up to 50 percent of each employee’s base salary, up to 75 percent of each employee’s annual bonus (that accepts employee contributions) and the Company’s matching contributions in excess of the government mandated limitations imposed in the 401(k) savings plan and money purchase retirement plan.

Vesting in the Company’s contributions in the 401(k) savings plan, the money purchase retirement plan, the non-qualified retirement savings plan and the non-qualified restorative retirement savings plan occurs at the rate of 20 percent for every completed year of employment. Upon a change in control of ownership, immediate and full vesting occurs.

Additionally, Apache Energy Limited, Apache Canada Ltd., and Apache North Sea Limited maintain separate retirement plans, as required under the laws of Australia, Canada, and the U.K., respectively.

The aggregate annual cost to Apache of all U.S. and International savings plans, the money purchase retirement plan, non-qualified retirement/savings plan, and non-qualified restorative retirement savings plan was $123 million, $117 million, and $93 million for 2013, 2012, and 2011, respectively.

Apache also provides a funded noncontributory defined benefit pension plan (U.K. Pension Plan) covering certain employees of the Company’s North Sea operations in the U.K. The plan provides defined pension benefits based on years of service and final salary. The plan applies only to employees who were part of the BP North Sea’s pension plan as of April 2, 2003, prior to the acquisition of BP North Sea by the Company effective July 1, 2003.

Additionally, the Company offers postretirement medical benefits to U.S. employees who meet certain eligibility requirements. Eligible participants receive medical benefits up until the age of 65, provided the participant remits the required portion of the cost of coverage. The plan is contributory with participants’ contributions adjusted annually. The postretirement benefit plan does not cover benefit expenses once a covered participant becomes eligible for Medicare.

 

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The following tables set forth the benefit obligation, fair value of plan assets and funded status as of December 31, 2013, 2012, and 2011, and the underlying weighted average actuarial assumptions used for the U.K. Pension Plan and U.S. postretirement benefit plan. Apache uses a measurement date of December 31 for its pension and postretirement benefit plans.

 

    2013     2012     2011  
    Pension     Postretirement     Pension     Postretirement     Pension     Postretirement  
    Benefits     Benefits     Benefits     Benefits     Benefits     Benefits  
    (In millions)  

Change in Projected Benefit Obligation

           

Projected benefit obligation beginning of year

  $ 177     $ 35     $ 150     $ 30     $ 136     $ 29  

Service cost

    5       4       5       4       5       3  

Interest cost

    7       1       7       1       7       1  

Foreign currency exchange rate changes

    4              7              (1       

Actuarial losses (gains)

           (8     14       1       6       (2

Effect of curtailment and settlements

           (3                            

Benefits paid

    (4     (2     (6     (1     (3     (1

Retiree contributions

           1                              
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Projected benefit obligation at end of year

    189       28       177       35       150       30  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Change in Plan Assets

           

Fair value of plan assets at beginning of year

    170              145              135         

Actual return on plan assets

    15              14              4         

Foreign currency exchange rates

    4              6              (1       

Employer contributions

    6       1       11       1       10       1  

Benefits paid

    (4     (2     (6     (1     (3     (1

Retiree contributions

           1                              
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Fair value of plan assets at end of year

    191              170              145         
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Funded status at end of year

  $ 2     $ (28   $ (7   $ (35   $ (5   $ (30
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Amounts recognized in Consolidated Balance Sheet

           

Current liability

           (1            (1            (1

Non-current asset (liability)

    2       (27     (7     (34     (5     (29
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
  $ 2     $ (28   $ (7   $ (35   $ (5   $ (30
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Pre-tax Amounts Recognized in Accumulated Other Comprehensive Income (Loss)

           

Accumulated gain (loss)

    (22     1       (32     (7     (25     (6
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
  $ (22   $ 1     $ (32   $ (7   $ (25   $ (6
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Weighted Average Assumptions used as of December 31

           

Discount rate

    4.60     4.33     4.30     3.43     4.70     4.04

Salary increases

    4.90     N/A        4.60     N/A        4.60     N/A   

Expected return on assets

    5.60     N/A        4.70     N/A        4.85     N/A   

Healthcare cost trend

           

Initial

    N/A        7.00     N/A        7.25     N/A        7.50

Ultimate in 2022

    N/A        5.00     N/A        5.00     N/A        5.00

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

 

As of December 31, 2013, 2012, and 2011, the accumulated benefit obligation for the U.K. Pension Plan was $160 million, $139 million, and $119 million, respectively.

Apache’s defined benefit pension plan assets are held by a non-related trustee who has been instructed to invest the assets in an equal blend of equity securities and low-risk debt securities. The Company intends that this blend of investments will provide a reasonable rate of return such that the benefits promised to members are provided. The U.K. Pension Plan policy is to target an ongoing funding level of 100 percent through prudent investments and includes policies and strategies such as investment goals, risk management practices, and permitted and prohibited investments. A breakout of previous allocations for plan asset holdings and the target allocation for the Company’s plan assets are summarized below:

 

     Target Allocation     Percentage of
Plan  Assets at
Year-End
 
     2013     2013     2012  

Asset Category

      

Equity securities:

      

U.K. quoted equities

     17     18     16

Overseas quoted equities

     33     33     33
  

 

 

   

 

 

   

 

 

 

Total equity securities

     50     51     49
  

 

 

   

 

 

   

 

 

 

Debt securities:

      

U.K. Government bonds

     30     29     30

U.K. corporate bonds

     20     20     20
  

 

 

   

 

 

   

 

 

 

Debt securities

     50     49     50
  

 

 

   

 

 

   

 

 

 

Cash

     0     0     1
  

 

 

   

 

 

   

 

 

 

Total

     100     100     100
  

 

 

   

 

 

   

 

 

 

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

 

The plan’s assets do not include any direct ownership of equity or debt securities of Apache. The fair value of plan assets is based upon unadjusted quoted prices for identical instruments in active markets, which is a Level 1 fair value measurement. The following tables present the fair values of plan assets for each major asset category based on the nature and significant concentration of risks in plan assets at December 31, 2013 and December 31, 2012:

 

     Fair Value Measurements Using:  
     Quoted Price
in Active
Markets
(Level 1)
     Significant
Other Inputs
(Level 2)
     Unobservable
Inputs
(Level 3)
     Total Fair
Value
 
     (In millions)  

December 31, 2013

           

Equity securities:

           

U.K. quoted equities(1)

   $ 35      $  —       $  —       $ 35  

Overseas quoted equities(2)

     63                        63  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total equity securities

     98                        98  
  

 

 

    

 

 

    

 

 

    

 

 

 

Debt securities:

           

U.K. Government bonds(3)

     54                        54  

U.K. corporate bonds(4)

     38                        38  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total debt securities

     92                        92  
  

 

 

    

 

 

    

 

 

    

 

 

 

Cash

     1                        1  
  

 

 

    

 

 

    

 

 

    

 

 

 

Fair value of plan assets

   $ 191      $  —       $  —       $ 191  
  

 

 

    

 

 

    

 

 

    

 

 

 

December 31, 2012

           

Equity securities:

           

U.K. quoted equities(1)

   $ 28      $  —       $  —       $ 28  

Overseas quoted equities(2)

     56                        56  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total equity securities

     84                        84  
  

 

 

    

 

 

    

 

 

    

 

 

 

Debt securities:

           

U.K. Government bonds(3)

     51                        51  

U.K. corporate bonds(4)

     34                        34  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total debt securities

     85                        85  
  

 

 

    

 

 

    

 

 

    

 

 

 

Cash

     1                        1  
  

 

 

    

 

 

    

 

 

    

 

 

 

Fair value of plan assets

   $ 170      $  —       $  —       $ 170  
  

 

 

    

 

 

    

 

 

    

 

 

 

 

(1)

This category comprises U.K. equities, which are benchmarked against the FTSE All-Share Index.

 

(2)

This category includes overseas equities, which comprises 85 percent global equities benchmarked against the MSCI World Index and 15 percent emerging markets benchmarked against the MSCI Emerging Markets Index, both of which have a performance target of 2 percent per annum over the benchmark over a rolling three-year period.

 

(3)

This category includes U.K. Government bonds: 33 percent benchmarked against iBoxx Sterling Overall Index, with a performance target of 0.75 percent per annum over the benchmark over a rolling three-year period; and 67 percent against the FTSE Actuaries Government Securities Index-Linked Over 5 Years Index.

 

(4)

This category comprises U.K. corporate bonds: 50 percent benchmarked against the iBoxx Sterling Overall Non Gilt index with a performance target of 0.75 percent per annum over the benchmark over a rolling three-year period; and 50 percent benchmarked against the iBoxx Sterling Overall Non Gilt Index with a performance target of 0.75 percent per annum over the benchmark over a rolling five year period.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—  (Continued)

 

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

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

 

     2013     2012     2011  
     Pension     Postretirement     Pension     Postretirement     Pension     Postretirement  
     Benefits     Benefits     Benefits     Benefits     Benefits     Benefits  
     (In millions)  

Component of Net Periodic Benefit Costs

            

Service cost

   $ 5     $ 4     $ 5     $ 4     $ 5     $ 3  

Interest cost

     7       1       7       1       7       1  

Expected return on assets

     (8            (7            (8       

Amortization of actuarial (gain) loss

     2              1                       

Curtailment (gain) loss

            (3                            
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net periodic benefit cost

   $ 6     $ 2     $ 6     $ 5     $ 4     $ 4  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Weighted Average Assumptions used to determine Net Period Benefit Cost for the Years ended December 31

            

Discount rate

     4.30     3.43     4.70     4.04     5.40     4.93

Salary increases

     4.60     N/A        4.60     N/A        5.00     N/A   

Expected return on assets

     4.70     N/A        4.85     N/A        6.25     N/A   

Healthcare cost trend

            

Initial

     N/A        7.25     N/A        7.50     N/A        8.00

Ultimate in 2022

     N/A        5.00     N/A        5.00     N/A        5.00

Assumed health care cost trend rates affect amounts reported for postretirement benefits. A one-percentage-point change in assumed health care cost trend rates would have the following effects:

 

     Postretirement Benefits  
     1% Increase      1% Decrease  
     (In millions)  

Effect on service and interest cost components

   $ 1      $ (1

Effect on postretirement benefit obligation

     6        (4

 

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

 

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

 

     Pension      Postretirement  
     Benefits      Benefits  
     (In millions)  

2014

   $ 5      $ 1  

2015

     5        1  

2016

     5        2  

2017

     5        2  

2018

     5        2  

Years 2019-2023

     30        16  

10.     CAPITAL STOCK

Common Stock Outstanding

 

     2013     2012      2011  

Balance, beginning of year

     391,640,770       384,117,643        382,391,742  

Shares issued for stock-based compensation plans:

       

Treasury shares issued

     25,214       60,767        144,313  

Common shares issued

     929,596       1,189,693        1,581,588  

Common shares issued for conversion of preferred shares

     14,399,247                 

Treasury shares acquired

     (11,221,919               

Cordillera consideration (Note 2)

            6,272,667          
  

 

 

   

 

 

    

 

 

 

Balance, end of year

     395,772,908       391,640,770        384,117,643  
  

 

 

   

 

 

    

 

 

 

Net Income per Common Share

A reconciliation of the components of basic and diluted net income per common share for the years ended December 31, 2013, 2012, and 2011 is presented in the table below.

 

     2013      2012      2011  
     Income      Shares      Per Share      Income      Shares      Per Share      Income      Shares      Per Share  
     (In millions, except per share amounts)  

Basic:

                          

Net income attributable to common stock

   $ 2,188        395      $ 5.53      $ 1,925        389      $ 4.95      $ 4,508        384      $ 11.75  
        

 

 

          

 

 

          

 

 

 

Effect of Dilutive Securities:

                          

Mandatory Convertible Preferred Stock

   $ 44        9         $  —                  $ 76        14     

Stock options and other

             2                   2                   2     
  

 

 

    

 

 

       

 

 

    

 

 

       

 

 

    

 

 

    

Diluted:

                          

Net income attributable to common stock, including assumed conversions

   $ 2,232        406      $ 5.50      $ 1,925        391      $ 4.92      $ 4,584        400      $ 11.47  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

 

The diluted EPS calculation excludes options and restricted shares that were anti-dilutive totaling 4.9 million, 4.4 million, and 2.5 million for the years ended December 31, 2013, 2012, and 2011, respectively. For the year ended December 31, 2012, 14.3 million shares related to the assumed conversion of the Mandatory Convertible Preferred Stock were also anti-dilutive.

