10-K 1 h43727e10vk.htm FORM 10-K - ANNUAL REPORT e10vk
 

 
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, 2006,
OR
[ ]
  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
    For the Transition Period from          to          
 
Commission File Number 1-4300
Apache Corporation
 
     
     
A Delaware Corporation   IRS Employer No. 41-0747868
One Post Oak Central
2000 Post Oak Boulevard, Suite 100
Houston, Texas 77056-4400
Telephone Number (713) 296-6000
Securities Registered Pursuant to Section 12(b) of the Act:
 
     
    Name of Each Exchange
Title of Each Class
 
On Which Registered
 
Common Stock, $0.625 par value   New York Stock Exchange
Chicago Stock Exchange
NASDAQ National Market
Preferred Stock Purchase Rights   New York Stock Exchange
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 of 1933. 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 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, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act
Large accelerated filer [X]     Accelerated filer [ ]     Non-accelerated filer [ ]
 
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, 2006
  $ 22,470,650,953  
Number of shares of registrant’s common stock outstanding as of January 31, 2007
    330,958,433  
 
DOCUMENTS INCORPORATED BY REFERENCE:
 
Portions of registrant’s proxy statement relating to registrant’s 2007 annual meeting of stockholders have been incorporated by reference into Part III hereof.
 


 

 
TABLE OF CONTENTS
 
DESCRIPTION
 
             
Item
     
Page
 
1.
  BUSINESS   1
1A.
  RISK FACTORS   12
1B.
  UNRESOLVED STAFF COMMENTS   16
2.
  PROPERTIES   1
3.
  LEGAL PROCEEDINGS   16
4.
  SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS   16
 
5.
  MARKET FOR THE REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS   17
6.
  SELECTED FINANCIAL DATA   19
7.
  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS   19
7A.
  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK   43
8.
  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA   45
9.
  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE   46
9A.
  CONTROLS AND PROCEDURES   46
9B.
  OTHER INFORMATION   46
 
10.
  DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT   46
11.
  EXECUTIVE COMPENSATION   47
12.
  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT   47
13.
  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS   47
14.
  PRINCIPAL ACCOUNTANT FEES AND SERVICES   47
 
15.
  EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K   47
       
 
All defined terms under Rule 4-10(a) of Regulation S-X shall have their statutorily prescribed meanings when used in this report. Quantities of natural gas are expressed in this report in terms of thousand cubic feet (Mcf), million cubic feet (MMcf), billion cubic feet (Bcf) or trillion cubic feet (Tcf). Oil is quantified in terms of barrels (bbls); thousands of barrels (Mbbls) and millions of barrels (MMbbls). Natural gas is compared to oil in terms of barrels of oil equivalent (boe) or million barrels of oil equivalent (MMboe). Oil and natural gas liquids are compared with natural gas in terms of million cubic feet equivalent (MMcfe) and billion cubic feet equivalent (Bcfe). One barrel of oil is the energy equivalent of six Mcf of natural gas. Daily oil and gas production is expressed in terms of barrels of oil per day (b/d) and thousands or millions of cubic feet of gas per day (Mcf/d and MMcf/d, respectively) or millions of British thermal units per day (MMBtu/d). Gas sales volumes may be expressed in terms of one million British thermal units (MMBtu), which is approximately equal to one Mcf. 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.


 

 
PART I
 
ITEMS 1 AND 2. BUSINESS AND PROPERTIES
 
General
 
Apache Corporation, a Delaware corporation formed in 1954, is an independent energy company that explores for, develops and produces natural gas, crude oil and natural gas liquids. In North America, our exploration and production interests are focused in the Gulf of Mexico, the Gulf Coast, East Texas, the Permian basin, the Anadarko basin and the Western Sedimentary basin of Canada. Outside of North America, we have exploration and production interests onshore Egypt, offshore Western Australia, offshore the United Kingdom in the North Sea (North Sea), and onshore Argentina. 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 January 2004. On May 18, 2006, we filed certifications of our compliance with the listing standards of the NYSE and the NASDAQ, including our chief executive officer’s certification of compliance with the NYSE standards. Through our website, http://www.apachecorp.com, you can access electronic copies of the charters of the committees of our Board of Directors, other documents related to Apache’s corporate governance (including our Code of Business Conduct and Governance Principles), and documents Apache files with the Securities and Exchange Commission (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. Included in our annual and quarterly reports are the certifications of our chief executive officer and our chief financial officer that are required by applicable laws and regulations. Access to these electronic filings is available as soon as practicable after filing with the SEC. You may also request printed copies of our committee charters or other governance documents by writing to our corporate secretary at the address on the cover of this report.
 
We hold interests in many of our U.S., Canadian, and other International properties through subsidiaries, including Apache Canada Ltd., DEK Energy Company (DEKALB), Apache Energy Limited (AEL), Apache North America, Inc., and Apache Overseas, Inc. Properties referred to in this document may be held by those subsidiaries. We treat all operations as one line of business.
 
Our Growth Strategy
 
Apache’s goal is to grow a profitable oil and gas company for the long-term benefit of our shareholders. Our strategy is to build a portfolio of core areas which provide growth opportunities through both grass-roots drilling and acquisition activity. We now have operations in six countries — the United States, Canada, Egypt, the United Kingdom sector of the North Sea, Australia, and our newest core area — Argentina. Whether in our oldest region, the U.S. Central region, or our newest, we seek to grow profitably while building critical mass that supports sustainable, lower-risk, repeatable drilling opportunities, balanced by higher-risk, higher-reward exploration. We also seek a balance in terms of gas vs. oil, geologic risk, reserve life and political risk.
 
When acquisition opportunities are identified, operational and technical teams participate in the evaluation process, enabling our personnel to move in quickly to execute exploitation activities (including workovers, recompletions and drilling) that will increase production and reserves, reduce costs per unit produced and enhance profitability. Over time, we build teams that have the technical knowledge and sense of urgency to maximize value. Our local knowledge of producing basins and our proactive culture provide a platform for continued growth through strategic acquisitions and drilling.
 
We also periodically evaluate our existing assets to determine whether sales of certain assets will provide opportunities to redeploy our capital resources to rebalance our portfolio and generate better prospective rates of return. As a result of this process, in January 2006, we sold our 55 percent interest in the deepwater section of Egypt’s West Mediterranean Concession to Amerada Hess for $413 million, and in August we sold our China holdings to Australia-based ROC Oil Company Limited for $260 million. We reinvested these proceeds and purchased estimated proved reserves of 109 MMboe in Argentina.
 
More than a decade ago, recognizing that the United States was a mature oil and gas country, we added an international exploration component to our portfolio strategy, which provides exposure to larger reserve targets with


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which to grow production and reserves through drilling. Apache is also one of the leading acquirers of three-dimensional (3-D) seismic data in the industry today. Our technology experts have developed strategies for rapid and cost-effective acquisition and processing of 3-D data, enabling our technical teams to analyze large swaths of acreage and generate drilling prospects on an accelerated timetable.
 
Operating regions are given the autonomy necessary to make drilling and operating decisions and to act quickly. Management and incentive systems underscore high cash flow and rate-of-return targets, which are measured monthly, reviewed with senior management quarterly and utilized to determine annual performance rewards.
 
In the United States, the Gulf Coast region consistently delivers high returns on capital invested, as well as cash flow significantly in excess of our exploration and development spending there. Acquisitions play an important role because with steep decline rates, offshore reserves are generally short-lived and difficult to replace through drilling alone. The Central region brings the balance of long-lived reserves and consistent drilling results in the Permian basin of West Texas and New Mexico, East Texas and the Anadarko basin of western Oklahoma. Apache’s future growth in the United States is more likely to be achieved through a combination of drilling and acquisitions, rather than through drilling activity alone. Our $821 million Gulf of Mexico acquisition from BP and $269 million Permian basin acquisition from Amerada Hess, for example, complimented our active drilling program in 2006 and buttressed our growth in the U.S.
 
In Canada, we have almost seven million gross acres across the Provinces of British Columbia, Alberta, Saskatchewan and the Northwest Territories. We have a multi-year inventory of low-risk drilling opportunities in a number of Apache fields in Central Alberta, including Provost, Hatton and Nevis, and on acreage acquired in the Exxon Mobil Corporation (ExxonMobil) farm-in agreements of 2004 and 2005. With acquisition and land costs having risen significantly in Canada, these farm-ins provide a way for Apache to earn acreage through drilling with no upfront costs. ExxonMobil retains a royalty on fee lands and a convertible working interest on leasehold acreage, both of which vary dependent on activity levels. We also have opportunities to drill deeper exploration targets with higher reserve potential in Northwest Alberta and Northeast British Columbia.
 
In Egypt’s Western Desert, Apache’s 10.2 million gross acres encompass a sizable resource in the Cretaceous Upper Bahariya formations and outstanding exploration potential in deeper intervals from lower Cretaceous to Jurassic, established producing trends. The Qasr gas/condensate field, discovered in 2003, is the largest field ever found by Apache with more than 2 trillion cubic feet of gas and 60 million barrels of estimated recoverable reserves.
 
In Australia, we have expanded our exploration program to the high-potential Exmouth, Browse and Gippsland basins while continuing to exploit our acreage position and control of key infrastructure in the Carnarvon basin. In the Gippsland basin we actively acquired almost 1.8 million acres over the past three years and have generated a 10-well inventory of high potential exploration prospects to be drilled in 2008. Additionally, Apache and its partners are designing three development projects in the Exmouth basin that are in process of being sanctioned and approved by all parties.
 
Apache entered the North Sea in 2003 with our acquisition of the Forties field (Forties), the largest field ever discovered in the United Kingdom. As operator, through drilling and extensive improvements to the production infrastructure, we virtually doubled production — and significantly reduced per-unit operating costs — from the second quarter of 2003. Our 2007 plans include infill and extentional drilling activity at Forties to determine if we can extend the field to the west, as well as exploration drilling on acreage blocks obtained over the past couple of years. We currently have around 100 Forties field drilling locations in our inventory.
 
For several years we held small interests in Argentina with the long-term view of expanding there through acquisitions. In April 2006, we purchased Pioneer Natural Resources’ (Pioneer) interests in Neuquén and the Austral basins for $675 million and subsequently purchased our partner’s, Pan American Fueguina S.R.L. (Pan American), interests in Tierra del Fuego, gaining operatorship in the under-exploited, highly prospective Austral basin concessions. Through subsequent workovers, recompletions and development activities, we increased production on the acquired properties and have established Argentina as Apache’s latest core area. While we expect unique challenges with evolving governmental regulations, we anticipate growing reserves and production in Argentina.
 
We exited 2006 with a year-end debt-to-capitalization ratio of 22 percent despite record capital spending of $6.4 billion, excluding asset retirement costs. This flexibility enables us to quickly act on attractive acquisition


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transactions as they are identified, such as our agreement in January 2007 to acquire, through a joint venture interest, Permian basin assets from Anadarko Petroleum Company (Anadarko) for $1 billion. The transaction, which is subject to normal closing conditions and adjustments for matters such as preferential rights, is expected to close around the end of the first-quarter of 2007.
 
Apache has increased reserves in each of the last 21 years and production in 27 of the last 28 years. We believe our strategy and our diversified portfolio of assets provide a platform for profitable growth through drilling and acquisitions across the cycles of our dynamic industry.
 
In 2007, we are planning another active year of drilling. We revise our capital expenditure estimates throughout the year based on changing industry conditions and results to date. Therefore, accurately projecting annual capital spending is difficult at best. Our preliminary 2007 capital budget approaches $4.5 billion. While in most years capital budgets are expanded as the year unfolds, if commodity prices soften from year-end 2006 levels and service costs do not also decline; we plan to reduce our capital spending. Regarding potential acquisitions, we continually look for properties to which we believe we can add value and earn adequate rates of return and will take advantage of those acquisition opportunities as they arise.
 
Operating Highlights
 
Following the sale of our interest in China in the third quarter of 2006, our interests in six countries now comprise our reportable segments: the United States, Canada, Egypt, Australia, the North Sea, and Argentina. In the U.S., our exploration and production activities are spread between two regions: Gulf Coast and Central.
 
The following table sets out a brief comparative summary of certain key 2006 data for each area. More detailed information regarding oil, natural gas and natural gas liquids (NGLs) production and the average sales prices received in each geographic area for 2006, 2005, and 2004 is available later in this section under “Production, Pricing and Lease Operating Cost Data.” Also, further discussion and analysis of this data is available in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations in this Form 10-K. For information concerning the revenues, expenses, operating income (loss) and total assets attributable to each of our reportable segments, see Note 13, Supplemental Oil and Gas Disclosures (Unaudited), and Note 12, Business Segment Information of Item 15 in this Form 10-K. For information regarding Oil and Gas Capital Expenditures for each of the last three years, see Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, “Capital Resources and Liquidity” in this Form 10-K.
 
                                                         
                      12/31/06
    Percentage
          2006
 
          Percentage
    2006
    Estimated
    of Total
    2006
    Gross New
 
    2006
    of Total
    Production
    Proved
    Estimated
    Gross New
    Productive
 
    Production
    2006
    Revenue
    Reserves
    Proved
    Wells
    Wells
 
    (In MMboe)     Production     (In millions)     (In MMboe)     Reserves     Drilled     Drilled  
 
Region/Country:
                                                       
Gulf Coast
    40.6       22.2 %   $ 1,865       393.3       17.0 %     83       65  
Central
    27.3       14.9       1,162       551.2       23.8       374       363  
                                                         
Total U.S. 
    67.9       37.1       3,027       944.5       40.8       457       428  
                                                         
Canada
    32.9       18.0       1,380       575.3       24.9       874       740  
                                                         
Total North America
    100.8       55.1       4,407       1,519.8       65.7       1,331       1,168  
                                                         
Egypt
    33.9       18.5       1,664       281.5       12.2       163       140  
Australia
    15.7       8.6       408       204.5       8.8       23       7  
United Kingdom
    21.5       11.8       1,355       196.8       8.5       5       4  
Argentina
    9.9       5.4       167       110.6       4.8       83       74  
China
    1.1       0.6       73                   6       6  
                                                         
Total International
    82.1       44.9       3,667       793.4       34.3       280       231  
                                                         
Total
    182.9       100.0 %   $ 8,074       2,313.2       100 %     1,611       1,399  
                                                         


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The following discussions include references to our plans for 2007. These only represent initial estimates and could vary significantly from actual results. In recent years, there have been large differences between our capital expenditure forecasts and our actual activity. During the year, we routinely adjust our level of spending based on results and changing industry conditions.
 
United States
 
Gulf Coast — The Gulf Coast region comprises our interests in and along the Gulf of Mexico, in the areas on-and offshore Louisiana and Texas. Apache is the largest held-by-production acreage holder and the second largest producer in Gulf waters less than 1,200 feet deep. For the third year in a row, the Gulf Coast was our leading region for both production volumes and revenues. Gulf Coast activities in 2006 focused on restoring production impacted by the 2005 hurricanes, while maintaining an active drilling program. This region performed 296 workover and recompletion operations during 2006 and completed 65 out of 83 total wells drilled as producers. Our drilling locations mostly included proved undeveloped reserves at platforms sustaining minimum or no hurricane damage with access to third-party transport facilities. In June 2006, we acquired producing properties, facilities and prospects on the Outer Continental Shelf of the Gulf of Mexico from BP plc (BP) for $845 million, adding an estimated 44.2 MMboe of proved reserves. The purchase price was allocated as follows: $747 million producing properties, $42 million prospects, $56 million facilities. As of year-end 2006, the Gulf Coast region accounted for 17 percent of our estimated proved reserves. Although actual annual capital expenditures may change considerably in 2007, we currently estimate investing approximately $900 million to drill over 90 wells and to continue our production enhancement and exploitation programs. In addition, we plan to spend an estimated $350 million on repair, redevelopment, and plugging and abandonment work required to repair damage caused by Hurricanes Katrina and Rita in 2005 that will not be covered by insurance.
 
Central — The Central Region includes assets in the Permian basin of West Texas and New Mexico, East Texas, and the Anadarko basin of western Oklahoma, where the Company got its start over 50 years ago. On January 5, 2006, the Company expanded its presence in the Permian basin by purchasing an estimated 31.5 MMboe of reserves in eight fields for $269 million from Amerada-Hess. In early 2007, we also entered into agreements to acquire additional Permian basin interests from Anadarko as described in more detail below under “Subsequent Events.” As of year-end 2006, the Central region accounted for approximately 24 percent of our estimated proved reserves, the second largest concentration in the Company. During 2006, we participated in drilling 374 wells, 363 of which were completed as productive. Apache performed 615 workovers and recompletions in the region during the year. We currently estimate spending approximately $570 million in 2007 on drilling and production enhancement projects.
 
Marketing — In general, most of our U.S. gas is sold on a monthly basis at either monthly or daily market prices. Our natural gas is sold primarily to Local Distribution Companies (LDCs), utilities, end-users, integrated major oil and gas companies and marketers. In an effort to increase sales to direct users of natural gas and to meet the needs of our customers, we also periodically sell some gas under long-term contracts at prices that fluctuate with market conditions. Approximately eight percent of our 2006 U.S. natural gas production was sold under long-term fixed-price physical contracts which expire in 2007 and 2008. See Item 7A, Quantitative and Qualitative Disclosures about Market Risk “Commodity Risk” in this Form 10-K.
 
Apache has historically marketed and continues to sell its U.S. crude oil to integrated major oil companies, purchasers, transporters, and refiners. The objective is to maximize the value of the crude oil sold by identifying the most economical markets and transportation routes available to move the crude oil via pipeline, truck or barge. Sales contracts are generally thirty (30) day evergreen contracts and renew automatically until canceled by either party. These contracts provide for sales at prices which fluctuate with daily oil market conditions, thus capturing the market value of the crude oil each day. We manage our credit risk by selling our oil to creditworthy counterparties and monitoring our exposure on a daily basis.
 
Canada
 
Overview — Our exploration and development activity in our Canadian region is concentrated in the Provinces of Alberta, British Columbia, Saskatchewan and to a lesser degree the Northwest Territories. The region comprises


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24.9 percent of our estimated proved reserves, the largest in the Company. We hold over 4.9 million net acres in Canada, the largest of our North American regions. Canada was our most active drilling area in 2006, with Apache participating in 874 wells, focused primarily on low-risk shallow development wells. We completed 740 as producers and conducted 274 workover and recompletion projects. Although actual annual capital expenditures may change with industry conditions and results, we currently estimate spending approximately $770 million in 2007 to drill approximately 380 wells, continue our exploitation program, albeit at a lower level, and continue developing our gas processing infrastructure. Our 2007 drilling program will include more deeper, higher risk-reward exploration wells and fewer shallow development wells.
 
Apache is also targeting fields such as Provost and Nevis in Alberta for coalbed methane (CBM) and in the process has emerged as one of Canada’s largest producers of CBM. The North and South Grant Lands obtained through farm-in agreements (discussed below) provide additional CBM potential.
 
In 2005, Apache signed a farm-in agreement with ExxonMobil covering approximately 650,000 acres of undeveloped properties in the Western Canadian province of Alberta. Under the agreement, Apache is to drill and operate 145 new wells over a 36-month period with upside potential for further drilling. ExxonMobil retains a royalty on fee lands and a convertible working interest on leasehold acreage, both of which vary dependent on activity levels. The agreement also allows Apache to test additional horizons on approximately 140,000 acres of property covered in a 2004 farm-in agreement with ExxonMobil. The 2004 farm-in agreement covered approximately 380,000 acres and stipulated drilling at least 250 wells over a two-year period beginning in October 2004. The 250 well commitment was met and the agreement was extended for an additional year. In 2006, Apache drilled 218 wells on the 2005 and 2004 farm-in acreage earning 93 additional acreage sections. Through the end of 2006, Apache has now drilled a total of 675 wells on the farm-in acreage from both agreements.
 
Marketing — Our Canadian natural gas sales focuses on sales to LDCs, utilities, end-users, integrated majors, supply aggregators and marketers. Our composite client portfolio is credit worthy and diverse. Improved North American natural gas pipeline connectivity has triggered a closer correlation between Canadian and United States natural gas prices. To diversify our market exposure and optimize pricing differences in the U.S. and Canada, we transport natural gas via our firm transportation contracts to California, the Chicago area, and eastern Canada. Our objective is to sell the majority of our production monthly, either into the first of the month market, or the daily market. Over 95 percent of our Canadian natural gas production is sold on a monthly basis at either monthly or daily market prices. Approximately two percent of our sales are long-term fixed-price sales. The longest term for these sales expires in 2011. The remainder is sold under long-term commitments to Canadian aggregators and end-users where the prices we receive under these contracts fluctuate monthly with market indices.
 
Our Canadian crude oil is primarily sold to refiners, integrated majors and marketers. To increase the market value of our condensate and heavier crudes, our condensate is either used or sold for blending purposes. We sell our crude oil and NGLs on Canadian Postings, which are market reflective prices that depend on worldwide crude oil prices and are adjusted for transportation and quality. In order to reach more purchasers and diversify our market, we transport crude on 12 pipelines to the major trading hubs within Alberta and Saskatchewan.
 
Egypt
 
Overview — In Egypt, our operations are conducted pursuant to production sharing contracts under which the contractor partner pays all operating and capital expenditure costs for exploration and development. A percentage of the production, usually up to 40 percent, is available to the contractor partners to recover operating and capital expenditure costs. In general, the balance of the production is allocated between the contractor partners and the Egyptian General Petroleum Corporation (EGPC) on a contractually defined basis. Apache is the second largest acreage holder and the most active driller in the Western Desert of Egypt. Egypt is the country with our largest single acreage position where, as of December 31, 2006, we held approximately 10.2 million gross acres in 19 separate concessions. Development leases within concessions generally have a 25-year life with extensions possible for additional commercial discoveries, or on a negotiated basis. Apache is the largest producer of liquid hydrocarbons and natural gas in the Western Desert. Egypt contributed approximately 21 percent of Apache’s production revenues and 19 percent of total production. Egypt accounted for 12 percent of total estimated proved reserves as of December 31, 2006. The Company reports all estimated proved reserves held under production sharing agreements utilizing the economic interest method, which excludes the host country’s share of reserves.


