-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, CunKYmZ95vGJP9ZgN/yihG3Y4HBKZ9qYqbQOuwP7tbAcpLBtI5grnphUx41W8dW1 dg/hfam57hBBu/udhY5f7A== 0000950129-05-002495.txt : 20050316 0000950129-05-002495.hdr.sgml : 20050316 20050316153016 ACCESSION NUMBER: 0000950129-05-002495 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 8 CONFORMED PERIOD OF REPORT: 20041231 FILED AS OF DATE: 20050316 DATE AS OF CHANGE: 20050316 FILER: COMPANY DATA: COMPANY CONFORMED NAME: APACHE CORP CENTRAL INDEX KEY: 0000006769 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 410747868 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-04300 FILM NUMBER: 05685237 BUSINESS ADDRESS: STREET 1: 2000 POST OAK BLVD STREET 2: ONE POST OAK CENTER STE 100 CITY: HOUSTON STATE: TX ZIP: 77056-4400 BUSINESS PHONE: 7132966000 MAIL ADDRESS: STREET 1: 2000 POST OAK BLVD STREET 2: STE 100 CITY: HOUSTON STATE: TX ZIP: 77056-4400 FORMER COMPANY: FORMER CONFORMED NAME: APACHE OIL CORP DATE OF NAME CHANGE: 19660830 10-K 1 h23217e10vk.txt APACHE CORPORATION - DECEMBER 31, 2004 =============================================================================== 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, 2004, 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 New York Stock Exchange 7.75% Notes Due 2029 Irrevocably and Unconditionally Guaranteed by Apache Corporation
Securities Registered Pursuant to Section 12(g) of the Act: Common Stock, $0.625 par value 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 whether registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). [X] Aggregate market value of the voting and non-voting common equity held by non-affiliates of registrant as of June 30, 2004...................................................... $14,197,397,378 Number of shares of registrant's common stock outstanding as of February 28, 2005...................................... 328,095,581
DOCUMENTS INCORPORATED BY REFERENCE: Portions of registrant's proxy statement relating to registrant's 2005 annual meeting of stockholders have been incorporated by reference into Part III hereof. ================================================================================ TABLE OF CONTENTS DESCRIPTION
ITEM PAGE - ---- ---- PART I 1. BUSINESS.................................................... 1 2. PROPERTIES.................................................. 1 3. LEGAL PROCEEDINGS........................................... 16 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS......... 16 PART II 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS......................................... 16 6. SELECTED FINANCIAL DATA..................................... 17 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS................................... 17 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK........................................................ 44 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA................. 46 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.................................... 46 9A. CONTROLS AND PROCEDURES..................................... 46 9B. OTHER INFORMATION........................................... 47 PART III 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.......... 47 11. EXECUTIVE COMPENSATION...................................... 47 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.................................................. 47 13. CETAIN RELATIONSHIPS AND RELATED TRANSACTIONS............... 47 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES...................... 47 PART IV 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K......................................................... 48
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, the Permian Basin, the Anadarko Basin and the Western Sedimentary Basin of Canada. Outside of North America we have exploration and production interests offshore and onshore Egypt, offshore Western Australia, offshore the United Kingdom in the North Sea (North Sea), offshore The People's Republic of China (China), 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. In June 2004, 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 operating subsidiaries, such as Apache Canada Ltd., DEK Energy Company (DEKALB), Apache Energy Limited (AEL), Apache International, 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. Throughout this report, per share results and share amounts have been adjusted for i) the 10 percent common stock dividend paid on January 21, 2002, to our shareholders of record on December 31, 2001, ii) the five percent common stock dividend paid on April 2, 2003, to our shareholders of record on March 12, 2003, and iii) the two-for-one stock split distributed on January 14, 2004, to our shareholders of record on December 31, 2003. The stock dividends and stock split reflect our board of directors' belief that we can reward our shareholders while remaining focused on our primary objective of building Apache to last by achieving profitable growth. OUR GROWTH STRATEGY Building on Apache's first 50 years in business, our mission remains the same; to grow a significant and profitable company for the benefit of our shareholders. However, over the years our strategy for achieving profitable growth has evolved. Over the most recent decade Apache has been an active acquirer of properties, following up each one with proactive exploitation operations, including workovers, re-completions, and drilling, to increase production and reserves, as well as efforts to reduce costs per unit produced and enhance profitability. Also during the past decade, we added an international exploration component to our strategy, which exposed our shareholders to larger reserve targets and a greater ability to grow production and reserves through drilling. This strategy starts with strong operating capabilities in core areas where we obtain local expertise and, through active operations, can make a difference. In each of our core producing areas, we have built teams that have the technical knowledge, sense of urgency, and the desire to wring more out of Apache's assets. Our local expertise also provides an advantage in day-to-day operations and when acquisition opportunities arise in core areas. After an extensive bottom-up/top-down planning process, each operating area is given the autonomy necessary to make drilling and operating decisions and to act quickly. To foster 1 predictable and generally consistent results, a numbers-intensive management and incentive system underscores high cash flow and rate-of-return targets. These and other goals are measured monthly and reviewed with senior management quarterly. We take a portfolio approach to the areas in which we drill in an effort to generate consistent, profitable growth. This approach provides diversity in terms of hydrocarbon mix (oil and gas), reserve life, geological risk and geographical location. In the U.S., our Gulf of Mexico operations generate substantial production and cash flow and excellent rates of return; however, with steep decline rates, offshore reserves are generally short lived and difficult to replace through drilling alone. Our Central region brings the balance of long-lived reserves and consistent drilling results. In general, the United States is mature, offering smaller reserve targets but presently, excellent prices and high margins. We seek to drill actively in the United States, but not to the extent of pursuing growth at any cost. Our future growth is more likely to be achieved in the U.S. through drilling and acquisitions, rather than through drilling activity alone. Our Canadian and other international operations provide a higher potential to grow through drilling. Canada, Australia, Egypt and, in the last year, the North Sea, all offer generally larger exploration reserve targets than those to which we are exposed in the United States. Also, Apache's operations in Egypt and Australia typically include large acreage positions with considerable running room when compared to the U.S., where there are more companies competing for acreage and drilling opportunities. Once established in a core area, Apache takes an active approach to drilling operations and supplements growth with occasional property acquisitions. While the incremental production and reserves from acquisitions are a key component in our evaluation of acquisitions, generally speaking, it is the exploitation opportunities associated with property acquisitions where we believe the greatest amount of value can be added and where the overall rate-of-return can be impacted most. Over the last decade, Apache has invested a little more than a dollar in drilling and exploitation operations for every dollar invested in acquisitions. The objective is to increase reserves and production on all properties, thereby lowering costs per unit, and increasing overall profitability. In the North Sea, for example, an active drilling and exploitation campaign since acquiring the Forties Field in April 2003 enabled us to drive fourth-quarter 2004 average daily production up to 61,680 barrels of oil from 40,950 barrels per day in the fourth quarter of 2003. This 50 percent increase in production spread operating costs over a greater production base, driving costs per unit down and profit margins up. For 2005, we plan on another active year of drilling. Because we revise our capital expenditure estimates frequently throughout the year based on industry conditions and results to date, accurately projecting annual capital expenditures is difficult at best. However, our preliminary estimate of 2005 capital expenditures is in excess of $2.5 billion. While we do not budget for acquisitions because their timing is unpredictable, we continue to look for acquisition properties where we believe we can add value and earn adequate rates of return. Because we have maintained our financial flexibility (our year-end ratio of debt-to-capitalization was 24 percent), we are in a good position to take advantage of acquisition opportunities should they arise. Apache has grown production 25 of the last 26 years and reserves for 19 consecutive years in varying industry environments. We are fortunate to have evolved to the point where we believe we have the necessary ingredients to continue growing over time through drilling, acquisition or both. OPERATING HIGHLIGHTS We currently have interests in seven countries: the United States, Canada, Egypt, Australia, the United Kingdom, China, and Argentina. Our reportable segments are the United States, Canada, Egypt, Australia, North Sea, and Other International. In the U.S., our exploration and production activities are divided into two regions: Gulf Coast and Central. At year-end, approximately 70 percent of our estimated proved reserves were located in North America. Outside North America, our exploration and production activities are focused primarily in Egypt, the North Sea, and Australia. Additionally, we have had production from our interests in China for over a year, and have a small production interest in Argentina. 2 The following table sets out a brief comparative summary of certain key 2004 data for each area. More detailed information regarding the natural gas, oil, and natural gas liquids (NGLs) production and average prices received in our core geographic areas for 2004, 2003, and 2002 is available later in this section under Production, Pricing and Lease Operating Cost Data with further discussion and analysis in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations in this Form 10-K. In addition, for information concerning the amount of revenue, expenses, operating income (loss) and total assets attributable to each of the reportable segments, see Note 14, Supplemental Oil and Gas Disclosures (Unaudited), and Note 13, 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 of Analysis of Financial Condition and Results of Operations, "Capital Resources and Liquidity" in this Form 10-K.
12/31/04 PERCENTAGE 2004 2004 ESTIMATED OF TOTAL 2004 GROSS NEW 2004 PRODUCTION PROVED ESTIMATED GROSS NEW PRODUCTIVE PRODUCTION REVENUE RESERVES PROVED WELLS WELLS (IN MMBOE) (IN MILLIONS) (IN MMBOE) RESERVES DRILLED DRILLED ---------- ------------- ---------- ---------- --------- ---------- Region/Country: Gulf Coast............... 47.2 $1,658.7 407 21.0% 133 106 Central.................. 20.1 673.4 452 23.3% 283 268 ----- -------- ----- ----- ----- ----- Total U.S.............. 67.3 2,332.1 859 44.3% 416 374 ----- -------- ----- ----- ----- ----- Canada................... 30.2 1,014.1 489 25.3% 1,313 1,211 ----- -------- ----- ----- ----- ----- Total North America.... 97.5 3,346.2 1,348 69.6% 1,729 1,585 ----- -------- ----- ----- ----- ----- Egypt.................... 27.5 932.8 234 12.1% 116 103 Australia................ 16.4 458.0 170 8.8% 31 16 United Kingdom........... 19.5 472.1 175 9.0% 17 12 China.................... 2.8 91.2 8 .4% 16 15 Argentina................ .4 7.7 2 .1% 4 4 ----- -------- ----- ----- ----- ----- Total International.... 66.6 1,961.8 589 30.4% 184 150 ----- -------- ----- ----- ----- ----- Total.................. 164.1 $5,308.0 1,937 100.0% 1,913 1,735 ===== ======== ===== ===== ===== =====
THE FOLLOWING DISCUSSIONS INCLUDE REFERENCES TO OUR PLANS FOR 2005. 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 SUCCESS AND CHANGING INDUSTRY CONDITIONS. UNITED STATES Gulf Coast -- The Gulf Coast region comprises our interests in and along the Gulf of Mexico, primarily in the areas in and offshore Louisiana and Texas. Apache is the largest acreage holder and the second largest producer in Gulf waters less than 1,200 feet deep. In 2004 and 2003, the Gulf Coast was our leading region for both production volumes and revenues. This region performed 452 workover and recompletion operations during 2004 and completed 106 out of 133 total wells drilled. As of year-end 2004, Gulf Coast accounted for 21 percent of our estimated proved reserves. Although actual annual capital expenditures may change considerably in 2005, we currently estimate spending approximately $600 million to drill around 120 wells and to continue our production enhancement and exploitation programs with a focus on properties acquired from Anadarko Petroleum (Anadarko) in 2004 and BP p.l.c. (BP) and Shell Exploration and Production Company (Shell) in 2003. See Note 2, Acquisitions and Divestitures of Item 15 in this Form 10-K for detailed discussion of acquisitions. 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 50 years ago. At year-end 2004, the Central region accounted for approximately 23 percent of our estimated proved reserves, 3 the second largest in the Company. The Central Region's estimated proved reserves increased 20 percent in 2004 through acquisitions, the most significant being the Exxon Mobil Corporation (ExxonMobil) transaction, discussed later in this section, and the most active drilling year in the region's history. During 2004, we participated in 283 wells, 268 of which were completed as productive. Apache performed 367 workovers and recompletions in the region during the year. Although actual annual capital expenditures may change considerably, in 2005, we currently estimate spending approximately $300 million drilling 200-plus wells spread among the newly acquired properties and our sizable acreage base in the Anadarko Basin and to continue our production enhancement programs. Marketing -- The Company began directly marketing its own U.S. natural gas production in July 2003. Our objective is to reduce our dependence on middlemen by taking control of our marketing activities in an effort to enhance the value of our natural gas sales by diversifying our customer base and optimizing transportation arrangements. The flexibility to transport our gas from the wellhead has provided us access to new markets as our customers now include Local Distribution Companies (LDCs), utilities, end-users, integrated majors and to a lesser extent, marketers. We manage the sales risk associated with our natural gas production fluctuations by selling a portion of our production into the daily market. We manage our credit risk by selling to creditworthy customers, monitoring our credit exposure daily and making adjustments as needed. Prior to July 2003, Apache sold most of its U.S. natural gas production to Cinergy Marketing and Trading, LLC (Cinergy), under a long-term gas purchase agreement. The prices received for our gas production under this agreement were based on a published index. See Note 12, Transactions with Related Parties and Major Customers of Item 15 in this Form 10-K. Several years ago, we locked in fixed prices on a portion of our U.S. future natural gas production using long-term, fixed-price physical contracts. These contracts, which represented approximately nine percent of our 2004 domestic natural gas production, will expire in 2005 through 2008. The contracts provide protection to the Company's cash flows in the event of decreasing natural gas prices. See Item 7a, Quantitative and Qualitative Disclosures about Market Risk "Commodity Risk" in this Form 10-K. In general, most of our gas is being sold on a monthly basis at either monthly or daily market prices. In an effort to increase our sales to direct users of natural gas and meet the needs of our customers, we also periodically sell some of our gas under long-term contracts at prices that fluctuate with market conditions. Our relationships with the LDCs and direct users of natural gas continue to be an important focus of our marketing efforts. We market our own U.S. crude oil to integrated majors, marketers and refiners. Contracts are generally 30 days and renew automatically until canceled. These oil contracts generally provide for sales at prices that change with daily market conditions. CANADA Overview -- Our exploration and development activity in the Canadian region is concentrated in the Provinces of Alberta, British Columbia, Saskatchewan and the Northwest Territories. The region comprises 25 percent of our estimated proved reserves, the largest in the Company. We hold over 4.8 million net acres in Canada, the largest of the North American regions. Canada was our most active drilling area in 2004, with Apache participating in 1,313 gross wells, approximately 75 percent of which were shallow development wells. We completed 1,211 as producers and conducted 1,095 workover and recompletion projects. Apache acquired four packages totaling 382,000 acres in a farmout from ExxonMobil in the third quarter of 2004. Apache is planning to drill at least 250 wells over a two-year period which began in October 2004, with an opportunity for further drilling in the third year. Apache earns its interest section by section, and the Company is off to a fast start with 50 wells drilled on this acreage in the fourth quarter of 2004 and a similar number estimated for the first quarter of 2005. The new acreage fits well with Apache's asset portfolio in Canada, which comprises large acreage plays with high working interest ownership -- fields such as Hatton, Provost and Nevis. Apache is also targeting those same areas for coalbed methane (CBM) and in the process has emerged as the nation's largest producer of CBM. The North and South Grant Lands in the ExxonMobil farmout provide additional CBM potential. Although actual annual capital expenditures may change 4 considerably with industry conditions and results, we currently estimate spending approximately $600 million drilling around 1,000 wells, continuing our exploration and exploitation program and developing our gas processing infrastructure. Marketing -- Our Canadian natural gas sales include sales to LDCs, utilities, end-users, integrated majors, supply aggregators and marketers in the United States and Canada. With the expansion of pipeline transport capacity out of Canada in recent years, Canadian prices have become more closely correlated with United States 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. We currently have a limited number of longer term commitments to sell gas into either the United States or eastern Canada, but the volumes are relatively small and none of the terms extends beyond 2011. The prices we receive under these contracts fluctuate monthly with market indices. The remainder, which represents over 95 percent of our Canadian natural gas production, is sold on a monthly basis at either monthly or daily market prices. 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. All our NGLs are sold to midstream companies. We sell our crude and NGLs on Canadian Postings which are market reflective prices that depend on worldwide crude 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, Saskatchewan and Manitoba. EGYPT Overview -- In Egypt, our operations are generally conducted pursuant to production sharing contracts under which contractor partners pay 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 group to recover operating and capital expenditure costs. In general, the balance of the production is allocated between the contractor group and the Egyptian General Petroleum Corporation (EGPC) on a contractually defined basis. Apache is the largest leaseholder and the most active driller in the Western Desert. Egypt is the country with our largest single acreage position where as of December 31, 2004, we held over 8.5 million net acres in 14 concessions, including four concessions in the Western Desert that were awarded in 2004 and are scheduled for parliamentary approval in the first half of 2005. Development leases within concessions generally have 25-year lives with extensions possible for additional commercial discoveries, or on a negotiated basis. Apache is the largest producer of liquid hydrocarbons and the second largest producer of natural gas in the Western Desert. Egypt accounted for approximately 18 percent of Apache's production revenues on 16 percent of total production for the year and accounted for 12 percent of total estimated proved reserves at December 31, 2004. Apache had an active drilling program in Egypt, completing 103 of 116 gross wells, for a success rate of 88 percent. Although actual annual capital expenditures may change considerably with industry conditions and success, we currently plan to spend approximately $500 million in 2005 on approximately 130 exploration, development and appraisal wells and installing and upgrading production facilities. Marketing -- Historically, we and our partners have sold our natural gas production to EGPC pursuant to 25-year take-or-pay contracts. Pricing under these contracts is based on the energy equivalent of 85 percent of Gulf of Suez Blend crude oil. Beginning in 2000, EGPC introduced an alternative gas pricing formula for certain quantities of gas purchased by them. This Industry Pricing 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 upon reaching a Dated-Brent price of $21.00 per barrel. We previously entered into new gas sales contracts containing Industry Pricing at our Matruh, Ras Kanayes, Ras El Hekma, and Akik development leases. In 2004, we entered into four new gas sales agreements containing Industry Pricing. Those gas sales agreements relate to the Qasr, Imhotep, North East Abu Gharadig and Atoun development leases. Additionally, in exchange for extension of the Khalda Concession lease, a further amendment to the Khalda Concession Agreement was executed in July 2004 whereby the old gas price formula based on Gulf of Suez Blend, was preserved until 2013 for up to 100 MMcf/d produced from the South Umbarka Concession and the Khalda, Khalda West, Salam and Tarek 5 development leases. Volumes above 100 MMcf/d from those areas are priced at Industry Pricing. The Btu factor for our Egyptian gas generally ranges from 1,100 to 1,300 Btu per Mcf. Production from our recently discovered Qasr field will be sold under the terms of a 25-year Gas Sales Agreement with EGPC, signed April 22, 2004, and covering up to 2.1 Tcf of natural gas. Principle terms include supplying up to 300 MMcf/d to the Egyptian market. Pricing under the Agreement will be according to Industry Pricing described above. Finally, a December 11, 2003, Memorandum of Understanding (MOU) for a Gas Sales Agreement, Field Development Plan and Deepwater Development Lease for a minimum of 2.7 Tcf of natural gas over 25 years from our deepwater interests in the West Mediterranean Concession was extended to a current expiration date of March 31, 2005, and is expected to be extended again. Reserve recognition and proper scaling of the significant future development infrastructure (currently estimated at over $800 million gross) are pending negotiation and completion of the final sales agreement with EGPC and resolution in delays of certain payments by EGPC. In Egypt, oil from the Khalda Concession is generally sold directly into the Egyptian oil pipeline grid. Oil from the Qarun Concession and other nearby Western Desert blocks is delivered by pipeline to tanks at the Dashour tank farm northeast of the Qarun Block. In Egypt, most of our oil production is presently sold to EGPC on a spot basis at a "Western Desert" price (indexed to Brent Crude Oil). In 2004, we exported our inaugural three cargoes (approximately 960,000 barrels) of Western Desert crude oil from the El Hamra terminal to refiners in the Mediterranean. These export cargoes were sold at market prices comparable to domestic sales to EGPC. Additional export sales from both the Khalda and Qarun areas have continued in 2005. 