Stock Repurchase Program

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

Common Stock Dividend

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

Stock Compensation Plans

The Company has several stock-based compensation plans, which include stock options, stock appreciation rights, restricted stock, and conditional restricted stock unit plans. On May 5, 2011, the Company’s shareholders approved the 2011 Omnibus Equity Compensation Plan (the 2011 Plan), which is intended to provide eligible employees with equity-based incentives. The 2011 Plan provides for the granting of Incentive Stock Options, Non-Qualified Stock Options, Performance Awards, Restricted Stock, Restricted Stock Units, Stock Appreciation Rights, or any combination of the foregoing. A total of 27.3 million shares were authorized and available for grant under the 2011 Plan as of December 31, 2013. Previously approved plans remain in effect solely for the purpose of governing grants still outstanding that were issued prior to approval of the 2011 Plan. All new grants are issued from the 2011 Plan.

For 2013, 2012, and 2011, stock-based compensation expensed was $136 million, $167 million, and $113 million ($94 million, $119 million, and $73 million after tax), respectively. Costs related to the plans are capitalized or expensed based on the nature of each employee’s activities. A description of the Company’s stock-based compensation plans and related costs follows:

 

     2013      2012      2011  
     (In millions)  

Stock-based compensation expensed:

        

General and administrative

   $ 89      $ 104      $ 69  

Lease operating expenses

     47        63        44  

Stock-based compensation capitalized

     55        67        42  
  

 

 

    

 

 

    

 

 

 
   $ 191      $ 234      $ 155  
  

 

 

    

 

 

    

 

 

 

Stock Options

As of December 31, 2013, officers and employees held options to purchase shares of the Company’s common stock under one or more of the employee stock option plans adopted in 2000 and 2005 (collectively, the Stock Option Plans), as well as the 2007 Omnibus Equity Compensation Plan (the 2007 Plan), and the 2011 Plan

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

 

discussed above (together, the Omnibus Plans). New shares of Company stock will be issued for employee stock option exercises; however, under the 2000 Stock Option Plan, shares of treasury stock are used for employee stock option exercises to the extent treasury stock is held. Under the Stock Option Plans and the Omnibus Plans, the exercise price of each option equals the closing price of Apache’s common stock on the date of grant. Options generally become exercisable ratably over a four-year period and expire 10 years after granted. The Omnibus Plans and all of the Stock Option Plans, except for the 2000 Stock Option Plan, were submitted to and approved by the Company’s shareholders.

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

 

     2013  
     Shares
Under Option
    Weighted Average
Exercise Price
 
     (In thousands)        

Outstanding, beginning of year

     7,573     $ 90.47  

Granted

     819       80.89  

Exercised

     (327     72.55  

Forfeited or expired

     (502     97.88  
  

 

 

   

Outstanding, end of year(1)

     7,563       89.71  
  

 

 

   

Expected to vest(1)

     2,370       92.50  
  

 

 

   

Exercisable, end of year(1)

     4,678       88.53  
  

 

 

   

Weighted average fair value of options granted during the year

   $ 23.18    
  

 

 

   

 

(1)

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

The fair value of each stock option award is estimated on the date of grant using the Black-Scholes option pricing model. Assumptions used in the valuation are disclosed in the following table. Expected volatilities are based on historical volatility of the Company’s common stock and other factors. The expected dividend yield is based on historical yields on the date of grant. The expected term of stock options granted represents the period of time that the stock options are expected to be outstanding and is derived from historical exercise behavior, current trends, and values derived from lattice-based models. The risk-free rate is based on the U.S. Treasury yield curve in effect at the time of grant.

 

     2013     2012     2011  

Expected volatility

     33.60     34.94     34.47

Expected dividend yields

     0.99     0.82     0.47

Expected term (in years)

     5.5       5.5       5.5  

Risk-free rate

     0.79     0.78     1.95

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

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

 

$24 million. The Company realized an additional tax benefit of approximately $1.5 million for the amount of intrinsic value in excess of compensation cost recognized in 2013. As of December 31, 2013, the total compensation cost related to non-vested options not yet recognized was $60 million, which will be recognized over the remaining vesting period of the options.

Stock Appreciation Rights

For some non-executive employees, the Company issued stock appreciation rights (SARs) in lieu of stock options. The SARs vest ratably over four years and are settled in cash upon exercise throughout their ten-year life. In 2012, the Company issued 180,555 SARs with a weighted-average exercise price of $82.63 under the 2011 Omnibus Plan. As of December 31, 2013, a total of 316,127 SARs were outstanding, of which 201,552 were exercisable. Since SARs are cash-settled, the Company records compensation expense based on the fair value of the SARs at the end of each period. As of year-end, the weighted-average fair value of SARs outstanding was $33.41 based on the Black-Scholes valuation methodology using assumptions comparable to those discussed above. During 2013, 237,288 SARs were exercised. The aggregate of cash payments made to settle SARs was $11 million.

Restricted Stock and Restricted Stock Units

The Company has restricted stock and restricted stock unit plans for eligible employees including officers. The programs created under the Omnibus Plans have been approved by Apache’s Board of Directors. In 2013, the Company awarded 3,098,029 restricted stock units at a weighted-average per-share market price of $82.95. In 2012 and 2011, the Company awarded 1,219,886 and 887,851 restricted stock units at a weighted-average per-share market price of $85.67 and $124.16, respectively. The value of the stock issued was established by the market price on the date of grant and is being recorded as compensation expense ratably over the vesting terms. During 2013, 2012, and 2011, $82 million ($53 million after tax), $74 million ($48 million after tax), and $76 million ($49 million after tax), respectively, was charged to expense. In 2013, 2012, and 2011, $30 million, $25 million, and $28 million was capitalized, respectively. As of December 31, 2013, there was $242 million of total unrecognized compensation cost related to 3,952,539 unvested restricted stock units. The weighted-average remaining life of unvested restricted stock units is approximately 1.3 years.

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

 

     Shares     Weighted-
Average Grant-
Date Fair Value
 
     (In thousands)  

Non-vested at January 1, 2013

     2,164     $ 97.34  

Granted

     3,098       82.95  

Vested

     (907     96.79  

Forfeited

     (402     88.61  
  

 

 

   

Non-vested at December 31, 2013

     3,953       86.70  
  

 

 

   

Conditional Restricted Stock Units

To provide long-term incentives for Apache employees to deliver competitive returns to the Company’s stockholders, the Company has granted conditional restricted stock units to eligible employees. The ultimate number of shares awarded from these conditional restricted stock units is based upon measurement of total

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

 

shareholder return of Apache common stock as compared to a designated peer group during a three-year performance period. Should any restricted stock units be awarded at the end of the three-year performance period, 50 percent of restricted stock units awarded will immediately vest, and an additional 25 percent will vest on succeeding anniversaries of the end of the performance period. Grants from two conditional restricted stock unit programs were outstanding at December 31, 2013, as described below:

 

   

In November 2010 the Company’s Board of Directors approved the 2011 Performance Program, pursuant to the 2007 Plan. In January 2011 eligible employees received initial conditional restricted stock unit awards totaling 585,811 units. Based on measurement of total shareholder return relative to the designated peer group at December 31, 2013, zero shares were awarded and all unvested conditional restricted stock units were cancelled. Upon cancellation, all remaining unamortized expense related to these awards was immediately amortized.

 

   

In January 2012 the Company’s Board of Directors approved the 2012 Performance Program, pursuant to the 2011 Plan. In January 2012 eligible employees received initial conditional restricted stock unit awards totaling 851,985 units. A total of 710,686 units were outstanding at December 31, 2013, from which a minimum of zero and a maximum of 1,776,715 units could be awarded.

 

   

In January 2013 the Company’s Board of Directors approved the 2013 Performance Program, pursuant to the 2011 Plan. In January 2013 eligible employees received initial conditional restricted stock unit awards totaling 1,232,176 units. In May 2013, the Company’s Board of Directors cancelled 918,016 awards under the 2013 Performance Program for nonexecutive employees. A total of 310,091 awards were outstanding at December 31, 2013, from which a minimum of zero and a maximum of 775,228 units could be awarded.

The fair value cost of the awards was estimated on the date of grant and is being recorded as compensation expense ratably over the vesting terms. During 2013, 2012, and 2011, $27 million ($17 million after tax), $47 million ($31 million after tax), and $12 million ($8 million after tax), respectively, was charged to expense. During 2013, 2012, and 2011, $13 million, $21 million, and $5 million was capitalized, respectively. As of December 31, 2013, there was $47 million of total unrecognized compensation cost related to 1,020,777 unvested conditional restricted stock units. The weighted-average remaining life of the unvested conditional restricted stock units is approximately 2.1 years.

 

     Shares     Weighted-
Average Grant-
Date Fair Value(1)
 
     (In thousands)        

Non-vested at January 1, 2013

     1,306     $ 78.40  

Granted

     1,232       79.60  

Vested

     0       79.49  

Cancelled

     (1,369     83.34  

Forfeited

     (149     78.09  
  

 

 

   

Non-vested at December 31, 2013

     1,020       73.73  
  

 

 

   

 

(1)

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

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

 

Preferred Stock

The Company has 10,000,000 shares of no par preferred stock authorized, of which 25,000 shares have been designated as Series A Junior Participating Preferred Stock (the Series A Preferred Stock). The Company’s 6.00 percent Mandatory Convertible Preferred Stock, Series D (the Series D Preferred Stock) were converted to Apache common shares in August 2013.

Series A Preferred Stock

In December 1995, the Company declared a dividend of one right (a Right) for each 2.31 shares (adjusted for subsequent stock dividends and a two-for-one stock split) of Apache common stock outstanding on January 31, 1996. Each full Right entitles the registered holder to purchase from the Company one ten-thousandth (1/10,000) of a share of Series A Preferred Stock at a price of $100 per one ten-thousandth of a share, subject to adjustment. The Rights are exercisable 10 calendar days following a public announcement that certain persons or groups have acquired 20 percent or more of the outstanding shares of Apache common stock or 10 business days following commencement of an offer for 30 percent or more of the outstanding shares of Apache’s outstanding common stock (flip-in event); each Right will become exercisable for shares of Apache’s common stock at 50 percent of the then-market price of the common stock. If a 20-percent shareholder of Apache acquires Apache, by merger or otherwise, in a transaction where Apache does not survive or in which Apache’s common stock is changed or exchanged (flip-over event), the Rights become exercisable for shares of the common stock of the Company acquiring Apache at 50 percent of the then-market price for Apache common stock. Any Rights that are or were beneficially owned by a person who has acquired 20 percent or more of the outstanding shares of Apache common stock and who engages in certain transactions or realizes the benefits of certain transactions with the Company will become void. If an offer to acquire all of the Company’s outstanding shares of common stock is determined to be fair by Apache’s board of directors, the transaction will not trigger a flip-in event or a flip-over event. The Company may also redeem the Rights at $.01 per Right at any time until 10 business days after public announcement of a flip-in event. These Rights were originally scheduled to expire on January 31, 2006. Effective as of that date, the Rights were reset to one right per share of common stock and the expiration was extended to January 31, 2016.

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

Series D Preferred Stock

On July 28, 2010, Apache issued 25.3 million depositary shares, each representing a 1/20th interest in a share of Apache’s 6.00-percent Mandatory Convertible Preferred Stock, Series D (Preferred Share), or 1.265 million Preferred Shares. Upon conversion of the outstanding Preferred Shares on August 1, 2013, 14.4 million Apache common shares were issued.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

 

11.     ACCUMULATED OTHER COMPREHENSIVE LOSS

Components of accumulated other comprehensive loss include the following:

 

     For the Year Ended December 31,  
         2013             2012             2011      
     (In millions)  

Currency translation adjustment(1)

   $ (109   $ (109   $ (109

Unrealized gain (loss) on derivatives (Note 3)

     1       (6     114  

Unfunded pension and postretirement benefit plan (Note 9)

     (7     (16     (14
  

 

 

   

 

 

   

 

 

 

Accumulated other comprehensive loss

   $ (115   $ (131   $ (9
  

 

 

   

 

 

   

 

 

 

 

(1)

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

12.     MAJOR CUSTOMERS

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

 

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Table of Contents

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

 

13.     BUSINESS SEGMENT INFORMATION

Apache is engaged in a single line of business. Both domestically and internationally, the Company explores for, develops, and produces natural gas, crude oil and natural gas liquids. At December 31, 2013, the Company had production in six countries: the United States, Canada, Egypt, Australia, the U.K. North Sea, and Argentina. Apache also pursues exploration interests in other countries that may over time result in reportable discoveries and development opportunities. Financial information for each country is presented below:

 

    United States     Canada     Egypt(1)     Australia     North
Sea
    Argentina     Other
International
    Total(1)  
    (In millions)  

2013

               

Oil and gas production revenues

  $ 6,902     $ 1,224     $ 3,917     $ 1,140     $ 2,728     $ 491     $     $ 16,402  

Operating Expenses:

               

Depreciation, depletion, and amortization

               

Recurring

    2,338       505       1,005       423       1,022       230       1       5,524  

Additional

    552                            367       181       76       1,176  

Asset retirement obligation accretion

    94       49              27       68       5              243  

Lease operating expenses

    1,320       459       471       214       400       192              3,056  

Gathering and transportation

    84       155       42              7       9              297  

Taxes other than income

    335       45       8       13       384       47              832  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating Income (Loss)

  $ 2,179     $ 11     $ 2,391     $ 463     $ 480     $ (173   $ (77     5,274  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

Other Income (Expense):

               

Derivative instrument gains (losses), net

                  (399

Other

                  51  

General and administrative

                  (503

Acquisitions, divestitures, and transition

                  (33

Financing costs, net

                  (174
               

 

 

 

Income Before Income Taxes

                $ 4,216  
               

 

 

 

Net Property and Equipment

  $ 27,010     $ 6,058     $ 5,454     $ 6,838     $ 5,622     $ 1,416     $ 23     $ 52,421  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total Assets

  $ 29,940     $ 6,952     $ 8,121     $ 8,094     $ 6,902     $ 1,577     $ 51     $ 61,637  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Additions to Net Property and Equipment

  $ 6,404     $ 1,082     $ 1,309     $ 1,954     $ 1,084     $ 205     $ 24     $ 12,062  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

(1) Includes a noncontrolling interest in Egypt.