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In 2006, Apache had an active drilling program in Egypt, completing 140 of 163 wells, an 86 percent success rate, and conducted 390 workovers and recompletions. We currently plan to spend approximately $1 billion in 2007. Of this, $600 million will be for drilling and production enhancement work. We recently received approval to expand our Western Desert gas processing capacity and infrastructure to evacuate an additional 200 MMcf/d gas volumes driven by the Qasr field discovery. We project that this upgrade will take two years to complete at a total cost of $950 million, excluding actual gas well drilling costs and we have included $350 million in our capital expenditures for 2007.
 
On January 6, 2006, the Company completed the sale of its 55 percent interest in the deepwater section of Egypt’s West Mediterranean Concession to Amerada Hess for $413 million.
 
Please refer to Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations “Critical Accounting Policies and Estimates, Allowance for Doubtful Accounts” in this Form 10-K for a discussion of our Egyptian receivables.
 
Marketing — We and our partners have sold our gas production to EGPC under an Industry Pricing Formula; which is 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 which corresponds to a Dated-Brent price of $21.00 per barrel. Generally, the Industry Pricing Formula applies to all new gas discovered and produced. In exchange for extension of the Khalda Concession lease in July 2004, Apache agreed to accept Industry Pricing on all production in excess of 100 MMcf/d, but preserved the higher price formula until 2013 on the initial 100 MMcf/d.
 
Oil from the Khalda Concession, the Qarun Concession and other nearby Western Desert blocks is either sold directly to EGPC or other third-parties. The oil sales are made either directly into the Egyptian oil pipeline grid, exported via one of two terminals on the north coast of Egypt, or sold to third parties (non-governmental) through the MIDOR refinery located in northern Egypt. Oil production that is presently sold to EGPC is sold on a spot basis at a “Western Desert” price (indexed to Brent). In 2006, we exported 28 cargoes (approximately 8.6 million barrels) of Western Desert crude oil from the El Hamra and Sidi Kerir terminals located on the northern coast of Egypt. These export cargoes were sold at market prices comparable to domestic sales to EGPC. Additionally, 24 cargoes representing 3.5 million barrels were sold in Egypt to other non-governmental purchasers at prevailing market prices. Export sales from both the Khalda and Qarun areas in the Western Desert have continued in 2007.
 
Australia
 
Overview — Our exploration activity in Australia is focused in the offshore Carnarvon, Gippsland, Browse, and Perth basins where Apache holds 6.8 million net acres in 35 Exploration Permits, 10 Production Licenses, and six Retention Leases. Production operations are concentrated in the Carnarvon basin which is the location of all 10 Production Licenses, nine of which are operated by Apache. In 2006, the region generated $408 million of production revenues producing 15.7 MMboe (8.6 percent of our total production) and accounted for 8.8 percent of our year-end estimated proved reserves. During the year we participated in drilling 23 wells; 18 exploration and five development wells. Four of the exploration wells and three of the development wells were productive for a 30 percent success rate.
 
Exploration successes in 2006 included the Theo and West Cycad oil discoveries and the Gnu and Bambra East gas finds. The West Cycad oil discovery was drilled in the Harriet Joint Venture (HJV) area and is slated to begin production in the first quarter of 2007. The successful Theo well was drilled in the Exmouth sub-basin and is scheduled to begin production in 2009. The Gnu well was drilled in the Reindeer/Caribou field and added significant new reserves. First production from the Reindeer/Caribou field is targeted for late 2008 or early 2009. The Bambra East well was a successful gas well in the HJV, which more than doubled the volume of gas attributed to the Bambra field area. Gas production from this asset will begin in 2007 subject to augmentation of existing infrastructure.
 
During 2007, our Australian region plans to expand the HJV oil and gas production through development of the 2006 discoveries and drilling three additional wells: Bambra 8, Doric 2 and Lee 3. We will monitor the effects of the increased water injection at Stag and possibly drill an additional producer. We will also begin the initial phase of development drilling at the Van Gogh field. A key factor for success in 2007 will be increasing gas production and


6


 

reserves to fulfill the requirements of our sales contracts, exploration success and initiating the Theo field development and final sanctions thereof. We currently estimate spending approximately $460 million in 2007 to drill 30 exploration, appraisal and development wells and another $50 million for new facilities.
 
Marketing — In 2006, we executed three new gas sales contracts in Australia. As of December 31, 2006, Apache had a total of 22 active gas contracts with expiration dates ranging from April 2007 to July 2030. Generally, natural gas is sold in Western Australia under long-term, fixed-price contracts, many of which contain price escalation clauses based on the Australian consumer price index.
 
We continue to export all of our crude oil production into the international market at prices which fluctuate with world market conditions.
 
North Sea
 
Overview — In 2006, the North Sea region generated $1.35 billion of revenue, producing 21.5 million barrels of oil equivalent. We continued to develop our North Sea core area around the Forties field, including investments in upgrades to improve the operating efficiency of our platforms. Despite this, 2006 production was down 11 percent from 2005 primarily because of production interruptions associated with commissioning of major facility projects, and temporary shutdown of the Forties Pipeline System during the third quarter of 2006. Our focus in 2006 on infrastructure projects also displaced drilling operations needed to mitigate natural decline.
 
In 2006, we invested $329 million of capital in the North Sea region, including investments on drilling, recompletion and facility upgrades.
 
At Forties we commissioned a number of key facility projects to improve production efficiency and lower operating costs, including new power generation, a multi-platform distribution system, water injection upgrades and drilling rig modification. Also during 2006, seismic survey data acquired over Forties in 2005 was processed for inversion to identify bypassed oil in the main reservoir units and update the inventory of future drilling targets. We also drilled one appraisal well outside Forties, and had a second appraisal well and an exploration well in progress at the end of 2006.
 
There were no significant additions to North Sea acreage in 2006; however, in early 2007 Apache was awarded 62,320 acres from four licenses applied for in the UK 24th Licensing Round. In block 22/6a (Bacchus), Apache increased equity from 60 percent to 70 percent and became Operator (purchasing ExxonMobil’s 20 percent share and farming out 10 percent). A further 652 square kilometers of 3D seismic was acquired over six blocks of our acreage.
 
North Sea capital expenditures for 2007 are currently estimated at $480 million. After a year with minimal drilling, activity will significantly increase. In Forties, we will continue the development drilling program, with 15 new wells planned, and complete platform upgrades begun last year. Upgrades for 2007 include finalizing installation of additional produced water re-injection pumps and deep gas lift compressors, and commissioning of direct fluid export from Forties Bravo to Forties Charlie. These projects will enable Forties to meet stringent new environmental targets for produced water discharge to sea as well as enhance reservoir management capabilities, and should enhance runtime efficiency. Outside Forties, four exploration and appraisal wells are scheduled to be drilled in the first half of the year.
 
Marketing — In 2006, we entered into two new term contracts for the physical sale of Forties crude at prevailing market prices, which are composed of base market indices, adjusted for the higher quality of Forties crude relative to Brent and a premium to reflect the higher market value for term arrangements. Also in 2006, a new value adjustment formula (Quality Bank Adjustor) was implemented in BP’s Forties Pipeline System, through which Forties crude is shipped and commingled with crudes from other central North Sea fields. The original formula was challenged by Apache in June 2005, as it did not accurately value the Forties crude quality relative to the other crudes shipped on the Forties Pipeline System. The new agreed upon comingled stream on the formula better represents Forties crude value and effectively increases the volume allocated to Apache from the Forties Pipeline System.


7


 

 
Argentina
 
Argentina became our newest core area following two significant acquisitions in 2006 that substantially increased our presence in the country. In the second quarter, we completed our purchase of Pioneer’s operations in Argentina for $675 million with estimated proved reserves of 22 MMbbls of liquid hydrocarbons and 297 Bcf of natural gas. In the third quarter, we acquired additional interests in (and now operate) seven concessions in the Tierra del Fuego Province from Pan American for total consideration of $429 million. Our oil and gas assets are located in the Neuquén, San Jorge and Austral basins of Argentina. In 2006, we had 9.9 MMboe of production and 110.6 MMboe of estimated proved reserves, approximately 5.4 percent and 4.8 percent, respectively, of Apache’s total production and reserves.
 
We plan to invest approximately $180 million drilling over 100 wells and spend an additional $60 million on production enhancement projects in 2007.
 
Marketing — In Argentina we extended our existing natural gas contracts to regulated markets through April 2007, per the Argentine Secretary of Energy’s request. We expect to reach a new agreement during the first-quarter of 2007 with the Argentine government, which will set the volumes to be delivered to the regulated market for the period 2007 through 2011. We also entered into four new term contracts up to two years in duration for a total of 22 MMcf/d. These four contracts enabled Apache to lock in higher priced contracts while awaiting a new agreement to cover the internal demand of Argentina for 2007 onward.
 
In October 2006, the Argentina government removed the export tax exempt status previously afforded the province of Tierra del Fuego through a Special Customs area exemption. The government has further assessed an export tax on all exports from Argentina based upon the price paid for natural gas imports from Bolivia. This tax reduces the value we are receiving under our contract with Methanex in Chile. We have entered into an interim agreement with Methanex to mitigate the effects of this tax and are working to reach an economically suitable final agreement. The Methanex contract represents less than 10 percent of our gas sales in Argentina.
 
Other International
 
China.  On August 8, 2006, the Company completed the sale of our 24.5 percent interest in the Zhao Dong block offshore the People’s Republic of China, to Australia-based ROC Oil Company Limited for $260 million, marking Apache’s exit from China. The transaction was effective July 1, 2006, and the Company recorded a gain of approximately $174 million in the third-quarter of 2006.
 
Subsequent Events
 
On January 18, 2007, the Company announced that it is acquiring controlling interest in 28 oil and gas fields in the Permian basin of West Texas from Anadarko Petroleum Corporation (Anadarko) for $1 billion. Apache estimates that these fields had proved reserves of 57 million barrels (MMbbls) of liquid hydrocarbons and 78 billion cubic feet (Bcf) of natural gas as of yearend 2006. The transaction will be effective the earlier of closing or March 31, 2007. Approximately 10 percent of the Permian basin properties are subject to third-party preferential purchase rights which, if exercised, would reduce the interests we purchase in those properties and the purchase price we would pay. The Company intends to fund the acquisition with debt. Apache and Anadarko are entering into a joint-venture arrangement to effect the transaction. In connection with the acquisition, the Company entered into cash flow hedges to protect against commodity price volatility. For the period of July 2007 through June 2010, the Company entered into hedges for a portion of both the oil and the natural gas with NYMEX based costless collars.
 
In anticipation of closing the Anadarko transaction, we completed a public offering in January 2007 of $500 million of 5.625-percent notes due 2017 and $1 billion of 6.0-percent notes due 2037. The net proceeds from the offering ($1.48 billion, net of original issue discounts and underwriting commissions) were used to repay a portion of our outstanding commercial paper, which was incurred to finance acquisitions we made in 2006 and for general corporate purposes.


8


 

 
Drilling Statistics
 
Worldwide, in 2006, we participated in drilling 1,611 gross wells, with 1,399 (87 percent) completed as producers. We also performed more than 1,700 workovers and recompletions during the year. Historically, our drilling activities in the U.S. generally concentrate 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 exploitation wells. In addition to our completed wells, at year-end several wells had not yet reached completion: 76 in the U.S. (40.27 net); 10 in Canada (10 net); 18 in Egypt (17.12 net); three in Australia (2.06 net); and two in the North Sea (1.94 net).
 
The following table shows the results of the oil and gas wells drilled and tested for each of the last three fiscal years:
 
                                                                         
    Net Exploratory     Net Development     Total Net Wells  
    Productive     Dry     Total     Productive     Dry     Total     Productive     Dry     Total  
 
2006
                                                                       
United States
    2.9       2.7       5.6       266.4       15.3       281.7       269.3       18.0       287.3  
Canada
    34.3       6.4       40.7       577.3       114.8       692.1       611.6       121.2       732.8  
Egypt
    11.8       8.9       20.7       122.7       10.4       133.1       134.5       19.4       153.9  
Australia
    1.2       9.3       10.5       1.0       1.3       2.3       2.2       10.6       12.8  
North Sea
          1.0       1.0       3.9             3.9       3.9       1.0       4.9  
Argentina
    9.3       5.3       14.6       60.8       2.0       62.8       70.1       7.3       77.4  
Other International
                      1.5             1.5       1.5             1.5  
                                                                         
Total
    59.5       33.6       93.1       1,033.6       143.8       1177.4       1,093.1       177.5       1,270.6  
                                                                         
2005
                                                                       
United States
    5.0       3.1       8.1       248.8       24.1       272.9       253.8       27.2       281.0  
Canada
    273.4       107.6       381.0       1,057.0             1,057.0       1,330.4       107.6       1,438.0  
Egypt
    17.8       6.9       24.7       79.4       7.1       86.5       97.2       14.0       111.2  
Australia
    .7       6.8       7.5       11.8       4.8       16.6       12.5       11.6       24.1  
North Sea
          7.8       7.8       12.6       1.9       14.5       12.6       9.7       22.3  
Argentina
    6.3       3.0       9.3       15.6       1.0       16.6       21.9       4.0       25.9  
Other International
                      3.7       .2       3.9       3.7       .2       3.9  
                                                                         
Total
    303.2       135.2       438.4       1,428.9       39.1       1,468.0       1,732.1       174.3       1,906.4  
                                                                         
2004
                                                                       
United States
    3.3       3.5       6.8       202.8       24.2       227.0       206.1       27.7       233.8  
Canada
    6.7       9.3       16.0       1,102.3       84.2       1,186.5       1,109.0       93.5       1,202.5  
Egypt
    9.5       6.5       16.0       91.5       4.5       96.0       101.0       11.0       112.0  
Australia
    4.0       7.5       11.5       3.4       1.2       4.6       7.4       8.7       16.1  
North Sea
          1.0       1.0       11.7       3.9       15.6       11.7       4.9       16.6  
Argentina
                      1.2             1.2       1.2             1.2  
Other International
                      3.7       .3       4.0       3.7       .3       4.0  
                                                                         
Total
    23.5       27.8       51.3       1,416.6       118.3       1,534.9       1,440.1       146.1       1,586.2  
                                                                         


9


 

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, 2006, is set forth below:
 
                                                 
    Gas     Oil     Total  
    Gross     Net     Gross     Net     Gross     Net  
 
Gulf Coast
    973       752       890       621       1,863       1,373  
Central
    3,113       1,609       5,219       3,337       8,332       4,946  
Canada
    7,980       6,915       2,453       995       10,433       7,910  
Egypt
    33       32       425       404       458       436  
Australia
    10       6       35       18       45       24  
North Sea
                59       57       59       57  
Argentina
    276       246       484       426       760       672  
                                                 
Total
    12,385       9,560       9,565       5,858       21,950       15,418  
                                                 
 
Production, Pricing and Lease Operating Cost Data
 
The following table describes, for each of the last three fiscal years, oil, NGLs and gas production, average lease operating costs per boe (including severance and other taxes) and average sales prices for each of the countries where we have operations.
 
                                                         
                      Average
                   
    Production     Lease
    Average Sales Price  
    Oil
    NGLs
    Gas
    Operating
    Oil
    NGLs
    Gas
 
Year Ended December 31,
  (Mbbls)     (Mbbls)     (MMcf)     Cost per Boe     (Per bbl)     (Per bbl)     (Per Mcf)  
 
2006
                                                       
United States
    24,394       2,915       243,442     $ 10.66     $ 54.22     $ 38.44     $ 6.54  
Canada
    7,561       798       147,579       9.54       59.90       35.40       6.09  
Egypt
    20,648             79,424       4.36       63.60             4.42  
Australia
    4,341             67,933       4.95       68.25             1.65  
North Sea
    21,368             752       27.00       63.04             10.64  
Argentina
    2,503       561       40,878       4.39       42.79       36.64       .99  
Other International
    1,156                   4.67       62.73              
                                                         
Total
    81,971       4,274       580,008     $ 10.35     $ 59.92     $ 37.70     $ 5.17  
                                                         
2005
                                                       
United States
    24,188       2,757       218,081     $ 9.11     $ 47.97     $ 32.44     $ 7.22  
Canada
    8,212       816       135,750       7.54       53.05       31.07       7.29  
Egypt
    20,126             60,484       3.85       53.69             4.59  
Australia
    5,613             45,003       7.17       57.61             1.72  
North Sea
    23,903             842       17.94       53.00             9.17  
Argentina
    424             1,137       6.54       37.54             1.14  
Other International
    2,968                   3.79       44.24              
                                                         
Total
    85,434       3,573       461,297     $ 8.87     $ 51.66     $ 32.13     $ 6.35  
                                                         
2004
                                                       
United States
    24,841       3,026       236,663     $ 6.53     $ 38.75     $ 26.66     $ 5.45  
Canada
    9,262       947       119,669       6.49       38.57       24.44       5.30  
Egypt
    19,099             50,412       3.37       37.35             4.35  
Australia
    9,214             43,227       7.11       41.96             1.65  
North Sea
    19,338             684       4.22       24.22             5.53  
Argentina
    207             1,394       6.46       32.89             .65  
Other International
    2,775                   3.89       32.88              
                                                         
Total
    84,736       3,973       452,049     $ 5.73     $ 35.24     $ 26.13     $ 4.91  
                                                         


10


 

Gross and Net Undeveloped and Developed Acreage
 
The following table sets out our gross and net acreage position in each country where we have operations.
 
                                 
    Undeveloped Acreage     Developed Acreage  
    Gross
    Net
    Gross
    Net
 
    Acres     Acres     Acres     Acres  
 
United States
    1,526,857       939,911       2,965,614       1,829,626  
Canada
    3,900,899       2,712,924       2,944,150       2,192,895  
Egypt
    8,806,053       6,037,303       1,399,203       1,274,567  
Australia
    11,319,040       6,694,350       527,450       316,480  
North Sea
    1,468,159       1,244,358       29,924       29,174  
Argentina
    2,447,510       2,108,575       257,000       195,000  
                                 
Total Company
    29,468,518       19,737,421       8,123,341       5,837,742  
                                 
 
As of December 31, 2006, we had 736,497, 2,918,890, and 1,802,281 net acres scheduled to expire by December 31, 2007, 2008 and 2009, respectively, if production is not established or we take no other action to extend the terms. We plan to continue the terms of many of these licenses and concession areas through operational or administrative actions and do not expect a significant portion of our net acreage position to expire before such actions occur.
 
The other international drilling statistics on the preceding page and the Production, Pricing and Lease Operating Cost Data above include activity in China, where Apache ceased operations in August 2006.
 
Estimated Proved Reserves and Future Net Cash Flows
 
As of December 31, 2006, Apache had total estimated proved reserves of 1,061 MMbbls of crude oil, condensate and NGLs and 7.5 Tcf of natural gas. Combined, these total estimated proved reserves are equivalent to 2.3 billion barrels of oil equivalent or 13.9 Tcf of natural gas. During 2006, the Company’s reserves grew nine percent with increases in all our countries. The Company’s reserves have increased for 21 consecutive years.
 
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 economic and operating conditions. 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. Reserve estimates are considered proved if economical producibility is supported by either actual production or conclusive formation tests. 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 in the reservoir provides support for the engineering analysis on which the project or program is based. Estimated proved developed oil and gas reserves can be expected to be recovered through existing wells with existing equipment and operating methods.
 
Apache emphasizes that its reported reserves are estimates which, by their nature, are subject to revision. The estimates are made using available geological and reservoir data, as well as production performance data. These estimates are reviewed throughout the year, and revised either upward or downward, as warranted by additional performance data.
 
Apache’s proved reserves are estimated at the property level and compiled for reporting purposes by a centralized group of experienced reservoir engineers who are 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. 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 centralized and operating region engineers to ensure forecasts of operating expenses, netback prices, production trends and development timing are reasonable.


11


 

 
We engage Ryder Scott Company, L.P. Petroleum Consultants as independent petroleum engineers to review our estimates of proved hydrocarbon liquid and gas reserves and provide an opinion letter on the reasonableness of Apache’s internal projections. Ryder Scott opined that they were in acceptable agreement with the Company’s overall reserve estimates and that the reserves they reviewed conform to the SEC’s definition of proved reserves as set forth in Rule 210.4-10(a) of Regulation S-X. The independent reviews typically cover a large percentage of major value fields, international properties and new wells drilled during the year. During 2006, 2005 and 2004, their review covered 75, 74 and 79 percent of Apache’s worldwide estimated reserve value, respectively.
 
The Company’s estimates of proved reserves and proved developed reserves as of December 31, 2006, 2005 and 2004, changes in estimated proved reserves during the last three years, and estimates of future net cash flows and discounted future net cash flows from estimated proved reserves are contained in Note 13, Supplemental Oil and Gas Disclosures (Unaudited) of Item 15 in this Form 10-K. These estimated future net cash flows are based on prices on the last day of the year and are calculated in accordance with Statement of Financial Accounting Standards (SFAS) No. 69, “Disclosures about Oil and Gas Producing Activities.” Disclosure of this value and related reserves has been prepared in accordance with SEC Regulation S-X Rule 4-10.
 
Employees
 
On December 31, 2006, we had 3,150 employees. Only 25 of these employees are subject to collective bargaining agreements, all of whom are in Argentina.
 
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 2006, we maintained regional exploration and/or production offices in 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, 2013. For information regarding the Company’s obligations under its office leases, see the information appearing in the table in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, “Capital Resources and Liquidity, Contractual Obligations” and Note 10, Commitments and Contingencies, “Other Commitments and Contingencies, Contractual Obligations” of Item 15 in this Form 10-K.
 