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. AUSTRALIA Overview -- Our exploration activity in Australia is focused in the offshore Carnarvon, Gippsland, and Perth Basins where Apache holds 5.3 million net acres in 29 Exploration Permits, 10 Production Licenses, and five Retention Leases. Production operations are concentrated in the Carnarvon Basin with 10 Production Licenses, nine of which are operated by Apache. In 2004, we produced 16.4 MMboe in Australia (10 percent of our total production) generating $458 million of production revenues. During the year we participated in drilling 31 wells; 22 exploration and nine development wells. Nine of the exploration wells and seven of the development wells were productive for an overall 52 percent success rate. Australian region exploration successes included 2004 discoveries at Stickle and Harrison in the Exmouth sub-basin. We also had a substantial appraisal program with five productive wells. On the development side, three new fields commenced production in 2004 including the Linda gas field in April, and the Gudrun and Monet oil fields in February and June, respectively. Apache owns a 68.5 percent working and revenue interest in all three developments. First production from the John Brookes gas development is scheduled for the third quarter of 2005 at an average projected rate of 60 MMcf of gas and 360 barrels of condensate per day net to Apache's 55 percent interest. Key factors for continuing success in 2005 will be maintaining oil production, increasing gas production to fulfill the requirements of two new gas contracts and continued success in our exploration program. Although actual annual capital expenditures may change considerably with industry conditions and success, we currently estimate spending approximately $300 million for around 60 exploration, appraisal and development wells, and various new facilities and facility upgrades in 2005. Marketing -- In Australia during 2004, we agreed to terms on four new gas sales contracts, increased our reserve commitment in two active contracts, and formalized an agreement to increase 2005 daily rates into two other active contracts. In aggregate, we committed an additional 130 Bcf of gas (gross) for delivery. Under the largest new contract, we will supply more than 77 Bcf of gas (gross) over a 10-year period commencing July 6 2005. As of December 31, 2004, Apache had a total of 27 active gas contracts with expiration dates ranging from 2005 to 2026. Apache's net sales during 2005 are expected to climb with the initiation of delivery into the Burrup Fertilizer contract at a net rate of 47 MMcf of gas per day. 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. Apache realized an average price of US$1.65 per Mcf for gas sold in Australia in 2004. 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 2003, we established a new core area in the North Sea with our acquisition of the Forties Field. First discovered in 1970, the Forties has been one of the most productive fields in the North Sea. In 2004, the region generated $472 million of production revenue, averaged 53,000 b/d of production and accounted for nine percent of our year-end estimated proved reserves. Although actual annual capital expenditures may change considerably with industry conditions and success, we currently estimate spending approximately $400 million on 20 wells and continuation of facility upgrades to increase the overall efficiency of the platforms. Marketing -- Concurrent with the acquisition of the North Sea properties, the Company entered into a separate crude oil physical sales contract with BP. The contract provided for BP to market all of the Company's equity crude oil through December 31, 2004. A portion of the crude oil (25,000 b/d through January 31, 2004 and 40,000 b/d for the remainder of the term) was sold at fixed prices. The balance of the crude oil was sold at prevailing market prices. Beginning in 2005, the Company entered into two new term contracts for the physical sale of our crude at prevailing market prices, which fluctuate with market conditions. In addition to receiving a higher value than Dated-Brent for the Forties production, we also receive a premium for committing to a longer term sales agreement. OTHER INTERNATIONAL We have exploration and production interests offshore China and in Argentina. During 2003, we ceased operations in Poland. In August 2003, first production came on stream from our interests in the Zhao Dong block in Bohai Bay, China. We are the operator, with a 24.5 percent interest, of the Zhao Dong Block pursuant to a production sharing contract through 2023. Fourth quarter 2004 average net production of 9,000 barrels per day was about 13 percent higher than the comparable prior-year period. In 2004, our Chinese interests produced $91 million of production revenue from over 2.8 MMbbls of production. Since production began, our portion of the production has been exported to international markets at prevailing market prices. Beginning in March 2005, we will sell our equity crude oil into the domestic Chinese market, pursuant to term contracts at market prices for oil imported into China. Although actual capital expenditures may change considerably with industry conditions and success, we currently estimate spending approximately $20 million on new wells, recompletions and facility upgrades during 2005. In 2001, we acquired exploration and production assets from Fletcher Challenge and Anadarko in Argentina. After these transactions, we hold interests in a small number of blocks in Argentina's Neuquen Basin. We are the operator with a 100 percent interest in two blocks and hold smaller interests in three non-operated blocks. For 2004, these interests represented under one percent of our estimated proved reserves and generated small amounts of production and revenue. All of our production is currently sold under term arrangements into the domestic market under prevailing market prices which are subject to regulatory caps. Our total net acreage position in Argentina is 321,000 developed acres at December 31, 2004. Although actual capital expenditures may change considerably with industry conditions and success, we currently estimate spending approximately $20 million to drill new wells in Argentina. 7 SIGNIFICANT ACQUISITIONS ACQUISITION FROM ANADARKO On August 20, 2004, Apache signed a definitive agreement to acquire all of Anadarko's Gulf of Mexico-Outer Continental Shelf properties (excluding certain deepwater properties) for $537 million, subject to normal post-closing adjustments, including preferential rights. The transaction was effective as of October 1, 2004, and included interests in 74 fields covering 232 offshore blocks (approximately 664,000 acres) and 104 platforms. Eighty-nine of the blocks were undeveloped at the time of the acquisition. Apache operates 49 of the fields comprising approximately 70 percent of the production. Prior to Apache's purchase from Anadarko, Morgan Stanley Capital Group, Inc. (Morgan Stanley) paid Anadarko $646 million to acquire an overriding royalty interest in these properties. For a complete discussion of this transaction, please refer to Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, Results of Operations "Acquisitions and Divestitures" and Note 2, Acquisitions and Divestitures of Item 15 in this Form 10-K. ACQUISITION FROM EXXONMOBIL During the third quarter of 2004, Apache entered into separate arrangements with ExxonMobil that provided for property transfers and joint operating and exploration activity across a broad range of prospective and mature properties in (1) Western Canada, (2) West Texas and New Mexico, and (3) onshore Louisiana and the Gulf of Mexico-Outer Continental Shelf. Apache's participation included cash payments of approximately $347 million, subject to normal post closing adjustments. For a complete discussion of this transaction, please refer to Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, "Results of Operations, Acquisitions and Divestitures" and Note 2, Acquisitions and Divestitures of Item 15 in this Form 10-K. DRILLING STATISTICS Worldwide, in 2004, we participated in drilling 1,913 gross wells, with 1,735 (90.7 percent) completed as producers. We also performed over 1,836 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: 21 in the U.S. (12.88 net); six in Canada (six net); 14 in Egypt (12.98 net); one in Australia (0.6 net); and two in Argentina (two net). 8 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 ---------- ---- ----- ---------- ----- ------- ---------- ----- ------- 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 China.................... -- -- -- 3.7 .3 4.0 3.7 .3 4.0 Argentina................ -- -- -- 1.2 -- 1.2 1.2 -- 1.2 ---- ---- ----- ------- ----- ------- ------- ----- ------- Total............. 23.5 27.8 51.3 1,416.6 118.3 1,534.9 1,440.1 146.1 1,586.2 ==== ==== ===== ======= ===== ======= ======= ===== ======= 2003 United States............ 2.2 -- 2.2 133.6 18.3 151.9 135.8 18.3 154.1 Canada................... 57.3 25.3 82.6 742.8 34.8 777.6 800.1 60.1 860.2 Egypt.................... 15.5 5.2 20.7 76.2 6.0 82.2 91.7 11.2 102.9 Australia................ 8.4 10.8 19.2 2.3 -- 2.3 10.7 10.8 21.5 North Sea................ -- -- -- -- -- -- -- -- -- China.................... -- -- -- 6.1 -- 6.1 6.1 -- 6.1 Other International...... -- .6 .6 .3 -- .3 .3 .6 .9 ---- ---- ----- ------- ----- ------- ------- ----- ------- Total............. 83.4 41.9 125.3 961.3 59.1 1,020.4 1,044.7 101.0 1,145.7 ==== ==== ===== ======= ===== ======= ======= ===== ======= 2002 United States............ 3.0 3.5 6.5 92.8 17.1 109.9 95.8 20.6 116.4 Canada................... 25.9 10.1 36.0 714.2 20.4 734.6 740.1 30.5 770.6 Egypt.................... 7.7 7.0 14.7 32.3 6.0 38.3 40.0 13.0 53.0 Australia................ 6.3 7.6 13.9 1.3 -- 1.3 7.6 7.6 15.2 Other International...... -- -- -- -- -- -- -- -- -- ---- ---- ----- ------- ----- ------- ------- ----- ------- Total............. 42.9 28.2 71.1 840.6 43.5 884.1 883.5 71.7 955.2 ==== ==== ===== ======= ===== ======= ======= ===== =======
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, 2004, is set forth below:
GAS OIL TOTAL --------------- -------------- ---------------- GROSS NET GROSS NET GROSS NET ------ ----- ----- ----- ------ ------ Gulf Coast..................................... 1,161 831 1,158 790 2,319 1,621 Central........................................ 2,635 1,350 4,907 2,882 7,542 4,232 Canada......................................... 6,169 5,363 2,298 945 8,467 6,308 Egypt.......................................... 28 27 300 287 328 314 Australia...................................... 7 5 41 22 48 27 North Sea...................................... -- -- 60 58 60 58 China.......................................... -- -- 20 5 20 5 Argentina...................................... 20 6 39 24 59 30 ------ ----- ----- ----- ------ ------ Total................................... 10,020 7,582 8,823 5,013 18,843 12,595 ====== ===== ===== ===== ====== ======
9 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 and average sales prices for each of the countries where we have operations.
PRODUCTION AVERAGE AVERAGE SALES PRICE --------------------------- LEASE --------------------------------- OIL NGLS GAS OPERATING OIL NGLS GAS YEAR ENDED DECEMBER 31, (MBBLS) (MBBLS) (MMCF) COST PER BOE (PER BBL) (PER BBL) (PER MCF) - ----------------------- ------- ------- ------- ------------ --------- --------- --------- 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 China.................. 2,775 -- -- 3.89 32.88 -- -- Argentina.............. 207 -- 1,394 6.46 32.89 -- .65 ------ ----- ------- ----- ------ ------ ----- Total............. 84,736 3,973 452,049 $5.73 $35.24 $26.13 $4.91 ====== ===== ======= ===== ====== ====== ===== 2003 United States.......... 25,332 2,766 242,782 $5.14 $27.48 $21.70 $5.22 Canada................. 9,205 571 116,263 5.41 29.06 19.25 4.69 Egypt.................. 17,356 -- 41,447 3.40 27.64 -- 4.18 Australia.............. 11,165 -- 40,537 4.05 29.87 -- 1.44 North Sea.............. 10,680 -- 626 11.94 25.40 -- 2.77 China.................. 1,019 -- -- 5.18 26.33 -- -- Argentina.............. 211 -- 2,607 5.76 29.23 -- .47 ------ ----- ------- ----- ------ ------ ----- Total............. 74,968 3,337 444,262 $5.27 $27.76 $21.28 $4.61 ====== ===== ======= ===== ====== ====== ===== 2002 United States.......... 19,348 2,442 183,708 $5.21 $25.31 $15.29 $3.15 Canada................. 9,205 641 120,210 3.83 23.46 12.41 2.74 Egypt.................. 15,977 -- 44,769 2.95 24.65 -- 3.71 Australia.............. 11,082 -- 42,998 3.06 25.17 -- 1.28 Other International.... 225 -- 2,656 2.58 23.90 -- .42 ------ ----- ------- ----- ------ ------ ----- Total............. 55,837 3,083 394,341 $4.12 $24.78 $14.69 $2.87 ====== ===== ======= ===== ====== ====== =====
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.................................. 1,752,700 1,110,449 2,953,594 1,757,512 Canada......................................... 3,857,522 2,833,499 2,737,015 1,998,702 Egypt.......................................... 12,998,891 7,283,878 1,304,750 1,219,328 North Sea...................................... 564,845 433,485 29,924 28,579 Australia...................................... 9,273,720 4,983,840 527,450 307,290 China.......................................... 840 206 5,911 1,448 Poland......................................... 473,469 355,252 -- -- Argentina...................................... -- -- 500,549 321,231 ---------- ---------- --------- --------- Total Company............................. 28,921,987 17,000,609 8,059,193 5,634,090 ========== ========== ========= =========
Apache's operations in Poland ceased in 2003 and remaining acreage was fully relinquished in early 2005. 10 ESTIMATED PROVED RESERVES AND FUTURE NET CASH FLOWS As of December 31, 2004, Apache had total estimated proved reserves of 932 MMbbls of crude oil, condensate and NGLs and 6.0 Tcf of natural gas. Combined, these total estimated proved reserves are equivalent to 1.94 billion barrels of oil equivalent or 11.6 Tcf of natural gas. The company's estimated reserves grew for the 19th consecutive year. The Company's estimates of proved reserves and proved developed reserves as of December 31, 2004, 2003, and 2002, 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 14, 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. 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. 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 annually, 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 the 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 insure forecasts of operating expenses, netback prices, production trends and development timing are reasonable. 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. During this review, they prepare independent projections for each reviewed property and determine if the Company's estimates are within engineering tolerance by geographical area. The independent reviews typically cover a large percentage of major value fields, international properties and new wells drilled during the year. During 2004, 2003, and 2002, their review covered 79, 78 and 68 percent of the Apache's estimated reserve value, respectively. RISK FACTORS RELATED TO OUR BUSINESS AND OPERATIONS 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. 11 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 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, blow-outs 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 12 remainder. However, even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it 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 (see above). 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 DOMESTIC GOVERNMENTAL RISKS THAT MAY IMPACT OUR OPERATIONS Our domestic operations have been, and at times in the future may be, affected by political developments and by federal, state 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 59 percent of our oil, NGLs and natural gas production in 2004 was outside the United States, and approximately 56 percent of our estimated proved oil and gas reserves at December 31, 2004 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 twenty-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. Actions of the United States government through tax and other legislation, executive order and commercial restrictions can adversely affect our operating profitability overseas, as well as in the U.S. 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. 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 13 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. In October 2003, Apache was issued a Findings of Violation and Order for Compliance (an "Administrative Order") by the United States Environmental Protection Agency (EPA), which cited certain paperwork administrative errors and effluent violations reported by Apache during the period May 1, 1998 to June 30, 2003, as part of our offshore discharge permit monitoring. Apache signed a Consent Agreement and Final Order (CAFO) to pay a monetary penalty of $21,000 and undertake a Supplemental Environmental Project (SEP) with an estimated cost of $94,500. The SEP Project is underway and is expected to be completed by the March 31, 2005, deadline imposed by the EPA. We are waiting for the EPA to set the effective date of the CAFO and will pay the $21,000 penalty within 30 days of that date. We maintain insurance coverage, which we believe is customary in the industry, although we are not fully insured against all environmental risks. As of December 31, 2004, we had an accrued liability of $11 million for environmental remediation. We have not incurred any material environmental remediation costs in any of the periods presented and 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, 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 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 14 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. INVESTORS IN OUR SECURITIES MAY ENCOUNTER DIFFICULTIES IN OBTAINING, OR MAY BE UNABLE TO OBTAIN, RECOVERIES FROM ARTHUR ANDERSEN WITH RESPECT TO ITS AUDITS OF OUR FINANCIAL STATEMENTS On March 14, 2002, our previous independent public accountant, Arthur Andersen LLP (Arthur Andersen), was indicted on federal obstruction of justice charges arising from the federal government's investigation of Enron Corp. On June 15, 2002, a jury returned with a guilty verdict against Arthur Andersen following a trial. As a public company, we are required to file with the SEC periodic financial statements audited or reviewed by an independent public accountant. On March 29, 2002, we decided not to engage Arthur Andersen as our independent auditors, and engaged Ernst & Young LLP (Ernst & Young) to serve as our new independent auditors for 2002. Ernst & Young also served as our independent public accountants in 2003 and 2004. However, included in this annual report on Form 10-K are financial data and other information for 2001 that were audited by Arthur Andersen. Investors in our securities may encounter difficulties in obtaining, or be unable to obtain, from Arthur Andersen with respect to its audits of our financial statements, relief that may be available to investors under the federal securities laws against auditing firms. EMPLOYEES On December 31, 2004, we had 2,642 employees. None of our employees are subject to collective bargaining agreements. 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 2004, we maintained regional exploration and/or production offices in Tulsa, Oklahoma; Houston, Texas; Calgary, Alberta; Cairo, Egypt; Perth, Western Australia; Aberdeen, Scotland; Beijing, China; 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, "Liquidity and Capital Resources" and Note 10, Commitments and Contingencies, "Other Commitments and Contingencies, Operating Leases and Other Commitments" of Item 15 in this Form 10-K. TITLE TO INTERESTS We believe that our title to 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 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, 15 easements and restrictions, none of which detract substantially from the value of the interests or materially interfere with their use in our operations. ITEM 3. LEGAL PROCEEDINGS See the information set forth in Note 10, Commitments and Contingencies of Item 15 and Items 1 and 2, Business and Properties, "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. PART II ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS During 2004, 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 2004 and 2003. Prices were obtained from The New York Stock Exchange, Inc. Composite Transactions Reporting System; however, the per share prices and dividends shown in the following table have been adjusted to reflect the two-for-one stock split, which is described below. Per share prices and quarterly dividends shown below have been rounded to the indicated decimal place.