  

2012

               

Oil and gas production revenues

  $ 6,226     $ 1,322     $ 4,554     $ 1,575     $ 2,751     $ 519     $     $ 16,947  

Operating Expenses:

               

Depreciation, depletion, and amortization

               

Recurring

    2,056       594       925       466       914       228              5,183  

Additional

           1,883                                   43       1,926  

Asset retirement obligation accretion

    112       41              17       58       4              232  

Lease operating expenses

    1,386       458       410       215       315       184              2,968  

Gathering and transportation

    69       163       39              24       8              303  

Taxes other than income

    292       50       14       11       451       44              862  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating Income (Loss)

  $ 2,311     $ (1,867   $ 3,166     $ 866     $ 989     $ 51     $ (43     5,473  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

Other Income (Expense):

               

Derivative instrument gains (losses), net

                  (79

Other

                  210  

General and administrative

                  (531

Acquisitions, divestitures, and transition

                  (31

Financing costs, net

                  (165
               

 

 

 

Income Before Income Taxes

                $ 4,877  
               

 

 

 

Net Property and Equipment

  $ 28,552     $ 6,640     $ 5,151     $ 5,312     $ 5,927     $ 1,621     $ 77     $ 53,280  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total Assets

  $ 31,175     $ 7,142     $ 7,311     $ 6,280     $ 6,874     $ 1,835     $ 120     $ 60,737  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Additions to Net Property and

               

Equipment

  $ 9,586     $ 1,096     $ 1,153     $ 1,581     $ 1,104     $ 337     $ 98     $ 14,955  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

F-52


Table of Contents

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

 

    United States     Canada     Egypt     Australia     North
Sea
    Argentina     Other
International
    Total  
    (In millions)  

2011

               

Oil and gas production revenues

  $ 6,103     $ 1,617     $ 4,791     $ 1,734     $ 2,091     $ 474     $      $ 16,810  

Operating Expenses:

               

Depreciation, depletion, and amortization

               

Recurring

    1,684       546       818       440       409       198              4,095  

Additional

                                              109       109  

Asset retirement obligation accretion

    97       26              10       17       4              154  

Lease operating expenses

    1,167       470       398       197       208       165              2,605  

Gathering and transportation

    64       165       35              25       7              296  

Taxes other than income

    259       51       13       9       539       28              899  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating Income (Loss)

  $ 2,832     $ 359     $ 3,527     $ 1,078     $ 893     $ 72     $ (109     8,652  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

Other Expense:

               

Other

                  78  

General and administrative

                  (459

Acquisitions, divestitures, and transition

                  (20

Financing costs, net

                  (158
               

 

 

 

Income Before Income Taxes

                $ 8,093  
               

 

 

 

Net Property and Equipment

  $ 21,038     $ 8,022     $ 4,923     $ 4,194     $ 5,737     $ 1,512     $ 22     $ 45,448  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total Assets

  $ 23,499     $ 8,816     $ 6,656     $ 4,681     $ 6,600     $ 1,766     $ 33     $ 52,051  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Additions to Net Property and

               

Equipment

  $ 3,854     $ 1,288     $ 1,015     $ 1,140     $ 4,175     $ 374     $ 73     $ 11,919  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

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Table of Contents

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

 

14.     SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited)

Oil and Gas Operations

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

 

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

2013

               

Oil and gas production revenues

  $ 6,902     $ 1,224     $ 3,917     $ 1,140     $ 2,728     $ 491     $  —      $ 16,402  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating cost:

               

Depreciation, depletion, and amortization

               

Recurring(1)

    2,227       426       881       361       999       220              5,114  

Additional

    552                            367       181       76       1,176  

Asset retirement obligation accretion

    94       49              27       68       5              243  

Lease operating expenses

    1,320       459       471       214       400       192              3,056  

Gathering and transportation

    84       155       42              7       9              297  

Production taxes(2)

    324       40              14       382       36              796  

Income tax

    817       24       1,161       157       313       (53            2,419  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
    5,418       1,153       2,555       773       2,536       590       76       13,101  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Results of operation

  $ 1,484     $ 71     $ 1,362     $ 367     $ 192     $ (99   $ (76   $ 3,301  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Amortization rate per boe

  $ 18.39     $ 10.89     $ 16.21     $ 17.47     $ 37.25     $ 14.13     $  —      $ 18.42  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

2012

               

Oil and gas production revenues

  $ 6,226     $ 1,322     $ 4,554     $ 1,575     $ 2,751     $ 519     $  —      $ 16,947  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating cost:

               

Depreciation, depletion, and amortization

               

Recurring(1)

    1,984       580       924       460       912       225              5,085  

Additional

           1,883                                   109       1,992  

Asset retirement obligation accretion

    112       41              17       58       4              232  

Lease operating expenses

    1,386       458       410       215       315       184              2,968  

Gathering and transportation

    69       163       39              24       8              303  

Production taxes(2)

    279       42              11       451       34              817  

Income tax

    851       (466     1,527       262       614       22              2,810  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
    4,681       2,701       2,900       965       2,374       477       109       14,207  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Results of operation

  $ 1,545     $ (1,379   $ 1,654     $ 610     $ 377     $ 42     $ (109   $ 2,740  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Amortization rate per boe

  $ 17.24     $ 11.66     $ 13.81     $ 17.67     $ 32.65     $ 12.39     $  —      $ 16.88  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

F-54


Table of Contents

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

 

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

2011

               

Oil and gas production revenues

  $ 6,103     $ 1,617     $ 4,791     $ 1,734     $ 2,091     $ 474     $  —      $ 16,810  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating cost:

               

Depreciation, depletion, and amortization

               

Recurring(1)

    1,634       537       818       435       405       195              4,024  

Additional

                                              109       109  

Asset retirement obligation accretion

    97       26              10       17       4              154  

Lease operating expenses

    1,167       470       398       197       208       165              2,605  

Gathering and transportation

    64       165       35              25       7              296  

Production taxes(2)

    255       44              9       538       19              865  

Income tax

    1,025       95       1,699       325       557       29              3,730  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
    4,242       1,337       2,950       976       1,750       419       109       11,783  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Results of operation

  $ 1,861     $ 280     $ 1,841     $ 758     $ 341     $ 55     $ (109   $ 5,027  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Amortization rate per boe

  $ 15.55     $ 10.44     $ 11.63     $ 16.59     $ 20.21     $ 10.87     $  —      $ 13.97  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(1)

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

 

(2)

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

 

(3)

2013 includes a noncontrolling interest in Egypt.

 

F-55


Table of Contents

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

 

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

 

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

2013

               

Acquisitions:

               

Proved

  $ 17     $  —      $ 35     $  —      $ 125     $  —      $     $ 177  

Unproved

           137       11              17                     165  

Exploration

    757       50       563       169       278       53       22       1,892  

Development

    5,435       722       618       996       635       142              8,548  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Costs incurred(1)

  $ 6,209     $ 909     $ 1,227     $ 1,165     $ 1,055     $ 195     $ 22     $ 10,782  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

(1) Includes capitalized interest and asset retirement costs as follows:

  

Capitalized interest

  $ 239     $ 35     $ 15     $ 16     $ 25     $ 10     $     $ 340  

Asset retirement costs

    480       17              (30     67       3              537  

(2) Includes a noncontrolling interest in Egypt.

  

2012

               

Acquisitions:

               

Proved

  $ 1,076     $ 5     $ 28     $ 32     $ 110     $     $     $ 1,251  

Unproved

    2,329                            26                     2,355  

Exploration

    1,369       111       696       149       111       157       96       2,689  

Development

    4,465       762       394       915       837       161       2       7,536  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Costs incurred(1)

  $ 9,239     $ 878     $ 1,118     $ 1,096     $ 1,084     $ 318     $ 98     $ 13,831  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

(1) Includes capitalized interest and asset retirement costs as follows:

  

Capitalized interest

  $ 215     $ 38     $ 16     $ 12     $ 24     $ 11     $     $ 316  

Asset retirement costs

    473       245              207       89       18              1,032  

2011

               

Acquisitions:

               

Proved

  $ 368     $  —      $ (12   $  —      $ 2,399     $     $     $ 2,755  

Unproved

    116       33       2       48       476              13       688  

Exploration

    418       209       570       286       18       202       59       1,762  

Development

    2,832       883       344       429       941       156       2       5,587  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Costs incurred(1)

  $ 3,734     $ 1,125     $ 904     $ 763     $ 3,834     $ 358     $ 74     $ 10,792  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

(1) Includes capitalized interest and asset retirement costs as follows:

  

Capitalized interest

  $ 152     $ 47     $ 18     $ 14     $  —      $ 12     $     $ 243  

Asset retirement costs

    380       228              125       678                     1,411  

 

F-56


Table of Contents

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

 

Capitalized Costs

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

 

    United States     Canada     Egypt(1)     Australia     North Sea     Argentina     Other
International
    Total(1)  
    (In millions)  

2013

               

Proved properties

  $ 41,904     $ 13,231     $ 8,418     $ 7,298     $ 9,378     $ 2,933     $ 228     $ 83,390  

Unproved properties

    5,042       1,116       660       471       702       349       23       8,363  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
    46,946       14,347       9,078       7,769       10,080       3,282       251       91,753  

Accumulated DD&A

    (20,745     (9,310     (5,356     (2,839     (4,811     (1,964     (228     (45,253
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
  $ 26,201     $ 5,037     $ 3,722     $ 4,930     $ 5,269     $ 1,318     $ 23     $ 46,500  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

(1) Includes a noncontrolling interest in Egypt.

  

2012

               

Proved properties

  $ 40,163     $ 13,477     $ 7,165     $ 6,319     $ 8,401     $ 2,706     $ 152     $ 78,383  

Unproved properties

    5,641       1,059       686       284       626       382       76       8,754  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
    45,804       14,536       7,851       6,603       9,027       3,088       228       87,137  

Accumulated DD&A

    (17,968     (8,899     (4,474     (2,478     (3,445     (1,562     (152     (38,978
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
  $ 27,836     $ 5,637     $ 3,377     $ 4,125     $ 5,582     $ 1,526     $ 76     $ 48,159  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Costs Not Being Amortized

The following table sets forth a summary of oil and gas property costs not being amortized at December 31, 2013, by the year in which such costs were incurred. There are no individually significant properties or significant development projects included in costs not being amortized. The majority of the evaluation activities are expected to be completed within five to ten years.