Title to Interests
 
As is customary in our industry, a preliminary review of title records is made at the time we acquire properties, which may include opinions or reports of appropriate professionals or counsel. 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 which 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, and 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.
 
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.


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Our Profitability is Highly Dependent on the Prices of Crude Oil, Natural Gas and Natural Gas Liquids, Which Have Historically Been Very Volatile
 
Our estimated proved reserves, revenues, profitability, operating cash flows and future rate of growth are highly dependent on the prices of crude oil, natural gas and NGLs, which are affected by numerous factors beyond our control. Historically, these prices have been very volatile. A significant downward trend in commodity prices would have a material adverse effect on our revenues, profitability and cash flow, and could result in a reduction in the carrying value of our oil and gas properties and the amounts of our estimated proved oil and gas reserves.
 
Our Commodity Hedging May Prevent Us From Benefiting Fully From Price Increases and May Expose Us to Other Risks
 
To the extent that we engage in hedging activities to protect ourselves from commodity price volatility, we may be prevented from realizing the benefits of price increases above the levels of the hedges.
 
Acquisitions or Discoveries of Additional Reserves are Needed to Avoid a Material Decline in Reserves and Production
 
The rate of production from oil and gas properties generally declines as reserves are depleted. Except to the extent that we find or acquire additional properties containing estimated proved reserves, conduct successful exploration and development activities or, through engineering studies, identify additional behind-pipe zones, secondary recovery reserves or tertiary recovery 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.
 
Our Drilling Activities May Not Be Productive
 
Drilling for oil and gas involves numerous risks, including the risk that we will not encounter commercially productive oil or gas reservoirs. 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
 
  •  shortages or delays in the delivery of equipment.
 
Certain 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.
 
Risks Arising From the Failure to Fully Identify Potential Problems Related to Acquired Reserves or to Properly Estimate Those Reserves
 
One of our primary growth strategies is the acquisition of oil and gas properties. Although we perform a review of the acquired properties 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


13


 

permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as ground water 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 actual future production rates and associated 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.
 
We Are Subject to Governmental Risks That May Impact Our Operations
 
Our operations have been, and at times in the future may be, affected by political developments and by federal, state, provincial and local laws and regulations such as restrictions on production, changes in taxes, royalties and other amounts payable to governments or governmental agencies, price controls and environmental protection laws and regulations.
 
Global Political and Economic Developments May Impact Our Operations
 
Political and economic factors in international markets may have a material adverse effect on our operations. On an equivalent-barrel basis, approximately 63 percent of our oil, NGLs and natural gas production in 2006 was outside the United States, and approximately 59 percent of our estimated proved oil and gas reserves on December 31, 2006 were located outside of the United States.
 
There are many risks associated with operations in international markets, including changes in foreign governmental policies relating to crude oil, NGLs, and natural gas pricing and taxation, other political, economic or diplomatic developments, changing political conditions and international monetary fluctuations. These risks include: political and economic instability or war; the possibility that a foreign government may seize our property with or without compensation; confiscatory taxation; legal proceedings and claims arising from our foreign investments or operations; a foreign government attempting to renegotiate or revoke existing contractual arrangements, or failing to extend or renew such arrangements; fluctuating currency values and currency controls; and constrained natural gas markets dependent on demand in a single or limited geographical area.
 
On December 23, 2004, Apache entered into a 20-year insurance contract with the Overseas Private Investment Corporation (OPIC) which provides $300 million of political risk insurance for the Company’s Egyptian operations. This policy insures us against (1) non-payment by EGPC of arbitral awards covering amounts owed Apache on past due invoices and (2) expropriation of exportable petroleum when actions taken by the Government of Egypt prevent Apache from exporting our share of production. See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, “Critical Accounting Policies and Estimates, Allowance for Doubtful Accounts” in this Form 10-K for additional discussion of our Egyptian receivables.
 
In addition to the contract with OPIC, the Company has acquired commercial political risk insurance covering significant portions of its investments in Egypt and Argentina. The insurance provides coverage for confiscation, nationalization, and expropriation risks and currency inconvertibility, and is written on multi-year contracts with highly rated international insurers.
 
Actions of the United States government through tax and other legislation, executive order and commercial restrictions can adversely affect our operating profitability in the U.S. as well as other countries. Various agencies of the United States and other governments have, from time to time, imposed restrictions which have limited our ability to gain attractive opportunities or even operate in various countries. These restrictions have in the past limited our foreign opportunities and may continue to do so in the future.


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Weather and Climate May Have a Significant Impact on Our Revenues and Productivity
 
Demand for oil and natural gas are, to a significant degree, dependent on weather and climate, which impacts 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 hurricanes in the Gulf of Mexico, which may cause a loss of production from temporary cessation of activity or lost or damaged equipment. While our planning for normal climatic variation, insurance program, and emergency recovery plans mitigate the effects of the weather, not all such effects can be predicted, eliminated or insured against.
 
Costs Incurred Related to Environmental Matters
 
We, as an owner or lessee and operator of oil and gas properties, 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 resulting from operations, subject the lessee to liability for pollution damages, and require suspension or cessation of operations in affected areas.
 
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 also have established operational procedures and training programs designed to minimize the environmental impact of our field facilities. The costs incurred by these policies and procedures are inextricably connected to normal operating expenses such that we are unable to separate the expenses related to environmental matters; however, we do not believe any such additional expenses are material to our financial position or results of operations.
 
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, its 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 our employees who are expected to devote a significant amount of time to any possible remediation effort. Our general policy is to limit any reserve additions to incidents or sites that are considered probable to result in an expected remediation cost exceeding $100,000.
 
We maintain insurance coverage, which we believe is customary in the industry, although we are not fully insured against all environmental risks. As described in Note 10, Commitments and Contingencies of Item 15, in this Form 10-K, on December 31, 2006, we had an accrued liability of $17 million for environmental remediation. We have not incurred any material environmental remediation costs in any of the periods presented and we are not aware of any future environmental remediation matters that would be material to our financial position or results of operations.
 
Although environmental requirements have a substantial impact upon the energy industry, generally these requirements do not appear to affect us any differently, or to any greater or lesser extent, than other upstream companies in the industry. We do not believe that compliance with federal, provincial, state, local or foreign country provisions regulating the discharge of materials into the environment, or otherwise relating to the protection of the environment, will have a material adverse effect upon the capital expenditures, earnings or competitive position of Apache or its subsidiaries; however, there is no assurance that changes in or additions to laws or regulations regarding the protection of the environment will not have such an impact.
 
Industry Competition
 
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 the marketing of oil and natural gas production. Higher recent crude oil and natural gas prices have increased the costs of properties


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available for acquisition and there are a greater number of companies with the financial resources to pursue acquisition opportunities. Many of our competitors have financial and other resources substantially larger than those 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 changing worldwide 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, geo-physicists, engineers and other specialists.
 
Insurance Does Not Cover All Risks
 
Exploration for and production of oil and natural gas can be hazardous, involving unforeseen occurrences such as blowouts, cratering, fires 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 or the environment. We maintain insurance against certain losses or liabilities arising from our operations in accordance with customary industry practices and in amounts that management believes to be prudent; however, insurance is not available to us against all operational risks.
 
In response to large underwriting losses caused by Hurricanes Katrina and Rita, the insurance industry has reduced capacity for windstorm damage and substantially increased premium rates. As a result, there is no assurance that Apache will be able to arrange insurance to cover fully its Gulf of Mexico exposures at a reasonable cost when the current policies expire.
 
ITEM 1B.  UNRESOLVED SEC STAFF COMMENTS
 
As of December 31, 2006, we did not have any unresolved comments from the SEC staff that were received 180 or more days prior to yearend. We responded to comments from the SEC staff that we received in December 2006, and are awaiting final resolution. We do not believe the comments or our responses thereto materially impact any previous or prospective disclosures.
 
ITEM 3.  LEGAL PROCEEDINGS
 
See the information set forth in Note 10, Commitments and Contingencies of Item 15 and Item 1A, Risk Factors, “Costs Incurred Related to Environmental Matters” in this Form 10-K.
 
ITEM 4.  SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
 
No matters were submitted to a vote of our security holders during the most recently ended fiscal quarter.


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PART II
 
ITEM 5.  MARKET FOR THE REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
 
During 2006, 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 2006 and 2005. 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.
 
                                                                 
    2006     2005  
    Price Range     Dividends Per Share     Price Range     Dividends Per Share  
    High     Low     Declared     Paid     High     Low     Declared     Paid  
 
First Quarter
  $ 76.25     $ 63.17     $ .10     $ .10     $ 65.90     $ 47.45     $ .08     $ .08  
Second Quarter
    75.66       56.50       .10       .10       67.99       51.52       .08       .08  
Third Quarter
    72.40       59.18       .15       .10       78.60       64.85       .10       .08  
Fourth Quarter
    70.50       59.99       .15       .15       75.95       59.36       .10       .10  
 
The closing price per share of our common stock, as reported on the New York Stock Exchange Composite Transactions Reporting System for January 31, 2007, was $72.97. On January 31, 2007, there were 330,958,433 shares of our common stock outstanding held by approximately 7,000 shareholders of record and approximately 319,000 beneficial owners.
 
We have paid cash dividends on our common stock for 42 consecutive years through December 31, 2006. 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.
 
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. Unless the rights have been previously redeemed, all shares of Apache common stock are issued with rights and, the rights trade automatically with our shares of common stock. For a description of the rights, please refer to Note 8, Capital Stock of Item 15 in this Form 10-K.
 
In 2003, our board of directors declared a two-for-one common stock split which was distributed on January 14, 2004 to holders of record on December 31, 2003. In connection with the stock split, the Company issued 166,254,667 shares.
 
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 2007 annual meeting of stockholders, which is incorporated herein by reference.
 
The following stock price performance graph is intended to allow review of stockholder returns, expressed in terms of the appreciation of the Company’s common stock relative to two broad-based stock performance indices. The information is included for historical comparative purposes only and should not be considered indicative of future stock performance. The graph compares the yearly percentage change in the cumulative total stockholder return on the Company’s common stock with the cumulative total return of the Standard & Poor’s Composite 500


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Stock Index and of the Dow Jones U.S. Exploration and Production Index (formerly Dow Jones Secondary Oils Stock Index) from December 31, 2001 through December 31, 2006.
 
Comparison of Five Year Cumulative Total Return
For the Year Ended December 31, 2006
 
 
                                                             
      2001     2002     2003     2004     2005     2006
Apache Corporation
      100         115.13         173.15         217.15         295.92         289.11  
S & P’s Composite 500 Stock
      100         77.9         100.25         111.15         116.61         135.03  
DJ US Expl & Prod Index*
      100         102.17         133.9         189.97         314.06         330.93  
                                                             
 
 
* formerly DJ Secondary Oil Stock Index


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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, 2006, 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 of Item 15 in this Form 10-K.
 
                                         
    As of or For the Year Ended December 31,  
    2006     2005     2004     2003     2002  
    (In thousands, except per share amounts)  
 
Income Statement Data
                                       
Total revenues
  $ 8,288,779     $ 7,584,244     $ 5,332,577     $ 4,190,299     $ 2,559,873  
Income (loss) attributable to common stock
    2,546,771       2,618,050       1,663,074       1,116,205       543,514  
Net income (loss) per common share:
                                       
Basic
    7.72       7.96       5.10       3.46       1.83  
Diluted
    7.64       7.84       5.03       3.43       1.80  
Cash dividends declared per common share
    .50       .36       .28       .22       .19  
Balance Sheet Data
                                       
Total assets
  $ 24,308,175     $ 19,271,796     $ 15,502,480     $ 12,416,126     $ 9,459,851  
Long-term debt
    2,019,831       2,191,954       2,588,390       2,326,966       2,158,815  
Preferred interests of subsidiaries
                            436,626  
Shareholders’ equity
    13,191,053       10,541,215       8,204,421       6,532,798       4,924,280  
Common shares outstanding
    330,737       330,121       327,458       324,497       302,506  
 
For a discussion of significant acquisitions and divestitures, see Note 2 of Item 15 in this Form 10-K.
 
ITEM 7.   MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
 
Overview
 
Apache Corporation (Apache or the Company) is an independent energy company whose principle business includes exploration, development and production of crude oil, natural gas and natural gas liquids. We operate in six countries: the United States, Canada, Egypt, Australia, offshore the United Kingdom in the North Sea, and Argentina.
 
In 2006, we earned $2.5 billion, within three percent of last year’s record earnings, despite a 19 percent decline in gas price realizations. Cash provided by operating activities totaled $4.3 billion, flat to 2005. We also set records for production and reserves with worldwide equivalent production increasing 10 percent, making 2006 the 27th out of the last 28 years that we have reported production growth. Reserves grew nine percent, increasing in every core area, marking the 21st consecutive year of reserve growth at Apache.
 
Our growth strategy focuses on economic growth through drilling, acquisitions, or a combination of both, depending on, among other things, costs levels, potential rates of return and the availability of acquisition opportunities. We utilize a portfolio approach to provide diversity in terms of geologic risk, geographic location, hydrocarbon mix (crude oil and natural gas) and reserve life. This strategy provides multiple avenues for growth. We took several steps in 2006 to balance and grow our asset base. Outside of North America, we divested two assets: the undeveloped deepwater section of Egypt’s West Mediterranean Concession and our interest in the Zhao Dong block offshore the People’s Republic of China. To rebalance our international portfolio, we bolstered our position in Argentina purchasing an estimated 109 MMboe of reserves in two separate transactions. After increasing our production on these properties through active operations, Argentina is now our newest core area and we operate an


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attractive property base that we believe has significant upside. In the U.S., we completed two strategic purchases strengthening our Permian basin and Gulf of Mexico positions. In January 2006, we purchased an estimated 31 MMboe of proved reserves in long life producing properties in the Permian basin of West Texas. The acquisition was balanced by purchasing 44 MMboe of shorter life, but higher rate-of-return reserves in the Gulf of Mexico. Worldwide, we purchased an estimated 196.5 MMboe of proved reserves. On the exploration and development side, we drilled 1,611 wells with an 87 percent success rate with active drilling programs in all core areas. We invested $3.7 billion in exploration and development activities, excluding asset retirement costs and capitalized interest, adding 224 MMboe in of estimated proved reserves. Our reserve life across our core areas spans from eight to twenty years, with a 46 percent oil and 54 percent natural gas mix, consistent with yearend 2005.
 
Apache’s profitability is a function of commodity prices, the cost to add reserves through drilling and acquisitions and the cost to produce our reserves. Trends in commodity prices directly impact oil and gas revenues and demand for services and thus, have a significant impact on drilling and operating costs. We closely monitor trends in drilling costs in each of our core areas and the prices paid to acquire producing properties and, when appropriate, adjust our capital budgets.
 
Commodity prices are driven by the prevailing worldwide price for crude oil, spot prices applicable to our United States and Canadian natural gas production and many other factors beyond our control. Historically, these prices have been volatile and unpredictable, and 2006 was no exception. Our 2006 crude oil price realizations averaged $59.92 per barrel, up 16 percent from 2005, ranging from an average monthly high of $68.59 per barrel in July to a low of $52.64 per barrel in October as demand waned in the U.S. with a delay in the onset of seasonal temperatures. Natural gas realizations were 19 percent lower than last year, averaging $5.17 per thousand cubic feet (Mcf), with a high of $8.05 per Mcf in January, and a low of $3.85 per Mcf in October.
 
A high drilling and operating cost environment once again challenged us in 2006, continuing the trend seen over the past few years. This upward trend is a reflection of increased demand driven by historically high commodity prices. In addition, repair activity from the 2005 Gulf of Mexico hurricanes also increased demand for services in the U.S., and accordingly, costs. Cost increases were reflected in nearly all of our drilling and lease operating cost components, including: rig rates, drill pipe costs, labor costs, chemical costs and the costs of power and fuel. The Company reviews costs for each core area on a routine basis and pursues alternatives in maintaining efficient levels of costs and expenses. Despite pressure from rising costs, 2006 margins, while down slightly from record 2005 levels, were the second highest in our 50-plus-year history. For purposes of this discussion, margins are calculated as follows:
 
                         
    2006     2005     2004  
    (In thousands, except margin)  
 
Income before Income Taxes
  $ 4,009,595     $ 4,206,524     $ 2,663,083  
Barrels of oil equivalent produced
    182,913       165,890       164,050  
Margin per boe produced
  $ 44.14     $ 44.95     $ 32.36  
 
While the Company has made considerable progress recovering from the damage caused by Hurricanes Katrina and Rita, which struck in late August and late September 2005, the hurricanes had considerable impact on both 2006 and 2005 operations and results, and will impact 2007 operations. In addition to extensive damage to Apache’s onshore and offshore Gulf of Mexico production and transportation facilities, third-party pipelines, terminals and processing facilities, which the Company relies upon to transport and process its crude oil and natural gas also sustained substantial damage. For a discussion of the impact on 2006 and 2005 operations and results refer to Results of Operations and Oil and Gas Capital Expenditures in this Item 7.
 
Results of Operations
 
This section includes a discussion of our 2006 and 2005 results of operations and provides insight into unique events and circumstances for each of the Company’s six reportable segments. Please refer to Note 12, Business Segment Information of Item 15 in this Form 10-K for segment information.


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Acquisitions and Divestitures
 
2006 Acquisitions
 
U.S. Permian Basin
 
On January 5, 2006, the Company purchased Amerada Hess’s interest in eight fields located in the Permian basin of West Texas and New Mexico. The original purchase price was reduced from $404 million to $269 million because other interest owners exercised their preferential rights to purchase a number of the properties. The settlement price at closing of $239 million was adjusted for revenues and expenditures occurring between the effective date and the closing date of the acquisition. The acquired fields had estimated proved reserves of 27 MMbbls of liquid hydrocarbons and 27 Bcf of natural gas as of yearend 2005.
 
Argentina
 
On April 25, 2006, the Company acquired the operations of Pioneer Natural Resources (Pioneer) in Argentina for $675 million. The settlement price at closing, of $703 million, was adjusted for revenues and expenditures occurring between the effective date and closing date of the acquisition. The properties are located in the Neuquén, San Jorge and Austral basins of Argentina and had estimated net proved reserves of approximately 22 MMbbls of liquid hydrocarbons and 297 Bcf of natural gas as of December 31, 2005. Eight gas processing plants (five operated and three non-operated), 112 miles of operated pipelines in the Neuquén basin and 2,200 square miles of three-dimensional (3-D) seismic data were also included in the transactions. Apache financed the purchase with cash on hand and commercial paper.
 
The purchase price was allocated to the assets acquired and liabilities assumed based upon the estimated fair values as of the date of acquisition, as follows (in thousands):
 
         
Proved property
  $ 501,938  
Unproved property
    189,500  
Gas Plants
    51,200  
Working capital acquired, net
    11,256  
Asset retirement obligation
    (13,635 )
Deferred income tax liability
    (37,630 )
         
Cash consideration
  $ 702,629  
         
 
On September 19, 2006, Apache acquired additional interests in (and now operates) seven concessions in the Tierra del Fuego Province from Pan American Fueguina S.R.L. (Pan American) for total consideration of $429 million. The settlement price at closing of $396 million was adjusted for normal closing items, including revenues and expenses between the effective date and the closing date of the acquisition. Apache financed the purchase with cash on hand and commercial paper.
 
The total cash consideration allocated below includes working capital balances purchased, asset retirement obligations assumed and an obligation to deliver specific gas volumes in the future. The purchase price was allocated to the assets acquired and liabilities assumed based upon the estimated fair values as of the date of acquisition, as follows (in thousands):
 
         
Proved property
  $ 289,916  
Unproved property
    132,000  
Gas plants
    12,722  
Working capital acquired, net
    8,929  
Asset retirement obligation
    (1,511 )
Assumed obligation
    (46,000 )
         
Cash consideration
  $ 396,056  
         


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Offshore Gulf of Mexico
 
In June 2006, the Company acquired the remaining producing properties of BP plc (BP) on the Outer Continental Shelf of the Gulf of Mexico. The original purchase price was reduced from $1.3 billion for 18 producing fields to $845 million because other interest owners exercised their preferential rights to purchase five of the 18 fields. The purchase price consisted of $747 million of proved property, $42 million of unproved property and $56 million of facilities. The settlement price on the date of closing of $821 million was adjusted primarily for revenues and expenditures occurring between the April 1, 2006 effective date and the closing date of the acquisition. The acquired properties include 13 producing fields (nine of which are operated) with estimated proved reserves of 19.5 MMbbls of liquid hydrocarbons and 148 Bcf of natural gas. Apache financed the purchase with cash on hand and commercial paper.
 
Pending Acquisition — U.S. Permian Basin
 
On January 18, 2007, the Company announced that it is acquiring controlling interest in 28 oil and gas fields in the Permian basin of West Texas from Anadarko Petroleum Corporation (Anadarko) for $1 billion. Apache estimates that these fields had proved reserves of 57 million barrels (MMbbls) of liquid hydrocarbons and 78 billion cubic feet (Bcf) of natural gas as of yearend 2006. The transaction will be effective the earlier of closing or March 31, 2007. Approximately 10 percent of the Permian basin properties are subject to third-party preferential purchase rights which, if exercised, would reduce the interests we purchase in those properties and the purchase price we would pay. The Company intends to fund the acquisition with debt. Apache and Anadarko are entering into a joint-venture arrangement to effect the transaction. In connection with the acquisition, the Company entered into cash flow hedges to protect against commodity price volatility. For the period of July 2007 through June 2010, the Company entered into hedges for a portion of both the oil and the natural gas with NYMEX based costless collars.
 
2006 Divestitures
 
On January 6, 2006, the Company completed the sale of its 55 percent interest in the deepwater section of Egypt’s West Mediterranean Concession to Amerada Hess for $413 million. Apache did not have any proved reserves booked for these properties.
 