2004 2003 ------------------------------------- ------------------------------------- PRICE RANGE DIVIDENDS PER SHARE PRICE RANGE DIVIDENDS PER SHARE --------------- ------------------- --------------- ------------------- HIGH LOW DECLARED PAID HIGH LOW DECLARED PAID ------ ------ --------- ------- ------ ------ --------- ------- First Quarter........... $43.49 $36.79 $.0600 $.0600 $32.15 $26.26 $.0500 $.0475 Second Quarter.......... 45.99 38.53 .0600 .0600 34.60 28.13 .0500 .0500 Third Quarter........... 57.00 42.45 .0800 .0600 35.04 30.41 .0600 .0500 Fourth Quarter.......... 55.16 47.77 .0800 .0800 41.68 34.05 .0600 .0600
The closing price per share of our common stock, as reported on the New York Stock Exchange Composite Transactions Reporting System for February 28, 2005, was $62.88. At February 28, 2005, there were 328,095,581 shares of our common stock outstanding held by approximately 8,000 shareholders of record and approximately 226,000 beneficial owners. We have paid cash dividends on our common stock for 40 consecutive years through December 31, 2004. 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" for each 2.310 outstanding shares of common stock (adjusted for subsequent stock dividends and two-for-one stock split) that the stockholder owned. 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. On December 18, 2002, our board of directors declared a five percent dividend on our shares of common stock payable in common stock on April 2, 2003 to shareholders of record on March 12, 2003. Pursuant to the terms of the declared five percent stock dividend, we issued 15,736,496 shares (adjusted for the 2003 stock split) of our common stock on April 2, 2003 to the holders of the 307,819,628 shares of common stock outstanding on March 12, 2003. No fractional shares were issued in connection with the stock dividend and we made cash payments totaling approximately $1,437,000 in lieu of fractional shares. On January 22, 2003, in conjunction with the pending acquisition from BP, the Company completed the public offering of 19.8 million shares (adjusted for the stock split) of Apache common stock, including 16 2.6 million shares (adjusted for the stock split) for the underwriters' over-allotment option, at $29.05 per share. Net proceeds after placement fees totaled approximately $554 million. The proceeds were used to repay indebtedness under our commercial paper program and money market lines of credit and to invest in short-term treasury-only money market funds and treasury notes to hold funds for the $1.3 billion acquisition from BP. On September 11, 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 2005 annual meeting of stockholders which is incorporated herein by reference. 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, 2004, which information has been derived from the Company's audited financial statements. Our financial statements for the years 2000 and 2001 were audited by Arthur Andersen. For a discussion of the risks relating to Arthur Andersen's audit of our financial statements, please see discussion of issues related to Arthur Andersen in Item 1 and 2, Business and Properties, "Risk Factors Related to our Business and Operations" of this Form 10-K. 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, ---------------------------------------------------------------- 2004 2003 2002 2001 2000 ----------- ----------- ---------- ---------- ---------- (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) INCOME STATEMENT DATA Total revenues..................... $ 5,332,577 $ 4,190,299 $2,559,873 $2,809,391 $2,301,978 Income (loss) attributable to common stock..................... 1,663,074 1,116,205 543,514 703,798 693,068 Net income (loss) per common share: Basic............................ 5.10 3.46 1.83 2.44 2.54 Diluted.......................... 5.03 3.43 1.80 2.37 2.46 Cash dividends declared per common share............................ .28 .22 .19 .17 .09 BALANCE SHEET DATA Total assets....................... $15,502,480 $12,416,126 $9,459,851 $8,933,656 $7,481,950 Long-term debt..................... 2,588,390 2,326,966 2,158,815 2,244,357 2,193,258 Preferred interests of subsidiaries..................... -- -- 436,626 440,683 -- Shareholders' equity............... 8,204,421 6,532,798 4,924,280 4,418,483 3,754,640 Common shares outstanding.......... 327,458 324,497 302,506 287,917 285,596
For a discussion of significant acquisitions, 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 is an independent energy company whose principle business includes exploration, development and production of crude oil, natural gas and natural gas liquids. The Company operates in five core countries which, collectively, contained over 99 percent of the Company's 2004 year-end estimated proved reserves and accounted for over 98 percent of the Company's 2004 oil and gas production revenues. These principle operations are located in the United States, Canada, Egypt, Australia and offshore the United 17 Kingdom in the North Sea. The Company's smaller non-core operations are conducted offshore China and in Argentina. Apache adheres to a portfolio approach to provide diversity in terms of hydrocarbon mix (crude oil and natural gas), reserve life, geologic risk and geographic location. Our growth strategy focuses on economic growth through drilling, acquisitions, or a combination of both, depending on, among other things, cost levels and availability of acquisition opportunities. As we pursue growth, we continually monitor the capital resources available to us to meet our future financial obligations and liquidity needs. These obligations and needs are met with cash on hand, cash generated from our operations, unused committed borrowing capacity under our global credit facility, and the capital markets. The interest cost of debt and access to the equity markets are greatly influenced by the Company's ability to maintain both a strong balance sheet and generate ongoing operating cash flow. For these reasons, we strive to maintain a manageable debt load that is properly balanced with equity, and our single-A credit ratings. We are also cognizant of the costs to add reserves through drilling and acquisitions as well as the costs necessary to produce such reserves. Consequently, we closely monitor trends by operating area in drilling costs and the price at which properties are available for purchase, so that we may adjust our budgets accordingly and allocate funds to projects based on potential rate of return. We review operating costs monthly by operating area, on both an absolute dollar and per unit of production basis. We then compare these results to our historical norms after factoring in the impact from property acquisitions and changes in industry conditions in order to actively manage individual cost elements as appropriate. Given the inherent volatility and unpredictability of commodity prices and changing industry conditions, we frequently revise our forecasts and adjust our budgets accordingly. We entered 2004 with historically strong commodity prices which strengthened further during the year. Average realized prices for crude oil and natural gas increased 27 and seven percent, respectively, over 2003; a reflection of higher worldwide commodity prices. In addition, oil and natural gas production increased 13 and one percent, respectively, a result of acquisitions and successful exploration and development drilling programs. Increased production combined with high commodity prices drove the Company's attainment of several operational and financial milestones as noted below. - Our 2004 oil and gas production revenues totaled $5.3 billion, $1.1 billion higher than in 2003. - We generated earnings of $1.7 billion, 49 percent above our prior-year level. On a diluted share basis earnings rose $1.60 to $5.03 per diluted share. - Net cash provided by operating activities increased 19 percent from the prior year to $3.2 billion. - Production increased for 25 of the last 26 years. - 2004 year-end estimated proved reserves grew 17 percent from 2003 to 1.94 billion barrels of oil equivalent, marking the 19th consecutive year of reserve growth. - Exploration, development and acquisition expenditures totaled $3.4 billion in 2004. - Apache ended the year with debt at 24 percent of capitalization, down 2% from year-end 2003. - Fitch upgraded Apache's senior unsecured long-term debt rating from A- to A and Moody's and Standard and Poor's continue to rate Apache's unsecured long-term debt A3 and A-, respectively. - The Company increased its common stock dividend from an annual rate of 24 cents per share to 32 cents per share. The Company spent $1.1 billion on acquisitions in 2004, down $500 million from 2003, as acquisition expenditures typically vary from year to year based on the availability of opportunities that fit Apache's overall strategy. On the exploration and development front, Apache spent $2.3 billion, 61 percent more than last year, drilling a record number of wells. Significant highlights resulting from the Company's acquisition, exploration and development programs in each of our core areas follow. 18 U.S.: - Apache entered into two separate Agreements with Exxon Mobil Corporation (ExxonMobil) in the U.S. In West Texas and New Mexico we acquired properties in 23 mature producing oil and gas fields for $318 million and separately entered into a partnership to obtain additional interests in the properties. Additionally, we entered into joint exploration agreements to explore Apache's acreage in South Louisiana and the Gulf of Mexico-Outer Continental Shelf. For additional details regarding these agreements refer to the Acquisitions and Divestitures section of this Item 7. - Apache purchased interests in 74 fields covering 232 blocks and 104 platforms in the Gulf of Mexico from Anadarko Petroleum Corporation (Anadarko) for $532 million. The properties were subject to a pre-existing overriding royalty interest owned by Morgan Stanley Capital Group, Inc. (Morgan Stanley). For additional details regarding this transaction refer to the Acquisitions and Divestitures section of this Item 7. - The Company spent $755 million to drill over 400 wells on continued exploitation of its U.S. properties, including those purchased from BP p.l.c. (BP) and Shell Exploration and Production Company (Shell) in 2003 and the 2004 acquisitions noted above. The U.S. accounted for 41 percent of our 2004 equivalent production and 44 percent of the Company's estimated proved reserves at year-end 2004. CANADA: - The Company entered in to a farm-in agreement with ExxonMobil covering approximately 380,000 gross acres of undeveloped properties in the Western Canadian Province of Alberta, increasing our gross acreage to 6.5 million acres of prospective properties in Canada. By drilling at least 250 wells over a two-year period, which began in October 2004, Apache will receive a one-year extension in which to earn additional sections. Apache drilled 50 wells on this acreage in the fourth quarter of 2004. For additional details regarding this transaction refer to the Acquisitions and Divestitures section of this Item 7. - The Company emerged as the largest producer of coalbed methane in Canada with its drilling activities in the Nevis area. The North and South Grant Lands in the ExxonMobil farmout provide additional coalbed methane potential. - Apache spent $757 million on exploration and development in Canada, completing 1,211 of 1,313 wells for a success rate of 92 percent. Canada accounted for approximately 18 percent of our equivalent production in 2004 and 25 percent of the Company's estimated proved reserves at year-end 2004. EGYPT: - We continued to evaluate and develop the Qasr field, a July 2003 discovery, drilling several successful appraisal wells and one development well, and commencing commercial production on a limited basis in September 2004. The appraisal wells confirmed the overall seismically-defined structure of the field and our original estimated range of ultimately recoverable reserves. Following further development of the field and construction of pipeline facilities, we currently expect gross gas production of approximately 75 MMcf/d by third quarter 2005, ramping up to approximately 150 MMcf/d and 5,000 barrels of condensate per day around year-end 2005. The Qasr production will be sold under the terms of a 25-year Gas Sales Agreement, signed April 22, 2004, with the Egyptian General Petroleum Company (EGPC) covering up to 2.1 Tcf of natural gas from the Qasr field. Principle terms include supplying up to 300 MMcf/d to the Egyptian market. The pricing terms under the agreement are indexed to crude oil and include a minimum price of $1.50 per million British thermal units (MMBtu) and a maximum price of $2.65 per MMBtu. The Btu factor for our Egyptian gas generally ranges between 1,100 and 1,300 Btu per Mcf. - On May 20, 2004, we announced the Sheiba 18-3 discovery. It is the first commercial oil discovery in the eastern part of the Shell-operated North East Abu Gharadig Concession in Egypt's Western Desert. We are continuing to evaluate and explore this area. 19 - On June 23, 2004, we announced the Ozoris-4 well which identified new field pays in the Khalda Concession. The discovery of stratigraphically trapped gas-condensate in Upper Safa sands in the Ozoris-4 opens up a large new play in the Shushan Basin, north of the Qasr high and west of the Khalda Ridge fields. - On August 19, 2004, we announced two gas discoveries, the Imhoptep-1X on the Khalda Offset Concession and the Mihos-1X well on the Matruh Concession, that began flowing into the Tarek gas plant allowing it to operate at full capacity of 100 MMcf/d. AUSTRALIA: - On January 6, 2004, we announced that the Thomas Bright-2 appraisal well in the John Brookes field of the Carnarvon Basin offshore Western Australia extended the boundary of the reservoir, thus increasing estimated gross recoverable reserves. All of the 628 Bcf of estimated proved reserves at John Brookes are dedicated to existing long-term contracts (also see Item 1 and 2, Business and Properties, "Operating Highlights -- Australia" in this Form 10-K for additional information on Apache's gas contracts in Australia). We expect to complete facility installation in mid-2005, with initial production commencing during the third quarter 2005. - On May 19, 2004, we announced the Stickle-1 well, our third wildcat discovery in the Exmouth Sub-Basin of the Carnarvon Basin offshore Western Australia. On July 13, 2004, we announced that our Ravensworth-2 appraisal well in the Exmouth Sub-Basin encountered an oil column 49 feet higher than we expected, extending the area of the field considerably farther north than we had mapped based on the July 2003 Ravensworth-1 well. Appraisal wells along with additional exploration drilling is currently scheduled for 2005. NORTH SEA: - Our focus in the North Sea was two-pronged: invest capital to improve field operating efficiency and undertake an active drilling program. During 2004, we drilled 12 successful wells and invested over $150 million in capital expenditures to improve operating efficiency, boosting fourth-quarter 2004 production to an average of 61,680 b/d, over 50 percent higher than the fourth quarter of 2003. Our year-end 2004 estimated reserves were balanced, with a 48 percent oil and 52 percent natural gas mix. This compares to 51 percent oil and 49 percent natural gas at the end of 2003. Estimated proved undeveloped reserves represented 32.7 percent of total estimated proved reserves for year-end 2004 compared to 28.5 percent at year-end 2003. The increase is primarily attributed to appraisal drilling in the Qasr field, expansion of our infill shallow-gas drilling programs in Canada, new gas contracts in Australia and a high percentage of undeveloped reserves in the Anadarko acquisition. Apache was challenged in 2004 by steadily increasing service and acquisition costs resulting from increased demand with high commodity prices. Service costs impacting both drilling and lease operating costs have grown significantly over the past year; including rig rates, drill pipe costs, chemical costs and the costs of power and fuel. The Company reviews these costs for each core area on a routine basis and pursues alternatives in maintaining efficient levels of costs and expenses. While we are encouraged by the current outlook for 2005, we will continue to monitor costs and unless drilling costs level out, we may act to reduce our drilling expenditures, as we did in 2001. This is especially true in the U.S. where reserve targets continue to decrease in size. Acquisition costs also increased, however Apache has developed approaches to complete prudent asset acquisitions even when prices are high by routinely hedging production from newly acquired assets in order to protect acquisition economics in the critical early years. We believe we are well positioned to pursue future acquisitions should the appropriate opportunities arise. The Company also experienced unfavorable foreign exchange rate movements in Canada, Australia and the U.K. in 2004 which impacted our lease operating and drilling costs. Refer to the "Costs" section of this Item 7, Management Discussion and Analysis of Financial Condition and Results of Operations, for further discussion of items impacting costs in 2004. 