 

     Total      2013      2012      2011      2010
and Prior
 
     (In millions)  

Property acquisition costs

   $ 6,437      $ 466      $ 3,391      $ 899      $ 1,681  

Exploration and development

     1,666        1,138        388        88        52  

Capitalized interest

     260        48        48        30        134  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 8,363      $ 1,652      $ 3,827      $ 1,017      $ 1,867  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Oil and Gas Reserve Information

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

 

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Table of Contents

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

 

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

 

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Table of Contents

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

 

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

 

     Crude Oil and Condensate  
     (Thousands of barrels)  
     United States     Canada     Egypt(1)     Australia     North
Sea
    Argentina     Total(1)  

Proved developed reserves:

              

December 31, 2010

     422,737       90,292       109,657       48,072       115,705       16,583       803,046  

December 31, 2011

     428,251       81,846       105,840       35,725       136,990       16,001       804,653  

December 31, 2012

     474,837       79,695       106,746       29,053       119,635       15,845       825,811  

December 31, 2013

     457,981       80,526       119,242       22,524       100,327       14,195       794,795  

Proved undeveloped reserves:

              

December 31, 2010

     214,117       56,855       17,470       18,064       38,663       4,062       349,231  

December 31, 2011

     205,763       59,746       22,195       32,220       32,415       4,585       356,924  

December 31, 2012

     203,068       70,650       17,288       34,808       28,019       2,981       356,814  

December 31, 2013

     195,835       56,366       16,302       36,703       29,253       2,231       336,690  

Total proved reserves:

              

Balance December 31, 2010

     636,855       147,146       127,127       66,136       154,368       20,645       1,152,277  

Extensions, discoveries and other additions

     45,676       16,712       45,021       15,762       332       3,230       126,733  

Purchase of minerals in-place

     5,097       705                     34,612              40,414  

Revisions of previous estimates

     (8,904     (17,117     (6,185                   215       (31,991

Production

     (43,587     (5,202     (37,928     (13,953     (19,907     (3,503     (124,080

Sale of properties

     (1,123     (653                                 (1,776
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance December 31, 2011

     634,014       141,591       128,035       67,945       169,405       20,587       1,161,577  

Extensions, discoveries and other additions

     84,656       18,935       36,188       6,277       346       1,133       147,535  

Purchase of minerals in-place

     15,942       188              276       2,143              18,549  

Revisions of previous estimates

     (7,474     (4,577     (3,678     (66     (928     671       (16,052

Production

     (49,089     (5,792     (36,511     (10,571     (23,312     (3,565     (128,840

Sale of properties

     (144                                        (144
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance December 31, 2012

     677,905       150,345       124,034       63,861       147,654       18,826       1,182,625  

Extensions, discoveries and other additions

     133,227       10,177       43,738       2,539       1,543       998       192,222  

Purchase of minerals in-place

     85              5              3,623              3,713  

Revisions of previous estimates

     1,683       (531     457       (118     18       24       1,533  

Production

     (53,621     (6,469     (32,690     (7,055     (23,258     (3,422     (126,515

Sale of properties

     (105,463     (16,630                                 (122,093
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance December 31, 2013

     653,816       136,892       135,544       59,227       129,580       16,426       1,131,485  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(1)

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

 

F-59


Table of Contents

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

 

     Natural Gas Liquids  
     (Thousands of barrels)  
     United States     Canada     Egypt     Australia      North Sea     Argentina     Total  

Proved developed reserves:

               

December 31, 2010

     91,800       23,701                             5,875       121,376  

December 31, 2011

     107,490       23,256                      8,753       5,939       145,438  

December 31, 2012

     154,508       21,996                      2,438       5,007       183,949  

December 31, 2013

     184,485       26,099                      2,435       4,110       217,129  

Proved undeveloped reserves:

               

December 31, 2010

     30,361       4,142                             579       35,082  

December 31, 2011

     52,543       8,193                      509       1,215       62,460  

December 31, 2012

     60,889       12,258                      380       876       74,403  

December 31, 2013

     63,538       9,970                      215       1,009       74,732  

Total proved reserves:

               

Balance December 31, 2010

     122,160       27,844                             6,454       156,458  

Extensions, discoveries and other additions

     43,915       5,890       18               72       1,784       51,679  

Purchase of minerals in-place

     586       47                      9,191              9,824  

Revisions of previous estimates

     1,713       774                             17       2,504  

Production

     (8,071     (2,174     (18             (1     (1,102     (11,366

Sale of properties

     (270     (931                                  (1,201
  

 

 

   

 

 

   

 

 

   

 

 

    

 

 

   

 

 

   

 

 

 

Balance December 31, 2011

     160,033       31,450                      9,262       7,153       207,898  

Extensions, discoveries and other additions

     71,965       7,655                      246              79,866  

Purchase of minerals in-place

     230       9                      231              470  

Revisions of previous estimates

     (4,559     (2,569                    (6,329     (169     (13,626

Production

     (12,272     (2,291                    (592     (1,101     (16,256

Sale of properties

                                                  
  

 

 

   

 

 

   

 

 

   

 

 

    

 

 

   

 

 

   

 

 

 

Balance December 31, 2012

     215,397       34,254                      2,818       5,883       258,352  

Extensions, discoveries and other additions

     69,231       4,014                                    73,245  

Purchase of minerals in-place

     45                             295              340  

Revisions of previous estimates

     1,591       546                      1       3       2,141  

Production

     (19,922     (2,442                    (464     (767     (23,595

Sale of properties

     (18,319     (303                                  (18,622
  

 

 

   

 

 

   

 

 

   

 

 

    

 

 

   

 

 

   

 

 

 

Balance December 31, 2013

     248,023       36,069                      2,650       5,119       291,861  
  

 

 

   

 

 

   

 

 

   

 

 

    

 

 

   

 

 

   

 

 

 

 

F-60


Table of Contents

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

 

    Natural Gas  
    (Millions of cubic feet)  
    United States     Canada     Egypt(1)     Australia     North
Sea
    Argentina     Total(1)  

Proved developed reserves:

             

December 31, 2010

    2,284,116       2,181,615       748,573       682,763       4,144       462,206       6,363,417  

December 31, 2011

    2,215,973       2,108,801       700,866       675,618       105,028       447,132       6,253,418  

December 31, 2012

    2,353,587       1,734,657       690,436       596,052       93,319       365,054       5,833,105  

December 31, 2013

    2,005,966       1,294,420       621,825       626,543       88,177       289,133       4,926,064  

Proved undeveloped reserves:

             

December 31, 2010

    988,869       1,310,352       328,344       805,735              70,465       3,503,765  

December 31, 2011

    760,238       1,438,710       282,100       893,966       3,414       90,427       3,468,855  

December 31, 2012

    832,320       403,227       205,055       1,074,018       18,985       97,496       2,631,101  

December 31, 2013

    667,160       439,037       190,355       975,224       18,988       121,584       2,412,348  

Total proved reserves:

             

Balance December 31, 2010

    3,272,985       3,491,967       1,076,917       1,488,498       4,144       532,671       9,867,182  

Extensions, discoveries and other additions

    169,506       505,049       77,049       148,640       475       81,274       981,993  

Purchase of minerals in-place

    67,595       8,838                     104,658              181,091  

Revisions of previous estimates

    (7,716     (133,359     (37,623                   1,107       (177,591

Production

    (315,631     (230,880     (133,377     (67,554     (835     (77,493     (825,770

Sale of properties

    (210,528     (94,104                                 (304,632
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance December 31, 2011

    2,976,211       3,547,511       982,966       1,569,584       108,442       537,559       9,722,273  

Extensions, discoveries and other additions

    365,863       252,130       55,967       176,969       16,397       2,623       869,949  

Purchase of minerals in-place

    313,885       2,503              1,745       8,494              326,627  

Revisions of previous estimates

    (156,840     (1,443,989     (13,974     101              496       (1,614,206

Production

    (312,600     (219,849     (129,468     (78,329     (21,029     (78,128     (839,403

Sale of properties

    (612     (422                                 (1,034
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance December 31, 2012

    3,185,907       2,137,884       895,491       1,670,070       112,304       462,550       8,464,206  

Extensions, discoveries and other additions

    306,721       359,493       44,382       13,351       2,750       16,515       743,212  

Purchase of minerals in-place

    855                            10,680              11,535  

Revisions of previous estimates

    61,247       109,551       2,413       (101     32       49       173,191  

Production

    (285,187     (181,593     (130,106     (81,553     (18,601     (68,397     (765,437

Sale of properties

    (596,417     (691,878                                 (1,288,295
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance December 31, 2013

    2,673,126       1,733,457       812,180       1,601,767       107,165       410,717       7,338,412  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(1)

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

 

F-61


Table of Contents

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

 

     Total Equivalent Reserves  
     (Thousands barrels of oil equivalent)  
     United States     Canada     Egypt(1)     Australia     North
Sea
    Argentina     Total(1)  

Proved developed reserves:

              

December 31, 2010

     895,223       477,594       234,419       161,866       116,396       99,493       1,984,991  

December 31, 2011

     905,069       456,569       222,651       148,328       163,248       96,462       1,992,327  

December 31, 2012

     1,021,610       390,800       221,819       128,395       137,626       81,695       1,981,945  

December 31, 2013

     976,795       322,362       222,880       126,948       117,457       66,494       1,832,936  

Proved undeveloped reserves:

              

December 31, 2010

     409,290       279,389       72,194       152,353       38,663       16,385       968,274  

December 31, 2011

     385,013       307,724       69,212       181,214       33,493       20,871       997,527  

December 31, 2012

     402,677       150,113       51,464       213,811       31,563       20,106       869,734  

December 31, 2013

     370,566       139,509       48,028       199,240       32,633       23,504       813,480  

Total proved reserves:

              

Balance December 31, 2010

     1,304,512       756,984       306,613       314,219       155,059       115,878       2,953,265  

Extensions, discoveries and other additions

     117,842       106,778       57,882       40,534       483       18,559       342,078  

Purchase of minerals in-place

     16,949       2,225                   61,246             80,420  

Revisions of previous estimates

     (8,477     (38,570     (12,456                 417       (59,086

Production

     (104,263     (45,856     (60,176     (25,211     (20,047     (17,521     (273,074

Sale of properties

     (36,481     (17,268                             (53,749
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance December 31, 2011

     1,290,082       764,293       291,863       329,542       196,741       117,333       2,989,854  

Extensions, discoveries and other additions

     217,598       68,612       45,516       35,772       3,325       1,570       372,393  

Purchase of minerals in-place

     68,486       614             567       3,790             73,457  

Revisions of previous estimates

     (38,172     (247,811     (6,007     (49     (7,258     585       (298,712

Production

     (113,461     (44,725     (58,089     (23,626     (27,409     (17,687     (284,997

Sale of properties

     (246     (70                             (316
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance December 31, 2012

     1,424,287       540,913       273,283       342,206       169,189       101,801       2,851,679  

Extensions, discoveries and other additions

     253,578       74,107       51,135       4,764       2,001       3,751       389,336  

Purchase of minerals in-place

     273             5             5,698             5,976  

Revisions of previous estimates

     13,482       18,274       859       (135     24       35       32,539  

Production

     (121,074     (39,177     (54,374     (20,647     (26,822     (15,589     (277,683

Sale of properties

     (223,185     (132,246                             (355,431
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance December 31, 2013

     1,347,361       461,871       270,908       326,188       150,090       89,998       2,646,416  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(1)

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

 

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

 

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

Approximately 10 percent of Apache’s year-end 2013 estimated proved developed reserves are classified as proved not producing. These reserves relate to zones that are either behind pipe, or that have been completed but not yet produced, or zones that have been produced in the past, but are not now producing because of mechanical reasons. These reserves are considered to be a lower tier of reserves than producing reserves because they are frequently based on volumetric calculations rather than performance data. Future production associated with behind pipe reserves is scheduled to follow depletion of the currently producing zones in the same wellbores. Additional capital may have to be spent to access these reserves. The capital and economic impact of production timing are reflected in this Note 14, under “Future Net Cash Flows.”

Future Net Cash Flows

Future cash inflows as of December 31, 2013 and 2012 were calculated using an unweighted arithmetic average of oil and gas prices in effect on the first day of each month in the respective year, except where prices are defined by contractual arrangements. Operating costs, production and ad valorem taxes and future development costs are based on current costs with no escalation.