On August 8, 2006, the Company completed the sale of its 24.5 percent interest in the Zhao Dong block offshore, the People’s Republic of China, to Australia-based ROC Oil Company Limited for $260 million, marking Apache’s exit from China. The effective date of the transaction was July 1, 2006. The Company recorded a gain of $174 million in the third quarter of 2006.
 
2005 Acquisitions
 
In May 2005, Apache signed a farm-in agreement with Exxon Mobil Corporation (ExxonMobil) covering approximately 650,000 acres of undeveloped properties in the Western Canadian province of Alberta. Under the agreement, Apache is to drill and operate 145 new wells over a 36-month period with upside potential for further drilling. ExxonMobil will retain a royalty on fee lands and a convertible working interest on leasehold acreage. The agreement also allows Apache to test additional horizons on approximately 140,000 acres of property covered in a 2004 farm-in agreement with ExxonMobil.
 
Revenues
 
Our revenues are sensitive to changes in prices received for our products. A substantial portion of our production is sold at prevailing market prices which fluctuate in response to many factors that are outside of our control. Given the current tightly balanced supply-demand market, small variations in either supply or demand, or both, can have dramatic effects on prices we receive for our oil and natural gas production. Political instability and availability of alternative fuels could impact worldwide supply, while other economic factors could impact demand.


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Oil and Natural Gas Prices
 
While the market price received for crude oil and natural gas varies among geographic areas, crude oil trades in a worldwide market, whereas natural gas, which has a limited global transportation system, is subject to local supply and demand conditions. Consequently, price movements for all types and grades of crude oil generally move in the same direction, while natural gas price movements generally follow local market conditions.
 
Apache primarily sells its natural gas into four markets:
 
  1)  North America, which has a common market and where supply and demand are currently tightly balanced, creating a volatile pricing environment;
 
  2)  Australia, which has a local market with mostly fixed-price contracts;
 
  3)  Egypt, which has a local market where the price received for our production is indexed to a weighted-average Dated-Brent crude oil price; most of which is subject to a ceiling of $2.65 per MMBtu at oil-prices of $21 per barrel or above; and
 
  4)  Argentina, where the price we receive on a portion of our natural gas production is regulated by the government, at prices from $.38 to $1.40 per MMBtu. The volumes we are required to sell at regulated prices are set by the government and vary with seasonal factors. The remainder of the volumes are sold at market-driven prices, presently in excess of $2.00/MMBtu.
 
For specific marketing arrangements by segment, please refer to Item 1 and 2. Business and Properties of this Form 10-K.


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Revenues
 
The table below presents oil and gas production revenues, production and average prices received from sales of natural gas, oil and natural gas liquids for the most recent three years.
 
                         
    For the Year Ended December 31,  
    2006     2005     2004  
 
Revenues (in thousands):
                       
Oil
  $ 4,911,861     $ 4,413,934     $ 2,986,208  
Natural gas
    3,001,246       2,928,578       2,217,983  
Natural gas liquids
    161,146       114,779       103,826  
                         
Total
  $ 8,074,253     $ 7,457,291     $ 5,308,017  
                         
Oil Volume — Barrels per day:
                       
United States
    66,832       66,268       67,872  
Canada
    20,715       22,499       25,305  
Egypt
    56,570       55,141       52,183  
Australia
    11,892       15,379       25,174  
North Sea
    58,544       65,488       52,836  
Argentina
    6,857       1,163       566  
China
    3,167       8,132       7,583  
                         
Total
    224,577       234,070       231,519  
                         
Average Oil Price — Per barrel:
                       
United States
  $ 54.22     $ 47.97     $ 38.75  
Canada
    59.90       53.05       38.57  
Egypt
    63.60       53.69       37.35  
Australia
    68.25       57.61       41.96  
North Sea
    63.04       53.00       24.22  
Argentina
    42.79       37.54       32.89  
China
    62.73       44.24       32.88  
Total
    59.92       51.66       35.24  
Natural Gas Volume — Mcf per day:
                       
United States
    666,965       597,481       646,619  
Canada
    404,325       371,917       326,965  
Egypt
    217,601       165,710       137,737  
Australia
    186,119       123,295       118,108  
North Sea
    2,061       2,306       1,871  
Argentina
    111,994       3,114       3,808  
                         
Total
    1,589,065       1,263,823       1,235,108  
                         
Average Natural Gas Price — Per Mcf:
                       
United States
  $ 6.54     $ 7.22     $ 5.45  
Canada
    6.09       7.29       5.30  
Egypt
    4.42       4.59       4.35  
Australia
    1.65       1.72       1.65  
North Sea
    10.64       9.17       5.53  
Argentina
    .97       1.14       .65  
Total
    5.17       6.35       4.91  
NGL Volume — Barrels per day:
                       
United States
    7,985       7,553       8,268  
Canada
    2,187       2,235       2,588  
Argentina
    1,537              
                         
Total
    11,709       9,788       10,856  
                         
Average NGL Price — Per barrel:
                       
United States
  $ 38.54     $ 32.44     $ 26.66  
Canada
    35.40       31.07       24.44  
Argentina
    36.64              
Total
    37.70       32.13       26.13  


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Contributions to Oil and Natural Gas Revenues
 
As with production and reserves, a consequence of geographic diversification is a shifting geographic mix of our oil revenues and natural gas revenues. For the reasons discussed in the Oil and Natural Gas Prices section above, contributions to oil revenues and gas revenues should be viewed separately.
 
The following table presents each segment’s oil revenues and gas revenues as a percentage of total oil revenues and gas revenues, respectively.
 
                                                 
    Oil Revenues
    Gas Revenues
 
    For the Year Ended December 31,     For the Year Ended December 31,  
    2006     2005     2004     2006     2005     2004  
 
United States
    27 %     26 %     32 %     53 %     54 %     58 %
Canada
    9 %     10 %     12 %     30 %     34 %     29 %
                                                 
North America
    36 %     36 %     44 %     83 %     88 %     87 %
Egypt
    27 %     25 %     24 %     12 %     9 %     10 %
Australia
    6 %     7 %     13 %     4 %     3 %     3 %
North Sea
    27 %     29 %     16 %                  
Argentina
    2 %                 1 %            
Other International
    2 %     3 %     3 %                  
                                                 
Total
    100 %     100 %     100 %     100 %     100 %     100 %
                                                 
 
Crude Oil Contribution
 
In 2006, oil revenue contributions outside of North America were 64 percent of our total consolidated oil revenues, equal to 2005 contributions. Except for Australia, all core regions saw oil revenue growth in 2006 when compared to 2005. Egypt and the United States saw their contributions rise as their 2006 revenue gains, relative to 2005, outpaced gains in our other regions, benefiting from both higher relative oil prices and production. Argentina’s contribution increase in 2006, compared to 2005, was virtually all attributable to the 2006 acquisitions discussed above, although the region also benefited from price improvement. The North Sea and Canada’s 2006 contributions fell because higher prices were somewhat neutralized by lower relative production and higher oil revenue in other core areas.
 
In 2005, oil revenue contributions from outside the U.S. rose six percent to 74 percent of our total consolidated oil revenues. Production growth and significantly higher price realizations drove the North Sea’s oil revenue contributions to 29 percent of consolidated oil revenues from 16 percent the prior year and were largely responsible for the growth of non-U.S. oil revenues. U.S. oil revenues made up 26 percent of 2005 oil revenues, down six percent from 2004, a consequence of the 2005 hurricane activity and the significant growth in North Sea production. Australia’s contribution to 2005 consolidated oil revenues fell to seven percent from 13 percent on a 39 percent decrease in production compared to 2004.
 
Crude Oil Revenues
 
Crude oil revenues in 2006 increased $498 million from 2005 to $4.9 billion. Price gains across all regions, which averaged $8.26 more per barrel than 2005, generated an additional $706 million of revenues. These additional revenues were partially offset by the effect on revenues from a four percent decline in production. All segments reported a significant increase in realized crude oil price, with Argentina, Egypt, and the U.S. also benefiting from production growth compared to 2005.
 
Egypt generated an additional $233 million of crude oil revenue in 2006 when compared to 2005. An 18 percent increase in crude oil price realizations, generated $200 million of the additional revenues, with the remainder coming from a three percent increase in production. While Egypt experienced production growth in many areas, the predominate contributor was the Khalda Concession which benefited from a full year of associated condensate related to increased Qasr field gas production.


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U.S. crude oil revenues for 2006 increased $162 million compared to 2005, with a 13 percent increase in crude oil price realizations contributing $151 million of the additional revenues. A small increase in 2006 oil production, relative to 2005, contributed the remaining $11 million. The third-quarter 2005 hurricanes reduced Apache’s 2006 average annual daily crude oil production 13,100 barrels per day (b/d), compared to 10,813 b/d in 2005. Shut-in production reduced the Company’s 2006 and 2005 crude oil revenues by approximately $297 million and $186 million, respectively. Central region production rose 18 percent, reflecting drilling and recompletion activity in the Permian basin and Southeast New Mexico, and the Amerada Hess acquired properties. Gulf Coast production was 10 percent below 2005 levels with downtime, hurricane production shut-ins and natural decline outpacing growth attributed to drilling and recompletion activity and the BP acquired properties. The Gulf Coast region’s fourth-quarter 2006 production averaged 43,995 b/d compared to 23,487 b/d in the comparable 2005 quarter, a testament to the progress in returning hurricane damaged properties to production during 2006, as well as the benefit of the BP acquired properties.
 
Argentina’s 2006 oil revenues increased $91 million over 2005 with $89 million of the increase associated with production growth, driven primarily by acquired properties and subsequent exploitation activities. Higher oil price realizations generated the other $2 million.
 
The North Sea’s 2006 crude oil revenues were $80 million higher than 2005 with $240 million of additional revenues generated from a 19 percent increase in price realizations, partially offset by lower production, which was down 11 percent on a comparative basis. Production was lower in 2006 primarily because of production interruptions associated with commissioning of major infrastructure projects and temporary unplanned shutdown of the third-party Forties Pipeline System during the third quarter of 2006. The focus in 2006 on upgrades also displaced drilling operations necessary to mitigate natural decline.
 
Canada’s 2006 oil revenues increased $17 million over 2005, with $56 million of additional revenues associated with higher price realizations, partially offset by lower production, which was down eight percent. Canada production was down in most areas as natural decline exceeded drilling and production enhancement activities.
 
Australia’s 2006 crude oil revenues were $27 million less than 2005, reflecting a 23 percent decline in production and an 18 percent increase in realized price. The production decrease resulted from normal field decline which offset a full year of associated condensate production from the John Brookes field and other development activities, mainly in the Bambra, Zephyrus and Stag areas.
 
China’s 2006 oil revenues were $59 million less than 2005, a consequence of the August 2006 divestiture.
 
Apache manages a small portion of its exposure to fluctuations in crude oil prices using financial derivatives. Approximately nine percent of our worldwide crude oil production was subject to financial derivative hedges in 2006, compared to six percent in 2005. (See Note 3, Hedging and Derivative Instruments, of this Form 10-K for a summary of the current derivative positions and terms.) These financial derivative instruments reduced our 2006 and 2005 worldwide realized prices $1.37 and $.68 per barrel, respectively.
 
Natural Gas Contribution
 
Our North American operations contributed 83 percent of 2006 consolidated natural gas revenues, down five percent from 2005. All core gas producing regions generated additional revenues in 2006 on production growth. However, these incremental production revenues were all but eliminated by the effect of lower prices, especially in our North American regions, where prices are typically higher, but more volatile, than our other regions. Revenues in the U.S. and Canada dropped in 2006 on a comparative basis, while all other core gas producing regions experienced an increase in revenue. Egypt’s contribution to 2006 consolidated gas revenues rose three percent in 2006, compared to 2005, while Australia’s contribution increased one percent. Argentina contributed one percent of consolidated gas revenues.
 
In 2005, 88 percent of Apache’s natural gas revenues came from North America, 54 percent from the U.S. and 34 percent from Canada. The U.S. contribution decreased four percent from 2004, primarily because of production declines, the impact Hurricanes Katrina and Rita had on U.S. Gulf of Mexico revenues, and the additional revenues generated by Canada and Egypt. Our U.S. Gulf Coast region, which contributed 63 percent of Apache’s U.S. 2005


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production, down six percent from 2004, is characterized by reservoirs which demonstrate high initial production rates followed by steep declines when compared to most other U.S. producing areas. Canada’s contribution was up five percent from 2004 resulting from 14 percent production growth and higher price gains, relative to other areas. Egypt’s contribution to total gas revenues decreased slightly to nine percent from 10 percent in 2004. Australia’s contribution to 2005 natural gas revenues remained the same as 2004 at three percent.
 
Natural Gas Revenues
 
Our 2006 consolidated natural gas revenues increased $73 million from the prior year with $614 million of additional revenues generated from production growth mostly offset by the effect of a 19 percent decline in realized prices. All core gas producing regions generated additional revenues in 2006 from production growth; however they were mostly offset by lower relative natural gas prices.
 
Egypt contributed $73 million more to 2006 consolidated natural gas revenues compared to 2005 on a 31 percent increase in production and a four percent decrease in realized gas prices. The year-over-year production growth came primarily from the Khalda concession, mostly attributable to a full year of production from the Qasr field.
 
Argentina’s 2006 natural gas revenues increased $38 million compared to 2005, with all of the additional revenues associated with production growth. As with oil, the production growth primarily came from acquired properties and subsequent exploitation activities.
 
Australia’s 2006 natural gas revenues were $35 million higher than 2005. Natural gas production increases added $38 million to revenues, while lower gas price realizations reduced revenues $3 million. The additional production was attributed to a full year of production from the John Brookes field.
 
U.S. natural gas revenues were $17 million higher in 2006 than 2005. U.S. natural gas production, up 12 percent, contributed $166 million of additional revenues, while a nine percent price decline lowered revenues $149 million, when compared to 2005. The 2005 hurricanes reduced Apache’s 2006 average annual daily natural gas production 37 MMcf/d compared to 59 MMcf/d in 2005. Shut-in production from the hurricanes reduced the Company’s 2006 and 2005 natural gas revenues by approximately $95 million and $211 million, respectively. Central region production rose 16 percent from 2005, benefiting from drilling and recompletion activity, primarily in Central and Western Oklahoma, in East Texas, and from acquired properties. Gulf Coast region production was nine percent above year-ago levels on the BP acquired properties, hurricane restoration, and drilling and recompletion activity, principally in the Chauvin, Ship Shoal and South Timbalier fields.
 
Canada’s 2006 natural gas revenues decreased $91 million from 2005. An additional $72 million of revenues generated from a nine percent increase in production were more than offset by the impact of a 16 percent decrease in realized natural gas prices. Canada’s production growth was concentrated in the North and South Grant Lands and Kabob areas, with activity in other areas more than offset by natural decline.
 
Our 2005 natural gas revenues increased $711 million with a $1.44 per Mcf increase in our average natural gas price realizations generating an additional $652 million of revenues. Higher production added the remaining $59 million. While all of our operating segments reported an increase in natural gas price realizations, most of the additional revenues attributable to price came from the U.S. and Canada as prices skyrocketed following the Gulf of Mexico hurricanes. The additional revenues attributable to production were primarily generated in Egypt, where natural gas production increased 20 percent, reflecting the success of our drilling program. Canada and Australia also contributed to increased production revenues with production growth of 14 percent and four percent, respectively. Canada’s increase was from new wells, while Australia’s increase was driven by higher customer demand and new contractual sales. Partially offsetting these additional production revenues was an eight percent decrease in U.S. production, primarily in the Gulf Coast region, related to the impact of the 2005 hurricanes and natural decline in mature fields.
 
The majority of our worldwide gas sales contracts are indexed to prevailing local market prices. As a result Apache uses a variety of strategies to manage its exposure to fluctuations in natural gas prices including fixed-price contracts and derivatives. In the U.S. and Canada most of our gas is sold on a monthly basis at either monthly or daily market prices; however, during 2006 and 2005, approximately eight percent and 10 percent of our U.S. natural


27


 

gas production, respectively, was subject to long-term, fixed-price physical contracts. These contracts provide a measure of protection to the Company in the event of decreasing natural gas prices. These fixed-price contracts reduced our 2006 and 2005 worldwide realized natural gas prices by $.10 per Mcf and $.19 per Mcf, respectively. In Australia, nearly all of our natural gas production is subject to long-term fixed-price contracts that are periodically adjusted for changes in Australia’s consumer price index. The majority of Egypt’s gas is sold to Egyptian General Petroleum Corporation (EGPC) under an Industry Pricing Formula tied to Dated Brent crude oil with a maximum price of $2.65 per MMbtu. However, in certain concessions Apache has retained a higher gas price formula until 2013 for up to 100 MMcf/d produced.
 
Approximately eight percent of our worldwide natural gas production was subject to financial derivative hedges for 2006 compared to nine percent in 2005. These financial derivative instruments reduced our 2006 and 2005 consolidated realized prices $.05 per Mcf and $.15 per Mcf, respectively. (See Note 3, Hedging and Derivative Instruments of Item 15 in this Form 10-K for a summary of current derivative positions and terms.)
 
Costs
 
The tables below compare our costs on an absolute dollar basis and an equivalent unit of production (boe) basis. Our discussion may reference either expenses on a boe basis or expenses on an absolute dollar basis, or both, depending on their relevance.
 
                                                 
    Year Ended December 31,     Year Ended December 31,  
    2006     2005     2004     2006     2005     2004  
    (In millions)     (Per boe)  
 
Depreciation, depletion and amortization:
                                               
Oil and gas property and equipment
  $ 1,699     $ 1,325     $ 1,149     $ 9.29     $ 7.99     $ 7.01  
Other assets
    118       91       73       .64       .55       .44  
Asset retirement obligation accretion
    89       54       46       .48       .32       .28  
Lease operating costs
    1,362       1,041       864       7.45       6.27       5.27  
Gathering and transportation costs
    104       100       82       .57       .60       .50  
Severance and other taxes
    554       453       94       3.03       2.73       .57  
General and administrative expenses
    211       198       173       1.16       1.20       1.06  
China litigation
                71                   .43  
Financing costs, net
    142       116       117       .78       .70       .71  
                                                 
Total
  $ 4,279     $ 3,378     $ 2,669     $ 23.40     $ 20.36     $ 16.27  
                                                 
 
Depreciation, Depletion and Amortization
 
Apache’s Depreciation, Depletion and Amortization (DD&A) of oil and gas properties is calculated using the Units of Production Method (UOP). The UOP calculation in simplest terms multiplies the percentage of estimated proved reserves produced each quarter times the costs of those reserves. The result is to recognize expense at the same pace that the reservoirs are actually depleting. The costs in the UOP calculation include both the net capitalized amounts on the balance sheet, and the estimated future costs to access and develop reserves needing additional facilities, equipment or downhole work in order to produce. Under the full-cost method of accounting, the DD&A calculation is prepared separately for each country in which Apache operates. Absolute DD&A determines the expense reported each period, while the cost per unit of production (DD&A rate) provides insight into the overall costs of the Company’s reserves growth. Current costs incurred to drill or acquire additional reserves that are higher than the historical cost level raises the overall DD&A rate. Conversely, if reserves are added in the current period at a rate per unit less than existing levels, they average down the Company’s DD&A rate. Changes from period to period in absolute DD&A expense are determined by production levels, the mix of production (high cost country versus a low cost country) and the impact of recent spending (higher or lower DD&A rates).
 
Our 2006 full-cost DD&A expense totaled $1.7 billion, $374 million more than 2005. Our 2006 full-cost DD&A rate of $9.29 per boe was $1.30 per boe more than 2005, reflecting rising acquisition costs, higher


28


 

abandonment cost estimates, rising industry-wide drilling and finding costs, especially in the U.S. and Canada, and incremental future development costs associated with recent acquisitions and newly identified development projects. The increase in costs, including increased estimates of future development costs, is related to increased demand for drilling and associated services, a consequence of both higher oil and gas prices and additional demand resulting from the ongoing need to repair damage caused by hurricanes Katrina and Rita in 2005. The increase in 2006 DD&A, relative to 2005 was mitigated by a decline in Egypt resulting from the January 2006 sale of Egypt’s deepwater acreage. Our 2006 full-cost DD&A expense was $73 million lower because of the production shut-in for hurricane damage.
 
Our 2005 full-cost DD&A expense totaled $1.3 billion, $176 million more than 2004. Our 2005 full-cost DD&A rate of $7.99 per boe was $.98 per boe more than 2004, driven by rising industry-wide drilling costs, especially in the U.S., Canada, the North Sea and Egypt. Higher commodity prices experienced throughout 2005, as well as the affect of the 2005 U.S. hurricanes, led to increased demand for drilling services and thus higher current drilling costs and higher estimated future development costs. The North Sea’s impact on our consolidated rate reflects the continuation of facility upgrades undertaken during 2005 to improve the overall efficiency of platforms. Our 2005 full-cost DD&A expense was $57 million lower because of the production shut-in for hurricane damage.
 
Depreciation of other assets increased $27 million in 2006, reflecting ongoing development of infrastructure in Canada that began in 2005 to accommodate development on the acquired ExxonMobil acreage, and the Qasr field support facilities in Egypt, including completion of the Tarek gas plant inter-connect.
 
Depreciation of other assets increased $18 million in 2005, reflecting new infrastructure built in Canada to accommodate development on acreage acquired from ExxonMobil in 2004 and new Qasr natural gas facilities in Egypt.
 
Impairments
 
We assess all of our unproved properties for possible impairment on a quarterly basis based on geological trend analysis, dry holes or relinquishment of acreage. When impairment occurs, costs associated with these properties are generally transferred to our proved property base where they become subject to amortization. Impairments in international areas without proved reserves are charged to earnings upon determination that impairment has occurred.
 