20 In July 2004, the Company signed an amendment agreement with the EGPC which, among other things, extended the term of the Khalda, Khalda West and Salam development leases through 2024. These development leases would have expired in 2011, 2012 and 2010, respectively. We also received a five-year extension on our Khalda Offset exploration acreage, with an option for an additional three-year extension. As part of this agreement and in conjunction with the Qasr 25-year Gas Sales Agreement discussed above, we agreed to re-price natural gas volumes in excess of 100 MMcf/d produced from the Khalda Concession development leases and future Khalda Offset development leases. Under the new pricing formula, Apache will receive a price indexed to crude oil, with a minimum of $1.50 per MMBtu and a maximum of $2.65 per MMBtu. Pricing for the first 100 MMcf/d remains subject to the original contract price, which is indexed to oil pricing, but without a minimum or maximum. The pricing for this first 100 MMcf/d continues until January 1, 2013, at which time all Khalda area gas will be priced at the new pricing formula. For 2004, Apache's price averaged $4.35 per Mcf, which was a blend of the old and new contracts. As discussed in Note 1, Summary of Significant Accounting Policies and Note 8, Capital Stock of Item 15 in this Form 10-K, Apache's share price exceeded the first threshold ($43.29) under its 2000 Share Appreciation Plan on April 28, 2004. As such, the Company will issue to substantially all employees approximately 900,000 shares of its common stock, after minimum tax withholding requirements, in three annual installments. The first installment was issued in May 2004. The second and third installments will be issued in 2005 and 2006 to employees remaining with the Company during those periods. Also, on October 26, 2004, Apache's share price exceeded the second threshold ($51.95) of the Company's 2000 Share Appreciation Plan. Accordingly, Apache will issue approximately 2.2 million additional shares of its common stock, after minimum tax withholding requirements, in three equal installments. The first installment was issued in November 2004. The second and third installments will be issued in 2005 and 2006 to employees remaining with the Company during those periods. In February, 2005, the Company's Board of Directors voted to present to the stockholders of the Company for approval a new plan that provides incentives for employees to double the share price again, to $108, by the end of 2008, with an interim goal to be achieved by the end of 2007. If the goals are achieved, the shareholder value of the Company will grow by an additional $18 billion. On January 14, 2004, we completed the two-for-one common stock split approved by our board of directors in September 2003. Separately, on January 26, 2004, the NASDAQ Stock Market, Inc. approved Apache for trading on the NASDAQ National Market (NASDAQ), an intention we first announced on January 12, 2004. Our common stock is now listed on the NASDAQ as well as the New York Stock Exchange and Chicago Stock Exchange. RESULTS OF OPERATIONS This section includes a discussion of our 2004 and 2003 results of operations and provides insight into unique events and circumstances for each of the Company's six reportable segments. Apache's geographic segments include the United States, Canada, Egypt, Australia, the North Sea and Other International. These segments are primarily in the business of crude oil and natural gas exploration and production. Please refer to Note 13, Business Segment Information of Item 15 in this Form 10-K for segment information. ACQUISITIONS AND DIVESTITURES ExxonMobil During the third quarter of 2004, Apache entered into separate arrangements with ExxonMobil that provided for property transfers and joint operating and exploration activity across a broad range of prospective and mature properties in (1) Western Canada, (2) West Texas and New Mexico, and (3) onshore Louisiana and on the Gulf of Mexico-Outer Continental Shelf. Apache's participation included cash payments of approximately $347 million, subject to normal post closing adjustments. The following summarizes these transactions: ExxonMobil -- Western Canada In August 2004, Apache signed a farm-in agreement with ExxonMobil covering approximately 380,000 gross acres of undeveloped properties in the Western Canadian Province of Alberta. Under the agreement, Apache has the right to earn acreage sections by drilling an initial 21 well on each such section. By drilling at least 250 wells during the initial two-year earning period under the agreement, Apache will receive a one-year extension in which to earn additional sections. As to any sections earned by Apache, ExxonMobil will retain a 37.5 percent royalty on fee lands and 35 percent of its working interest on leasehold acreage. Under certain circumstances, ExxonMobil has the right to convert its retained 35 percent working interest into a 12.5 percent overriding royalty. In addition, during the terms of this agreement, Apache is required to carry ExxonMobil's retained working interest with respect to certain drilling, capping, completion, equipping and tie-in costs associated with wells drilled on leasehold acreage. ExxonMobil -- West Texas and New Mexico In September 2004, Apache acquired interests from ExxonMobil in 23 mature producing oil and gas fields in West Texas and New Mexico for $318 million. Apache separately contributed approximately $29 million into a partnership to obtain additional interests in the properties. ExxonMobil will retain interests in the properties through the partnership, including the right to receive, on certain fields, 60 percent of the oil proceeds above $30 per barrel in 2004, $29 per barrel in 2005 and $28 per barrel during the period from 2006 thru 2009. ExxonMobil -- Louisiana and Gulf of Mexico-Outer Continental Shelf Also in September 2004, Apache and ExxonMobil entered into joint exploration agreements to explore Apache's acreage in South Louisiana and the Gulf of Mexico-Outer Continental Shelf. The agreements provide for an initial term of five years, with the potential for an additional five years based on expenditures by ExxonMobil. Pursuant to the agreement covering South Louisiana, Apache leased 50 percent of its interests below certain producing or productive formations in the acreage to ExxonMobil, subject to retention of a 20 percent royalty interest. Pursuant to the agreement covering the Gulf of Mexico-Outer Continental Shelf, no assignments will be made until a prospect has been proposed and the initial well has been drilled. Apache will retain all rights in each prospect above certain producing or productive formations and further will retain a three percent overriding royalty interest in any property assigned to ExxonMobil. See Note 2, Acquisitions and Divestitures of Item 15 in this Form 10-K for a complete discussion of those transactions. Anadarko On August 20, 2004, Apache signed a definitive agreement to acquire all of Anadarko Gulf of Mexico-Outer Continental Shelf properties (excluding certain deepwater properties) for $537 million, subject to normal post-closing adjustments, including preferential rights. The transaction was effective as of October 1, 2004, and included interests in 74 fields covering 232 offshore blocks (approximately 664,000 acres) and 104 platforms. Eighty-nine of the blocks were undeveloped at the time of the acquisition. Apache operates 49 of the fields comprising approximately 70 percent of the production. Prior to Apache's purchase from Anadarko, Morgan Stanley paid Anadarko $646 million to acquire an overriding royalty interest in these properties. Anadarko's sale of an overriding royalty interest to Morgan Stanley is commonly known in the industry as a volumetric production payment (VPP), the obligations of which Apache assumed along with its subsequent purchase. Under the terms of the VPP, Morgan Stanley is to receive a fixed volume of oil and natural gas production (20 MMboe) over four years beginning in October 2004. The VPP represents a non-operating interest in the properties that is free of all costs of operations and production. Morgan Stanley is entitled to first production and may receive up to 90 percent of the production from the assets encumbered by the VPP in any given month to satisfy these deliverables. However, Morgan Stanley has no right to look to other assets or production of Apache. The VPP is scheduled to terminate on August 31, 2008, but may be extended if all scheduled VPP volumes have not been delivered to Morgan Stanley and the properties are still producing. The VPP includes restrictions on the Company's ability to sell the properties subject to the VPP or resign as operator of VPP properties it currently operates. Upon termination of the VPP, all rights, titles and interests revert back to Apache. Apache does not record the reserves and production volumes attributable to the VPP. The strategic rationale for Apache buying these assets burdened by a volumetric production payment is several fold. First, because Morgan Stanley gets their production first and Apache receives the remainder, Morgan Stanley is paying substantially more per boe, thereby significantly reducing Apache's cost per unit. Second, although Morgan Stanley's priority call on production leaves Apache with more risk, in exchange we 22 retain all the upside associated with finding more reserves on the acquired properties than anticipated at the time of the acquisition. This is a risk/reward scenario with which we are comfortable and that plays to our long history of adding value to numerous acquired properties through proactive operations. Third, our experience is that invariably we earn higher rates of return from drilling and related activities than we do from acquisitions. Yet acquisitions bring an inventory of drilling and exploitation opportunities. Because Morgan Stanley paid Anadarko more than Apache for proved reserves, a higher percentage of Apache's investment will be concentrated in the higher risk but generally higher reward, future drilling activity. As a final note, Morgan Stanley, while having less risk, is not risk free. In the event that the properties purchased by Apache are insufficient to deliver the volumes sold to Morgan Stanley, there is no recourse to any properties other than those acquired from Anadarko. See the Capital Resources and Liquidity section of this item for further discussion of VPPs. The $537 million purchase price agreed to in the definitive agreement was subsequently adjusted for the exercise of preferential rights by third parties and other normal post-closing adjustments. After adjusting for these items, Apache paid $532 million for the properties and recorded estimated proved reserves of 60 MMboe, of which 50 percent is natural gas. In addition, an $84 million liability for the future cost to produce and deliver the VPP volumes was recorded by the Company. This liability will be amortized as the volumes are produced and delivered to Morgan Stanley. Apache also recorded abandonment obligations for the properties of approximately $134 million and other obligations assumed from Anadarko in the amount of $27 million. Apache allocated $122 million of the purchase price to unproved property. The purchase price was funded by borrowings under the Company's commercial paper program. 2003 Acquisitions In 2003, we spent $1.6 billion on oil and gas acquisitions, adding 267 MMboe to our reserve base. The preponderance of our 2003 acquisition activity was focused in the North Sea and Gulf of Mexico. In January 2003, we agreed to purchase from BP the North Sea Forties Field offshore the United Kingdom and properties in the Gulf of Mexico. The BP purchase, representing 72 percent of our 2003 acquisition capital expenditures, established a new international core area and augmented our Gulf of Mexico portfolio. In July 2003, we consummated a deal with Shell adding additional oil and gas fields on the outer Continental Shelf of the Gulf of Mexico. Apache recorded 27.4 MMboe of reserves from the Shell acquisition, with interest in 26 fields and two onshore gas plants. The balance of our 2003 activity involved smaller acquisitions in Australia and North America. In association with the BP acquisition, Apache agreed to sell all of the production from the North Sea properties to BP for a two-year period ending December 31, 2004 at a combination of fixed and market sensitive prices pursuant to a contract entered into in connection with the North Sea purchase agreement. To protect the acquisition economics on the Gulf of Mexico properties acquired from BP we hedged prices on a substantial portion of the oil production for a 12-month period ending January 31, 2004, and a substantial portion of the gas production for the first two years. Prior to Apache's transaction with Shell, Morgan Stanley paid Shell $300 million to acquire an overriding royalty interest in a portion of the reserves to be produced and delivered under a VPP agreement. Under the terms of the VPP obligation which Apache assumed, Morgan Stanley is to receive a total of 11.4 MMboe of production from the properties over the period from August 2003 through October 2007. Morgan Stanley is entitled to first production and may receive up to 90 percent of the production from the assets encumbered by the VPP, but Morgan Stanley may look only to the acquired properties for delivery of the scheduled volumes. The VPP may be extended beyond October 2007 if all scheduled VPP volumes have not been delivered to Morgan Stanley and the acquired properties are still producing. The VPP is a non-operating interest free of all costs associated with operations and production. As a result of this VPP obligation, Apache recorded a $60 million liability for the future cost to produce and deliver volumes subject to the VPP. This liability is being amortized as the volumes are produced and delivered to Morgan Stanley. Apache does not record the reserves and production volumes attributable to the VPP. 23 Our acquisitions help maintain diversity in terms of hydrocarbon product (oil or gas), geologic risk and geographic location. As shown in Note 14, Supplemental Oil and Gas Disclosures (Unaudited) of Item 15 in this Form 10-K, our North American 2004 and 2003 year-end reserves were 70 percent of total reserves. Our 2004 North American average daily production as a percent of our total production decreased to 59 percent from 64 percent in 2003. While the U.S., a highly stable political environment, remains our largest producing core area, Apache will continue to evaluate acquisition opportunities in existing core areas and in new areas should they arise. We routinely evaluate our property portfolio and divest those that are marginal or no longer fit into our strategic growth program. We divested $4 million, $59 million and $7 million of properties during 2004, 2003 and 2002, respectively. 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. 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 world-wide 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. However, throughout 2004 the quality differential between prices we received for our North American sour crude oil compared to the NYMEX index prices widened, with a substantial increase in the fourth quarter of 2004. These quality differentials, which impacted approximately 30 percent of our North American production, occurred largely because OPEC produced more sour crude to satisfy rising world demand, while worldwide sour crude refining capacity remained the same. This excess in sour crude supply over the refining capacity created competition between the producers driving a deeper discount for sour crude. In the fourth quarter, we received an average of $41.00 per barrel for sour crude, approximately $5.00 less than we received for our sweet crude. Apache primarily sells its natural gas into three markets: 1) North America, which has a common market and where production is currently in short supply relative to demand creating a volatile pricing environment; 2) Australia, which has a local market with limited demand and infrastructure and generally long-term fixed prices; and 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, a portion of which is subject to a minimum floor price and maximum ceiling price. The current outlook for 2005 indicates that the sour crude quality differentials while narrowing somewhat, will remain above historical averages. All of our North Sea production will trade at market prices, following expiration on December 31, 2004, of a fixed-price contract on 40,000 b/d. For specific marketing arrangements by segment, please refer to Item 1 and 2. Business and Properties of this Form 10-K. 24 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 Price 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 FOR THE YEAR ENDED DECEMBER 31, DECEMBER 31, ------------------------ ------------------------ 2004 2003 2002 2004 2003 2002 ---- ---- ---- ---- ---- ---- United States....................................... 32% 33% 35% 58% 62% 51% Canada.............................................. 12% 13% 16% 29% 27% 29% --- --- --- --- --- --- North America....................................... 44% 46% 51% 87% 89% 80% Egypt............................................... 24% 23% 29% 10% 8% 15% Australia........................................... 13% 16% 20% 3% 3% 5% North Sea........................................... 16% 13% -- -- -- -- Other International................................. 3% 2% -- -- -- -- --- --- --- --- --- --- Total........................................ 100% 100% 100% 100% 100% 100% === === === === === ===
Crude Oil Contribution In 2004, oil revenues from areas outside the U.S. rose slightly to 68 percent of consolidated oil revenues, up from 67 percent in 2003. Lack of production growth reduced the U.S. overall contribution one percent to 32 percent of consolidated oil revenues. Canada's contribution also declined one percent to 12 percent on lower relative production growth. Egypt's share rose one percent to 24 percent as it saw both price gains and production growth. The North Sea's contribution increased three percent on both an increase in average daily production and a full year of revenues versus nine months in 2003. Australia's contribution fell three percent on lower production. In 2003, oil revenues from areas outside the U.S. rose to 67 percent of consolidated oil revenues, up from 65 percent in 2002. The increase is directly related to the acquisition of the North Sea properties and, to a much lesser extent, initial production from China. The percentage contribution from all other areas fell, reflecting the impact of revenues from the North Sea and China. Natural Gas Contribution A significant portion of the Company's natural gas revenues comes from our North American operations. In 2004, 87 percent of Apache's natural gas revenues came from North America of which 58 percent was from the U.S. and 29 percent was from Canada. The U.S. contribution decreased four percent from 2003, primarily because of production declines, the impact Hurricane Ivan 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 69 percent of Apache's U.S. 2004 production, down two percent from 2003, 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 two percent from 2003 resulting from three percent production growth and higher price gains relative to other areas. Egypt's contribution to total gas revenues increased to 10 percent from eight percent in 2003, on 21 percent production growth. Australia's contribution to 2004 natural gas revenues remained the same as 2003 at three percent. In 2003, 89 percent of Apache's natural gas revenues came from North America, 62 percent from the U.S. and 27 percent from Canada. The U.S. contribution rose 11 percent from 2002, primarily because of the properties acquired from BP and Shell in 2003, and properties acquired in South Louisiana in December 2002. Canada's contribution was down two percent from 2002 primarily because of the production growth in the U.S. Egypt's contribution to total gas revenues declined to eight percent from 15 percent in 2002. Egypt's total 25 natural gas revenues were relatively flat year-over-year, as higher natural gas prices were offset by lower net production. Australia's contribution to 2003 natural gas revenues declined to three percent from five percent in 2002. 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 YEAR ENDED DECEMBER 31, ------------------------------------ 2004 2003 2002 ---------- ---------- ---------- Revenues (in thousands): Natural gas............................................ $2,217,983 $2,046,625 $1,130,692 Oil.................................................... 2,986,208 2,081,283 1,383,749 Natural gas liquids.................................... 103,826 71,012 45,307 ---------- ---------- ---------- Total............................................... $5,308,017 $4,198,920 $2,559,748 ========== ========== ========== Natural Gas Volume -- Mcf per day: United States.......................................... 646,619 665,156 503,310 Canada................................................. 326,965 318,528 329,344 Egypt.................................................. 137,737 113,554 122,655 Australia.............................................. 118,108 111,061 117,802 North Sea.............................................. 1,871 1,714 -- Argentina.............................................. 3,808 7,144 7,276 ---------- ---------- ---------- Total............................................... 1,235,108 1,217,157 1,080,387 ========== ========== ========== Average Natural Gas Price -- Per Mcf: United States.......................................... $ 5.45 $ 5.22 $ 3.15 Canada................................................. 5.30 4.69 2.74 Egypt.................................................. 4.35 4.18 3.71 Australia.............................................. 1.65 1.44 1.28 North Sea.............................................. 5.53 2.77 -- Argentina.............................................. .65 .47 .42 Total............................................... 4.91 4.61 2.87 Oil Volume -- Barrels per day: United States.......................................... 67,872 69,404 53,009 Canada................................................. 25,305 25,220 25,220 Egypt.................................................. 52,183 47,551 43,772 Australia.............................................. 25,174 30,589 30,361 North Sea.............................................. 52,836 29,260 -- China.................................................. 7,583 2,791 -- Argentina.............................................. 566 579 617 ---------- ---------- ---------- Total............................................... 231,519 205,394 152,979 ========== ========== ==========