 

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APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

 

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

 

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

2013

              

Cash inflows

   $ 79,654     $ 19,260     $ 16,864     $ 20,637     $ 15,359     $ 2,824     $ 154,598  

Production costs

     (26,032     (8,105     (2,590     (4,494     (8,147     (1,176     (50,554

Development costs

     (4,834     (2,458     (1,899     (2,283     (3,284     (397     (15,155

Income tax expense

     (12,832     (678     (4,328     (3,072     (2,376     (142     (23,428
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net cash flows

     35,956       8,019       8,047       10,788       1,552       1,109       65,471  

10 percent discount rate

     (20,117     (3,987     (2,193     (6,423     85       (242     (32,877
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Discounted future net cash flows(1)

   $ 15,839     $ 4,032     $ 5,854     $ 4,365     $ 1,637     $ 867     $ 32,594  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

2012

              

Cash inflows

   $ 84,060     $ 20,512     $ 16,210     $ 20,823     $ 16,732     $ 3,010     $ 161,347  

Production costs

     (27,230     (8,543     (2,126     (4,896     (8,451     (1,162     (52,408

Development costs

     (6,768     (2,916     (1,756     (2,484     (3,053     (248     (17,225

Income tax expense

     (12,740     (754     (4,246     (3,172     (3,163     (141     (24,216
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net cash flows

     37,322       8,299       8,082       10,271       2,065       1,459       67,498  

10 percent discount rate

     (19,464     (4,472     (2,107     (6,361     (98     (443     (32,945
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Discounted future net cash flows(1)

   $ 17,858     $ 3,827     $ 5,975     $ 3,910     $ 1,967     $ 1,016     $ 34,553  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(1)

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

 

(2)

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

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

 

     For the Year Ended December 31,  
     2013     2012     2011  
     (In millions)  

Sales, net of production costs

   $ (12,271   $ (12,589   $ (13,152

Net change in prices and production costs

     1,438       (1,941     12,167  

Discoveries and improved recovery, net of related costs

     6,892       6,742       6,751  

Change in future development costs

     (2,017     (935     (2,250

Previously estimated development costs incurred during the period

     4,654       4,359       2,479  

Revision of quantities

     500       (4,065     (1,475

Purchases of minerals in-place

     227       1,181       2,139  

Accretion of discount

     4,823       5,234       4,161  

Change in income taxes

     855       2,711       (4,303

Sales of properties

     (6,232     (3     (1,285

Change in production rates and other

     (828     (2,088     273  
  

 

 

   

 

 

   

 

 

 
   $ (1,959   $ (1,394   $ 5,505  
  

 

 

   

 

 

   

 

 

 

 

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Table of Contents

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

 

15.     SUPPLEMENTAL QUARTERLY FINANCIAL DATA (Unaudited)

 

     First      Second      Third      Fourth      Total  
     (In millions, except per share amounts)  

2013

              

Revenues and other

   $ 4,076      $ 4,383      $ 4,019      $ 3,576      $ 16,054  

Expenses(2)

     3,359        3,348        3,713        3,346        13,766  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Net income including noncontrolling interest

   $ 717      $ 1,035      $ 306      $ 230      $ 2,288  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Net income attributable to common stock

   $ 698      $ 1,016      $ 300      $ 174      $ 2,188  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Net income per common share(1):

              

Basic

   $ 1.78      $ 2.59      $ 0.75      $ 0.44      $ 5.53  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Diluted

   $ 1.76      $ 2.54      $ 0.75      $ 0.43      $ 5.50  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

2012

              

Revenues and other

   $ 4,536      $ 3,972      $ 4,179      $ 4,391      $ 17,078  

Expenses(2)

     3,739        3,616        3,999        3,723        15,077  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Net income including noncontrolling interest

   $ 797      $ 356      $ 180      $ 668      $ 2,001  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Net income attributable to common stock

   $ 778      $ 337      $ 161      $ 649      $ 1,925  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Net income per common share(1):

              

Basic

   $ 2.02      $ 0.87      $ 0.41      $ 1.66      $ 4.95  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Diluted

   $ 2.00      $ 0.86      $ 0.41      $ 1.64      $ 4.92  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1)

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

 

(2)

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

16.     SUPPLEMENTAL GUARANTOR INFORMATION

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

Apache Finance Canada has been fully consolidated in Apache’s consolidated financial statements. As such, these condensed consolidating financial statements should be read in conjunction with the financial statements of Apache Corporation and subsidiaries and notes thereto, of which this note is an integral part.

 

F-65


Table of Contents

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

 

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME

For the Year Ended December 31, 2013

 

     Apache
Corporation
    Apache
Finance
Canada
     All Other
Subsidiaries
of Apache
Corporation
    Reclassifications
& Eliminations
    Consolidated  
     (In millions)  

REVENUES AND OTHER:

           

Oil and gas production revenues

   $ 4,585     $  —       $ 11,817     $  —      $ 16,402  

Equity in net income (loss) of affiliates

     2,313       17        36       (2,366       

Derivative instrument gains (losses), net

     (399                           (399

Other

            61        (6     (4     51  
  

 

 

   

 

 

    

 

 

   

 

 

   

 

 

 
     6,499       78        11,847       (2,370     16,054  
  

 

 

   

 

 

    

 

 

   

 

 

   

 

 

 

OPERATING EXPENSES:

           

Depreciation, depletion, and amortization

     2,250               4,450              6,700  

Asset retirement obligation accretion

     67               176              243  

Lease operating expenses

     939               2,117              3,056  

Gathering and transportation

     61               236              297  

Taxes other than income

     190               642              832  

General and administrative

     408               99       (4     503  

Acquisitions, divestitures, and transition

     33                             33  

Financing costs, net

     97       5        72              174  
  

 

 

   

 

 

    

 

 

   

 

 

   

 

 

 
     4,045       5        7,792       (4     11,838  
  

 

 

   

 

 

    

 

 

   

 

 

   

 

 

 

INCOME (LOSS) BEFORE INCOME TAXES

     2,454       73        4,055       (2,366     4,216  

Provision (benefit) for income taxes

     222       20        1,686              1,928  
  

 

 

   

 

 

    

 

 

   

 

 

   

 

 

 

NET INCOME (LOSS) INCLUDING

           

NONCONTROLLING INTEREST

     2,232       53        2,369       (2,366     2,288  

Net income attributable to noncontrolling interest

                    56              56  

Preferred stock dividends

     44                             44  
  

 

 

   

 

 

    

 

 

   

 

 

   

 

 

 

NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK

   $ 2,188     $ 53      $ 2,313     $ (2,366   $ 2,188  
  

 

 

   

 

 

    

 

 

   

 

 

   

 

 

 

COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK

   $ 2,204     $ 53      $ 2,313     $ (2,366   $ 2,204  
  

 

 

   

 

 

    

 

 

   

 

 

   

 

 

 

 

F-66


Table of Contents

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

 

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME

For the Year Ended December 31, 2012

 

     Apache
Corporation
    Apache
Finance
Canada
    All Other
Subsidiaries
of Apache
Corporation
     Reclassifications
& Eliminations
    Consolidated  
     (In millions)  

REVENUES AND OTHER:

           

Oil and gas production revenues

   $ 4,237     $  —      $ 12,710      $  —      $ 16,947  

Equity in net income (loss) of affiliates

     1,523       (737     248        (1,034       

Other

     (80     69       146        (4     131  
  

 

 

   

 

 

   

 

 

    

 

 

   

 

 

 
     5,680       (668     13,104        (1,038     17,078  
  

 

 

   

 

 

   

 

 

    

 

 

   

 

 

 

OPERATING EXPENSES:

           

Depreciation, depletion, and amortization

     1,391              5,718               7,109  

Asset retirement obligation accretion

     76              156               232  

Lease operating expenses

     957              2,011               2,968  

Gathering and transportation

     51              252               303  

Taxes other than income

     185              677               862  

General and administrative

     425              110        (4     531  

Acquisitions, divestitures, and transition

     25              6               31  

Financing costs, net

     94       (20     91               165  
  

 

 

   

 

 

   

 

 

    

 

 

   

 

 

 
     3,204       (20     9,021        (4     12,201  
  

 

 

   

 

 

   

 

 

    

 

 

   

 

 

 

INCOME (LOSS) BEFORE INCOME TAXES

     2,476       (648     4,083        (1,034     4,877  

Provision (benefit) for income taxes

     475       (159     2,560               2,876  
  

 

 

   

 

 

   

 

 

    

 

 

   

 

 

 

NET INCOME (LOSS)

     2,001       (489     1,523        (1,034     2,001  

Preferred stock dividends

     76                             76  
  

 

 

   

 

 

   

 

 

    

 

 

   

 

 

 

NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK

   $ 1,925     $ (489   $ 1,523      $ (1,034   $ 1,925  
  

 

 

   

 

 

   

 

 

    

 

 

   

 

 

 

COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK

   $ 1,803     $ (489   $ 1,523      $ (1,034   $ 1,803  
  

 

 

   

 

 

   

 

 

    

 

 

   

 

 

 

 

F-67


Table of Contents

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

 

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME

For the Year Ended December 31, 2011

 

     Apache
Corporation
     Apache
Finance
Canada
    All Other
Subsidiaries
of Apache
Corporation
    Reclassifications
& Eliminations
    Consolidated  
     (In millions)  

REVENUES AND OTHER:

           

Oil and gas production revenues

   $ 4,380      $     $ 12,430     $  —      $ 16,810  

Equity in net income (loss) of affiliates

     3,590        234       46       (3,870       

Other

     9        125       (52     (4     78  
  

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 
     7,979        359       12,424       (3,874     16,888  
  

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

OPERATING EXPENSES:

           

Depreciation, depletion, and amortization

     1,257               2,947              4,204  

Asset retirement obligation accretion

     70               84              154  

Lease operating expenses

     794               1,811              2,605  

Gathering and transportation

     51               245              296  

Taxes other than income

     170               729              899  

General and administrative

     365               98       (4     459  

Acquisitions, divestitures, and transition

     14               6              20  

Financing costs, net

     149        (18     27              158  
  

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 
     2,870        (18     5,947       (4     8,795  
  

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

INCOME (LOSS) BEFORE INCOME TAXES

     5,109        377       6,477       (3,870     8,093  

Provision (benefit) for income taxes

     525        97       2,887              3,509  
  

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

NET INCOME (LOSS)

     4,584        280       3,590       (3,870     4,584  

Preferred stock dividends

     76                             76  
  

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK

   $ 4,508      $ 280     $ 3,590     $ (3,870   $ 4,508  
  

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK

   $ 4,640      $ 280     $ 3,590     $ (3,870   $ 4,640  
  

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

 

F-68


Table of Contents

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

 

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

For the Year Ended December 31, 2013

 

     Apache
Corporation
    Apache
Finance
Canada
    All Other
Subsidiaries
of Apache
Corporation
    Reclassifications
& Eliminations
     Consolidated  
     (In millions)  

CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES

   $ 1,421     $ 315     $ 8,099     $      $ 9,835  
  

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

CASH FLOWS FROM INVESTING ACTIVITIES:

        

Additions to oil and gas property

     (4,291            (5,728             (10,019

Additions to gas gathering, transmission, and processing facilities

     (124            (1,077             (1,201

Proceeds from divestiture of Gulf of Mexico Shelf properties

     3,702                             3,702  

Acquisitions, other

                   (215             (215

Proceeds from Kitimat LNG transaction, net

                   396               396  

Proceeds from sale of oil and gas properties

                   307               307  

Other

     (58            (28             (86
  

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES

     (771            (6,345             (7,116
  

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

CASH FLOWS FROM FINANCING ACTIVITIES:

        

Commercial paper, credit facility, and bank notes, net

     (501            (12             (513

Intercompany borrowings

     3,056       1       (3,057               

Payments on fixed rate debt

     (1,722     (350                    (2,072

Dividends paid

     (360                           (360

Proceeds from sale of noncontrolling interest

                   2,948               2,948  

Shares repurchased

     (997                           (997

Other

     29       37       (45             21  
  

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES

     (495     (312     (166             (973
  

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS

     155       3       1,588               1,746  

CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR

                   160               160  
  

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

CASH AND CASH EQUIVALENTS AT END OF PERIOD

   $ 155     $ 3     $ 1,748     $       $ 1,906  
  

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

 

F-69


Table of Contents

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

 

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

For the Year Ended December 31, 2012

 

     Apache
Corporation
    Apache
Finance
Canada
    All Other
Subsidiaries
of Apache
Corporation
    Reclassifications
& Eliminations
    Consolidated  
     (In millions)  

CASH PROVIDED BY OPERATING ACTIVITIES

   $ 2,357     $ (40   $ 6,187     $  —      $ 8,504  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

CASH FLOWS FROM INVESTING ACTIVITIES:

        

Additions to oil and gas property

     (3,313            (5,468            (8,781

Additions to gas gathering, transmission, and processing facilities

     (48            (702            (750

Acquisition of Cordillera

     (2,666                          (2,666

Equity investment in Yara Pilbara Holdings Pty Limited

                   (439            (439

Acquisitions, other

     (66            (186            (252

Proceeds from sale of oil and gas properties

     25              2              27  

Investment in subsidiaries, net

     (657                   657         

Other

     (450            (113            (563
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES

     (7,175            (6,906     657       (13,424
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

CASH FLOWS FROM FINANCING ACTIVITIES:

        