Goodwill is subject to a periodic fair-value-based impairment assessment. Goodwill totaled $189 million on December 31, 2006, and no impairment was recorded in 2006, 2005 or 2004. For further discussion, see Note 1, Summary of Significant Accounting Policies of Item 15 in this Form 10-K.
 
Lease Operating Costs
 
Lease operating expenses (LOE) are comprised of several components: direct operating costs, repair and maintenance, workover costs and ad valorem taxes.
 
LOE rates are driven by the underlying commodity price levels, whether oil or gas is produced, level of workover activity and geographical location of the properties. Commodity prices have a significant impact on operating cost elements; both directly and indirectly. They directly impact costs such as power, fuel, chemicals and ad valorem taxes, which are commodity price based. The remaining elements, which include among other things, labor, services and equipment, are indirectly impacted by high price environments which drive up activity and demand and therefore, increase costs. All components of LOE have been rising throughout the industry for several years with historically strong oil and gas prices. Also, oil is inherently more expensive to produce than natural gas. Repair and maintenance costs are higher on offshore properties and in areas with remote plants and facilities. Workovers allow us to exploit our existing reserve base by accelerating production, taking advantage of high prices. Fluctuations in exchange rates impact the Company’s LOE, with a weakening U.S. dollar adding to per unit costs and a stronger U.S. dollar lowering per unit costs.
 
The Company reviews production costs in each of its core areas on a monthly basis and pursues alternatives to maintain efficient levels of costs. The following discussion will focus on per unit operating costs as management believes this is the most informative method of analyzing LOE trends.


29


 

 
Rising per unit cost remained a challenge in 2006 with LOE averaging $7.45 per boe, $1.18 per boe higher than 2005. The 2005 hurricanes increased our worldwide rate by $.44 and $.41 per boe in 2006 and 2005, respectively, a reflection of shut-in production and additional expenses in excess of our insurance coverage. The remainder of the increase was driven by industry-wide cost increases, as discussed above, workover activity, a weaker U.S. dollar relative to the Canadian dollar and British Pound and higher non-hurricane related repair costs in our U.S. Gulf Coast and Canadian regions.
 
Regionally, 2006 LOE was up from 2005 as follows:
 
U.S. — The U.S. added $.63 per boe to the 2006 worldwide rate. The Central region added $.04 per boe, with production growth nearly outpacing increases in costs, while the Gulf Coast region added $.59 per boe. In addition to the impact of industry-wide cost increases, activity levels soared in the Gulf of Mexico as producers continue to repair and restore production following the 2005 hurricanes. This increase in demand on top of an already tight-supply market for boats, helicopters, divers, labor, equipment and parts to complete repairs, pushed costs even higher in the region. The region’s fourth-quarter 2006 LOE included approximately $26 million for repairs in excess of insurance coverage. We will incur an estimated $60 million of additional LOE expenses to complete the repairs during the first half of 2007. The 2006 rate increase was also impacted by additional workover activity, higher insurance rates and more non-hurricane repair costs, relative to 2005.
 
Canada — Canada added $.40 per boe to the 2006 worldwide rate. Higher costs added $.46 per boe, however, higher production offset $.06 of that increase. Twenty-two percent of the increase in Canada’s rate was attributed to the strengthening Canadian dollar. The balance related to a higher level of workover activity, higher repair and maintenance costs, reclamation and restoration projects undertaken during 2006 and the general rise in costs, including increases in power rates, contract labor and fuel.
 
Egypt — Egypt added $.02 to the 2006 worldwide rate as a $32 million increase in costs, including increased workover activity, was mostly offset by associated production growth.
 
Australia — Australia reduced the 2006 worldwide rate $.11 per boe with production growth more than offsetting associated incremental operating costs.
 
North Sea — The North Sea added $.37 per boe to the 2006 consolidated rate, with approximately two-thirds of the increase in rate related to lower relative production, the strengthening British Pound and an increase in pension liabilities. The balance of the increase in costs related to major 2006 turnaround activity, higher fuel rates and usage as major projects were commissioned, and higher maintenance and repair activity, relative to 2005.
 
Argentina — Argentina reduced the 2006 consolidated rate $.19 per boe with production growth related to the 2006 acquisitions more than offsetting associated incremental operating costs.
 
On a per unit produced basis, 2005 LOE averaged $6.27 per boe, $1.00 per boe higher than 2004. Production shut-ins and additional insurance costs associated with the 2005 hurricanes added $.41 to the 2005 rate. The remaining increase reflects higher service costs associated with rising commodity prices and the associated increase in demand for services, an increase in workover activity, higher repair and maintenance costs and the impact a weaker U.S. dollar had on Canadian LOE. The slight strengthening against the Australian dollar and British pound had less impact on LOE.
 
Regionally, 2005 LOE was up as follows:
 
U.S. — The U.S. added $.77 per boe to the 2005 consolidated rate with nearly one-third of the impact attributed to the additional insurance costs and production shut-ins caused by the 2005 hurricanes. Higher contract labor costs, workover activity, repair and maintenance, and various other commodity-price driven service costs accounted for the remaining impact. Gulf Coast region LOE included approximately $30 million for insurance deductibles and additional premiums assessed by OIL.
 
Australia — Australia added $.15 per boe to the 2005 consolidated rate on a 20 percent drop in equivalent production. Australia also saw a rise in insurance cost. Lower production added $.13 per boe to the 2005 consolidated rate, while additional costs added $.02 per boe.


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Canada — Canada added $.21 per boe to the 2005 consolidated rate increase, with costs adding $.27 per boe, partially offset by the impact of higher volumes, which reduced the rate $.06 per boe. 2005 costs were up $44 million from 2004, with 42 percent attributable to the strengthening Canadian dollar. The balance related to various other costs associated with an increase in activity and the general rise in costs, including higher contract labor, power and fuel, repair and maintenance and workover costs.
 
Egypt — Egypt’s 2005 costs were $23 million higher than 2004 on higher diesel fuel costs, an increase in workover activity, higher labor costs and insurance costs. The diesel fuel costs were previously subsidized by the Egyptian government. Egypt added $.04 per boe to the consolidated rate increase, with higher costs adding $.14 per boe and increased volumes lowering the rate $.10 per boe.
 
North Sea — The North Sea reduced the 2005 consolidated rate $.16 per boe on a 24 percent increase in production, partially offset by a two percent increase in costs. North Sea costs were up on increased repair and maintenance activity.
 
Gathering and Transportation Costs
 
Apache generally sells oil and natural gas under two types of agreements, typical in our industry. Both types of agreements include a transportation charge. One is a netback arrangement, under which Apache sells oil or natural gas at the wellhead and collects a price, net of transportation incurred by the purchaser. In this case, the Company records sales at the price received from the purchaser, which is net of transportation costs. Under the other arrangement, Apache sells oil or natural gas at a specific delivery point, pays transportation to a third-party carrier and receives from the purchaser a price with no transportation deduction. In this case, the Company records the transportation cost as gathering and transportation costs. The Company’s treatment of transportation costs is pursuant to Emerging Issues Task Force Issue 00-10, “Accounting for Shipping and Handling Fees and Costs” and as a result a portion of our transporting costs is reflected in sales prices and a portion is reflected as Gathering and Transportation Costs rendering the separately identified transportation costs incomplete.
 
In both the U.S. and Canada, Apache sells oil and natural gas under both types of arrangements. In the North Sea, Apache pays transportation to a third-party carrier and receives a purchase price with no transportation deduction. In Australia, oil and natural gas are sold under netback arrangements. In Egypt, our oil and natural gas production has historically been sold to EGPC under netback arrangements. During 2005 and 2006, Apache exported a portion of its Egyptian crude oil under both types of arrangements. Future export cargoes may be sold at the loading port or Apache may arrange shipping and receive prices which include transportation. The following table presents gathering and transportation costs paid directly by Apache to third-party carriers for each of the periods presented.
 
                         
    For the Year Ended December 31,  
    2006     2005     2004  
    (In millions)  
 
U.S. 
  $ 32     $ 30     $ 28  
Canada
    34       33       31  
North Sea
    26       28       22  
Egypt
    11       8        
Argentina
    1              
Other International
          1       1  
                         
Total Gathering and Transportation
  $ 104     $ 100     $ 82  
                         
 
These costs are primarily related to the transportation of natural gas in our North American operations, North Sea crude oil sales and Egyptian crude oil exports. The four percent increase in costs for 2006 was driven primarily by U.S. production growth and Egyptian crude exports.


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Transportation costs in 2005 increased 22 percent from 2004 driven primarily by the North Sea’s production growth and Egyptian crude exports. Apache began exporting Egyptian crude in the second half of 2004 and first incurred third-party transportation charges in early 2005.
 
Severance and Other Taxes
 
Severance and other taxes are primarily comprised of severance taxes on properties onshore and in state or provincial waters in the U.S. and Australia, and the United Kingdom (U.K.) Petroleum Revenue Tax (PRT). Severance taxes are generally based on a percentage of oil and gas production revenues, while the U.K. PRT is assessed on net receipts (revenues less qualifying operating costs and capital spending) from the Forties field in the U.K. North Sea. We are also subject to the Australian Petroleum Resources Rent Tax (PRRT), and various Canadian taxes including the Freehold Mineral Tax, Saskatchewan Capital Tax and Saskatchewan Resource Surtax. The Canadian Federal Large Corporation Tax was phased out in 2006. The table below presents a comparison of these expenses.
 
                         
    For the Year Ended December 31,  
    2006     2005     2004  
    (In millions)  
 
Severance taxes
  $ 124     $ 139     $ 127  
U.K. PRT
    394       285       (61 )
Canadian taxes
    16       22       23  
Other
    20       7       5  
                         
Total Severance and Other Taxes
  $ 554     $ 453     $ 94  
                         
 
Severance and other taxes totaled $554 million in 2006, $101 million greater than 2005. U.K. PRT increased $109 million in 2006 on a six percent increase in revenue and a 21 percent decrease in qualifying capital spending. Australia’s severance taxes declined on lower revenues associated with lower oil production. Canada’s severance taxes decreased $6 million with the phase out of the federal large corporation tax. Other taxes increased $13 million on additional U.S. franchise taxes, consistent with our growth and a $5 million special profits charge levied on petroleum revenues by the Chinese government.
 
In 2005, severance and other taxes increased $359 million. U.K. PRT increased $346 million in 2005 on significantly higher oil price realizations and higher production. U.S. severance taxes increased $36 million on higher oil and gas prices. Australia’s taxes decreased $24 million reflecting lower excise tax on declining production from the Legendre field.
 
General and Administrative Expenses
 
General and administrative expenses (G&A) averaged $1.16 per boe for 2006, $.04 per boe less than 2005. Absolute costs increased $13 million to $211 million. The additional cost in 2006 was primarily associated with expansion of international operations in conjunction with acquisitions and increasing insurance costs.
 
G&A of $1.20 per boe in 2005 increased $.14 per boe over 2004. Absolute costs increased $25 million, or 14 percent. Nearly three-fourths of the increase in year-over-year costs related to the impact of Apache’s stock-based compensation programs. Stock-based compensation costs increased relative to the prior year because of new stock option grants issued in 2005, a new targeted stock plan approved by stockholders in May 2005, and the impact Apache’s rising common stock price had on stock-based compensation expense. The balance of the G&A increase was primarily attributed to the increased cost of insurance, a consequence of the hurricanes, higher charitable contributions and higher Sarbanes-Oxley compliance audit fees.
 
Financing Costs, Net
 
The major components of financing costs, net, include interest expense and capitalized interest.


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Net financing costs for 2006 were $26 million higher than in 2005. Gross interest expense increased $42 million in 2006 as a result of a higher average debt balance and higher short-term interest rates. Capitalized interest increased $4 million, a result of a higher average unproved property balance. Interest income rose $10 million compared to 2005 on higher cash balances. Our weighted-average cost of borrowing on December 31, 2006 was 6.3 percent compared to 6.7 percent on December 31, 2005.
 
Net financing costs in 2005 were slightly lower than 2004. Gross interest expense increased $7 million in 2005, on a higher average debt balance. This was mostly offset by a $6 million increase in the amount of interest capitalized as a result of a higher average unproved property balance. Our weighted-average cost of borrowing was 6.7 percent on December 31, 2005 and 6.1 percent on December 31, 2004.
 
Provision for Income Taxes
 
Income tax expense for 2006 totaled $1.5 billion, $125 million less than 2005. The effective tax rate for 2006 was 36.3 percent, down from 37.6 percent in 2005. The 2006 effective rate was impacted by a combination of federal and provincial tax rate reductions enacted by Canada during the second quarter of 2006, a 10 percent increase in the oil and gas company supplemental tax enacted by the U.K. during the third quarter of 2006 and the gain recognized on the sale of China, as discussed below. Currency fluctuations had a negligible impact on the 2006 effective tax rate.
 
The effective income tax rate for 2006 was impacted by the gain recognized in conjunction with divestment of operations in China. The Company intends to permanently reinvest earnings of its foreign subsidiaries and as such, has not recorded U.S. income tax expense on any undistributed foreign earnings, including the gain from the China sale.
 
Income tax expense in 2005 of $1.6 billion was $590 million or 20 percent higher than 2004. The higher taxes were driven by higher taxable income related to increased oil and gas revenues in 2005, compared to 2004. Our effective tax rate was 37.6 percent in 2005 compared to 37.3 percent in 2004. Currency fluctuations added $13 million of additional deferred tax expense to 2005 and $58 million to 2004. For a discussion of Apache’s sensitivity to foreign currency fluctuations, please refer to Item 7A, Quantitative and Qualitative Disclosures about Market Risk, “Foreign Currency Risk” of this Form 10-K.
 
Capital Resources and Liquidity
 
Financial Indicators
 
                         
    At December 31,  
Millions of dollars except as indicated   2006     2005     2004  
 
Current ratio
    .65       .99       1.05  
Net cash provided by operating activities
  $ 4,313     $ 4,332     $ 3,232  
Total debt
    3,822       2,192       2,588  
Shareholders’ equity
    13,191       10,541       8,204  
Percent of total debt to capitalization
    22 %     17 %     24 %
Floating-rate debt/total debt
    43 %           15 %
 
Overview
 
Apache’s primary uses of cash are exploration, development and acquisition of oil and gas properties, costs and expenses necessary to maintain continued operations, repayment of principal and interest on outstanding debt and payment of dividends.
 
Our business, as with other extractive industries, is a depleting one in which each barrel produced must be replaced or the Company, and a critical source of our future liquidity, will shrink. Cash investments are continuously required to fund exploration and development projects and acquisitions which are necessary to offset the inherent declines in production and proven reserves. See Item 1 and 2, Business and Properties, “Risks Factors,” in this Form 10-K. Future success in maintaining and growing reserves and production will be highly dependent on having


33


 

adequate capital resources available, on our success in both exploration and development activities and on acquiring additional reserves.
 
Our 2006 yearend reserve life index indicates an average decline of 7.9 percent per year. This projection is based on prices at yearend 2006, except in those instances where future natural gas and oil sales are covered by physical contract terms providing for higher or lower prices, estimates of investments required to develop estimated proved undeveloped reserves, and costs and taxes reflected in our standardized measure in Note 13, Supplemental Oil and Gas Disclosures (Unaudited) of Item 15 in this Form 10-K.
 
The Company funds its exploration and development activities primarily through net cash provided by operating activities (cash flow) and budgets capital expenditures based on projected cash flow. Our cash flow, both in the short and long-term, is impacted by highly volatile oil and natural gas prices, production levels, industry trends impacting operating expenses and our ability to continue to acquire or find high-margin reserves at competitive prices. For these reasons, we only forecast, for internal use by management, an annual cash flow. Longer-term cash flow and capital spending projections are not used by management to operate our business. The annual cash flow forecasts are revised monthly in response to changing market conditions and production projections. Apache routinely adjusts capital expenditure budgets in response to the adjusted cash flow forecasts and market trends in drilling and acquisitions costs.
 
The Company has historically utilized internally generated cash flow, committed and uncommitted credit facilities and access to both debt and equity capital markets for all other liquidity and capital resources needs. Because of the liquidity and capital resources alternatives available to Apache, including internally generated cash flows, Apache’s management believes that its short-term and long-term liquidity will be adequate to fund operations, including its capital spending program, repayment of debt maturities and any amounts that may ultimately be paid in connection with contingencies.
 
The Company’s ratio of current assets to current liabilities was .65 on December 31, 2006 compared to .99 at the end of 2005. Current liabilities increased 74 percent ($1.6 billion) in 2006 versus a 15 percent ($328 million) increase in current assets. Changes in our current debt particularly impacted the ratio. The Company had $1.6 billion of commercial paper outstanding at the end of 2006 that was subsequently reduced with proceeds from $1.5 billion of long-term debt issued in January 2007. Also, another $173 million of debt is payable in 2007. The current ARO liability of $377 million, an increase of $283 million over 2005, reflects the cost expected to be incurred over the next 12 months to abandon the platforms damaged by Hurricanes Katrina and Rita. The increase in current liabilities was partially offset by overall decreases in our current derivative payable, the U.K. PRT liability, accrued income taxes, and accounts payable of $186 million, $175 million, $118 million and $70 million, respectively. Collectively, the increase in liabilities more than offset the higher current asset balances. The current derivative receivable increased $123 million, reflecting changes in oil and gas strip pricing. Current accounts receivables increased $207 million, or 14 percent, most of which was related to oil receivables impacted by higher oil prices. The remaining current asset categories, inventories, cash and drilling advances, decreased $45 million from 2005.
 
Net Cash Provided by Operating Activities
 
Apache’s net cash provided by operating activities totaled $4.3 billion in both 2006 and 2005. For a detailed discussion of commodity prices, production, costs and expenses, please refer to the Results of Operations section of this Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations. For a detailed discussion of changes in current assets and current liabilities please refer to the discussion under the Overview of this Capital and Liquidity section.
 
Apache’s net cash provided by operating activities during 2005 totaled $4.3 billion, up from $3.2 billion in 2004. The increase in 2005 cash flow was attributed primarily to the significant increase in commodity prices. The Company’s average realized oil and natural gas prices increased 47 percent and 29 percent, respectively; a reflection of higher worldwide commodity prices. Higher production also added to our 2005 cash flow relative to 2004, albeit to a much less extent. These increases in cash flow were partially offset by higher production costs attributable to the effect of increased commodity prices, costs related to Hurricanes Katrina and Rita and an increase in exchange rates in Canada.


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Historically, fluctuations in commodity prices have been the primary reason for the Company’s short-term changes in cash flow from operating activities. Sales volume changes have also impacted cash flow in the short-term, but have not been as volatile as commodity prices. Apache’s long-term cash flow from operating activities is dependent on commodity prices, reserve replacement and the level of costs and expenses required for continued operations.
 
Debt
 
We exited 2006 with a debt-to-capitalization ratio of approximately 22 percent, compared to 17 percent at the end of 2005. Yearend 2006 outstanding current and long-term debt totaled $3.8 billion, $1.6 billion higher than yearend 2005. The increase was associated with the issuance of commercial paper in conjunction with $2.4 billion of acquisitions. The Company’s outstanding debt consisted of notes and debentures maturing in the years 2007 through 2096. Approximately $1.8 billion of our total debt is due in 2007. This debt consists of $1.6 billion of commercial paper, that was subsequently reduced with $1.5 billion of long-term debt issued in January 2007, and $170 million of Apache Finance Australia 6.5-percent notes and various money market lines of credit in Argentina and the U.S. The $1.6 billion of commercial paper is fully supported by available borrowing capacity under committed credit facilities which expire in 2011. An additional $100 million in debt matures in 2009 with the remaining $1.9 billion maturing thereafter.
 
On January 26, 2007, the Company issued $500 million principal amount, $499.5 million net of discount, of senior unsecured 5.625-percent notes maturing January 15, 2017. The Company also issued $1.0 billion principal amount, $993 million net of discount, of senior unsecured 6.0-percent notes maturing January 15, 2037. The notes are redeemable, as a whole or in part, at Apache’s option, subject to a make-whole premium. The proceeds were used to repay a portion of the Company’s outstanding commercial paper and for general corporate purposes. Please refer to Note 5 Debt, Subsequent Debt of Item 15 in this Form 10-K.
 
In May 2006, the Company amended its existing five-year revolving U.S. credit facility which was scheduled to mature on May 28, 2009. The amendment: (a) extended the maturity to May 28, 2011, (b) increased the size of the facility from $750 million to $1.5 billion, and (c) reduced the facility fees from .08 percent to .06 percent and reduced the margin over LIBOR on loans from .27 percent to .19 percent. The lenders also extended the maturity dates of the $150 million Canadian facility, the $150 million Australian facility and $385 million of the $450 million U.S. credit facility, for an additional year to May 12, 2011 from May 12, 2010. The Company also increased commercial paper availability to $1.95 billion from $1.20 billion.
 
By yearend 2006, the Company extended the maturity of another $50 million of commitments under the $450 million U.S. credit facility for an additional year. As a result, $435 million will mature on May 12, 2011, and $15 million will mature on May 12, 2010.
 
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. The negative covenants include restrictions on the Company’s ability to create liens and security interests on our 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., Canada and Australia of up to five percent of the Company’s consolidated assets. There are no restrictions on incurring liens in countries other than the U.S., Canada and Australia. There are also restrictions on Apache’s ability to merge with another entity, unless the Company is the surviving entity, and a restriction on our ability to guarantee debt of entities not within our 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 (MAC clauses). 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., Canadian and Australian subsidiaries, defaults on any direct payment obligation in excess of $100 million or has any unpaid, non-appealable judgment against it in excess of $100 million. The Company was in compliance with the terms of the credit facilities as of December 31, 2006.