26
FOR THE YEAR ENDED DECEMBER 31, ------------------------------------ 2004 2003 2002 ---------- ---------- ---------- Average Oil Price -- Per barrel: United States.......................................... $ 38.75 $ 27.48 $ 25.31 Canada................................................. 38.57 29.06 23.46 Egypt.................................................. 37.35 27.64 24.65 Australia.............................................. 41.96 29.87 25.17 North Sea.............................................. 24.22 25.40 -- China.................................................. 32.88 26.33 -- Argentina.............................................. 32.89 29.23 23.90 Total............................................... 35.24 27.76 24.78 NGL Volume -- Barrels per day: United States.......................................... 8,268 7,578 6,691 Canada................................................. 2,588 1,565 1,756 ---------- ---------- ---------- Total............................................... 10,856 9,143 8,447 ========== ========== ========== Average NGL Price -- Per barrel: United States.......................................... $ 26.66 $ 21.70 $ 15.29 Canada................................................. 24.44 19.25 12.41 Total............................................... 26.13 21.28 14.69
Natural Gas Revenues Our 2004 natural gas revenues increased $171 million with a $.30 per Mcf increase in our average natural gas price realizations generating an additional $133 million of revenues. Higher production added the remaining $38 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. The additional revenues attributable to production were primarily generated in Egypt, where natural gas production increased 21 percent, reflecting the success of our drilling program. Canada and Australia also contributed to the increase in production revenues with production growth of three percent and six percent, respectively. Canada's increase is from new wells while Australia's increase was driven by higher customer demand and new contractual sales. Partially offsetting these additional production revenues was a three percent decrease in U.S. production. The lower U.S. production was focused in the Gulf Coast region and is related to the impact of Hurricane Ivan and natural decline in mature fields. Consolidated natural gas revenues increased $916 million in 2003, consistent with a $1.74 per Mcf increase in the average price realized for natural gas and a 13 percent increase in production. The price increase generated $686 million of revenues while production growth added another $230 million. U.S. production increased 32 percent, reflecting the impact from the 2003 BP and Shell acquisitions and the December 2002 South Louisiana acquisition. Offsetting the U.S. production growth were lower production in Egypt, Australia, and Canada, down seven percent, six percent, and three percent, respectively. The decline in Egypt related to gas production curtailment imposed by EGPC and scheduled plant shutdowns, while Australia experienced lower customer demand. Apache uses a variety of strategies to manage its exposure to fluctuations in natural gas prices, including fixed-price physical contracts and derivatives. Although a majority of our worldwide sales contracts are indexed to prevailing market prices, approximately nine percent of our 2004 and 2003 domestic natural gas production was subject to long-term, fixed-price physical contracts. The long-term, fixed-price physical contracts apply to a small portion of our U.S. future natural gas production and provide a measure of protection to the Company in the event of decreasing natural gas prices. These contracts negatively impacted our 2004 and 2003 realized prices by $.10 per Mcf and $.08 per Mcf, respectively. Additionally, substantially all of our natural gas production sold in Australia is subject to long-term fixed-price supply contracts. These contracts are periodically adjusted for changes in Australia's consumer price index and are also impacted by 27 changes in the value of the Australian dollar relative to the U.S. dollar. In 2004, we saw an increase in our realized prices primarily because of the stronger Australian dollar. Approximately 16 percent of our worldwide natural gas production was subject to financial derivative hedging for 2004 and 2003. Refer to Note 3, Hedging and Derivative Instruments of Item 15 in this Form 10-K for a summary of current derivative positions and terms. We also amortized unrealized gains and losses from derivative positions closed in October and November 2001, which had no impact on 2004 average realized prices. The following table shows the impact on average prices for these financial derivatives:
FOR THE YEAR ENDED DECEMBER 31, -------------------- 2004 2003 2002 ----- ----- ---- (PER MCF) Derivatives................................................. $(.20) $(.01) $ -- Amortization................................................ -- (.01) .04
Crude Oil Revenues Our 2004 consolidated oil revenues increased $905 million with a $7.48 per barrel increase in our average realized oil price generating an additional $561 million of revenues. A 13 percent growth in production added the remaining $344 million. The increase in production came from the North Sea, China and Egypt. North Sea production is up 23,576 b/d, with 53 percent of the increase reflecting additional production from new wells and operational enhancements. The balance of the North Sea increase results from reporting a full year of production in 2004 versus nine-months in 2003. A portion of the North Sea revenue was tied to an average $23.38 per barrel fixed-price sales contract entered into in at the time of the BP acquisition. This two-year contract expired at the end of 2004. See Note 2, Acquisitions and Divestitures of Item 15 in this Form 10-K for a discussion of the terms of this contract. Production in China, which commenced in July 2003, added 4,792 b/d on exploration and production activity and a full year of production. Egypt's production is up 4,632 b/d on exploration and production activity. These production increases were partially offset by lower production in the U.S. and Australia, down 1,532 b/d and 5,415 b/d, respectively. The U.S. decline is related to Hurricane Ivan, downtime, and natural decline in mature fields. Australia's decrease was driven by natural decline. Consolidated oil revenues increased $698 million in 2003 with a 34 percent increase in oil production generating an additional $531 million of revenues. The average crude oil realized price increased $2.98 per barrel, adding the remaining $167 million of oil revenues. Revenues from properties acquired in the North Sea accounted for over half of the oil revenue increase attributable to production. U.S. production increased 31 percent, primarily from the Gulf of Mexico BP properties and to a lesser extent from properties acquired from Shell and in South Louisiana in December 2002. Initial production from China and a nine percent increase in production from Egypt also contributed to the revenue gains. Apache also manages its exposure to fluctuations in crude oil prices using financial derivatives. Approximately four percent and 22 percent of our worldwide crude oil production was subject to financial derivative hedging for 2004 and 2003, respectively. Please refer to Note 3, Hedging and Derivature of Item 15 in this Form 10-K for a summary of current derivative positions and terms. We also continued to amortize unrealized gains and losses over the original production life of derivative positions closed in October and November 2001, which had no impact on 2004 average realized prices. The following table shows the impact on prices of these financial derivatives:
FOR THE YEAR ENDED DECEMBER 31, -------------------- 2004 2003 2002 ----- ----- ---- (PER BBL) Derivatives................................................. $(.21) $(.95) $ -- Amortization................................................ -- .03 .15
28 COSTS The tables below present a comparison of 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, ------------------------ ------------------------ 2004 2003 2002 2004 2003 2002 ------ ------ ------ ------ ------ ------ (IN MILLIONS) (PER BOE) Depreciation, depletion and amortization: Oil and gas property and equipment...... $1,149 $1,003 $ 784 $ 7.01 $ 6.59 $ 6.29 Other assets............................ 73 70 60 .44 .46 .48 Asset retirement obligation accretion..... 46 38 -- .28 .25 -- International impairments................. -- 13 20 -- .08 .16 Lease operating costs..................... 864 700 458 5.27 4.59 3.67 Gathering and transportation costs........ 82 60 38 .50 .40 .31 Severance and other taxes................. 94 122 67 .57 .80 .54 General and administrative expenses....... 173 138 105 1.06 .91 .84 China litigation.......................... 71 -- -- .43 -- -- Financing costs, net...................... 117 115 113 .71 .75 .91 ------ ------ ------ ------ ------ ------ Total................................ $2,669 $2,259 $1,645 $16.27 $14.83 $13.20 ====== ====== ====== ====== ====== ======
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). Full-cost DD&A expense of $1.1 billion, increased $146 million compared to 2003. Approximately 59 percent of the increase in absolute costs was related to higher production levels, mainly in the North Sea, Egypt and China. The balance was primarily attributable to higher drilling costs, as our 2004 DD&A rate increased $.42 to $7.01 per boe. The increase in per unit costs is primarily attributable to our North American operations where high commodity prices have led to increased demand for drilling services and thus higher drilling costs. Additionally, high commodity prices have increased the costs of properties available for acquisition and therefore, the cost of properties we acquired in 2004 were higher than our historical cost. A full year's production from China, which carries the second highest DD&A rate in the Company, also contributed to the increase in the worldwide rate. These increases were partially offset by a decrease in the DD&A rate in Egypt from a successful exploration and development program which added significant reserves through drilling at lower costs. Our 2003 full-cost DD&A expense of $1 billion increased $220 million compared to 2002. The majority of the increase in absolute costs was related to production increases following our acquisitions from BP and Shell in the Gulf of Mexico and from BP in the North Sea and first production in China. On a per unit basis, our DD&A rate in 2003 increased $.30 to $6.59 from $6.29 in 2002. The increase was driven by higher drilling 29 costs in Australia, Egypt and the U.S. and higher acquisition costs in the U.S. In addition, China and the North Sea contributed to the increase in per unit rates, with production reported for the first time in 2003 at higher DD&A rates than other regions. Depreciation of other assets increased $3 million in 2004, in line with our overall growth. 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 an 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. In 2002, we impaired $20 million in Poland ($12 million after-tax). In 2003, we impaired the final $13 million ($8 million after-tax) of unproved property costs in Poland. Goodwill became subject to a periodic fair-value-based impairment assessment in 2002. Goodwill totaled $189 million on December 31, 2004 and no impairment was recorded in either 2004 or 2003. For further discussion, see Note 1, Summary of Significant Accounting Policies of Item 15 in this Form 10-K. Lease Operating Costs Lease operating costs (LOE) are generally comprised of several components; direct operating costs, repair and maintenance costs, workover costs and ad valorem tax costs. LOE is driven in part by the type of commodity produced, the level of workover activity and the geographical location of the properties. Oil is inherently more expensive to produce than natural gas. Workovers continue to be an important part of our strategy enabling us to exploit our existing reserve base by accelerating production and taking advantage of high commodity prices. Repair and maintenance costs are higher on offshore properties and in areas with remote plants and facilities. Commodity prices and exchange rates also impact LOE. Historically, electricity, fuel and other service costs have risen in high commodity price environments, leading to an increase in industry-wide LOE. Rising per unit operating costs remained a challenge in 2004, especially in North America. The Company reviews production costs in each of its core areas on a monthly basis and pursues alternatives in maintaining efficient levels of costs. Fluctuations in exchange rates also impact the Company's LOE in Canada, Australia and the North Sea. The dollar has generally weakened against these currencies, particularly in 2004, increasing the impact of foreign exchange rates on the Company's per unit costs in these countries. The following discussion will focus on per unit operating costs as this is the most informative method of analyzing LOE trends. Acquisitions increase absolute LOE costs, but they do not necessarily increase per unit costs or lower margins. On a per unit/boe produced basis, 2004 LOE increased $.68 to $5.27 per boe. The increase was primarily attributable to an increase in industry-wide service costs in North America with higher commodity prices (see discussion in preceding paragraph), the increase in currency exchange rates in Canada, North Sea and Australia, and higher expense resulting from our incentive programs, primarily stock-based programs which we began expensing in 2003. Per unit costs were also negatively impacted by the combined impact of lost production and additional costs related to Hurricane Ivan in the Gulf of Mexico and higher repair and maintenance costs in Australia. These increases offset the impact of a $2.75 decline in the unit cost in the North Sea, where our investments to increase production and lower operating costs over the long-term are beginning to pay off. During 2003, the Company LOE per boe increased $.92 to $4.59, with all of the increase occurring outside the U.S. Half of the increase was attributable to our acquisition of the North Sea Forties field, which is located offshore, produces oil and carries a higher unit rate than our other core areas. Upon taking over operations, we performed multiple platform turnarounds and repair and maintenance projects aimed at increasing production efficiency and lowering operating costs over the long-term. The remainder of the increase was related to an increase in currency exchange rates, the impact of higher commodity prices in Canada, more workover activity in Egypt and higher repair and maintenance costs in Australia. The LOE rate 30 in the U.S. declined as the impact from the additional absolute costs associated with the acquisitions were more than offset by the incremental production. 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 or 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 China, we incur costs for barges to transport crude oil to onshore terminal facilities. In Egypt, our oil and natural gas production has historically been sold to EGPC under netback arrangements. Apache exported three inaugural cargoes of Egyptian crude oil in 2004 pursuant to netback arrangements with third parties. Future export cargoes may be sold under similar terms or Apache may arrange shipping and receive prices without transportation deductions. 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, ------------------ 2004 2003 2002 ---- ---- ---- (IN MILLIONS) U.S. ....................................................... $28 $21 $17 Canada...................................................... 31 28 21 North Sea................................................... 22 11 -- China....................................................... 1 -- -- --- --- --- Total Gathering and Transportation.......................... $82 $60 $38 === === ===
These costs are primarily related to the transportation of natural gas in our North American operations and crude oil in the North Sea. Transportation costs in the U.S. increased 33 percent on higher volumes transported under third-party transportation contracts, compared to the prior-year period. Canada's 2004 costs were 11 percent higher than 2003 because of an increase in third-party transportation rates and the impact of a weaker U.S. dollar. The North Sea's costs increased on production growth and a full year of production. In 2003, the increase in Canada primarily involved higher third-party transportation charges for gas transported from several fields, increased production volumes from 2002 acquisitions and transportation charges for crude oil as we began taking our oil "in-kind" and marketing it ourselves instead of selling it at the lease. The increase in the U.S. is related to the higher volumes transported under third-party transportation contracts, compared to the prior-year period. In the North Sea, these costs are related to the transportation of crude oil upon our entry to the region in April 2003. Severance and Other Taxes Severance and other taxes are comprised primarily of severance taxes on properties onshore and in state or provincial waters in the U.S. and Australia. In both 2004 and 2003, these severance taxes, which are generally based on a percentage of oil and gas production revenues, represented the majority of the total 31 severance and other taxes incurred. The other tax components are primarily made up of the Australian Petroleum Resources Rent Tax (PRRT), to which Apache first became subject in 2002, the Petroleum Revenue Tax (PRT) on the North Sea properties and the Canadian Large Corporation Tax, Saskatchewan Capital Tax, Saskatchewan Resource Surtax and Freehold Mineral Tax. Oil and gas production revenues generated from Egypt, Canada and the North Sea are not subject to severance taxes. The table below presents a comparison of these expenses.