Commercial paper, credit facility, and bank notes, net

     502              47              549  

Intercompany borrowings

                   697       (697       

Fixed rate debt borrowings

     4,978                            4,978  

Payments on fixed rate debt

     (400                          (400

Dividends paid

     (332                          (332

Other

     29       35       (114     40       (10
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES

     4,777       35       630       (657     4,785  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS

     (41     (5     (89            (135

CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR

     41       5       249              295  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

CASH AND CASH EQUIVALENTS AT END OF PERIOD

   $  —      $     $ 160     $  —      $ 160  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

F-70


Table of Contents

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

 

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

For the Year Ended December 31, 2011

 

     Apache
Corporation
    Apache
Finance
Canada
    All Other
Subsidiaries
of Apache
Corporation
    Reclassifications
& Eliminations
    Consolidated  
     (In millions)  

CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES

   $ 2,191     $ 13     $ 7,749     $  —      $ 9,953  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

CASH FLOWS FROM INVESTING ACTIVITIES:

      

Additions to oil and gas property

     (1,478            (4,936            (6,414

Additions to gas gathering, transmission, and processing facilities

                   (664            (664

Acquisitions of Mobil North Sea

                   (1,246            (1,246

Acquisitions, other

     (448            (119            (567

Proceeds from sales of oil and gas properties

     204              218              422  

Investment in and advances to subsidiaries, net

     772                     (772       

Other

     (81            (95            (176
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

NET CASH USED IN INVESTING ACTIVITIES

     (1,031            (6,842     (772     (8,645
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

CASH FLOWS FROM FINANCING ACTIVITIES:

      

Commercial paper, credit facility, and bank notes, net

     (927            2              (925

Intercompany borrowings

            (1     (763     764         

Dividends paid

     (306                          (306

Other

     108       (7     (25     8       84  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES

     (1,125     (8     (786     772       (1,147
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS

     35       5       121              161   

CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR

     6              128              134  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

CASH AND CASH EQUIVALENTS AT END OF PERIOD

   $ 41     $ 5     $ 249     $  —      $ 295  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

F-71


Table of Contents

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

 

CONDENSED CONSOLIDATING BALANCE SHEET

December 31, 2013

 

     Apache
Corporation
     Apache
Finance
Canada
     All Other
Subsidiaries
of Apache
Corporation
     Reclassifications
& Eliminations
    Consolidated  
     (In millions)  
ASSETS              

CURRENT ASSETS:

             

Cash and cash equivalents

   $ 155      $ 3      $ 1,748      $  —      $ 1,906  

Receivables, net of allowance

     1,043                1,909               2,952  

Inventories

     48                843               891  

Drilling advances

     49                322               371  

Derivative instruments

     1                               1  

Prepaid assets and other

     99                146               245  

Intercompany receivable

     5,357                        (5,357       
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 
     6,752        3        4,968        (5,357     6,366  
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

PROPERTY AND EQUIPMENT, NET

     16,092                36,329               52,421  
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

OTHER ASSETS:

             

Intercompany receivable

     1,572                        (1,572       

Equity in affiliates

     24,743        1,155        449        (26,347       

Goodwill, net

     173                1,196               1,369  

Deferred charges and other

     166        1,006        1,309        (1,000     1,481  
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 
   $ 49,498      $ 2,164      $ 44,251      $ (34,276   $ 61,637  
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 
LIABILITIES AND EQUITY              

CURRENT LIABILITIES:

             

Accounts payable

   $ 956      $ 2      $ 658      $  —      $ 1,616  

Current debt

                     53               53  

Asset retirement obligation

     115                6               121  

Derivative instruments

     299                               299  

Other current liabilities

     896        10        1,705               2,611  

Intercompany payable

                     5,357        (5,357       
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 
     2,266        12        7,779        (5,357     4,700  
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

LONG-TERM DEBT

     9,374        298                       9,672  
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:

             

Intercompany payable

                     1,572        (1,572       

Income taxes

     3,586                4,778               8,364  

Asset retirement obligation

     430                2,671               3,101  

Other

     446        250        711        (1,000     407  
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 
     4,462        250        9,732        (2,572     11,872  
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

COMMITMENTS AND CONTINGENCIES APACHE SHAREHOLDERS’ EQUITY

     33,396        1,604        24,743        (26,347     33,396  
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

Noncontrolling interest

                     1,997               1,997  
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

TOTAL EQUITY

     33,396        1,604        26,740        (26,347     35,393  
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 
   $ 49,498      $ 2,164      $ 44,251      $ (34,276   $ 61,637  
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

 

F-72


Table of Contents

APACHE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  —  (Continued)

 

CONDENSED CONSOLIDATING BALANCE SHEET

December 31, 2012

 

     Apache
Corporation
     Apache
Finance
Canada
     All Other
Subsidiaries
of Apache
Corporation
     Reclassifications
& Eliminations
    Consolidated  
     (In millions)  
ASSETS              

CURRENT ASSETS:

             

Cash and cash equivalents

   $  —       $  —       $ 160      $  —      $ 160  

Receivables, net of allowance

     876                2,210               3,086  

Inventories

     95                813               908  

Drilling advances

     21        1        562               584  

Derivative instruments

     31                               31  

Prepaid assets and other

     102                91                193   

Intercompany receivable

     3,766                         (3,766       
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 
     4,891        1        3,836        (3,766     4,962  
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

PROPERTY AND EQUIPMENT, NET

     18,517                34,763               53,280  
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

OTHER ASSETS:

             

Intercompany receivable

     4,628                        (4,628       

Equity in affiliates

     21,047        934        97        (22,078       

Goodwill, net

     173                1,116               1,289  

Deferred charges and other

     152        1,002        1,052        (1,000     1,206  
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 
   $ 49,408      $ 1,937      $ 40,864      $ (31,472   $ 60,737  
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 
LIABILITIES AND EQUITY              

CURRENT LIABILITIES:

             

Accounts payable

   $ 639      $ 1      $ 452      $      $ 1,092  

Current debt

     912                78               990  

Asset retirement obligation

     471                7               478  

Derivative instruments

     96                20               116  

Other current liabilities

     893        3        1,964               2,860  

Intercompany payable

                     3,766         (3,766       
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 
     3,011        4        6,287        (3,766     5,536  
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

LONG-TERM DEBT

     10,706        647        2               11,355  
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:

             

Intercompany payable

                     4,628         (4,628       

Income taxes

     2,990        5        5,029               8,024  

Asset retirement obligation

     992                3,108               4,100  

Other

     378        250        763        (1,000     391  
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 
     4,360        255        13,528        (5,628     12,515  
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

COMMITMENTS AND CONTINGENCIES TOTAL EQUITY

     31,331        1,031        21,047        (22,078     31,331  
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 
   $ 49,408      $ 1,937      $ 40,864      $ (31,472   $ 60,737  
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

 

F-73


Table of Contents
Board of Directors   Officers

G. Steven Farris

Chairman of the Board, Chief Executive Officer, and President

Apache Corporation

 

Randolph M. Ferlic, M.D.(1)

Founder and Former President,

Surgical Services of the Great Plains, P.C.

 

Eugene C. Fiedorek(1)

Private Investor, Co-Founder and Former President

and Managing Director, EnCap Investments L.C.

 

A.D. Frazier, Jr.(2)(4)

President, Georgia Oak Partners

 

Chansoo Joung(1)(3)

Senior Advisor and Former Partner,

Warburg Pincus LLC

 

George D. Lawrence(2)

Private Investor; Former Chief Executive Officer,

The Phoenix Resource Companies, Inc.

 

John E. Lowe(2)(4)

Former Executive Vice President,

ConocoPhillips

 

William C. Montgomery(2)(3)

Managing Director, Quantum Energy Partners

 

Amy H. Nelson

President and Founder, Greenridge Advisors, LLC

 

Rodman D. Patton(1)

Former Managing Director,

Merrill Lynch Energy Group

 

Charles J. Pitman(3)(4)

Former Regional President — Middle East/

Caspian/Egypt/India, BP Amoco plc

 

G. Steven Farris

Chairman of the Board, Chief Executive Officer, and President

 

John J. Christmann

Executive Vice President and Chief Operating Officer — North America

 

Thomas E. Voytovich

Executive Vice President and Chief Operating Officer — International

 

Michael S. Bahorich

Executive Vice President and Chief Technology Officer

 

Rodney J. Eichler

Executive Advisor to the Chairman; Chief Executive Officer — Kitimat

 

Margery M. Harris

Executive Vice President — Human Resources

 

P. Anthony Lannie

Executive Vice President and General Counsel

 

Alfonso Leon

Executive Vice President and Chief Financial Officer

 

W. Kregg Olson

Executive Vice President — Corporate Reservoir Engineering

 

Thomas P. Chambers

Senior Vice President, Finance

 

Matthew W. Dundrea

Senior Vice President — Treasury and Administration

 

Robert J. Dye

Senior Vice President — Global Communication and Corporate Affairs

 

Janine J. McArdle

Senior Vice President — Gas Monetization

 

Sarah B. Teslik

Senior Vice President — Policy and Governance

 

Jon A. Graham

Vice President — Environmental, Health and Safety

 

Rodney A. Gryder

Vice President — Audit

 

Rebecca A. Hoyt

Vice President — Chief Accounting Officer and Controller

 

Aaron S.G. Merrick

Vice President — Information Technology

 

Urban F. O’Brien

Vice President — Government Affairs

 

F. Brady Parish, Jr

Vice President — Investor Relations

 

Jon W. Sauer

Vice President — Tax

 

Cheri L. Peper

Corporate Secretary

 

(1)

Audit Committee

 

(2)

Management Development and Compensation Committee

 

(3)

Corporate Governance and Nominating Committee

 

(4)

Stock Plan Committee


Table of Contents

Shareholder Information

Stock Data

 

    Price Range     Dividends
per Share
 
    High     Low     Declared     Paid  

2013

       

First Quarter

  $ 86.35      $ 72.20      $ 0.20      $ 0.17   

Second Quarter

    87.57        67.91        0.20        0.20   

Third Quarter

    89.17        75.07        0.20        0.20   

Fourth Quarter

    94.84        84.15        0.20        0.20   

2012

       

First Quarter

  $ 112.09      $ 91.48      $ 0.17      $ 0.15   

Second Quarter

    102.13        77.93        0.17        0.17   

Third Quarter

    94.87        81.55        0.17        0.17   

Fourth Quarter

    89.08        74.50        0.17        0.17   

The Company has paid cash dividends on its common stock for 49 consecutive years through December 31, 2013. Future dividend payments will depend upon the Company’s level of earnings, financial requirements and other relevant factors.

Apache common stock is listed on the New York and Chicago stock exchanges and the NASDAQ National Market (symbol APA). At December 31, 2013, the Company’s shares of common stock outstanding were held by approximately 5,000 shareholders of record and 327,000 beneficial owners. Also listed on the New York Stock Exchange are Apache Finance Canada’s 7.75% notes, due 2029 (symbol APA/29).

Corporate Offices

One Post Oak Central

2000 Post Oak Boulevard

Suite 100

Houston, Texas 77056-4400

(713) 296-6000

Independent Public Accountants

Ernst & Young LLP

Five Houston Center

1401 McKinney Street, Suite 1200

Houston, Texas 77010-2007

Stock Transfer Agent and Registrar

Wells Fargo Bank, N.A.

Attn: Shareowner Services

P.O. Box 64854

South St. Paul, Minnesota 55164-0854

(651) 450-4064 or (800) 468-9716

Communications concerning the transfer of shares, lost certificates, dividend checks, duplicate mailings, or change of address should be directed to the stock transfer agent. Shareholders can access account information on the web site: www.shareowneronline.com

Dividend Reinvestment Plan

Shareholders of record may invest their dividends automatically in additional shares of Apache common stock at the market price. Participants may also invest up to an additional $25,000 in Apache shares each quarter through this service. All bank service fees and brokerage commissions on purchases are paid by Apache. A prospectus describing the terms of the Plan and an authorization form may be obtained from the Company’s stock transfer agent, Wells Fargo Bank, N.A.

Direct Registration

Shareholders of record may hold their shares of Apache common stock in book-entry form. This eliminates costs related to safekeeping or replacing paper stock certificates. In addition, shareholders of record may request electronic movement of book-entry shares between your account with the Company’s stock transfer agent and your broker. Stock certificates may be converted to book-entry shares at any time. Questions regarding this service may be directed to the Company’s stock transfer agent, Wells Fargo Bank, N.A.