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Stock Transactions
 
On April 19, 2006, the Company announced that its Board of Directors authorized the purchase of up to 15 million shares of the Company’s common stock representing a market value of approximately $1 billion on the date of announcement. The Company may buy shares from time to time on the open market, in privately negotiated transactions, or a combination of both. The timing and amounts of any purchases will be at the discretion of Apache’s management. The Company initiated the purchase program on May 1, 2006, after the Company’s first-quarter 2006 earnings information was disseminated in the market. Through December 31, 2006, the Company purchased 2,500,000 shares at an average price of $69.74 per share.
 
Oil and Gas Capital Expenditures
 
The Company funded its exploration and development (E&D) capital expenditures, gathering, transportation and marketing (GTM) investments, capitalized interest and asset retirement costs of $4.4 billion, $4.4 billion and $2.7 billion in 2006, 2005 and 2004, respectively, primarily with internally generated cash flow of $4.3 billion, $4.3 billion and $3.2 billion.
 
The Company uses a combination of internally generated cash flow, borrowings under the Company’s lines of credit and commercial paper program and, from time to time, issues of public debt or common stock to fund its significant acquisitions. During 2005 and 2004, the Company primarily used internally generated cash flow or its lines of credit and commercial paper program, which were subsequently paid down with internally generated cash flow. In 2006, the Company primarily used its commercial paper program to fund its’ significant acquisitions. The commercial paper was subsequently repaid with the proceeds from the issuance of $1.5 billion of senior unsecured notes in January 2007.
 
The following table presents a summary of the Company’s Capital Expenditures for each of our reportable segments for the past three years.
 
                         
    Year Ended December 31,  
    2006     2005     2004  
    (In thousands)  
 
Exploration and Development:
                       
United States
  $ 1,532,959     $ 1,072,040     $ 755,056  
Canada
    1,056,614       1,188,096       756,912  
Egypt
    454,892       352,324       301,912  
Australia
    179,892       217,816       138,694  
North Sea
    329,498       489,072       362,054  
Argentina
    115,570       25,963       4,674  
Other International
    12,288       22,521       21,819  
                         
    $ 3,681,713     $ 3,367,832     $ 2,341,121  
                         
Capitalized Interest
  $ 61,301     $ 56,988     $ 50,748  
                         
Gathering Transmission and Processing Facilities
  $ 248,589     $ 392,872     $ 138,738  
                         
Asset Retirement Costs (ARC)
  $ 228,384     $ 532,505     $ 37,758  
                         
ARC — Acquired
  $ 162,228     $ 14,164     $ 156,195  
                         
Acquisitions:
                       
Oil and gas properties
  $ 2,310,853     $ 39,228     $ 1,063,851  
Gas gathering, transmission and processing facilities
    117,579              
                         
    $ 2,428,432     $ 39,228     $ 1,063,851  
                         


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Capital expenditures, excluding ARC, totaled $6.4 billion in 2006, up 66 percent or $2.6 billion from 2005 driven by an increase in acquisition activity. The Company invested $3.7 billion on exploration and development activities in 2006 up nine percent from 2005 including drilling 1,611 wells.
 
In the U.S., we invested $1.5 billion on exploration and development activities. Our Gulf Coast region invested approximately $1 billion on drilling, recompletions, and platform and production support facilities, including $50 million of associated hurricane redevelopment capital in excess of insurance coverage. The region drilled 60 wells in the Gulf of Mexico and 23 wells onshore, with a 78 percent success rate, despite ongoing hurricane repair activity. The Central region had its most active year ever investing $540 million including the drilling of 374 wells with a 97 percent success rate. The region added to its inventory of opportunities to grow production with the addition of Amerada Hess’s Permian basin properties in Texas and New Mexico at the beginning of 2006 and will do so again with the close of the acquisition of additional Permian basin properties from Anadarko in the first quarter of 2007.
 
Canada’s drilling program accounted for more than half of the Company’s wells drilled. The region invested $1.1 billion in 2006 on exploration and development activities and drilled 874 wells with an 85 percent success rate. Twenty-five percent of those wells were on the undeveloped acreage Apache obtained through farm-in agreements with ExxonMobil.
 
We invested $329 million in the North Sea; $112 million of which was on facility upgrades intended to improve the operating efficiency and drilling capability in the Forties field. Four of the five exploration and development wells drilled during 2006 were productive. We completed the Forties power generation and gas ring in 2006, which reduced fuel oil generating costs and improved production reliability. We also started the upgrade of our produced water re-injection system, upgraded the primary gas-lift compression system and replaced instrumentation and control systems on several platforms. At the end of 2006, we were in the process of upgrading drilling equipment on all existing Forties’ platforms that will extend the reach of our drilling equipment, allowing us to determine if the bounds of the Forties field can be extended to the west. The latter project should be completed by the end of the first quarter of 2007.
 
Egypt had another active and successful exploration and development program investing $455 million and drilling 163 wells of which 86 percent were productive as we continued development of the Qasr field.
 
In Australia, we invested $180 million in exploration and development activities as we participated in drilling 23 wells; 18 exploration wells and five development wells. Four of the exploration wells and three of the development wells were productive for a success rate of 30 percent.
 
Our 2006 exploration and development activities in Argentina increased by $90 million over 2005 as we invested $116 million drilling 83 wells, 16 exploratory and 67 development, with a 89% success rate.
 
The Company invested $249 million in gathering, transmission and processing facilities in 2006 compared to $393 million in 2005. In Canada we invested $130 million in processing plants, $106 million of which was to construct five additional gas processing plants to support production from wells drilled on the acreage we earned from ExxonMobil. Egypt invested $108 million to complete the Tarek gas plant pipeline inter-connect and on expansion of gas processing facilities to alleviate the processing capacity bottleneck throttling deliverability.
 
In 2006 we also recorded $391 million in asset retirement costs. The Gulf Coast region recorded an additional $232 million to reflect the estimated abandonment costs to be incurred resulting from the hurricane activity, in addition to the approximately $492 million recorded in 2005. This cost to abandon the 11 operated and 12 non-operated platforms lost or severely damaged during the 2005 storms is expected to be incurred by the end of 2009 (See Note 4, Asset Retirement Obligations of Item 15 in this Form 10-K). We also recorded $162 million in asset retirement costs associated with our 2006 acquisition activity.
 
On the acquisition front we invested a record $2.4 billion in 2006, closing four significant transactions; one in the Gulf of Mexico, one in West Texas and two in Argentina. Acquisition activity fluctuates from year-to-year based on the availability of acquisition opportunities that fit the Company’s strategy.
 
In 2005, the Company had its most active drilling year ever, drilling 2,383 wells investing $3.4 billion on exploration and development activities, a 44 percent increase from 2004. Approximately two-thirds of our 2005


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exploration and development expenditures were invested in Canada and the U.S., where nearly 69 percent of Apache’s 2005 year-end estimated proved reserves were located. Exploration and development expenditures in 2005 for Canada and the U.S. increased 57 percent and 42 percent, respectively, over 2004. Canada was our most active region, drilling 1,674 wells, 82 percent of which were shallow development wells. Canada was also very active in the undeveloped acreage Apache obtained through two farm-in agreements with ExxonMobil. The Central region was the second most active region, drilling 364 wells, with a 97 percent success rate. In the Gulf Coast region, despite the disruptions caused by the Gulf of Mexico hurricanes, we drilled 114 wells, including 66 offshore. Seventy-seven percent of our Gulf Coast wells were productive. In the North Sea, we drilled a total of 23 wells, including 18 Forties field wells, and invested approximately $198 million of maintenance capital to continue to improve the operating efficiency of the Forties field. In Egypt, we drilled 121 wells of which 86 percent were productive. We continued development of the Qasr field, where gross production averaged 128 MMcf/d in December 2005. In Australia, we participated in drilling 36 wells; 26 exploration wells and 10 development wells. China’s capital expenditures were flat compared to 2004 as they continued their development drilling program.
 
In 2005 Apache also invested $393 million in gathering, transmission and processing facilities investing $180 million constructing 11 gas processing plants in Canada, six of which were completed by yearend, $182 million in Egypt developing Qasr field facilities and $31 million on facility upgrades in Australia.
 
We incurred $547 million in asset retirement costs in 2005, most of which was attributed to the hurricane activity in the Gulf of Mexico escalating our abandonment obligations.
 
The Company spent $39 million on acquisitions in 2005 compared to $1.1 billion in 2004, as the high-price commodity market in 2005 limited the number of attractive acquisition opportunities. Those that were pursued closed in the first quarter of 2006. Acquisition expenditures typically vary year-to-year based on the availability of opportunities that fit Apache’s overall strategy.
 
For 2007, we plan another active year of drilling. Because we revise our estimates of exploration and development capital expenditures frequently throughout the year based on industry conditions, year-to-year results and the relative levels of commodity prices and service costs, accurately projecting future expenditures is difficult at best. At the end of 2006 we had a fairly active drilling program underway; however, if commodity prices soften and service costs do not decline accordingly, Apache will not hesitate to reduce activity until margins are back in line. Our 2007 preliminary estimate of exploration and development capital and oil and gas processing facilities and pipelines is approximately $4.5 billion. We generally do not project estimates for acquisitions because their timing is unpredictable. We continually look for properties in which we believe we can add value and earn adequate rates of return and will take advantage of those opportunities as they arise.
 
Cash Dividend Payments
 
The Company has paid cash dividends on its common stock for 42 consecutive years through 2006. Future dividend payments will depend on the Company’s level of earnings, financial requirements and other relevant factors. Common dividends paid during 2006 rose 33 percent to $148 million, reflecting the increase in common shares outstanding and the higher common stock dividend rate. The Company increased its quarterly cash dividend 50 percent, to 15 cents per share from 10 cents per share, effective with the November 2006 dividend payment.
 
During 2006 and 2005, Apache paid a total of $6 million in dividends each year on its Series B Preferred Stock issued in August 1998. See Note 8, Capital Stock of Item 15 in this Form 10-K. Common dividends paid during 2005 rose 32 percent to $112 million, reflecting the increase in common shares outstanding and the higher common stock dividend rate.
 
Contractual Obligations
 
We are subject to various financial obligations and commitments in the normal course of operations. These contractual obligations represent known future cash payments that we are required to make and relate primarily to long-term debt, operating leases, pipeline transportation commitments and international commitments. The Company expects to fund these contractual obligations with cash generated from operating activities. The following


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table summarizes the Company’s contractual obligations as of December 31, 2006. See Note 10, Commitments and Contingencies of Item 15 in this Form 10-K for further information regarding these obligations.
 
                                                                 
    Note
                                           
Contractual Obligations
  Reference     Total     2007     2008     2009     2010     2011     Thereafter  
    (In thousands)  
 
Debt
    Note 5     $ 3,821,925     $ 1,802,094     $ 353     $ 99,809     $     $     $ 1,919,669  
Operating leases and other commitments
    Note 10       815,685       384,651       127,037       46,536       36,787       32,844       187,830  
International lease commitments
    Note 10       239,556       104,987       59,884       48,328       26,357              
Other International purchase commitments
    Note 10       389,744       310,944       78,800                          
Operating costs associated with pre-existing volumetric production payments on acquired properties
    Note 2       32,330       24,088       8,242                          
             
             
Total Contractual Obligations(a)(b)
          $ 5,299,240     $ 2,626,764     $ 274,316     $ 194,673     $ 63,144     $ 32,844     $ 2,107,499  
             
             
 
(a) This table does not include the estimated liability for dismantlement, abandonment and restoration costs of oil and gas properties of $1.7 billion. The Company records a separate liability for the fair value of this asset retirement obligation. See Note 4, Asset Retirement Obligation of Item 15 in this Form 10-K for further discussion.
 
(b) This table does not include the Company’s pension or postretirement benefit obligations. See Note 10, Commitments and Contingencies of Item 15 in this Form 10-K for further discussion.
 
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 any impact on future liquidity. Such obligations include environmental contingencies and potential settlements resulting from litigation. Apache’s management feels that it has adequately reserved for its contingent obligations including approximately $17 million for environmental remediation and approximately $7 million for various legal liabilities, in addition to the $71 million, plus interest, we accrued for the Texaco China B.V. litigation. See Note 10, Commitments and Contingencies of Item 15 in this Form 10-K for a detailed discussion of the Company’s environmental and legal contingencies.
 
The Company accrued approximately $34 million as of December 31, 2006, for an insurance contingency because of our involvement with Oil Insurance Limited (OIL). Apache is a member of this insurance pool which insures specific property, pollution liability and other catastrophic risks of the Company. As part of its membership, the Company is contractually committed to pay termination fees were we to elect to withdraw from OIL. Apache does not anticipate withdrawal from the insurance pool; however, the potential termination fee is calculated annually based on past losses and the liability reflecting this potential charge has been accrued as required.
 
As discussed under Note 2, Acquisitions and Divestitures of Item 15 in this Form 10-K, Apache assumed obligations for pre-existing volumetric production payments (VPPs) in the 2004 acquisition of properties from Anadarko and the 2003 acquisition of properties from Shell. Under the terms of the VPP agreements, Apache is scheduled to deliver a total of 4.7 MMboe in 2007 and 1.6 MMboe in 2008 to Morgan Stanley as owner of the VPP interests. Morgan Stanley is entitled to the first production and may demand up to 90 percent of the production from the assets encumbered by each VPP in any given month to satisfy the VPP interests. However, they have no right to look to other assets or production of Apache beyond that encumbered in the acquisition. Apache does not record the reserves and production volumes attributable to the VPPs. As of December 31, 2006, Apache has booked a total of 87.4 MMboe of reserves attributable to the Anadarko and Shell transactions. The VPPs are non-operating interests,


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free of costs incurred for operations and production. Apache provided a liability for these costs as reflected in the preceding table.
 
Upon closing of our 2003 acquisition of the North Sea properties, Apache assumed BP’s abandonment obligation for those properties and such costs were considered in determining the purchase price. The purchase of the properties, however, did not relieve BP of its liabilities if Apache fails to satisfy the abandonment obligation. Although not currently required, to ensure Apache’s payment of these costs, Apache agreed to deliver a letter of credit to BP if the rating of our senior unsecured debt is lowered by both Moody’s and Standard and Poor’s from the Company’s current ratings of A3 and A-, respectively. Any such letter of credit would be in an amount equal to the net present value of future abandonment costs of the North Sea properties as of the date of any such ratings change. If Apache is required to provide a letter of credit, it will expire if either rating agency restores its rating to the present level. The letter of credit amount would be 134 million British pounds, an amount that represents the letter of credit requirement through March 2008, and will be negotiated annually based on Apache’s future abandonment obligation estimates.
 
The Company’s future liquidity could be impacted by a significant downgrade of its credit ratings by Standard and Poor’s and Moody’s. The Company’s credit facilities do not require the Company to maintain a minimum credit rating. The negative covenants associated with our debt are outlined in greater detail under “Capital Resources and Liquidity, Debt” in this section of this Form 10-K. In addition, generally under our commodity hedge agreements, Apache may be required to post margin or terminate outstanding positions if the Company’s credit ratings decline significantly.
 
Off-Balance Sheet Arrangements
 
Apache does not currently utilize any off-balance sheet arrangements with unconsolidated entities to enhance liquidity and capital resource positions. Apache entered into a partnership with ExxonMobil to obtain additional interests in specific West Texas and New Mexico oil and gas properties acquired from ExxonMobil in September 2004. Apache concluded that they were not the primary beneficiary of the partnership and, therefore, proportionately consolidated only the Company’s portion of the oil and gas properties.
 
Critical Accounting Policies and Estimates
 
Full-Cost Method of Accounting for Oil and Gas Operations
 
The accounting for our business is subject to special accounting rules that are unique to the oil and gas industry. There are two allowable methods of accounting for oil and gas business activities: the successful-efforts method and the full-cost method. There are several significant differences between these methods. Under the successful-efforts method, costs such as geological and geophysical (G&G), exploratory dry holes and delay rentals are expensed as incurred, where under the full-cost method these types of charges would be capitalized to their respective full-cost pool. In the measurement of impairment of oil and gas properties, the successful-efforts method of accounting follows the guidance provided in Statement of Financial Accounting Standards (SFAS) No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” where the first measurement for impairment is to compare the net book value of the related asset to its undiscounted future cash flows using commodity prices consistent with management expectations. Under the full-cost method, the net book value (full-cost pool) is compared to the future net cash flows discounted at 10 percent using commodity prices in effect on the last day of the reporting period (ceiling limitation). If the full-cost pool is in excess of the ceiling limitation, the excess amount is charged through income.
 
We have elected to use the full-cost method to account for our investment in oil and gas properties. Under this method, the Company capitalizes all acquisition, exploration and development costs for the purpose of finding oil and gas reserves, including salaries, benefits and other internal costs directly attributable to these finding activities. Although some of these costs will ultimately result in no additional reserves, we expect the benefits of successful wells to more than offset the costs of any unsuccessful ones. In addition, gains or losses on the sale or other disposition of oil and gas properties are not recognized unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a country. As a result, we believe that the full-cost method of accounting better reflects the true economics of exploring for and


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developing oil and gas reserves. Our financial position and results of operations would have been significantly different had we used the successful-efforts method of accounting for our oil and gas investments. Generally, the application of the full-cost method of accounting for oil and gas property results in higher capitalized costs and higher DD&A rates compared to similar companies applying the successful efforts methods of accounting.
 
Reserve Estimates
 
Our estimate of proved reserves is based on the quantities of oil and gas which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. 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. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment. For example, we must estimate the amount and timing of future operating costs, severance taxes, development costs, and workover costs, all of which may in fact vary considerably from actual results. In addition, as prices and cost levels change from year to year, the estimate of proved reserves also changes. Any significant variance in these assumptions could materially affect the estimated quantity and value of our reserves. As such, our reserve engineers review and revise the Company’s reserve estimates at least annually.
 
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.
 
We engage an independent petroleum engineering firm to review our estimates of proved hydrocarbon liquid and gas reserves. During 2006, 2005 and 2004, their review covered 75, 74 and 79 percent of the reserve value, respectively.
 
Costs Excluded
 
Under the full-cost method of accounting, oil and gas properties include costs that are excluded from capitalized costs being amortized. These amounts represent investments in unproved properties and major development projects. Apache excludes these costs on a country-by-country basis until proved reserves are found or until it is determined that the costs are impaired. All costs excluded are reviewed at least quarterly by the Company’s accounting, exploration and engineering staffs to determine if impairment has occurred. Nonproducing leases are evaluated based on the progress of the Company’s exploration program to date. Exploration costs are transferred to the DD&A pool upon completion of drilling individual wells. If geological and geophysical (G&G) costs cannot be associated with specific properties, they are included in the amortization base as incurred. The amount of any impairment is transferred to the capitalized costs being amortized (the DD&A pool) or a charge is made against earnings for those international operations where a proved reserve base has not yet been established. Impairments transferred to the DD&A pool increase the DD&A rate for that country. For international operations where a reserve base has not yet been established, all costs associated with a prospect or play would be considered quarterly for impairment upon full evaluation of such prospect or play. This evaluation considers among other factors, seismic data, requirements to relinquish acreage, drilling results, remaining time in the commitment period, remaining capital plans, and political, economic, and market conditions.
 
Allowance for Doubtful Accounts
 
We routinely assess the recoverability of all material trade and other receivables to determine their collectibility. Many of our receivables are from joint interest owners on properties we operate. Thus, we may have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. Our crude oil and natural gas receivables are typically collected within two months. We accrue 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.


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Beginning in 2001, we experienced a gradual decline in the timeliness of receipts from EGPC for our Egyptian oil and gas sales. Deteriorating economic conditions in Egypt lessened the availability of U.S. dollars, resulting in a one to two month delay in receipts from EGPC. During 2006, we experienced wide variability in the timing of cash receipts. We have not established a reserve for these Egyptian receivables because we continue to get paid, albeit late, and have no indication that we will not be able to collect our receivable.
 
Asset Retirement Obligation
 
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 because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations.
 
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 Asset Retirement Obligation liability, a corresponding adjustment is made to the oil and gas property balance.
 
Income Taxes
 
Our oil and gas exploration and production operations are currently located in six countries. As a result, we are subject to taxation on our income in numerous jurisdictions. 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. We consider future taxable income in making such assessments. 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 have been fully documented in the Company’s tax returns. 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.
 
Derivatives
 
Apache uses derivative contracts on a limited basis to manage its exposure to oil and gas price volatility and foreign currency volatility. The Company accounts for the contracts in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” The estimated fair values of Apache’s derivative contracts within the scope of this statement are carried on the Company’s consolidated balance sheet. For oil and gas derivative contracts designated and qualifying as cash flow hedges, realized gains and losses are recognized in oil and gas production revenues when the forecasted transaction occurs. For foreign currency forward contracts designated and qualifying as cash flow hedges, realized gains and losses are generally recognized in lease operating expense when the forecasted transaction occurs. SFAS No. 133 requires that gains and losses from the change in fair value of derivative instruments that do not qualify for hedge accounting be “marked-to-market” and reported in current period income, rather than in the period in which the hedged transaction is settled. Realized gains and losses on derivative contracts not qualifying as cash flow hedges are reported in “Other” under “Revenues and Other” of the Statement of Consolidated Operations.


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The fair value estimate of Apache’s derivative contracts requires judgment; however, the Company’s derivative contracts are either exchange traded or valued by reference to commodities and currencies that are traded in highly liquid markets. As such, the ultimate fair value is determined by references to readily available public data. Option valuations are verified against independent third-party quotations. See Item 7A, Quantitative and Qualitative Disclosures about Market Risk, “Commodity Risk” in this Form 10-K for commodity price sensitivity information and the Company’s policies related to the use of derivatives.
 
Stock-Based Compensation
 
Consistent with the Company’s desire to reflect the ultimate cost of stock-based compensation on the income statement, Apache early adopted the provisions of SFAS No. 123-R “Share-Based Payment” upon the FASB’s issuance of the revised statement in the fourth quarter 2004. Stock-based compensation awards that vest during the year are reflected in the Company’s net income. Awards granted in future periods will be valued on the date of grant and expensed using a straight-line basis over the required service period.
 