FOR THE YEAR ENDED DECEMBER 31, ------------------ 2004 2003 2002 ---- ---- ---- (IN MILLIONS) Severance taxes............................................. $127 $ 77 $53 U.K. PRT.................................................... (61) 20 -- Canadian taxes.............................................. 23 20 10 Other....................................................... 5 5 4 ---- ---- --- Total Severance and Other Taxes............................. $ 94 $122 $67 ==== ==== ===
In 2004, severance and other taxes decreased 23 percent, or $28 million. Severance and other taxes in the U.S. increased $15 million, in line with higher production revenues. Australia's taxes increased $36 million as production from the Legendre field crossed a cumulative threshold, triggering an excise tax. U.K. PRT tax is based on revenues less qualifying operating costs and capital spending. Apache was in a PRT credit position for 2004 as deductible capital spending exceeded taxable cash flows from the Forties field. Canadian taxes increased $3 million on an increase in Freehold Mineral Taxes. In 2003, severance and other taxes increased 81 percent, or $54 million. Twenty million dollars of the increase is associated with PRT expense in the North Sea, where Apache began operating in April 2003. Canadian taxes increased $10 million as a result of currency exchange rate increases and higher prices in 2003, and a $2 million refund in 2002. U.S. and Australia severance taxes increased $17 million and $7 million, respectively, in line with higher production revenues. General and Administrative Expenses General and administrative expenses (G&A) of $1.06 per boe for 2004 increased $.15 per boe over 2003. Absolute costs increased $35 million, or 25 percent. Over $21 million, or 61 percent of the additional expense is related to the impact Apache's rising stock price had on stock-based compensation programs and incremental incentive compensation. The impact from the higher stock price stems from Apache's decision, effective January 1, 2003, to expense stock-based compensation plans (see Note 8, Capital Stock of Item 15 in this Form 10-K). Approximately $3 million, or 8 percent, of the increase is related to our new North Sea operations, with the first full year of operations in 2004. The balance of the increase was related to higher audit and tax fees, increased insurance premiums, and expansion of the Company's gas marketing group. General and administrative expenses of $.91 per boe for 2003 increased $.07 per boe over 2002. Absolute costs increased $34 million, or 32 percent. Over $11 million, or 34 percent, is associated with expensing compensation, including Stock Appreciation Rights (SARs), stock options, restricted stock and incremental incentive compensation. Approximately $9 million, or 28 percent, of the increase is related to our new North Sea operations. The balance of the increase was related to the Company's decision to increase its charitable contributions, expansion of the Company's new gas marketing group and transition costs incurred on acquisitions. Financing Costs, Net The major components of financing costs, net, include interest expense and capitalized interest. Net financing costs were slightly higher than in 2003. Gross interest expense decreased $1 million in 2004, a result of a lower average debt balance. This decrease was offset by a $2 million decrease in the amount of interest 32 capitalized, a result of a lower average unproved property balance. Our weighted-average cost of borrowing on December 31, 2004 was 6.1 percent compared to 6.4 percent on December 31, 2003. Net financing costs for 2003 increased $2 million compared to 2002 with a $13 million increase in expense largely offset by an increase in capitalized interest. Five million dollars of the increase is interest expense related to the write-off of unamortized fees triggered by the retirement of preferred interests of subsidiaries discussed below. The remaining $8 million of higher interest expense was attributable to a higher average debt balance in 2003 compared to 2002. Capitalized interest increased $12 million driven by a higher unproved property balance associated with acquisitions and an active drilling program. If net financing costs included distributions from Preferred Interests of Subsidiaries, net financing costs would have decreased by approximately $5 million. Provision for Income Taxes 2004 income tax expense of $993 million was $166 million or 20 percent higher than in 2003. The higher taxes were primarily associated with higher income driven by higher oil and gas production revenues in 2004. Our effective tax rate was 37.29 percent in 2004 compared to 43.02 percent in 2003. The 2003 effective tax rate included $172 million of additional deferred tax expense because of currency fluctuations compared to $58 million in 2004. 2003 income tax expense of $827 million was $482 million or 140 percent higher than the 2002. The higher taxes were primarily associated with higher income in 2003 and, to a lesser extent, a higher effective tax rate. Our effective tax rate increased primarily because of $172 million of additional deferred tax expenses resulting from currency fluctuations. The impact caused by currency fluctuations was partially offset by a $71 million reduction in deferred tax expense related to a reduction in Canadian federal statutory income tax rates. Our effective tax rate for 2003 was 43.02 percent compared to 38.34 percent for the prior year. 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, ------------------------ 2004 2003 2002 MILLIONS OF DOLLARS EXCEPT AS INDICATED ------ ------ ------ Current ratio............................................... 1.05 1.10 1.44 Net cash provided by operation activities................... $3,232 $2,706 $1,381 Total debt(1)............................................... 2,588 2,327 2,595 Shareholders' equity........................................ 8,204 6,533 4,924 Percent of total debt to capitalization(1).................. 24% 26% 35% Floating-rate debt/total debt(1)............................ 15% 6% 29%
(1) Year-end 2002 debt included $437 million of preferred interests of subsidiaries. The Company retired its preferred interests of subsidiaries in September 2003. 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 Related to Our Business and Operations," in this Form 10-K. Future success in maintaining 33 and growing reserves and production will be highly dependent on having adequate capital resources available, on our success in both exploration and development activities and on acquiring additional reserves. Our year-end reserve life index indicates an average decline of 8.5 percent per year. This projection is based on prices at year-end, except in those instances where future natural gas and oil sales are covered by physical contract terms providing for higher or lower amounts, estimates of investments required to develop estimated proved undeveloped reserves, costs and taxes reflected in our standardized measure in Note 14, 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. Apache's ability to access the debt capital market is supported by its investment grade credit ratings. 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 is 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. Apache's senior unsecured debt is currently rated investment grade by Moody's, Standard and Poor's and Fitch with ratings of A3, A- and A, respectively. The Company's ratio of current assets to current liabilities was 1.05 at December 31, 2004 compared to 1.10 at the end of last year. Year-end 2004 current receivable and payable balances increased by $450 million and $463 million, respectively, from December 31, 2003. The increase in current receivables was primarily attributable to the impact of higher commodities prices and increased production on receivables from the sale of oil and natural gas. In addition, current receivables include amounts collectible from insurance proceeds for lost production and physical damage resulting from Hurricane Ivan in the Gulf of Mexico in the fourth quarter of 2004. The increase in current payables is primarily attributable to an increase in trade payables because of an increased number of drilling and development projects in progress at the end of 2004 versus year-end 2003 and the impact of higher commodity prices and production on revenue payable to third party royalty and working interest owners. NET CASH PROVIDED BY OPERATING ACTIVITIES Apache's net cash provided by operating activities during 2004 totaled $3.2 billion, up from $2.7 billion in 2003. The increase in 2004 cash flow is attributed primarily to the significant increase in commodity prices. The Company's averaged realized oil and natural gas prices increased 27 and 7 percent, respectively; a reflection of higher worldwide commodity prices. Higher production also increased our 2004 cash flow. Oil and natural gas production increased 13 and one percent, respectively, a result of acquisitions and a successful drilling program. These increases were partially offset by higher production costs attributable to the effect of increased commodity prices, an increase in exchange rates in Canada, North Sea and Australia, costs related to Hurricane Ivan and increases in costs from our stock based employee incentive programs. The Company reviews production costs for each core area on a monthly basis and pursues alternatives in maintaining efficient levels of costs and expenses. For a more 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. 34 Apache's 2003 cash flows totaled $2.7 billion, an increase of 96 percent from 2002 cash flows of $1.4 billion. The increase was attributable primarily to higher oil and gas production revenues which were driven by increases in both production volumes and realized prices and partially offset by higher operating expenses. Oil and natural gas production increased 34 and 13 percent, respectively. The increase in oil production was primarily attributable to our acquisition of properties in the North Sea and first production from our China operations. The increase in natural gas production was primarily related to two significant acquisitions in the Gulf of Mexico, which offset declines in other core areas. Oil and natural gas prices increased 12 and 61 percent, respectively on higher worldwide commodity prices. Higher lease operating costs were primarily attributable to the acquisition of the North Sea properties, which carry a higher rate per unit than our other core areas, and where, upon taking over operations, we performed multiple platform turnarounds and repair and maintenance projects aimed at increasing production and lowering operating costs over the long-term. Outside of the United States, costs were higher with an increase in exchange rates and the impact of higher commodity prices in Canada, more workover activity in Egypt and higher repair and maintenance costs in Australia. For a more detailed discussion of commodity prices, production, operating costs and acquisitions please refer to the Results of Operations section of this Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations. 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 in the past. 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 During 2004, we continued to strengthen our financial flexibility and to build on the solid financial positions of previous years. We exited 2004 with a debt-to-capitalization ratio of 24 percent, a decrease of two percent from year-end 2003, with slightly higher debt offset by increases in equity resulting from earnings. At year-end 2004 the Company had long-term debt of $2.6 billion, $261 million higher than year-end 2003, as the Company's $3.4 billion in capital spending slightly exceeded internally generated cash flow. The Company's outstanding debt consisted of $396 million under our commercial paper program and uncommitted lines of credit and a total of $2.2 billion of other debt. This other debt included notes and debentures maturing in the years 2006 through 2096. Approximately $.3 million, $173 million, $.4 million, $497 million and $1.9 billion mature in 2006, 2007, 2008, 2009 and thereafter, respectively. During 2004, the Company maintained its senior unsecured long-term debt ratings of A3 from Moody's and A- from Standard and Poor's. In June 2004, Fitch upgraded Apache's senior unsecured long-term debt rating from A- to A. The Company has a $1.2 billion commercial paper program which enables Apache to borrow funds for up to 270 days at competitive interest rates. The commercial paper balances of $392 million and $130 million at December 31, 2004 and 2003, respectively, were classified as long-term debt in the accompanying consolidated balance sheet as the Company has the ability and intent to refinance such amounts on a long-term basis through either the rollover of commercial paper or available borrowing capacity under its U.S. credit facilities. If the Company is unable to issue commercial paper following a significant credit downgrade or dislocation in the market, the Company's U.S. credit facilities are available as a 100 percent backstop. The weighted-average interest rate for commercial paper was 1.79 percent in 2004 and 1.19 percent in 2003. As of December 31, 2004, available borrowing capacity under our credit facilities was $1.1 billion. We had $111 million in cash and cash equivalents on hand at December 31, 2004, an increase from $34 million at the prior year-end. On May 28, 2004, the Company's $750 million 364-day U.S. credit facility matured and was replaced with a new five-year credit facility which matures May 28, 2009. Also on this date, the Company amended its existing $450 million facility and its two existing $150 million facilities in order to make their terms consistent with the new five-year facility. Significant changes included raising the cross-default threshold, increasing 35 flexibility under the negative lien covenant and eliminating covenants which established minimum levels for tangible net worth and book values for assets of Apache and certain subsidiaries. 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, which approximated $775 million at December 31, 2004. 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, 2004. STOCK TRANSACTIONS The Company periodically uses access to equity capital markets to fund significant acquisitions. On January 22, 2003, in conjunction with the BP transaction, we completed a public offering of approximately 19.8 million shares of common stock, including 2.6 million shares for the underwriters' over-allotment option, for net proceeds of $554 million. The Company currently has no plans to access equity capital markets. The Company's board of directors approved a stock split and several stock dividends in 2003, 2002 and 2001; a reflection of their belief that we can reward our shareholders while remaining focused on our primary objective of building Apache to last by achieving profitable growth. On December 18, 2003, we announced that holders of our common stock approved an increase in the number of authorized common shares to 430 million from 215 million in order to complete a previously announced two-for-one stock split. The record date for the stock split was December 31, 2003 and the additional shares were distributed on January 14, 2004. On December 18, 2002, our Board of Directors declared a five percent stock dividend payable on April 2, 2003 to shareholders of record on March 12, 2003. As a result, in December 2002, we reclassified approximately $396 million from retained earnings to common stock and paid-in capital, which represents the fair market value at the date of declaration of the shares distributed. In 2003, at the date of the distribution, an additional $26 million was reclassified from retained earnings to common stock and paid-in capital. No fractional shares were issued and cash payments were made in lieu of fractional shares. On May 15, 2002, we completed the mandatory conversion of our Series C Preferred Stock into approximately 13.1 million common shares. OIL AND GAS CAPITAL EXPENDITURES The Company funded its exploration and production (E&D) capital expenditures, including Gathering, Transportation and Marketing (GTM) facilities, of $2.5 billion, $1.5 billion and $892 million in 2004, 2003 and 2002, respectively, primarily with internally generated cash flow of $3.2 billion, $2.7 billion and $1.4 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 the three year period presented, the Company primarily used 36 internally generated cash flow or its lines of credit and commercial paper program; which were subsequently paid down with internally generated cash flow. However, in 2003 in conjunction with the BP acquisition, the Company completed a public offering of approximately 19.8 million shares of common stock, including 2.6 million shares for the underwriters' over-allotment option, for net proceeds of $554 million. 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, ------------------------------------ 2004 2003 2002 ---------- ---------- -------- (IN THOUSANDS) Exploration and Development: United States............................................ $ 755,056 $ 417,701 $302,611 Canada................................................... 756,912 568,856 258,191 Egypt.................................................... 301,912 242,652 171,160 Australia................................................ 138,694 128,261 89,813 North Sea................................................ 362,054 60,204 -- Other International...................................... 26,493 35,098 38,409 ---------- ---------- -------- $2,341,121 $1,452,772 $860,184 ========== ========== ======== Capitalized Interest....................................... $ 50,748 $ 52,891 $ 40,691 ========== ========== ======== Gas Gathering Transmission and Processing Facilities....... $ 138,738 $ 38,533 $ 32,155 ========== ========== ======== Acquisitions: Oil and gas properties................................... $1,063,851 $1,568,106 $351,707 Gas gathering, transmission and processing facilities.... -- 5,484 2,875 ---------- ---------- -------- $1,063,851 $1,573,590 $354,582 ========== ========== ========
In 2004, Apache drilled a record number of wells and completed two significant acquisitions. Each of our North America operating areas drilled a record number of wells in 2004. In the Gulf of Mexico the majority of our activity focused in and around our existing asset base, including continued exploitation of the properties purchased from BP and Shell in 2003 and the Anadarko properties purchased in 2004. In the Central region, where Apache got its start 50 years ago, estimated proved reserves increased 20 percent in 2004 through a combination of the ExxonMobil acquisition and Apache's most active drilling year, completing 268 of 283 wells in the region. Canada was our most active area with over 1,300 wells drilled, three-fourths of which were shallow development wells, with over 92 percent completed as producers. At the Forties Field, an experienced workforce is tackling projects to extend the life of the largest field in the United Kingdom sector of the North Sea. Production increases at Forties -- the anchor of Apache's newest core area -- were driven by Apache's first drilling program since acquiring the field and a maintenance program aimed at improving efficiency of the field. During 2004, Apache completed 12 of 17 wells drilled as part of a $362 million capital program, including $150 million of maintenance and operations capital expenditures. In Egypt and Australia, Apache continued its successful exploration programs with several new discoveries. Our continuing development program in Egypt increased gross production to over 100,000 b/d for the first time. Capital expenditures in China decreased in 2004 with the completion of production facilities and first production in the second half of 2003. In 2004, Apache added 444.7 MMboe of estimated proved reserves through acquisitions, drilling and revisions. During 2004, GTM expenditures included additional gathering system pipelines in Egypt and a gas plant expansion on Varanus Island in Australia. In 2003, E&D capital expenditures increased approximately $593 million over the previous year with more drilling and development activity in each of our cores areas. Apache drilled more wells than it ever had in Canada, completing 913 of 984 wells. Apache's successful drilling program in Egypt pushed production to then all-time highs and resulted in several discoveries, including the largest discovery in the history of the Company at the Qasr-1X well in the Khalda Offset Concession. In the North Sea, which Apache acquired in April 2003, we began a program of upgrades to the surface facilities to increase efficiencies. 37 For 2005, 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 and results to date, accurately projecting future expenditures is difficult at best. However, our preliminary estimate of exploration and development capital expenditures for 2005 is in excess of $2.5 billion. We do not project estimates for acquisitions because their timing is unpredictable. However, we continually look for properties which we believe will 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 40 consecutive years through 2004. Future dividend payments will depend on the Company's level of earnings, financial requirements and other relevant factors. Common dividends paid during 2004 rose 26 percent to $85 million, reflecting the increase in common shares outstanding and the higher common stock dividend rate. The Company increased its quarterly cash dividend 33 percent, to eight cents per share from six cents per share, effective with the November 2004 dividend payment. During 2004, Apache paid a total of $6 million in dividends on its Series B Preferred Stock issued in August 1998. Dividends on the Series C Preferred Stock were paid through May 15, 2002, when the shares automatically converted to common stock. See Note 8, Capital Stock of Item 15 in this Form 10-K. Common dividends paid during 2003 rose 19 percent to $67 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 table summarizes the Company's contractual obligations as of December 31, 2004. 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 2005 2006 2007 2008 2009 THEREAFTER - ----------------------- --------- ---------- -------- -------- -------- ------- -------- ---------- (IN THOUSANDS) Long-term debt.............. Note 5 $2,588,390 $ 830 $ 274 $172,530 $ 353 $495,662 $1,918,741 Operating leases and other commitments............... Note 10 360,443 127,592 72,566 47,579 31,273 17,257 64,176 International lease commitments............... Note 10 179,694 48,437 36,042 76,528 15,687 3,000 -- Operating costs associated with pre-existing volumetric production payments on acquired properties................ Note 2 118,804 49,112 37,362 24,088 8,242 -- -- ----------------------------------------------------------------------------- Total Contractual Obligations(a)(b)......... $3,247,331 $225,971 $146,244 $320,725 $55,555 $515,919 $1,982,917 =============================================================================