Annual Meeting

Apache will hold its annual meeting of shareholders on Thursday, May 15, 2014, at 10:00 a.m. in the Ballroom, Hilton Houston Post Oak, 2001 Post Oak Boulevard, Houston, Texas. Apache plans to web cast the annual meeting live; connect through the Apache web site: www.apachecorp.com

Stock Held in “Street Name”

The Company maintains a direct mailing list to ensure that shareholders with stock held in brokerage accounts receive information on a timely basis. Shareholders wanting to be added to this list should direct their requests to Apache’s Public and International Affairs Department, 2000 Post Oak Boulevard, Suite 100, Houston, Texas, 77056-4400, by calling (713) 296-6157 or by registering on Apache’s web site: www.apachecorp.com

Form 10-K Request

Shareholders and other persons interested in obtaining, without cost, a copy of the Company’s Form 10-K filed with the Securities and Exchange Commission may do so by writing to Cheri L. Peper, Corporate Secretary, 2000 Post Oak Boulevard, Suite 100, Houston, Texas, 77056-4400.

Investor Relations

Shareholders, brokers, securities analysts, or portfolio managers seeking information about the Company are welcome to contact F. Brady Parish, Jr., Vice President of Investor Relations, at (713) 296-6472.

Members of the news media and others seeking information about the Company should contact Apache’s Public and International Affairs Department at (713) 296-7276.

Web site: www.apachecorp.com

 


Table of Contents

INDEX TO EXHIBITS

 

EXHIBIT

NO.

      

DESCRIPTION

2.1      Agreement and Plan of Merger, dated April 14, 2010, by and among Registrant, ZMZ Acquisitions LLC, and Mariner Energy, Inc. (incorporated by reference to Exhibit 2.1 to Registrant’s Current Report on Form 8-K, dated April 14, 2010, filed April 16, 2010, SEC File No. 001-4300) (the schedules and annexes have been omitted pursuant to Item 601(b)(2) of Regulation S-K).
2.2      Amendment No. 1, dated August 2, 2010, to Agreement and Plan of Merger, dated April 14, 2010, by and among Registrant, ZMZ Acquisitions LLC, and Mariner Energy, Inc. (incorporated by reference to Exhibit 2.1 to Registrant’s Current Report on Form 8-K, dated August 2, 2010, filed on August 3, 2010, SEC File No. 001-4300) (the schedules and annexes have been omitted pursuant to Item 601(b)(2) of Regulation S-K).
2.3      Purchase and Sale Agreement by and between BP America Production Company and ZPZ Delaware I LLC dated July 20, 2010 (incorporated by reference to Exhibit 2.1 to Registrant’s Current Report on Form 8-K/A, dated July 20, 2010, filed on July 21, 2010, SEC File No. 001-4300) (the exhibits and schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K).
2.4      Partnership Interest and Share Purchase and Sale Agreement by and between BP Canada Energy and Apache Canada Ltd. dated July 20, 2010 (incorporated by reference to Exhibit 2.2 to Registrant’s Current Report on Form 8-K/A, dated July 20, 2010, filed on July 21, 2010, SEC File No. 001-4300) (the exhibits have been omitted pursuant to Item 601(b)(2) of Regulation S-K).
2.5      Purchase and Sale Agreement by and among BP Egypt Company, BP Exploration (Delta) Limited and ZPZ Egypt Corporation LDC dated July 20, 2010 (incorporated by reference to Exhibit 2.3 to Registrant’s Current Report on Form 8-K/A, dated July 20, 2010, filed on July 21, 2010, SEC File No. 001-4300) (the exhibits and schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K).
3.1      Restated Certificate of Incorporation of Registrant, dated September 19, 2013, as filed with the Secretary of State of Delaware on September 19, 2013 (incorporated by reference to Exhibit 3.2 to Registrant’s Current Report on Form 8-K filed September 20, 2013, SEC File No. 001-4300).
3.2      Certificate of Designations of the 6.00% Mandatory Convertible Preferred Stock, Series D (incorporated by reference to Exhibit 3.3 to Registrant’s Registration Statement on Form 8-A, dated July 29, 2010, SEC File No. 001-4300).
3.3      Certificate of Elimination of Series D Preferred Stock of Registrant, dated September 18, 2013, as filed with the Secretary of State of Delaware on September 19, 2013 (incorporated by reference to Exhibit 3.1 to Registrant’s Current Report on Form 8-K filed September 19, 2013, SEC File No. 001-4300).
3.4      Bylaws of Registrant, as amended May 16, 2013 (incorporated by reference to Exhibit 3.1 to Registrant’s Current Report on Form 8-K filed May 17, 2013, SEC File No. 001-4300).
4.1      Form of Certificate for Registrant’s Common Stock (incorporated by reference to Exhibit 4.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2004, SEC File No. 001-4300).
4.2      Form of Certificate for the 6.00% Mandatory Convertible Preferred Stock, Series D (incorporated by reference to Exhibit A of Exhibit 3.3 to Registrant’s Registration Statement on Form 8-A, dated July 29, 2010, SEC File No. 001-4300).
4.3      Form of 3.625% Notes due 2021 (incorporated by reference to Exhibit 4.1 to Registrant’s Current Report on Form 8-K, dated November 30, 2010, filed on December 3, 2010, SEC File No. 001-4300).


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4.4        Form of 5.250% Notes due 2042 (incorporated by reference to Exhibit 4.2 to Registrant’s Current Report on Form 8-K, dated November 30, 2010, filed on December 3, 2010, SEC File No. 001-4300).
4.5        Form of 5.100% Notes due 2040 (incorporated by reference to Exhibit 4.1 to Registrant’s Current Report on Form 8-K, dated August 17, 2010, filed on August 20, 2010, SEC File No. 001-4300).
4.6        Form of 1.75% Notes due 2017 (incorporated by reference to Exhibit 4.1 to Registrant’s Current Report on Form 8-K, dated April 3, 2012, filed on April 9, 2012, SEC File No. 001-4300).
4.7        Form of 3.25% Note due 2022 (incorporated by reference to Exhibit 4.2 to Registrant’s Current Report on Form 8-K, dated April 3, 2012, filed on April 9, 2012, SEC File No. 001-4300).
4.8        Form of 4.75% Notes due 2043 (incorporated by reference to Exhibit 4.3 to Registrant’s Current Report on Form 8-K, dated April 3, 2012, filed on April 9, 2012, SEC File No. 001-4300).
4.9        Form of 2.625% Notes due 2023 (incorporated by reference to Exhibit 4.1 to Registrant’s Current Report on Form 8-K, dated November 28, 2012, filed on December 4, 2012, SEC File No. 001-4300).
4.10      Form of 4.250% Notes due 2044 (incorporated by reference to Exhibit 4.2 to Registrant’s Current Report on Form 8-K, dated November 28, 2012, filed on December 4, 2012, SEC File No. 001-4300).
4.11      Rights Agreement, dated January 31, 1996, between Registrant and Wells Fargo Bank, N.A. (as successor-in-interest to Norwest Bank Minnesota, N.A.), rights agent, relating to the declaration of a rights dividend to Registrant’s common shareholders of record on January 31, 1996 (incorporated by reference to Exhibit (a) to Registrant’s Registration Statement on Form 8-A, dated January 24, 1996, SEC File No. 001-4300).
4.12      Amendment No. 1, dated as of January 31, 2006, to the Rights Agreement dated as of December 31, 1996, between Apache Corporation, a Delaware corporation, and Wells Fargo Bank, N.A. (as successor-in-interest to Norwest Bank Minnesota, N.A.) (incorporated by reference to Exhibit 4.4 to Registrant’s Amendment No. 1 to Registration Statement on Form 8-A, dated January 31, 2006, SEC File No. 001-4300).
4.13      Senior Indenture, dated February 15, 1996, between Registrant and The Bank of New York Mellon Trust Company, N.A. (formerly known as the Bank of New York Trust Company, N.A., as successor-in-interest to JPMorgan Chase Bank), formerly known as The Chase Manhattan Bank, as trustee, governing the senior debt securities and guarantees (incorporated by reference to Exhibit 4.6 to Registrant’s Registration Statement on Form S-3, dated May 23, 2003, Reg. No. 333-105536).
4.14      First Supplemental Indenture to the Senior Indenture, dated as of November 5, 1996, between Registrant and The Bank of New York Mellon Trust Company, N.A. (formerly known as the Bank of New York Trust Company, N.A., as successor-in-interest to JPMorgan Chase Bank, formerly known as The Chase Manhattan Bank), as trustee, governing the senior debt securities and guarantees (incorporated by reference to Exhibit 4.7 to Registrant’s Registration Statement on Form S-3, dated May 23, 2003, Reg. No. 333-105536).
4.15      Form of Indenture among Apache Finance Pty Ltd, Registrant and The Bank of New York Mellon Trust Company, N.A. (formerly known as the Bank of New York Trust Company, N.A., as successor-in-interest to The Chase Manhattan Bank), as trustee, governing the debt securities and guarantees (incorporated by reference to Exhibit 4.1 to Registrant’s Registration Statement on Form S-3, dated November 12, 1997, Reg. No. 333-339973).


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  4.16      Form of Indenture among Registrant, Apache Finance Canada Corporation and The Bank of New York Mellon Trust Company, N.A. (formerly known as the Bank of New York Trust Company, N.A., as successor-in-interest to The Chase Manhattan Bank), as trustee, governing the debt securities and guarantees (incorporated by reference to Exhibit 4.1 to Amendment No. 1 to Registrant’s Registration Statement on Form S-3, dated November 12, 1999, Reg. No. 333-90147).
  4.17      Deposit Agreement, dated as of July 28, 2010, between Registrants and Wells Fargo Bank, N.A., as depositary, on behalf of all holders from time to time of the receipts issued there under (incorporated by reference to Exhibit 4.2 to Registrant’s Current Report on Form 8-K, dated July 22, 2010, filed on July 28, 2010, SEC File No. 001-4300).
  4.18      Form of Depositary Receipt for the Depositary Shares (incorporated by reference to Exhibit A to Exhibit 4.2 to Registrant’s Current Report on Form 8-K, dated July 22, 2010, filed on July 28, 2010, SEC File No. 001-4300).
 4.19      Senior Indenture, dated May 19, 2011, between Registrant and Wells Fargo Bank, National Association, as trustee, governing the senior debt securities of Apache Corporation (incorporated by reference to Exhibit 4.14 to Registrant’s Registration Statement on Form S-3, dated May 23, 2011, Reg. No. 333-174429).
  4.20      Senior Indenture, dated May 19, 2011, among Apache Finance Pty Ltd, Apache Corporation, as guarantor, and Wells Fargo Bank, National Association, as trustee, governing the senior debt securities of Apache Finance Pty Ltd and the related guarantees (incorporated by reference to Exhibit 4.16 to Registrant’s Registration Statement on Form S-3, dated May 23, 2011, Reg. No. 333-174429).
  4.21      Senior Indenture, dated May 19, 2011, among Apache Finance Canada Corporation, Apache Corporation, as guarantor, and Wells Fargo Bank, National Association, as trustee, governing the senior debt securities of Apache Finance Corporation and the related guarantees (incorporated by reference to Exhibit 4.20 to Registrant’s Registration Statement on Form S-3, dated May 23, 2011, Reg. No. 333-174429).
  4.22      Form of Apache Corporation November 10, 2010 First Non-Qualified Stock Option Agreement for Certain Employees of Apache Corporation (incorporated by reference to Exhibit 4.6 to Registrant’s Registration Statement on Form S-8 filed on November 10, 2010, Reg. No. 333-170533).
  4.23      Form of Apache Corporation November 10, 2010 Second Non-Qualified Stock Option Agreement for Certain Employees of Apache Corporation (incorporated by reference to Exhibit 4.7 to Registrant’s Registration Statement on Form S-8 filed on November 10, 2010, Reg. No. 333-170533).
  4.24      Form of Apache Corporation November 10, 2010 Non-Statutory Stock Option Agreement for Certain Employees of Apache Corporation (incorporated by reference to Exhibit 4.8 to Registrant’s Registration Statement on Form S-8 filed on November 10, 2010, Reg. No. 333-170533).
10.1        Credit Agreement, dated August 12, 2011, among Registrant, the lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, and Citibank, N.A., Bank of America, N.A., and Wells Fargo Bank, National Association, as Syndication Agents (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed August 18, 2011, SEC File No. 001-4300).