The Company chose to adopt the statement under the “Modified Retrospective” approach as prescribed under SFAS No. 123-R. Under this approach, the Company is required to expense all options and stock-based compensation that vested during the year of adoption based on the fair value of the stock compensation determined on the date of grant. Had the Company not early adopted SFAS No. 123-R under this transition approach, 2004 net income would have been lower by $89 million ($56 million after tax) or $.17 per diluted share. Normally, net income would be negatively impacted by adopting SFAS No. 123-R under this transition method. However, the Company’s 2000 Share Appreciation Plan, which triggered in 2004, has a fair market value-based expense recorded under the provisions of SFAS No. 123-R that is substantially less than the intrinsic value cost that would have been recorded under the provisions of APB Opinion No. 25. Please refer to Note 8, Capital Stock of Item 15 of this Form 10-K for a detailed description of the 2000 Share Appreciation Plan and costs associated with our stock compensation plans.
 
Also, inherent in expensing stock options and other stock-based compensation under SFAS No. 123-R are several judgments and estimates that must be made. These include determining the underlying valuation methodology for stock compensation awards and the related inputs utilized in each valuation, such as the Company’s expected stock price volatility, expected term of the employee option, expected dividend yield, the expected risk-free interest rate, the underlying stock price and the exercise price of the option. Changes to these assumptions could result in different valuations for individual share awards and will be carefully scrutinized for each material grant. For option valuations, Apache utilizes the Black-Scholes option pricing model. For valuing the Share Appreciation Plan awards, the Company utilizes a Monte Carlo simulation model developed by a third party.
 
ITEM 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
 
Commodity Risk
 
The major market risk exposure is in the pricing applicable to our oil and gas production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot prices applicable to our United States and Canadian natural gas production. Prices received for oil and gas production have been and remain volatile and unpredictable. Monthly average oil price realizations, including the impact of fixed-price contracts and hedges, ranged from a low of $52.64 per barrel to a high of $68.59 per barrel during 2006. Average gas price realizations, including the impact of fixed-price contracts and hedges, ranged from a monthly low of $3.85 per Mcf to a monthly high of $8.05 per Mcf during the same period. Based on the Company’s 2006 worldwide oil and gas production levels, a $1.00 per barrel change in the weighted-average realized price of oil would increase or decrease revenues by $82 million and a $.10 per Mcf change in the weighted-average realized price of gas would increase or decrease revenues by $55 million.
 
If oil and gas prices decline significantly, even if only for a short period of time, it is possible that non-cash write-downs of our oil and gas properties could occur under the full-cost accounting method allowed by the Securities Exchange Commission (SEC). Under these rules, we review the carrying value of our proved oil and gas properties each quarter on a country-by-country basis to ensure that capitalized costs of proved oil and gas properties, net of accumulated depreciation, depletion and amortization, and deferred income taxes do not exceed


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the “ceiling.” This ceiling is the present value of estimated future net cash flows from proved oil and gas reserves, discounted at 10 percent, plus the lower of cost or fair value of unproved properties included in the costs being amortized, net of related tax effects. If capitalized costs exceed this ceiling, the excess is charged to additional DD&A expense. The calculation of estimated future net cash flows is based on the prices for crude oil and natural gas in effect on the last day of each fiscal quarter except for volumes sold under long-term contracts. Write-downs required by these rules do not impact cash flow from operating activities; however, as discussed above, sustained low prices would have a material adverse effect on future cash flows.
 
We periodically enter into hedging activities on a portion of our projected oil and natural gas production through a variety of financial and physical arrangements intended to support oil and natural gas prices at targeted levels and to manage our overall exposure to oil and gas price fluctuations. Apache may use futures contracts, swaps, options and fixed-price physical contracts to hedge its commodity prices. Realized gains or losses from the Company’s price risk management activities are recognized in oil and gas production revenues when the associated production occurs. Apache does not generally hold or issue derivative instruments for trading purposes.
 
Apache has historically only hedged long-term oil and gas prices related to a portion of its expected production associated with acquisitions; however, in 2006, the Company’s Board of Directors authorized management to hedge a portion of production generated from the Company’s drilling program. In 2006, financial derivative hedges represented approximately eight percent of the total worldwide natural gas and nine percent of the total worldwide crude oil production. At year end, hedges in place were primarily related to North America production and represent approximately 12 percent of worldwide production for natural gas and crude oil.
 
On December 31, 2006, the Company had open natural gas derivative positions with a fair value of $87 million. A 10 percent increase in natural gas prices would reduce the fair value by approximately $58 million, while a 10 percent decrease in prices would increase the fair value by approximately $60 million. The Company also had open crude oil derivative positions with a fair value of $40 million. A 10 percent increase in oil prices would reduce the fair value by approximately $104 million, while a 10 percent decrease in prices would increase the fair value by approximately $107 million. These fair value changes assume volatility based on prevailing market parameters at December 31, 2006. See Note 3, Hedging and Derivative Instruments of Item 15 in this Form 10-K for notional volumes and terms associated with the Company’s derivative contracts.
 
Apache conducts its risk management activities for its commodities under the controls and governance of its risk management policy. The Risk Management Committee, comprising the Chief Financial Officer, Controller, Treasurer and other key members of Apache’s management, approve and oversee these controls, which have been implemented by designated members of the treasury department. The treasury and accounting departments also provide separate checks and reviews on the results of hedging activities. Controls for our commodity risk management activities include limits on credit, limits on volume, segregation of duties, delegation of authority and a number of other policy and procedural controls.
 
Governmental Risk
 
Apache’s U.S. and international operations have been, and at times in the future may be, affected by political developments and by federal, state and local laws and regulations impacting production levels, taxes, environmental requirements and other assessments including a potential Windfall Profits Tax.
 
Weather and Climate Risk
 
Demand for oil and natural gas are, to a significant degree, dependent on weather and climate, which impacts 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 hurricanes in the Gulf of Mexico, which may cause a loss of production from temporary cessation of activity or lost or damaged equipment. While our planning for normal climatic variation, insurance program, and emergency recovery plans mitigate the effects of the weather, not all such effects can be predicted, eliminated or insured against.
 
In response to large underwriting losses caused by Hurricanes Katrina and Rita, the insurance industry has reduced capacity for windstorm damage and substantially increased premium rates. As a result, there is no


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assurance that Apache will be able to arrange insurance to cover fully its Gulf of Mexico exposures at a reasonable cost when the current policies expire.
 
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 fixed-price Australian dollar contracts. Over half the costs incurred for Australian operations are paid in Australian dollars. In Canada, the majority of oil and gas production is sold under Canadian dollar contracts. The majority of the costs incurred are paid in Canadian dollars. The North Sea production is sold under U.S. dollar contracts and the majority of costs incurred are paid in British pounds. In contrast, all oil and gas production in Egypt is sold for U.S. dollars and the majority of the costs incurred are denominated in U.S. dollars. Argentina revenues and expenditures are largely denominated in U.S. dollars but translated into pesos at the then current exchange rate. Revenue and disbursement transactions denominated in Australian dollars, Canadian dollars, British pounds, Egyptian pounds or Argentine pesos are converted to U.S. dollar equivalents based on the exchange rate as of the transaction date.
 
Foreign currency gains and losses also come about when monetary assets and liabilities denominated in foreign currencies are translated at the end of each month. A 10 percent strengthening or weakening of the Australian dollar, Canadian dollar, British pound, Egyptian pound, or Argentine peso as of December 31, 2006, would result in a foreign currency net loss or gain of approximately $112 million.
 
Interest Rate Risk
 
On December 31, 2006, the Company’s debt with fixed interest rates represented approximately 57 percent of total debt. As a result, the interest expense on approximately 43 percent of Apache’s debt will fluctuate based on short-term interest rates. A 10 percent change in floating interest rates on year-end floating debt balances would change annual interest expense by approximately $9.2 million.
 
Forward-Looking Statements and Risk
 
Certain statements in this report, including statements of the future plans, objectives, and expected performance of the Company, are forward-looking statements that are dependent upon certain events, risks and uncertainties that may be outside the Company’s control, and which could cause actual results to differ materially from those anticipated. Some of these include, but are not limited to, capital expenditure projections, the market prices of oil and gas, economic and competitive conditions, inflation rates, legislative and regulatory changes, financial market conditions, political and economic uncertainties of foreign governments, future business decisions and other uncertainties, all of which are difficult to predict.
 
There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and in projecting future rates of production and the timing of development expenditures. The total amount or timing of actual future production may vary significantly from reserve and production estimates. The drilling of exploratory wells can involve significant risks, including those related to timing, success rates and cost overruns. Lease and rig availability, complex geology and other factors can affect these risks. Although Apache makes use of futures contracts, swaps, options and fixed-price physical contracts to mitigate risk, fluctuations in oil and gas prices, or a prolonged continuation of low prices may substantially adversely affect the Company’s financial position, results of operations and cash flows.
 
ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
 
The financial statements and supplementary financial information required to be filed under this item are presented on pages F-1 through F-57 of this Form 10-K, and are incorporated herein by reference.


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ITEM 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
 
The financial statements for the fiscal years ended December 31, 2006, 2005 and 2004, included in this report, have been audited by Ernst & Young LLP, independent public auditors, as stated in their audit report appearing herein.
 
ITEM 9A.  CONTROLS AND PROCEDURES
 
Disclosure Controls and Procedures
 
G. Steven Farris, the Company’s President, Chief Executive Officer and Chief Operating Officer, and Roger B. Plank, the Company’s Executive Vice President and Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures as of December 31, 2006, 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 were effective, providing effective means to insure that information we are required to disclose under applicable laws and regulations is recorded, processed, summarized, and reported in a timely manner. We also made no changes in internal controls over financial reporting during the quarter ending December 31, 2006 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
 
We periodically review the design and effectiveness of our disclosure controls, including compliance with various laws and regulations that apply to our operations both inside and outside the United States. We make modifications to improve the design and effectiveness of our disclosure controls, and may take other corrective action, if our reviews identify deficiencies or weaknesses in our controls.
 
Management’s Report on Internal Control Over Financial Reporting
 
The management report called for by Item 308(a) of Regulation S-K is incorporated herein by reference to Report of Management on Internal Control Over Financial Reporting, included on Page F-1 in Item 15 of this report.
 
The independent auditors attestation report called for by Item 308(b) of Regulation S-K is incorporated by reference to Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting, included on Page F-3 in Item 15 of this report.
 
Changes in Internal Control Over Financial Reporting
 
There was no change in our internal controls over financial reporting during the quarter ending December 31, 2006, that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.
 
ITEM 9B.  OTHER INFORMATION
 
None.
 
PART III
 
ITEM 10.  DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
 
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 2007 annual meeting of stockholders (the Proxy Statement) is incorporated herein by reference.


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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), which 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 Investor Relations page of the Company’s website at http://www.apachecorp.com. Any stockholder who so requests may obtain a printed copy of the Code of Conduct by submitting a request to the Company’s Corporate Secretary. 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.
 
ITEM 11.  EXECUTIVE COMPENSATION
 
The information set forth under the captions “Summary Compensation Table,” “Grants of Plan Based Awards,” “Outstanding Equity Awards at Fiscal Year-End,” “Option Exercises and Stock Vested,” “Non-Qualified Deferred Compensation,” “Employment Contracts and Termination of Employment and Change-in-Control Arrangements” and “Director Compensation” in the Proxy Statement is incorporated herein by reference.
 
ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
 
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
 
The information set forth under the caption “Certain Business Relationships and Transactions” in the Proxy Statement is incorporated herein by reference.
 
ITEM 14.  PRINCIPAL ACCOUNTANT FEES AND SERVICES
 
The information set forth under the caption “Independent Public Accountants” in the Proxy Statement is incorporated herein by reference.
 
PART IV
 
ITEM 15.  EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
 
(a) Documents included in this report:
 
1. Financial Statements
 
         
  F-1
  F-2
  F-3
  F-4
  F-5
  F-6
  F-7
  F-8
 
2. Financial Statement Schedules


47


 

 
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 among Registrant, YPY Acquisitions, Inc. and The Phoenix Resource Companies, Inc., dated March 27, 1996 (incorporated by reference to Exhibit 2.1 to Registrant’s Registration Statement on Form S-4, Registration No. 333-02305, filed April 5, 1996).
  2 .2     Purchase and Sale Agreement by and between BP Exploration & Production Inc., as seller, and Registrant, as buyer, dated January 11, 2003 (incorporated by reference to Exhibit 2.1 to Registrant’s Current Report on Form 8-K, dated and filed January 13, 2003, SEC File No. 001-4300).
  2 .3     Sale and Purchase Agreement by and between BP Exploration Operating Company Limited, as seller, and Apache North Sea Limited, as buyer, dated January 11, 2003 (incorporated by reference to Exhibit 2.2 to Registrant’s Current Report on Form 8-K, dated and filed January 13, 2003, SEC File No. 001-4300).
  3 .1     Restated Certificate of Incorporation of Registrant, dated February 11, 2004, as filed with the Secretary of State of Delaware on February 12, 2004 (incorporated by reference to Exhibit 3.1 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2003, SEC File No. 001-4300).
  *3 .2     Bylaws of Registrant, as amended December 14, 2006.
  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 Registrant’s 5.68% Cumulative Preferred Stock, Series B (incorporated by reference to Exhibit 4.2 to Amendment No. 2 on Form 8-K/A to Registrant’s Current Report on Form 8-K, dated and filed April 18, 1998, SEC File No. 001-4300).
  4 .3     Rights Agreement, dated January 31, 1996, between Registrant and 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 .4     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. (successor 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 .5     Senior Indenture, dated February 15, 1996, between Registrant and 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 .6     First Supplemental Indenture to the Senior Indenture, dated as of November 5, 1996, between Registrant and 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 .7     Form of Indenture among Apache Finance Pty Ltd, Registrant and 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 .8     Form of Indenture among Registrant, Apache Finance Canada Corporation and 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).


48


 

             
Exhibit
       
No.
     
Description
 
  *10 .1     Form of Amended and Restated Credit Agreement, dated as of May 9, 2006, among Registrant, the Lenders named therein, JPMorgan Chase Bank, as Administrative Agent, Citibank, N.A. and Bank of America, N.A., as Co-Syndication Agents, and BNP Paribas and UBS Loan Finance LLC, as Co-Documentation Agents.
  10 .2     Form of Credit Agreement, dated as of May 12, 2005, among Registrant, the Lenders named therein, JPMorgan Chase Bank, N.A., as Global Administrative Agent, J.P. Morgan Securities Inc. and Banc of America Securities, LLC, as Co-Lead Arrangers and Joint Bookrunners, Bank of America, N.A. and Citibank, N.A., as U.S. Co-Syndication Agents, and Calyon New York Branch and Société Générale, as U.S. Co-Documentation Agents (excluding exhibits and schedules) (incorporated by reference to Exhibit 10.01 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005, SEC File No. 001-4300).
  10 .3     Form of Credit Agreement, dated as of May 12, 2005, among Apache Canada Ltd, a wholly-owned subsidiary of Registrant, the Lenders named therein, JPMorgan Chase Bank, N.A., as Global Administrative Agent, RBC Capital Markets and BMO Nesbitt Burns, as Co-Lead Arrangers and Joint Bookrunners, Royal Bank of Canada, as Canadian Administrative Agent, Bank of Montreal and Union Bank of California, N.A., Canada Branch, as Canadian Co-Syndication Agents, and The Toronto-Dominion Bank and BNP Paribas (Canada), as Canadian Co-Documentation Agents (excluding exhibits and schedules) (incorporated by reference to Exhibit 10.02 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005, SEC File No. 001-4300).
  10 .4     Form of Credit Agreement, dated as of May 12, 2005, among Apache Energy Limited, a wholly-owned subsidiary of Registrant, the Lenders named therein, JPMorgan Chase Bank, N.A., as Global Administrative Agent, Citigroup Global Markets Inc. and Deutsche Bank Securities Inc., as Co-Lead Arrangers and Joint Bookrunners, Citisecurities Limited, as Australian Administrative Agent, Deutsche Bank AG, Sydney Branch, and JPMorgan Chase Bank, as Australian Co-Syndication Agents, and Bank of America, N.A., Sydney Branch, and UBS AG, Australia Branch, as Australian Co-Documentation Agents (excluding exhibits and schedules) (incorporated by reference to Exhibit 10.03 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005, SEC File No. 001-4300).
  10 .5     Form of Five-Year Credit Agreement, dated May 28, 2004, among Registrant, the Lenders named therein, JPMorgan Chase Bank, as Administrative Agent, Citibank N.A. and Bank of America, N.A., as Co-Syndication Agents, and Barclays Bank PLC and UBS Loan Finance LLC. as Co-Documentation Agents (excluding exhibits and schedules) (incorporated by reference to Exhibit 10.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2004, SEC File No. 001-4300).
  10 .6     Form of First Amendment to Combined Credit Agreements, dated May 28, 2004, among Registrant, Apache Energy Limited, Apache Canada Ltd., the Lenders named therein, JP Morgan Chase Bank, as Global Administrative Agent, Bank of America, N.A., as Global Syndication Agent, and Citibank, N.A., as Global Documentation Agent (excluding exhibits and schedules) (incorporated by reference to Exhibit 10.2 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2004, SEC File No. 001-4300).
  10 .7     Concession Agreement for Petroleum Exploration and Exploitation in the Khalda Area in Western Desert of Egypt by and among Arab Republic of Egypt, the Egyptian General Petroleum Corporation and Phoenix Resources Company of Egypt, dated April 6, 1981 (incorporated by reference to Exhibit 19(g) to Phoenix’s Annual Report on Form 10-K for year ended December 31, 1984, SEC File No. 1-547).
  10 .8     Amendment, dated July 10, 1989, to Concession Agreement for Petroleum Exploration and Exploitation in the Khalda Area in Western Desert of Egypt by and among Arab Republic of Egypt, the Egyptian General Petroleum Corporation and Phoenix Resources Company of Egypt incorporated by reference to Exhibit 10(d)(4) to Phoenix’s Quarterly Report on Form 10-Q for quarter ended June 30, 1989, SEC File No. 1-547).

49


 

             
Exhibit
       
No.
     
Description
 
  10 .9     Farmout Agreement, dated September 13, 1985 and relating to the Khalda Area Concession, by and between Phoenix Resources Company of Egypt and Conoco Khalda Inc. (incorporated by reference to Exhibit 10.1 to Phoenix’s Registration Statement on Form S-1, Registration No. 33-1069, filed October 23, 1985).
  10 .10     Amendment, dated March 30, 1989, to Farmout Agreement relating to the Khalda Area Concession, by and between Phoenix Resources Company of Egypt and Conoco Khalda Inc. (incorporated by reference to Exhibit 10(d)(5) to Phoenix’s Quarterly Report on Form 10-Q for quarter ended June 30, 1989, SEC File No. 1-547).
  10 .11     Amendment, dated May 21, 1995, to Concession Agreement for Petroleum Exploration and Exploitation in the Khalda Area in Western Desert of Egypt between Arab Republic of Egypt, the Egyptian General Petroleum Corporation, Repsol Exploration Egypt S.A., Phoenix Resources Company of Egypt and Samsung Corporation (incorporated by reference to Exhibit 10.12 to Registrant’s Annual Report on Form 10-K for year ended December 31, 1997, SEC File No. 001-4300).
  10 .12     Concession Agreement for Petroleum Exploration and Exploitation in the Qarun Area in Western Desert of Egypt, between Arab Republic of Egypt, the Egyptian General Petroleum Corporation, Phoenix Resources Company of Qarun and Apache Oil Egypt, Inc., dated May 17, 1993 (incorporated by reference to Exhibit 10(b) to Phoenix’s Annual Report on Form 10-K for year ended December 31, 1993, SEC File No. 1-547).
  10 .13     Agreement for Amending the Gas Pricing Provisions under the Concession Agreement for Petroleum Exploration and Exploitation in the Qarun Area, effective June 16, 1994 (incorporated by reference to Exhibit 10.18 to Registrant’s Annual Report on Form 10-K for year ended December 31, 1996, SEC File No. 001-4300).
  †10 .14     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 .15     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 .16     Apache Corporation 401(k) Savings Plan, dated January 1, 2007.
  *†10 .17     Apache Corporation Money Purchase Retirement Plan, dated January 1, 2007.
  *†10 .18     Non-Qualified Retirement/Savings Plan of Apache Corporation, amended and restated as of January 1, 2005.
  †10 .19     Apache Corporation 1990 Stock Incentive Plan, as amended and restated September 13, 2001 (incorporated by reference to Exhibit 10.01 to Registrant’s Quarterly Report on Form 10-Q, as amended by Form 10-Q/A, for the quarter ended September 30, 2001, SEC File No. 001-4300).
  †10 .20     Apache Corporation 1995 Stock Option Plan, as amended and restated September 15, 2005, effective as of January 1, 2005 (incorporated by reference to Exhibit 10.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2005, SEC File No. 001-4300).
  †10 .21     Apache Corporation 2000 Share Appreciation Plan, as amended and restated September 15, 2005, effective as of January 1, 2005 (incorporated by reference to Exhibit 10.4 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2005, SEC File No. 001-4300).
  †10 .22     Apache Corporation 1996 Performance Stock Option Plan, as amended and restated September 13, 2001 (incorporated by reference to Exhibit 10.03 to Registrant’s Quarterly Report on Form 10-Q, as amended by Form 10-Q/A, for the quarter ended September 30, 2001, SEC File No. 001-4300).
  †10 .23     Apache Corporation 1998 Stock Option Plan, as amended and restated September 15, 2005, effective as of January 1, 2005 (incorporated by reference to Exhibit 10.2 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2005, SEC File No. 001-4300).
  †10 .24     Apache Corporation 2000 Stock Option Plan, as amended and restated September 15, 2005, effective as of January 1, 2005 (incorporated by reference to Exhibit 10.3 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2005, SEC File No. 001-4300).