(a) This table does not include the liability for dismantlement, abandonment and restoration costs of oil and gas properties. Effective with adoption of SFAS No. 143, "Accounting for Asset Retirement Obligations" on January 1, 2003, the Company recorded 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. - --------------- 38 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. The Company has reserved approximately $11 million for environmental remediation. The Company has also reserved approximately $10 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. In 2004, the Company accrued approximately $10 million 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 if Apache ever withdraws 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. The calculation will change annually based on future period losses incurred by OIL. As discussed under Note 2, Acquisitions and Divestitures of Item 15 in this Form 10-K, Apache assumed obligations for pre-existing 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 10.7 MMboe in 2005, 7.6 MMboe in 2006, 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. Apache does not record the reserves and production volumes attributable to the VPPs. As of December 31, 2004, Apache has booked a total of 91 MMboe of reserves attributable to the Anadarko and Shell transactions. The VPPs are non-operating interests, 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 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 136 million British pounds, an amount that represents the letter of credit requirement through March 2006, 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; however, we do not believe that such a sharp downgrade is reasonably likely. 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. 39 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 & gas properties acquired from ExxonMobil in September 2004. As discussed in Note 2, Acquisitions and Divestitures of Item 15 in this Form 10-K, Apache contributed $29 million into this partnership which was determined to be a variable interest entity as defined by Financial Accounting Standards Board (FASB) Interpretation No. 46 "Variable Interest Entities." 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 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 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. 40 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 2004, 2003 and 2002, their review covered 79, 78 and 68 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. 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 of which we are the operator. 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. 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 2004, we experienced wide variability in the timing of cash receipts, but our past due balance improved at year-end. 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. Prior to 2003, under the full-cost method of accounting, as described in the preceding critical accounting policy sections, the 41 estimated undiscounted costs of the abandonment obligations, net of the value of salvage, were included as a component of our depletion base and expensed over the production life of the oil and gas properties. In 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations." Apache adopted this statement effective January 1, 2003, as discussed in Note 4, Asset Retirement Obligation of Item 15 of this Form 10-K. SFAS No. 143 significantly changed the method of accruing for costs an entity is legally obligated to incur related to the retirement of fixed assets ("asset retirement obligations" or "ARO"). Primarily, the new statement requires the Company to record a separate liability for the discounted present value of the Company's asset retirement obligations, with an offsetting increase to the related oil and gas properties on the balance sheet. As such, beginning in 2003 our depletion expense is reduced since we will deplete a discounted ARO rather than the undiscounted value previously depleted in our oil and gas property base. The lower depletion expense under SFAS No. 143 is offset, however, by accretion expense, which reflects increases in the discounted asset retirement obligation over time. 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. Also, the Company had to determine how to incorporate the asset retirement obligations into the quarterly calculation of its full-cost ceiling tests (see Note 1, Summary of Significant Accounting Policies of Item 15 in this Form 10-K). SFAS No. 143 is silent with respect to this issue and, although there were various views, the Company initially elected to perform the calculation similarly to the prior year by including expected abandonment costs as a reduction to the present value of future net revenues used to determine the ceiling limitation. The oil and gas property balance is capped by this limitation. Because abandonment costs are now reflected in the oil and gas property balance, the Company reduced the property balance by the accrued abandonment liability to place it on a comparable basis with the ceiling. In September 2004, the SEC issued Staff Accounting Bulletin (SAB) No. 106 to provide new guidance on how asset retirement obligations should impact the calculation of the ceiling test. The new guidance states that the property balance should not be adjusted; however, the expected future abandonment costs should be omitted from the present value ceiling limitation to provide for a comparable basis when performing the calculation. Based on this guidance, the Company changed its method of calculating the ceiling test as of year end and there was no material impact to the financial statements. INCOME TAXES Our oil and gas exploration and production operations are currently located in seven 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. 42 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 as 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. 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 During 2002, Apache began modifying its stock compensation plans in order to reflect the cost of these plans in the Statement of Consolidated Operations. As part of this effort, Apache began issuing stock appreciation rights and restricted stock and, effective January 1, 2003, adopted the expense provisions of SFAS No. 123 "Accounting for Stock Based Compensation," as amended, on a prospective basis for all stock options granted under the Company's existing option plans. Consistent with the Company's desire to reflect the ultimate cost of stock compensation plans 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. In response to certain changes in U.S. tax laws passed in 2004, for future compensation the Company plans to make grants of stock options, rather than share appreciation rights, assuming the Company's shareholders approve a new stock option plan at the 2005 annual meeting of shareholders. Upon adoption of SFAS No. 123-R, all stock based compensation awards that vested during 2004 are now reflected in the Company's net income for the year. Awards that vested in prior years continue to be reflected in the income statement under the accounting guidelines in place for the applicable year. 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. Pro-forma income statement presentations have been provided for in Note 1. Summary of Significant Accounting Policies of Item 15 in this Form 10-K to present a comparative basis of all plans outstanding during the reported periods. 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 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 Share Appreciation Plan. 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 43 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 valuation purposes, Apache has historically utilized the Black-Scholes option pricing model, however, the Company is currently evaluating its policy to determine if a different method should be used, such as a lattice model. Apache's next grant to substantially all Company employees is anticipated to occur in May 2005. 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 oil price realizations, including the impact of fixed-price contracts and hedges, ranged from a low of $28.97 per barrel to a high of $43.82 per barrel during 2004. Average gas price realizations, including the impact of fixed-price contracts and hedges, ranged from a monthly low of $4.40 per Mcf to a monthly high of $5.61 per Mcf during the same period. Based on the Company's 2004 worldwide oil production levels, a $1.00 per barrel change in the weighted-average realized price of oil would increase or decrease revenues by $85 million. Based on the Company's 2004 worldwide gas production levels, a $.10 per Mcf change in the weighted-average realized price of gas would increase or decrease revenues by $45 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 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 limit, 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. As indicated in Note 3, Hedging and Derivative Instruments of Item 15 in this Form 10-K, the Company entered into several derivative positions in conjunction with our 2002, 2003 and 2004 acquisitions. These positions were entered into to preserve our strong financial position in a period of cyclically high gas and oil prices and were designated as cash flow hedges of anticipated production. Apache has historically only hedged long-term oil and gas prices related to a portion of its expected production associated with acquisitions. As such, the Company's use of hedging activity remains at a correspondingly low level. In 2004, financial derivative hedges represented approximately 16 percent of the total worldwide natural gas production and four percent of the total worldwide crude oil production. Heading into 2005, hedges in place were entirely related to U.S. production and represented 11 percent and six percent of worldwide production for natural gas and crude oil, respectively. 44 On December 31, 2004, the Company had open natural gas derivative positions with a fair value of $(23) million. A 10 percent change in natural gas prices would change the fair value by plus or minus $41 million. The Company also had open oil price swap positions with a fair value of $(28) million. A 10 percent increase in oil prices would reduce the fair value by $31 million. A 10 percent decrease in oil prices would increase the fair value by $28 million. These fair value changes assume volatility based on prevailing market parameters at December 31, 2004. 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. INTEREST RATE RISK Approximately 85 percent of the Company's year-end 2004 debt is term debt with fixed interest rates, minimizing the Company's exposure to fluctuations in short-term interest rates. At December 31, 2004, the Company had $396 million of floating-rate debt which is subject to fluctuations in short-term interest rates. A 10 percent change in the floating interest rate (approximately 23 basis points) on these year-end balances, would change annual interest expense by approximately $1 million. The Company did not have any open derivative contracts relating to interest rates at December 31, 2004. 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. Revenue and disbursement transactions denominated in Australian dollars, Canadian dollars and British pounds are converted to U.S. dollar equivalents based on the exchange rate as of the transaction date. Prior to October 1, 2002, reported cash flow from Canadian operations was measured in Canadian dollars and converted to the U.S. dollar equivalent based on the average of the Canadian and U.S. dollar exchange rates for the period reported. The majority of Apache's debt in Canada is denominated in U.S. dollars and, as such, was adjusted for differences in exchange rates at each period end and recorded as Revenues and Other. In light of the continuing transformation of the U.S. and Canadian energy markets into a single energy market, we adopted the U.S. dollar as our functional currency in Canada, effective October 1, 2002. A 10 percent strengthening of the Australian and Canadian dollars and the British pound as of December 31, 2004 would result in a foreign currency net loss of approximately $68 million. This is primarily driven from foreign currency effects on the Company's deferred tax liability positions in its international operations. The Company began hedging a portion of its foreign exchange risk associated with lease operating expenditures in 2004. The Company's treasury department administers this hedging program. For information on open derivative contracts, please see Note 3, Hedging and Derivative Instruments of Item 15 in this Form 10-K. 45 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-65 of this Form 10-K, and are incorporated herein by reference. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE The financial statements for the fiscal years ended December 31, 2004, 2003 and 2002, 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, 2004, 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 significant changes in internal controls over financial reporting during the quarter ending December 31, 2004 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. 46 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 period covered by this Annual Report on Form 10-K that 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 2005 annual meeting of stockholders (the Proxy Statement) is incorporated herein by reference. CODE OF BUSINESS CONDUCT Pursuant to Rule 303A.10 of the NYSE and Rule 4350(n) of the NASDAQ, we are required to adopt a code of business conduct and ethics for our directors, officers and employees. In February 2004, the Board of Directors adopted the Code of Business Conduct (Code of Conduct), 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," "Option/SAR Exercises and Year-End Value Table," "Long-Term Incentive Plan Awards Table," "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. 47 PART IV ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (a) Documents included in this report: 1. Financial Statements Report of management........................................ F-1 Report of independent registered public accounting firm..... F-2 Report of independent registered public accounting firm..... F-3 Statement of consolidated operations for each of the three years in the period ended December 31, 2004............... F-4 Statement of consolidated cash flows for each of the three years in the period ended December 31, 2004............... F-5 Consolidated balance sheet as of December 31, 2004 and 2003...................................................... F-6 Statement of consolidated shareholders' equity for each of the three years in the period ended December 31, 2004..... F-7 Notes to consolidated financial statements.................. F-8
2. Financial Statement Schedules Financial statement schedules have been omitted because they are either not required, not applicable or the information required to be presented is included in the Company's financial statements and related notes. 3. Exhibits
EXHIBIT NO. DESCRIPTION - ------- ----------- 2.1 -- Agreement and Plan of Merger 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. 1-4300). 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. 1-4300). 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. 1-4300). 3.2 -- Bylaws of Registrant, as amended February 5, 2004 (incorporated by reference to Exhibit 3.2 to Registrant's Annual Report on Form 10-K for year ended December 31, 2003, SEC File No. 1-4300). 4.1 -- Form of Certificate for Registrant's Common Stock (incorporated by reference to Exhibit 4.1 to Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, 2004, SEC File No. 1-4300). 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. 1-4300).
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EXHIBIT NO. DESCRIPTION - ------- ----------- 4.3 -- Form of Certificate for Registrant's Automatically Convertible Equity Securities, Conversion Preferred Stock, Series C (incorporated by reference to Exhibit 99.8 to Amendment No. 1 on Form 8-K/A to Registrant's Current Report on Form 8-K, dated and filed April 29, 1999, SEC File No. 1-4300). 4.4 -- 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. 1-4300). 10.1 -- 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. 1-4300). 10.2 -- 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. 1-4300). 10.3 -- Form of Credit Agreement, dated as of June 3, 2002, among Registrant, the Lenders named therein, JPMorgan Chase Bank, as Global Administrative Agent, Bank of America, N.A., as Global Syndication Agent, Citibank, N.A., as Global Documentation Agent, Bank of America, N.A. and Wachovia Bank, National Association, as U.S. Co-Syndication Agents, and Citibank, N.A. and Union Bank of California, N.A., as U.S. Co-Documentation Agents (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, 2002, SEC File No. 1-4300). 10.4 -- Form of 364-Day Credit Agreement, dated as of June 3, 2002, among Registrant, the Lenders named therein, JPMorgan Chase Bank, as Global Administrative Agent, Bank of America, N.A., as Global Syndication Agent, Citibank, N.A., as Global Documentation Agent, Bank of America, N.A. and BNP Paribas, as 364-Day Co-Syndication Agents, and Deutsche Bank AG, New York Branch, and Societe Generale, as 364-Day Co-Documentation Agents (excluding exhibits and schedules) (incorporated by reference to Exhibit 10.3 to Registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2002, SEC File No. 1-4300). 10.5 -- Form of Credit Agreement, dated as of June 3, 2002, among Apache Canada Ltd, a wholly-owned subsidiary of Registrant, the Lenders named therein, JPMorgan Chase Bank, as Global Administrative Agent, Bank of America, N.A., as Global Syndication Agent, Citibank, N.A., as Global Documentation Agent, Royal Bank of Canada, as Canadian Administrative Agent, The Bank of Nova Scotia and The Toronto-Dominion Bank, as Canadian Co-Syndication Agents, and BNP Paribas (Canada) and Bayerische Landesbank Girozentrale, as Canadian Co-Documentation Agents (excluding exhibits and schedules) (incorporated by reference to Exhibit 10.4 to Registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2002, SEC File No. 1-4300).
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EXHIBIT NO. DESCRIPTION - ------- ----------- 10.6 -- Form of Credit Agreement, dated as of June 3, 2002, among Apache Energy Limited, a wholly-owned subsidiary of Registrant, the Lenders named therein, JPMorgan Chase Bank, as Global Administrative Agent, Bank of America, N.A., as Global Syndication Agent, Citibank, N.A., as Global Documentation Agent, Citisecurities Limited, as Australian Administrative Agent, Bank of America, N.A., Sydney Branch, and Deutsche Bank AG, Sydney Branch, as Australian Co- Syndication Agents, and Royal Bank of Canada and Bank One, N.A., Australia Branch, as Australian Co-Documentation Agents (excluding exhibits and schedules) (incorporated by reference to Exhibit 10.5 to Registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2002, SEC File No. 1-4300). 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). 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 Exploracion Egipto 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. 1-4300). 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. 1-4300). +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. 1-4300). +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. 1-4300).
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EXHIBIT NO. DESCRIPTION - ------- ----------- +10.16 -- Apache Corporation 401(k) Savings Plan, dated August 1, 2002 (incorporated by reference to Exhibit 10.1 to Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2002, SEC File No. 1-4300). +10.17 -- Amendment to Apache Corporation 401(k) Savings Plan, dated January 27, 2003, effective January 1, 2003 (incorporated by reference to Exhibit 10.18 to Registrant's Annual Report on Form 10-K, as amended by Form 10-K/A, for year ended December 31, 2002, SEC File No. 1-4300). +10.18 -- Apache Corporation Money Purchase Retirement Plan, dated August 1, 2002 (incorporated by reference to Exhibit 10.2 to Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2002, SEC File No. 1-4300). +10.19 -- Amendment to Apache Corporation Money Purchase Retirement Plan, dated January 27, 2003, effective January 1, 2003 (incorporated by reference to Exhibit 10.20 to Registrant's Annual Report on Form 10-K for year ended December 31, 2002, SEC File No. 1-4300). +10.20 -- Non-Qualified Retirement/Savings Plan of Apache Corporation, restated January 1, 1997, and amendments effective January 1, 1997, January 1, 1998 and January 1, 1999 (incorporated by reference to Exhibit 10.17 to Registrant's Annual Report on Form 10-K for year ended December 31, 1998, SEC File No. 1-4300). +10.21 -- Amendment to Non-Qualified Retirement/Savings Plan of Apache Corporation, dated February 22, 2000, effective January 1, 1999 (incorporated by reference to Exhibit 4.7 to Registrant's Registration Statement on Form S-8, Registration No. 333-31092, filed February 25, 2000); and Amendment dated July 27, 2000 (incorporated by reference to Exhibit 4.8 to Amendment No. 1 to Registrant's Registration Statement on Form S-8, Registration No. 333-31092, filed August 18, 2000). +10.22 -- Amendment to Non-Qualified Retirement/Savings Plan of Apache Corporation, dated August 3, 2001, effective September 1, 2000 and July 1, 2001 (incorporated by reference to Exhibit 10.13 to Registrant's Quarterly Report on Form 10-Q, as amended by Form 10-Q/A, for the quarter ended June 30, 2001, SEC File No. 1-4300). +10.23 -- Amendment to Non-Qualified Retirement/Savings Plan of Apache Corporation, dated December 18, 2003, effective January 1, 2004 (incorporated by reference to Exhibit 10.24 to Registrant's Annual Report on Form 10-K for year ended December 31, 2003, SEC File No. 1-4300). +10.24 -- 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. 1-4300). +10.25 -- Apache Corporation 1995 Stock Option Plan, as amended and restated September 13, 2001 (incorporated by reference to Exhibit 10.02 to Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2001, as amended by Form 10-Q/A, SEC File No. 1-4300). +10.26 -- Apache Corporation 2000 Share Appreciation Plan, as amended and restated February 5, 2004 (incorporated by reference to Exhibit 10.27 to Registrant's Annual Report on Form 10-K for year ended December 31, 2003, SEC File No. 1-4300). +10.27 -- 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. 1-4300). +10.28 -- Apache Corporation 1998 Stock Option Plan, as amended and restated September 13, 2001 (incorporated by reference to Exhibit 10.04 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. 1-4300).
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EXHIBIT NO. DESCRIPTION - ------- ----------- +10.29 -- Apache Corporation 2000 Stock Option Plan, as amended and restated March 5, 2003 (incorporated by reference to Exhibit 4.5 to Registrant's Registration Statement on Form S-8, Registration No. 333-103758, filed March 12, 2003). +10.30 -- 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. 1-4300). +10.31 -- 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. 1-4300). +10.32 -- 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. 1-4300). +10.33 -- Apache Corporation Deferred Delivery Plan, as amended and restated December 18, 2002, effective May 2, 2002 (incorporated by reference to Exhibit 4.5 to Post-Effective Amendment No. 2 to Registrant's Registration Statement on Form S-8, Registration No. 333-31092, filed March 11, 2003). +10.34 -- Apache Corporation Executive Restricted Stock Plan, as amended and restated December 18, 2002, effective May 2, 2002 (incorporated by reference to Exhibit 4.5 to Post-Effective Amendment No. 1 to Registrant's Registration Statement on Form S-8, Registration No. 333-97403, filed December 30, 2002). +10.35 -- Apache Corporation Non-Employee Directors' Compensation Plan, as amended and restated May 1, 2003, effective July 1, 2003 (incorporated by reference to Exhibit 10.1 to Registrant's Quarterly Report on Form 10-Q, as amended by Form 10-Q/A, for the quarter ended June 30, 2003, SEC File No. 1-4300). +10.36 -- Apache Corporation Outside Directors' Retirement Plan, as amended and restated May 3, 2001 (incorporated by reference to Exhibit 10.08 to Registrant's Quarterly Report on Form 10-Q, as amended by Form 10-Q/A, for the quarter ended June 30, 2001, SEC File No. 1-4300). +10.37 -- 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. 1-4300). +10.38 -- 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. 1-4300). +10.39 -- 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. 1-4300). +10.40 -- 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. 1-4300). +10.41 -- 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. 1-4300). +10.42 -- Amended and Restated Conditional Stock Grant Agreement, dated June 6, 2001, between Registrant and G. Steven Farris (incorporated by reference to Exhibit 10.10 to Registrant's Quarterly Report on Form 10-Q, as amended by Form 10-Q/A, for the quarter ended June 30, 2001, SEC File No. 1-4300).
52
EXHIBIT NO. DESCRIPTION - ------- ----------- 10.43 -- 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. 1-4300). 10.44 -- 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. 1-4300). *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. 1-4300). *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) Reports filed on Form 8-K The following current reports on Form 8-K were filed by the Company during the fiscal quarter ended December 31, 2004: None 53 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: March 11, 2005 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, Thomas L. Mitchell, 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 Director, President, Chief March 11, 2005 ------------------------------------------------------ Executive Officer and Chief G. Steven Farris Operating Officer (Principal Executive Officer) /s/ ROGER B. PLANK Executive Vice President and March 11, 2005 ------------------------------------------------------ Chief Financial Officer Roger B. Plank (Principal Financial Officer) /s/ THOMAS L. MITCHELL Vice President and Controller March 11, 2005 ------------------------------------------------------ (Principal Accounting Thomas L. Mitchell Officer) /s/ RAYMOND PLANK Chairman of the Board March 11, 2005 ------------------------------------------------------ Raymond Plank /s/ FREDERICK M. BOHEN Director March 11, 2005 ------------------------------------------------------ Frederick M. Bohen /s/ RANDOLPH M. FERLIC Director March 11, 2005 ------------------------------------------------------ Randolph M. Ferlic /s/ EUGENE C. FIEDOREK Director March 11, 2005 ------------------------------------------------------ Eugene C. Fiedorek /s/ A. D. FRAZIER, JR. Director March 11, 2005 ------------------------------------------------------ A. D. Frazier, Jr.