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   10.2        First Amendment to Credit Agreement, dated as of July 17, 2013, among Apache Corporation, the lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, and the other agents party thereto, amending Credit Agreement, dated as of August 12, 2011, among the same parties (incorporated by reference to Exhibit 10.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2013, SEC File No. 001-4300).
   10.3        Credit Agreement, dated as of June 4, 2012, among Apache Corporation, the lenders party thereto, JPMorgan Chase Bank, N.A., as Global Administrative Agent, Bank of America, N.A. and Citibank, N.A., as Global Syndication Agents, and The Royal Bank of Scotland plc and Royal Bank of Canada, as Global Documentation Agents (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed June 7, 2012, SEC File No. 001-04300).
  10.4        Credit Agreement, dated as of June 4, 2012, among Apache Canada Ltd., the lenders party thereto, JPMorgan Chase Bank, N.A., as Global Administrative Agent, Royal Bank of Canada, as Canadian Administrative Agent, Bank of America, N.A. and Citibank, N.A., as Global Syndication Agents, and The Royal Bank of Scotland plc and Royal Bank of Canada, as Global Documentation Agents (incorporated by reference to Exhibit 10.2 to Registrant’s Current Report on Form 8-K filed June 7, 2012, SEC File No. 001-04300)
   10.5        Syndicated Facility Agreement, dated as of June 4, 2012, among Apache Energy Limited (ACN 009 301 964), the lenders party thereto, JPMorgan Chase Bank, N.A., as Global Administrative Agent, Citisecurities Limited (ABN 51 008 489 610), as Australian Administrative Agent, Bank of America, N.A. and Citibank, N.A., as Global Syndication Agents, and The Royal Bank of Scotland plc and Royal Bank of Canada, as Global Documentation Agents (incorporated by reference to Exhibit 10.3 to Registrant’s Current Report on Form 8-K filed June 7, 2012, SEC File No. 001-04300).
  †10.6        Apache Corporation Corporate Incentive Compensation Plan A (Senior Officers’ Plan), dated July 16, 1998 (incorporated by reference to Exhibit 10.13 to Registrant’s Annual Report on Form 10-K for year ended December 31, 1998, SEC File No. 001-4300).
  †10.7        First Amendment to Apache Corporation Corporate Incentive Compensation Plan A, dated November 20, 2008, effective as of January 1, 2005 (incorporated by reference to Exhibit 10.17 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2008, SEC File No. 001-4300).
  †10.8        Apache Corporation Corporate Incentive Compensation Plan B (Strategic Objectives Format), dated July 16, 1998 (incorporated by reference to Exhibit 10.14 to Registrant’s Annual Report on Form 10-K for year ended December 31, 1998, SEC File No. 001-4300).
  †10.9        First Amendment to Apache Corporation Corporate Incentive Compensation Plan B, dated November 20, 2008, effective as of January 1, 2005 (incorporated by reference to Exhibit 10.19 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2008, SEC File No. 001-4300).
*†10.10      Apache Corporation 401(k) Savings Plan, as amended and restated, dated May 14, 2013, effective May 1, 2013.
  †10.11      Amendment to Apache Corporation 401(k) Savings Plan, dated October 25, 2013 (incorporated by reference to Exhibit 10.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2013, SEC File No. 001-4300).
  †10.12      Non-Qualified Retirement/Savings Plan of Apache Corporation, as amended and restated July 14, 2010, except as otherwise specified (incorporated by reference to Exhibit 10.3 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, SEC File No. 001-4300).


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  †10.13      Amendment to Apache Corporation Non-Qualified Retirement/Savings Plan of Apache Corporation, dated December 19, 2011, effective January 1, 2012 (incorporated by reference to Exhibit 10.20 to Registrant’s Annual Report Form 10-K for year ended December 31, 2011, SEC File No. 001-4300).
  †10.14      Amendment to Non-Qualified Retirement/Savings Plan of Apache Corporation, dated November 8, 2012, effective January 1, 2013 (incorporated by reference to Exhibit 10.25 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2012, SEC File No. 001-4300).
  †10.15      Non-Qualified Restorative Retirement Savings Plan of Apache Corporation, dated November 7, 2011, effective January 1, 2012 (incorporated by reference to Exhibit 4.7 to Registrant’s Registration Statement on Form S-8, dated December 21, 2011, Reg. No. 333-178672).
  †10.16      Amendment to Non-Qualified Restorative Retirement Savings Plan of Apache Corporation, dated November 8, 2012, effective January 1, 2013 (incorporated by reference to Exhibit 10.27 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2012, SEC File No. 001-4300).
*†10.17      Apache Corporation 2011 Omnibus Equity Compensation Plan, as amended and restated February 3, 2014.
  †10.18      Apache Corporation 2007 Omnibus Equity Compensation Plan, as amended and restated May 4, 2011 (incorporated by reference to Exhibit 10.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2011, SEC File No. 001-4300).
  †10.19      Apache Corporation 2000 Stock Option Plan, as amended and restated May 5, 2011 (incorporated by reference to Exhibit 10.3 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2011, SEC File No. 001-4300).
  †10.20      Apache Corporation 2003 Stock Appreciation Rights Plan, as amended and restated September 16, 2013 (incorporated by reference to Exhibit 10.2 to Registrant’s Quarterly Report on Form 10-Q for quarter ended September 30, 2013, SEC File No. 001-4300).
  †10.21      Apache Corporation 2005 Stock Option Plan, as amended and restated September 16, 2013 (incorporated by reference to Exhibit 10.3 to Registrant’s Quarterly Report on Form 10-Q for quarter ended September 30, 2013, Commission File No. 001-4300).
  †10.22      Apache Corporation Income Continuance Plan, as amended and restated July 14, 2010, effective January 1, 2009 (incorporated by reference to Exhibit 10.5 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, SEC File No. 001-4300).
*†10.23      Apache Corporation Deferred Delivery Plan, as amended and restated November 11, 2013.
  †10.24      Apache Corporation Non-Employee Directors’ Compensation Plan, as amended and restated February 6, 2013 (incorporated by reference to Exhibit 10.39 to Registrant’s Annual Report on Form 10-K for the year ended December 31, 2012, SEC File No. 001-4300).
  †10.25      Apache Corporation Outside Directors’ Retirement Plan, as amended and restated February 6, 2013 (incorporated by reference to Exhibit 10.40 to Registrant’s Annual Report on Form 10-K for the year ended December 31, 2012, SEC File No. 001-4300).
  †10.26      Apache Corporation Equity Compensation Plan for Non-Employee Directors, as amended and restated February 8, 2007 (incorporated by reference to Exhibit 10.2 to Registrant’s Quarterly Report on Form 10-Q for quarter ended March 31, 2007, SEC File No. 001-4300).
  †10.27      Apache Corporation Non-Employee Directors’ Restricted Stock Units Program Specifications, dated May 5, 2011, pursuant to Apache Corporation 2011 Omnibus Equity Compensation Plan (incorporated by reference to Exhibit 10.6 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2011, SEC File No. 001-4300).


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*†10.28      Apache Corporation Non-Employee Directors’ Restricted Stock Units Program Specifications, as amended and restated May 15, 2013, pursuant to Apache Corporation 2011 Omnibus Equity Compensation Plan.
  †10.29      Restated Employment and Consulting Agreement, dated January 15, 2009, between Registrant and Raymond Plank (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K, dated January 15, 2009, filed January 16, 2009, SEC File No. 001-4300).
  †10.30      Amended and Restated Employment Agreement, dated December 20, 1990, between Registrant and John A. Kocur (incorporated by reference to Exhibit 10.10 to Registrant’s Annual Report on Form 10-K for year ended December 31, 1990, SEC File No. 001-4300).
  †10.31      Employment Agreement between Registrant and G. Steven Farris, dated June 6, 1988, and First Amendment, dated November 20, 2008, effective as of January 1, 2005 (incorporated by reference to Exhibit 10.44 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2008, SEC File No. 001-4300).
  †10.32      Restricted Stock Unit Award Agreement, dated May 8, 2008, between Registrant and G. Steven Farris (incorporated by reference to Exhibit 10.4 to Registrant’s Quarterly Report on Form 10-Q for quarter ended March 31, 2008, SEC File No. 001-4300).
  †10.33      Form of Restricted Stock Unit Award Agreement, dated February 12, 2009, between Registrant and each of John A. Crum, Rodney J. Eichler, and Roger B. Plank (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K, dated February 12, 2009, filed February 18, 2009, SEC File No. 001-4300).
  †10.34      Amendment to Restricted Stock Unit Award Agreement, dated March 7, 2011, between Registrant and John A. Crum (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report Form 8-K/A filed March 8, 2011, SEC File No. 001-4300).
  †10.35      Resignation Agreement, dated March 7, 2011 between Registrant and John A. Crum (incorporated by reference to Exhibit 10.2 to Registrant’s Current Report on Form 8-K/A filed March 8, 2011, SEC File No. 001-4300).
  †10.36      Form of Restricted Stock Unit Award Agreement, dated November 18, 2009, between Registrant and Michael S. Bahorich (incorporated by reference to Exhibit 10.37 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2009, SEC File No. 001-4300).
  †10.37      Form of Restricted Stock Unit Grant Agreement, dated May 6, 2009, between Registrant and each of G. Steven Farris, Roger B. Plank, John A. Crum, Rodney J. Eichler, and Michael S. Bahorich (incorporated by reference to Exhibit 10.38 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2009, SEC File No. 001-4300).
  †10.38      Form of Stock Option Award Agreement, dated May 6, 2009, between Registrant and each of G. Steven Farris, Roger B. Plank, John A. Crum, Rodney J. Eichler, and Michael S. Bahorich (incorporated by reference to Exhibit 10.39 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2009, SEC File No. 001-4300).
  †10.39      Form of 2010 Performance Program Agreement, dated January 15, 2010, between Registrant and each of G. Steven Farris, John A. Crum, Rodney J. Eichler, and Roger B. Plank (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed January 19, 2010, SEC File No. 001-4300).
  †10.40      Form of First Amendment, effective May 5, 2010, to 2010 Performance Program Agreement, dated January 15, 2010, between Registrant and each of G. Steven Farris, John A. Crum, Rodney J. Eichler, and Roger B. Plank (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed May 11, 2010, SEC File No. 001-4300).


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  †10.41      Form of Restricted Stock Unit Award Agreement, dated January 15, 2010, between Registrant and each of John A. Crum, Rodney J. Eichler, and Roger B. Plank (incorporated by reference to Exhibit 10.2 to Registrant’s Current Report on Form 8-K filed January 19, 2010, SEC File No. 001-4300).
  †10.42      Form of 2011 Performance Program Agreement, dated January 7, 2011, between Registrant and each of G. Steven Farris, John A. Crum, Rodney J. Eichler, Roger B. Plank, Michael S. Bahorich, and Thomas P. Chambers (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed January 13, 2011, SEC File No. 001-4300).
  †10.43      Restricted Stock Unit Award Agreement, dated February 9, 2011, between Registrant and Thomas P. Chambers (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed February 14, 2011, SEC File No. 001-4300).
  †10.44      Form of 2012 Performance Program Agreement, dated January 11, 2012, between Registrant and each of G. Steven Farris, Rodney J. Eichler, Roger B. Plank, P. Anthony Lannie, and Thomas P. Chambers (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed January 13, 2012, SEC File No. 001-4300).
  †10.45      Form of 2013 Performance Program Agreement, dated January 9, 2013, between Registrant and each of G. Steven Farris, Rodney J. Eichler, Roger B. Plank, and Thomas P. Chambers (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed January 11, 2013, SEC File No. 001-4300).
  *10.46      Form of 2014 Performance Agreement (Total Shareholder Return), dated January 9, 2014, between Registrant and each of G. Steven Farris, Rodney J. Eichler, Roger B. Plan, P. Anthony Lannie, and Thomas P. Chambers.
  *10.47      Form of 2014 Performance Agreement (Business Performance), dated February 3, 2014, between Registrant and each of G. Steven Farris, Roger B. Plank, Rodney J. Eichler, P. Anthony Lannie, and Thomas P. Chambers.
  *12.1      Statement of Computation of Ratios of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividends.
  *14.1      Code of Business Conduct, as amended and restated November 13, 2013.
  *21.1      Subsidiaries of Registrant
  *23.1      Consent of Ernst & Young LLP
  *23.2      Consent of Ryder Scott Company L.P., Petroleum Consultants
  *24.1      Power of Attorney (included as a part of the signature pages to this report)
  *31.1      Certification (pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Exchange Act) by Principal Executive Officer.
  *31.2      Certification (pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Exchange Act) by Principal Financial Officer.
  *32.1      Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by Principal Executive Officer and Principal Financial Officer.
  *99.1      Report of Ryder Scott Company L.P., Petroleum Consultants
*101.INS      XBRL Instance Document.
*101.SCH      XBRL Taxonomy Schema Document.
*101.CAL      XBRL Calculation Linkbase Document.
*101.LAB      XBRL Label Linkbase Document.
*101.PRE      XBRL Presentation Linkbase Document.
*101.DEF      XBRL Definition Linkbase Document.


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* 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.