50


 

             
Exhibit
       
No.
     
Description
 
  †10 .25     Apache Corporation 2003 Stock Appreciation Rights Plan, dated and effective May 1, 2003 (incorporated by reference to Exhibit 10.31 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2003, SEC File No. 001-4300).
  †10 .26     Apache Corporation 2005 Stock Option Plan, dated February 3, 2005 (incorporated by reference to Appendix B to the Proxy Statement relating to Apache’s 2005 annual meeting of stockholders, as filed with the Commission on March 28, 2005, Commission File No. 001-4300).
  †10 .27     Apache Corporation 2005 Share Appreciation Plan, dated February 3, 2005 (incorporated by reference to Appendix C to the Proxy Statement relating to Apache’s 2005 annual meeting of stockholders, as filed with the Commission on March 28, 2005, Commission File No. 001-4300).
  †10 .28     1990 Employee Stock Option Plan of The Phoenix Resource Companies, Inc., as amended through September 29, 1995, effective April 9, 1990 (incorporated by reference to Exhibit 10.33 to Registrant’s Annual Report on Form 10-K for year ended December 31, 1996, SEC File No. 001-4300).
  †10 .29     Apache Corporation Income Continuance Plan, as amended and restated May 3, 2001 (incorporated by reference to Exhibit 10.30 to Registrant’s Annual Report on Form 10-K for the year ended December 31, 2001, SEC File No. 001-4300).
  †10 .30     Apache Corporation Deferred Delivery Plan, as amended and restated September 15, 2005, effective as of January 1, 2005 (incorporated by reference to Exhibit 10.5 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2005, SEC File No. 001-4300).
  †10 .31     Apache Corporation Executive Restricted Stock Plan, as amended and restated December 14, 2005, effective January 1, 2005 (incorporated by reference to Exhibit 10.36 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2005, SEC File No. 001-4300).
  †10 .32     Apache Corporation Non-Employee Directors’ Compensation Plan, as amended and restated September 15, 2005, effective as of January 1, 2005 (incorporated by reference to Exhibit 10.7 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2005, SEC File No. 001-4300).
  †10 .33     Apache Corporation Outside Directors’ Retirement Plan, as amended and restated May 4, 2006, effective as of January 1, 2006 (incorporated by reference to Exhibit 10.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2006, SEC File No. 001-4300).
  †10 .34     Apache Corporation Equity Compensation Plan for Non-Employee Directors, as amended and restated February 5, 2004 (incorporated by reference to Exhibit 10.38 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2003, SEC File No. 001-4300).
  †10 .35     Amended and Restated Employment Agreement, dated December 5, 1990, between Registrant and Raymond Plank (incorporated by reference to Exhibit 10.39 to Registrant’s Annual Report on Form 10-K for year ended December 31, 1996, SEC File No. 001-4300).
  †10 .36     First Amendment, dated April 4, 1996, to Restated Employment Agreement between Registrant and Raymond Plank (incorporated by reference to Exhibit 10.40 to Registrant’s Annual Report on Form 10-K for year ended December 31, 1996, SEC File No. 001-4300).
  †10 .37     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 .38     Employment Agreement, dated June 6, 1988, between Registrant and G. Steven Farris (incorporated by reference to Exhibit 10.6 to Registrant’s Annual Report on Form 10-K for year ended December 31, 1989, SEC File No. 001-4300).
  †10 .39     Amended and Restated Conditional Stock Grant Agreement, dated September 15, 2005, effective January 1, 2005, between Registrant and G. Steven Farris (incorporated by reference to Exhibit 10.06 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2005, SEC File No. 001-4300).
  10 .40     Amended and Restated Gas Purchase Agreement, effective July 1, 1998, by and among Registrant and MW Petroleum Corporation, as seller, and Producers Energy Marketing, LLC, as buyer (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K, dated June 18, 1998, filed June 23, 1998, SEC File No. 001-4300).

51


 

             
Exhibit
       
No.
     
Description
 
  10 .41     Deed of Guaranty and Indemnity, dated January 11, 2003, made by Registrant in favor of BP Exploration Operating Company Limited (incorporated by reference to Registrant’s Current Report on Form 8-K, dated and filed January 13, 2003, SEC File No. 001-4300).
  *12 .1     Statement of Computation of Ratios of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividends.
  14 .1     Code of Business Conduct (incorporated by reference to Exhibit 14.1 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2003, SEC File No. 001-4300).
  *21 .1     Subsidiaries of Registrant
  *23 .1     Consent of Ernst & Young LLP
  *23 .2     Consent of Ryder Scott Company L.P., Petroleum Consultants
  *24 .1     Power of Attorney (included as a part of the signature pages to this report)
  *31 .1     Certification of Chief Executive Officer
  *31 .2     Certification of Chief Financial Officer
  *32 .1     Certification of Chief Executive Officer and Chief Financial Officer
 
 
* 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.
 
(b) See (a) 3. above.
 
(c) See (a) 2. above.

52


 

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, thereunto duly authorized.
 
APACHE CORPORATION
 
   
/s/  G. STEVEN FARRIS
G. Steven Farris
President, Chief Executive Officer and
Chief Operating Officer
 
Dated: February 28, 2007
 
POWER OF ATTORNEY
 
The officers and directors of Apache Corporation, whose signatures appear below, hereby constitute and appoint G. Steven Farris, Roger B. Plank, P. Anthony Lannie, Rebecca A. Hoyt, and Jeffrey B. King, 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
  Director, President, Chief Executive Officer and Chief Operating Officer (Principal Executive Officer)   February 28, 2007
         
/s/  ROGER B. PLANK

Roger B. Plank
  Executive Vice President and Chief Financial Officer (Principal Financial Officer)   February 28, 2007
         
/s/  REBECCA A. HOYT

Rebecca A. Hoyt
  Vice President and Controller (Principal Accounting Officer)   February 28, 2007
         
/s/  RAYMOND PLANK

Raymond Plank
  Chairman of the Board   February 28, 2007
         
/s/  FREDERICK M. BOHEN

Frederick M. Bohen
  Director   February 28, 2007
         
/s/  RANDOLPH M. FERLIC

Randolph M. Ferlic
  Director   February 28, 2007
         
/s/  EUGENE C. FIEDOREK

Eugene C. Fiedorek
  Director   February 28, 2007
         
/s/  A. D. FRAZIER, JR

A. D. Frazier, Jr.
  Director   February 28, 2007
         
/s/  PATRICIA ALBJERG GRAHAM

Patricia Albjerg Graham
  Director   February 28, 2007


 

             
Name
 
Title
 
Date
 
/s/  JOHN A. KOCUR

John A. Kocur
  Director   February 28, 2007
         
/s/  GEORGE D. LAWRENCE

George D. Lawrence
  Director   February 28, 2007
         
/s/  F. H. MERELLI

F. H. Merelli
  Director   February 28, 2007
         
/s/  RODMAN D. PATTON

Rodman D. Patton
  Director   February 28, 2007
         
/s/  CHARLES J. PITMAN

Charles J. Pitman
  Director   February 28, 2007
         
/s/  JAY A. PRECOURT

Jay A. Precourt
  Director   February 28, 2007


 

 
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 (“Exchange Act”). 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, 2006. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework.  Based on our assessment, management believes that the Company maintained effective internal control over financial reporting as of December 31, 2006.
 
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, management’s assessment of the effectiveness of the Company’s internal control over financial reporting 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.
 
G. Steven Farris
President, Chief Executive Officer
and Chief Operating Officer
 
Roger B. Plank
Executive Vice President and Chief Financial Officer
 
Rebecca A. Hoyt
Vice President and Controller
(Chief Accounting Officer)
 
Houston, Texas
February 28, 2007


F-1


 

 
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
The Board of Directors and Shareholders of Apache Corporation:
 
We have audited the accompanying consolidated balance sheets of Apache Corporation and subsidiaries as of December 31, 2006 and 2005, and the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2006. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated 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 audit provides 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 as of December 31, 2006 and 2005 and the consolidated results of their operations and their cash flows for each of the three years ended December 31, 2006, in conformity with U.S. generally accepted accounting principles.
 
As described in Note 1 and Note 8 to the consolidated financial statements, during 2004, the Company adopted the modified prospective provisions of Statement of Financial Accounting Standards (“SFAS”) No. 123(revised), “Share-Based Payment.” In addition, as described in Note 1 and Note 10 to the Consolidated Financial Statements, the Company adopted the provisions of SFAS No. 158, “Employees Accounting for Defined Benefit Plans and Other Postretirement Plans.”
 
We also have audited in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Apache Corporation and subsidiaries’ internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 28, 2007 expressed an unqualified opinion thereon.
 
ERNST & YOUNG LLP
 
Houston, Texas
February 28, 2007


F-2


 

 
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
The Board of Directors and Shareholders of Apache Corporation:
 
We have audited management’s assessment, included in the accompanying Report of Management on Internal Control over Financial Reporting, that Apache Corporation and subsidiaries maintained effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Apache Corporation’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of 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, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
 
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
 
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
 
In our opinion, management’s assessment that Apache Corporation and subsidiaries maintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on the COSO criteria. Also, in our opinion, Apache Corporation and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, 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, 2006 and 2005, and the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2006 and our report dated February 28, 2007 expressed an unqualified opinion thereon.
 
ERNST & YOUNG LLP
 
Houston, Texas
February 28, 2007


F-3


 

 
APACHE CORPORATION AND SUBSIDIARIES
 
STATEMENT OF CONSOLIDATED OPERATIONS
 
                         
    For the Year Ended December 31,  
    2006     2005     2004  
    (In thousands, except per common share data)  
 
REVENUES AND OTHER:
                       
Oil and gas production revenues
  $ 8,074,253     $ 7,457,291     $ 5,308,017  
Gain on China divestiture
    173,545              
Other
    40,981       126,953       24,560  
                         
      8,288,779       7,584,244       5,332,577  
                         
OPERATING EXPENSES:
                       
Depreciation, depletion and amortization
    1,816,359       1,415,682       1,222,152  
Asset retirement obligation accretion
    88,931       53,720       46,060  
Lease operating costs
    1,362,374       1,040,475       864,378  
Gathering and transportation costs
    104,322       100,260       82,261  
Severance and other taxes
    553,978       453,258       93,748  
General and administrative
    211,334       198,272       173,194  
China litigation provision
                71,216  
Financing costs:
                       
Interest expense
    217,454       175,419       168,090  
Amortization of deferred loan costs
    2,048       3,748       2,471  
Capitalized interest
    (61,301 )     (56,988 )     (50,748 )
Interest income
    (16,315 )     (5,856 )     (3,328 )
                         
      4,279,184       3,377,990       2,669,494  
                         
INCOME BEFORE INCOME TAXES
    4,009,595       4,206,254       2,663,083  
Provision for income taxes
    1,457,144       1,582,524       993,012  
                         
INCOME BEFORE CHANGE IN ACCOUNTING PRINCIPLE
    2,552,451       2,623,730       1,670,071  
Cumulative effect of change in accounting principle, net of income tax
                (1,317 )
                         
NET INCOME
    2,552,451       2,623,730       1,668,754  
Preferred stock dividends
    5,680       5,680       5,680  
                         
INCOME ATTRIBUTABLE TO COMMON STOCK
  $ 2,546,771     $ 2,618,050     $ 1,663,074  
                         
BASIC NET INCOME PER COMMON SHARE:
                       
Before change in accounting principle
  $ 7.72     $ 7.96     $ 5.10  
Cumulative effect of change in accounting principle
                 
                         
    $ 7.72     $ 7.96     $ 5.10  
                         
DILUTED NET INCOME PER COMMON SHARE:
                       
Before change in accounting principle
  $ 7.64     $ 7.84     $ 5.04  
Cumulative effect of change in accounting principle
                (.01 )
                         
    $ 7.64     $ 7.84     $ 5.03  
                         
 
The accompanying notes to consolidated financial statements are an integral part of this statement.


F-4


 

 
APACHE CORPORATION AND SUBSIDIARIES
 
STATEMENT OF CONSOLIDATED CASH FLOWS
 
                         
    For the Year Ended December 31,  
    2006     2005     2004  
    (In thousands)  
 
CASH FLOWS FROM OPERATING ACTIVITIES:
                       
Net income
  $ 2,552,451     $ 2,623,730     $ 1,668,754  
Adjustments to reconcile net income to net cash provided by operating activities:
                       
Depreciation, depletion and amortization
    1,816,359       1,415,682       1,222,152  
Provision for deferred income taxes
    751,457       598,927       444,906  
Asset retirement obligation accretion
    88,931       53,720       46,060  
Gain on sale of China operations
    (173,545 )            
Other
    32,380       52,274       43,482  
Changes in operating assets and liabilities, net of effects of acquisitions:
                       
(Increase) decrease in receivables
    (153,616 )     (504,038 )     (296,383 )
(Increase) decrease in inventories
    10,238       11,295       (659 )
(Increase) decrease in drilling advances and other
    66,323       (144,154 )     (35,761 )
(Increase) decrease in deferred charges and other
    (126,869 )     (26,454 )     (35,328 )
Increase (decrease) in accounts payable
    (136,663 )     97,447       182,454  
Increase (decrease) in accrued expenses
    (475,021 )     214,491       28,431  
Increase (decrease) in advances from gas purchasers
    (25,601 )     (22,108 )     (18,331 )
Increase (decrease) in deferred credits and noncurrent liabilities
    86,082       (38,542 )     (18,258 )
                         
NET CASH PROVIDED BY OPERATING ACTIVITIES
    4,312,906       4,332,270       3,231,519  
                         
CASH FLOWS FROM INVESTING ACTIVITIES:
                       
Additions to property and equipment
    (3,891,639 )     (3,715,856 )     (2,456,488 )
Acquisition of BP plc properties
    (833,820 )            
Acquisition of Pioneer’s Argentine operations
    (704,809 )            
Acquisition of Amerada Hess properties
    (229,134 )            
Acquisition of Pan American properties
    (396,056 )            
Acquisition of ExxonMobil properties
                (348,173 )
Acquisition of Anadarko properties
                (531,963 )
Proceeds from China divestiture
    264,081              
Proceeds from sale of Egypt properties
    409,203              
Additions to gas gathering, transmission and processing facilities
    (248,589 )            
Proceeds from sales of oil and gas properties
    4,740       79,663       4,042  
Other, net
    (149,559 )     (95,649 )     (78,431 )
                         
NET CASH USED IN INVESTING ACTIVITIES
    (5,775,582 )     (3,731,842 )     (3,411,013 )
                         
CASH FLOWS FROM FINANCING ACTIVITIES:
                       
Debt borrowings
    1,779,963       153,368       544,824  
Payments on debt
    (150,266 )     (549,530 )     (283,400 )
Dividends paid
    (154,143 )     (117,395 )     (90,369 )
Common stock activity
    31,963       18,864       21,595  
Treasury stock activity, net
    (166,907 )     6,620       12,472  
Cost of debt and equity transactions
    (2,061 )     (861 )     (2,303 )
Other
    35,791       6,273       54,265  
                         
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES
    1,374,340       (482,661 )     257,084  
                         
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
    (88,336 )     117,767       77,590  
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR
    228,860       111,093       33,503  
                         
CASH AND CASH EQUIVALENTS AT END OF YEAR
  $ 140,524     $ 228,860     $ 111,093  
                         
 
The accompanying notes to consolidated financial statements are an integral part of this statement.


F-5


 

 
APACHE CORPORATION AND SUBSIDIARIES
 
CONSOLIDATED BALANCE SHEET
 
                 
    December 31,  
    2006     2005  
    (In thousands)  
 
ASSETS
CURRENT ASSETS:
               
Cash and cash equivalents
  $ 140,524     $ 228,860  
Receivables, net of allowance
    1,651,664       1,444,545  
Inventories
    320,386       209,670  
Drilling advances
    78,838       146,047  
Derivative instruments
    139,756       16,319  
Prepaid assets and other
    159,103       116,636  
                 
      2,490,271       2,162,077  
                 
PROPERTY AND EQUIPMENT:
               
Oil and gas, on the basis of full cost accounting:
               
Proved properties
    29,107,921       23,836,789  
Unproved properties and properties under development, not being amortized
    1,284,743       795,706  
Gas gathering, transmission and processing facilities
    1,725,619       1,359,477  
Other
    358,605       312,970  
                 
      32,476,888       26,304,942  
Less: Accumulated depreciation, depletion and amortization
    (11,130,636 )     (9,513,602 )
                 
      21,346,252       16,791,340  
                 
OTHER ASSETS:
               
Goodwill, net
    189,252       189,252  
Deferred charges and other
    282,400       129,127  
                 
    $ 24,308,175     $ 19,271,796  
                 
 
LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
               
Accounts payable
  $ 644,889     $ 714,598  
Accrued operating expense
    70,551       66,609  
Accrued exploration and development
    534,924       460,203  
Accrued compensation and benefits
    127,779       125,022  
Accrued interest
    30,878       32,564  
Accrued income taxes
    2,133       120,153  
Current debt
    1,802,094       274  
Asset retirement obligation
    376,713       93,557  
Derivative instruments
    70,128       256,115  
United Kingdom Petroleum Revenue Tax
          174,491  
Other
    151,523       142,978  
                 
      3,811,612       2,186,564  
                 
LONG-TERM DEBT
    2,019,831       2,191,954  
                 
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
               
Income taxes
    3,618,989       2,580,629  
Advances from gas purchasers
    43,167       68,768  
Asset retirement obligation
    1,370,853       1,362,358  
Derivative instruments
          152,430  
Other
    252,670       187,878  
                 
      5,285,679       4,352,063  
                 
COMMITMENTS AND CONTINGENCIES (Note 10) SHAREHOLDERS’ EQUITY:
               
Preferred stock, no par value, 5,000,000 shares authorized — Series B, 5.68% Cumulative Preferred Stock, 100,000 shares issued and outstanding
    98,387       98,387  
Common stock, $0.625 par, 430,000,000 shares authorized, 339,783,392 and 336,997,053 shares issued, respectively
    212,365       210,623  
Paid-in capital
    4,269,795       4,170,714  
Retained earnings
    8,898,577       6,516,863  
Treasury stock, at cost, 9,045,967 and 6,875,823 shares, respectively
    (256,739 )     (89,764 )
Accumulated other comprehensive loss
    (31,332 )     (365,608 )
                 
      13,191,053       10,541,215  
                 
    $ 24,308,175     $ 19,271,796  
                 
 
The accompanying notes to consolidated financial statements are an integral part of this statement.


F-6


 

APACHE CORPORATION AND SUBSIDIARIES
 
STATEMENT OF CONSOLIDATED SHAREHOLDERS’ EQUITY
 
                                                                   
                                          Accumulated
       
            Series B
                            Other
    Total
 
    Comprehensive
      Preferred
    Common
    Paid-In
    Retained
    Treasury
    Comprehensive
    Shareholders’
 
    Income       Stock     Stock     Capital     Earnings     Stock     Income (Loss)     Equity  
    (In thousands)  
 
                                                                 
BALANCE AT DECEMBER 31, 2003
            $ 98,387     $ 207,818     $ 4,038,007     $ 2,445,698     $ (105,169 )   $ (151,943 )   $ 6,532,798  
Comprehensive income (loss):
                                                                 
Net income
  $ 1,668,754                           1,668,754                   1,668,754  
Commodity hedges, net of income tax expense of $13,742
    22,461                                       22,461       22,461  
                                                                   
Comprehensive income
  $ 1,691,215                                                            
                                                                   
Cash dividends:
                                                                 
Preferred
                                (5,680 )                 (5,680 )
Common ($.28 per share)
                                (91,433 )                 (91,433 )
Five percent common stock dividend
                                                   
Common shares issued
                    1,502       25,030                         26,532  
Treasury shares issued, net
                          8,312             7,844             16,156  
Compensation expense
                          34,462                         34,462  
Other
                          371                         371  
                                                                   
BALANCE AT DECEMBER 31, 2004
              98,387       209,320       4,106,182       4,017,339       (97,325 )     (129,482 )     8,204,421  
Comprehensive income (loss):
                                                                 
Net income
  $ 2,623,730                           2,623,730                   2,623,730  
Commodity hedges, net of income tax benefit of $128,990
    (236,126 )                                     (236,126 )     (236,126 )
                                                                   
Comprehensive income
  $ 2,387,604                                                            
                                                                   
Cash dividends:
                                                                 
Preferred
                                (5,680 )                 (5,680 )
Common ($.36 per share)
                                (118,526 )                 (118,526 )
Common shares issued
                    1,303       21,125                         22,428  
Treasury shares issued, net
                          2,736             7,561             10,297  
Compensation expense
                          40,528                         40,528  
Other
                          143                         143  
                                                                   
BALANCE AT DECEMBER 31, 2005
              98,387       210,623       4,170,714       6,516,863       (89,764 )     (365,608 )     10,541,215  
Comprehensive income (loss):
                                                                 
Net income
  $ 2,552,451                           2,552,451                   2,552,451  
Post retirement, net of income tax benefit of $2,816
    (6,116 )                                     (6,116 )     (6,116 )
Commodity hedges, net of income tax expense of $187,162
    340,392                                       340,392       340,392  
                                                                   
Comprehensive income
  $ 2,886,727                                                            
                                                                   
Cash dividends:
                                                                 
Preferred
                                (5,680 )                 (5,680 )
Common ($.50 per share)
                                (165,059 )                 (165,059 )
Common shares issued
                    1,742       54,917                         56,659  
Treasury shares purchased, net
                          1,968             (166,967 )           (164,999 )
Compensation expense
                          42,085                         42,085  
Other
                          111       2       (8 )           105  
                                                                   
BALANCE AT DECEMBER 31, 2006
            $ 98,387     $ 212,365     $ 4,269,795     $ 8,898,577     $ (256,739 )   $ (31,332 )   $ 13,191,053  
                          &n