NAME TITLE DATE ---- ----- ---- /s/ PATRICIA ALBJERG GRAHAM Director March 11, 2005 ------------------------------------------------------ Patricia Albjerg Graham /s/ JOHN A. KOCUR Director March 11, 2005 ------------------------------------------------------ John A. Kocur /s/ GEORGE D. LAWRENCE Director March 11, 2005 ------------------------------------------------------ George D. Lawrence /s/ F. H. MERELLI Director March 11, 2005 ------------------------------------------------------ F. H. Merelli /s/ RODMAN D. PATTON Director March 11, 2005 ------------------------------------------------------ Rodman D. Patton /s/ CHARLES J. PITMAN Director March 11, 2005 ------------------------------------------------------ Charles J. Pitman /s/ JAY A. PRECOURT Director March 11, 2005 ------------------------------------------------------ Jay A. Precourt
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, 2004. 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, 2004. 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 Thomas L. Mitchell Vice President and Controller (Chief Accounting Officer) Houston, Texas March 11, 2005 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, 2004 and 2003, and the related consolidated statements of operations, shareholders' equity, and cash flows for each of the three years in the period ended December 31, 2004. 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, 2004 and 2003 and the consolidated results of their operations and their cash flows for each of the three years ended December 31, 2004, in conformity with accounting principles generally accepted in the United States. As described in 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 Notes 1 and 4, effective January 1, 2003, the Company adopted the provisions of SFAS No. 143, "Accounting for Asset Retirement Obligations" and the prospective provisions of SFAS No. 148, "Accounting for Stock-Based Compensation -- Transition and Disclosure." 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, 2004, based on criteria established in Internal Control -- Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 11, 2005 expressed an unqualified opinion thereon. ERNST & YOUNG LLP Houston, Texas March 11, 2005 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 Management's Report on Internal Control over Financial Reporting, that Apache Corporation and subsidiaries maintained effective internal control over financial reporting as of December 31, 2004, 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, 2004, 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, 2004, 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, 2004 and 2003, and the related consolidated statements of operations, shareholders' equity, and cash flows for each of the three years in the period ended December 31, 2004 and our report dated March 11, 2005 expressed an unqualified opinion thereon. ERNST & YOUNG LLP Houston, Texas March 11, 2005 F-3 APACHE CORPORATION AND SUBSIDIARIES STATEMENT OF CONSOLIDATED OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, -------------------------------------------- 2004 2003 2002 ---------- ---------- ---------- (IN THOUSANDS, EXCEPT PER COMMON SHARE DATA) REVENUES AND OTHER: Oil and gas production revenues................. $5,308,017 $4,198,920 $2,559,748 Other........................................... 24,560 (8,621) 125 ---------- ---------- ---------- 5,332,577 4,190,299 2,559,873 ---------- ---------- ---------- OPERATING EXPENSES: Depreciation, depletion and amortization........ 1,222,152 1,073,286 843,879 Asset retirement obligation accretion........... 46,060 37,763 -- International impairments....................... -- 12,813 19,600 Lease operating costs........................... 864,378 699,663 457,903 Gathering and transportation costs.............. 82,261 60,460 38,567 Severance and other taxes....................... 93,748 121,793 67,309 General and administrative...................... 173,194 138,524 104,588 China litigation provision...................... 71,216 -- -- Financing costs: Interest expense............................. 168,090 169,090 155,667 Amortization of deferred loan costs.......... 2,471 2,163 1,859 Capitalized interest......................... (50,748) (52,891) (40,691) Interest income.............................. (3,328) (3,290) (4,002) ---------- ---------- ---------- 2,669,494 2,259,374 1,644,679 ---------- ---------- ---------- PREFERRED INTERESTS OF SUBSIDIARIES............... -- 8,668 16,224 ---------- ---------- ---------- INCOME BEFORE INCOME TAXES........................ 2,663,083 1,922,257 898,970 Provision for income taxes...................... 993,012 827,004 344,641 ---------- ---------- ---------- INCOME BEFORE CHANGE IN ACCOUNTING PRINCIPLE...... 1,670,071 1,095,253 554,329 Cumulative effect of change in accounting principle, net of income tax................. (1,317) 26,632 -- ---------- ---------- ---------- NET INCOME........................................ 1,668,754 1,121,885 554,329 Preferred stock dividends....................... 5,680 5,680 10,815 ---------- ---------- ---------- INCOME ATTRIBUTABLE TO COMMON STOCK............... $1,663,074 $1,116,205 $ 543,514 ========== ========== ========== BASIC NET INCOME PER COMMON SHARE: Before change in accounting principle........... $ 5.10 $ 3.38 $ 1.83 Cumulative effect of change in accounting principle.................................... -- .08 -- ---------- ---------- ---------- $ 5.10 $ 3.46 $ 1.83 ========== ========== ========== DILUTED NET INCOME PER COMMON SHARE: Before change in accounting principle........... $ 5.04 $ 3.35 $ 1.80 Cumulative effect of change in accounting principle.................................... (.01) .08 -- ---------- ---------- ---------- $ 5.03 $ 3.43 $ 1.80 ========== ========== ==========
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, --------------------------------------- 2004 2003 2002 ----------- ----------- ----------- (IN THOUSANDS) CASH FLOWS FROM OPERATING ACTIVITIES: Net income................................................ $ 1,668,754 $ 1,121,885 $ 554,329 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion and amortization................ 1,222,152 1,073,286 843,879 Provision for deferred income taxes..................... 444,906 546,357 137,672 Asset retirement obligation accretion................... 46,060 37,763 -- Amortization of deferred loan costs..................... 2,471 2,163 1,859 International impairments............................... -- 12,813 19,600 Cumulative effect of change in accounting principle, net of income tax......................................... 1,317 (26,632) -- Other................................................... 39,694 32,923 9,531 Changes in operating assets and liabilities, net of effects of acquisitions: (Increase) decrease in receivables...................... (296,383) (94,295) (122,830) (Increase) decrease in inventories...................... (659) (4,216) 717 (Increase) decrease in drilling advances and other...... (35,761) (19,881) (26,116) (Increase) decrease in deferred charges and other....... (35,328) (29,520) 496 Increase (decrease) in accounts payable................. 182,454 68,176 32,219 Increase (decrease) in accrued expenses................. 28,431 11,227 (16,595) Increase (decrease) in advances from gas purchasers..... (18,331) (16,246) (14,574) Increase (decrease) in deferred credits and noncurrent liabilities........................................... (18,258) (9,903) (39,469) ----------- ----------- ----------- NET CASH PROVIDED BY OPERATING ACTIVITIES.......... 3,231,519 2,705,900 1,380,718 ----------- ----------- ----------- CASH FLOWS FROM INVESTING ACTIVITIES: Additions to property and equipment....................... (2,456,488) (1,594,936) (1,037,368) Acquisition of ExxonMobil properties...................... (348,173) -- -- Acquisition of Anadarko properties........................ (531,963) -- -- Acquisition of BP properties.............................. -- (1,140,156) -- Acquisition of Shell properties........................... -- (203,033) -- Acquisition of Louisiana properties....................... -- -- (258,885) Acquisition of Occidental properties...................... -- (22,000) (11,000) Proceeds from sales of oil and gas properties............. 4,042 58,944 7,043 Proceeds from short-term investments, net................. -- -- 101,723 Other..................................................... (78,431) (57,576) (37,520) ----------- ----------- ----------- NET CASH USED IN INVESTING ACTIVITIES.............. (3,411,013) (2,958,757) (1,236,007) ----------- ----------- ----------- CASH FLOWS FROM FINANCING ACTIVITIES: Long-term borrowings...................................... 544,824 1,780,870 1,467,929 Payments on long-term debt................................ (283,400) (1,613,362) (1,553,471) Dividends paid............................................ (90,369) (72,832) (68,879) Common stock activity..................................... 21,595 583,837 30,708 Treasury stock activity, net.............................. 12,472 4,378 1,991 Cost of debt and equity transactions...................... (2,303) (5,417) (6,728) Repurchase of preferred interests of subsidiaries......... -- (443,000) -- Other..................................................... 54,265 -- -- ----------- ----------- ----------- NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES....................................... 257,084 234,474 (128,450) ----------- ----------- ----------- NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS........ 77,590 (18,383) 16,261 CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR.............. 33,503 51,886 35,625 ----------- ----------- ----------- CASH AND CASH EQUIVALENTS AT END OF YEAR.................... $ 111,093 $ 33,503 $ 51,886 =========== =========== ===========
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, ------------------------- 2004 2003 ----------- ----------- (IN THOUSANDS) ASSETS CURRENT ASSETS: Cash and cash equivalents................................. $ 111,093 $ 33,503 Receivables, net of allowance............................. 939,736 639,055 Inventories............................................... 157,293 125,867 Drilling advances......................................... 82,889 58,062 Prepaid assets and other.................................. 57,771 42,585 ----------- ----------- 1,348,782 899,072 ----------- ----------- PROPERTY AND EQUIPMENT: Oil and gas, on the basis of full cost accounting: Proved properties....................................... 19,933,041 16,277,930 Unproved properties and properties under development, not being amortized.................................... 777,690 795,161 Gas gathering, transmission and processing facilities..... 966,605 828,169 Other..................................................... 284,069 239,548 ----------- ----------- 21,961,405 18,140,808 Less: Accumulated depreciation, depletion and amortization............................................ (8,101,046) (6,880,723) ----------- ----------- 13,860,359 11,260,085 ----------- ----------- OTHER ASSETS: Goodwill, net............................................. 189,252 189,252 Deferred charges and other................................ 104,087 67,717 ----------- ----------- $15,502,480 $12,416,126 =========== =========== LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES: Accounts payable.......................................... $ 542,074 $ 300,598 Accrued operating expense................................. 80,741 72,250 Accrued exploration and development....................... 341,063 212,028 Accrued compensation and benefits......................... 83,636 56,237 Accrued interest.......................................... 32,575 32,621 Accrued income taxes...................................... 78,042 18,936 Derivative instruments.................................... 21,273 63,542 Other..................................................... 103,487 64,166 ----------- ----------- 1,282,891 820,378 ----------- ----------- LONG-TERM DEBT.............................................. 2,588,390 2,326,966 ----------- ----------- DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES: Income taxes.............................................. 2,146,637 1,697,238 Advances from gas purchasers.............................. 90,876 109,207 Asset retirement obligation............................... 932,004 739,775 Derivative instruments.................................... 31,417 5,931 Other..................................................... 225,844 183,833 ----------- ----------- 3,426,778 2,735,984 ----------- ----------- 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, 334,912,505 and 332,509,478 shares issued, respectively............................................ 209,320 207,818 Paid-in capital........................................... 4,106,182 4,038,007 Retained earnings......................................... 4,017,339 2,445,698 Treasury stock, at cost, 7,455,002 and 8,012,302 shares, respectively............................................ (97,325) (105,169) Accumulated other comprehensive loss...................... (129,482) (151,943) ----------- ----------- 8,204,421 6,532,798 ----------- ----------- $15,502,480 $12,416,126 =========== ===========
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
SERIES B SERIES C COMPREHENSIVE PREFERRED PREFERRED COMMON PAID-IN RETAINED INCOME STOCK STOCK STOCK CAPITAL EARNINGS ------------- --------- --------- -------- ---------- ---------- (IN THOUSANDS) BALANCE AT DECEMBER 31, 2001..................... $98,387 $ 208,207 $185,288 $2,803,825 $1,336,478 Comprehensive income (loss): Net income................................... $ 554,329 -- -- -- -- 554,329 Currency translation adjustments............. 5,328 -- -- -- -- -- Commodity hedges............................. (16,322) -- -- -- -- -- Marketable securities........................ (125) -- -- -- -- -- ---------- Comprehensive income........................... $ 543,210 ========== Cash dividends: Preferred.................................... -- -- -- -- (10,815) Common ($.19 per share)...................... -- -- -- -- (56,565) Five percent common stock dividend............. -- -- -- 395,820 (395,820) Common shares issued........................... -- -- 1,240 26,044 -- Conversion of Series C Preferred Stock......... -- (208,207) 7,803 200,404 -- Treasury shares issued, net.................... -- -- -- 666 -- Other.......................................... -- -- -- 691 -- ------- --------- -------- ---------- ---------- BALANCE AT DECEMBER 31, 2002..................... 98,387 -- 194,331 3,427,450 1,427,607 Comprehensive income (loss): Net income................................... $1,121,885 -- -- -- -- 1,121,885 Commodity hedges............................. (39,007) -- -- -- -- -- ---------- Comprehensive income........................... $1,082,878 ========== Cash dividends: Preferred.................................... -- -- -- -- (5,680) Common ($.22 per share)...................... -- -- -- -- (72,200) Five percent common stock dividend............. -- -- 581 25,333 (25,914) Common shares issued........................... -- -- 12,906 579,107 -- Treasury shares issued, net.................... -- -- -- 4,109 -- Other.......................................... -- -- -- 2,008 -- ------- --------- -------- ---------- ---------- BALANCE AT DECEMBER 31, 2003..................... 98,387 -- 207,818 4,038,007 2,445,698 Comprehensive income (loss): Net income................................... $1,668,754 -- -- -- -- 1,668,754 Commodity hedges............................. 22,461 -- -- -- -- -- ---------- Comprehensive income........................... $1,691,215 ========== Cash dividends: Preferred.................................... -- -- -- -- (5,680) Common ($.28 per share)...................... -- -- -- -- (91,433) Five percent common stock dividend............. -- -- -- -- -- Common shares issued........................... -- -- 1,502 56,660 -- Treasury shares issued, net.................... -- -- -- 11,144 -- Other.......................................... -- -- -- 371 -- ------- --------- -------- ---------- ---------- BALANCE AT DECEMBER 31, 2004..................... $98,387 $ -- $209,320 $4,106,182 $4,017,339 ======= ========= ======== ========== ========== ACCUMULATED OTHER TOTAL TREASURY COMPREHENSIVE SHAREHOLDERS' STOCK INCOME (LOSS) EQUITY --------- ------------- ------------- (IN THOUSANDS) BALANCE AT DECEMBER 31, 2001..................... $(111,885) $(101,817) $4,418,483 Comprehensive income (loss): Net income................................... -- -- 554,329 Currency translation adjustments............. -- 5,328 5,328 Commodity hedges............................. -- (16,322) (16,322) Marketable securities........................ -- (125) (125) Comprehensive income........................... Cash dividends: Preferred.................................... -- -- (10,815) Common ($.19 per share)...................... -- -- (56,565) Five percent common stock dividend............. -- -- -- Common shares issued........................... -- -- 27,284 Conversion of Series C Preferred Stock......... -- -- -- Treasury shares issued, net.................... 1,326 -- 1,992 Other.......................................... -- -- 691 --------- --------- ---------- BALANCE AT DECEMBER 31, 2002..................... (110,559) (112,936) 4,924,280 Comprehensive income (loss): Net income................................... -- -- 1,121,885 Commodity hedges............................. -- (39,007) (39,007) Comprehensive income........................... Cash dividends: Preferred.................................... -- -- (5,680) Common ($.22 per share)...................... -- -- (72,200) Five percent common stock dividend............. -- -- -- Common shares issued........................... -- -- 592,013 Treasury shares issued, net.................... 5,390 -- 9,499 Other.......................................... -- -- 2,008 --------- --------- ---------- BALANCE AT DECEMBER 31, 2003..................... (105,169) (151,943) 6,532,798 Comprehensive income (loss): Net income................................... -- -- 1,668,754 Commodity hedges............................. -- 22,461 22,461 Comprehensive income........................... Cash dividends: Preferred.................................... -- -- (5,680) Common ($.28 per share)...................... -- -- (91,433) Five percent common stock dividend............. -- -- -- Common shares issued........................... -- -- 58,162 Treasury shares issued, net.................... 7,844 -- 18,988 Other.......................................... -- -- 371 --------- --------- ---------- BALANCE AT DECEMBER 31, 2004..................... $ (97,325) $(129,482) $8,204,421 ========= ========= ==========
The accompanying notes to consolidated financial statements are an integral part of this statement. F-7 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES NATURE OF OPERATIONS -- Apache Corporation (Apache or the Company) is an independent energy company that explores for, develops and produces natural gas, crude oil and natural gas liquids. The Company's North American exploration and production activities are divided into two U.S. operating regions (Central and Gulf Coast) and a Canadian region. Approximately 70 percent of the Company's proved reserves are located in North America. Outside of North America, Apache has exploration and production interests in Egypt, offshore Western Australia, offshore the United Kingdom in the North Sea (North Sea), offshore The People's Republic of China (China) and in Argentina. In 2003, we ceased operations in Poland. The Company's future financial condition and results of operations will depend upon prices received for its oil and natural gas production and the costs of finding, acquiring, developing and producing reserves. A substantial portion of the Company's production is sold under market-sensitive contracts. Prices for oil and natural gas are subject to fluctuations in response to changes in supply, market uncertainty and a variety of other factors beyond the Company's control. These factors include worldwide political instability (especially in the Middle East), the foreign supply of oil and natural gas, the price of foreign imports, the level of consumer demand, and the price and availability of alternative fuels. All share and per share information in these financial statements and notes thereto has been restated to reflect the 10 percent and five percent stock dividends and the two-for-one stock split. See Note 8, Capital Stock, for further discussion. PRINCIPLES OF CONSOLIDATION -- The accompanying consolidated financial statements include the accounts of Apache and its subsidiaries after elimination of intercompany balances and transactions. The Company consolidates all investments in which the Company, either through direct or indirect ownership, has more than a 50 percent voting interest. In addition, Apache consolidates all variable interest entities where it is the primary beneficiary. The Company's interests in oil and gas exploration and production ventures and partnerships are proportionately consolidated, including Apache Offshore Investment Partnership. CASH EQUIVALENTS -- The Company considers all highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents. These investments are carried at cost, which approximates fair value. ALLOWANCE FOR DOUBTFUL ACCOUNTS -- The Company routinely assesses the recoverability of all material trade and other receivables to determine their collectibility. Many of Apache's receivables are from joint interest owners on properties which Apache operates. Thus, Apache may have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. Generally, the Company's crude oil and natural gas receivables are collected within two months. However, beginning in 2001, the Company experienced a gradual decline in the timeliness of receipts from the Egyptian General Petroleum Corporation (EGPC). Deteriorating economic conditions in Egypt lessened the availability of U.S. dollars, resulting in an additional one to two month delay in receipts from EGPC. During 2004, we experienced wide variability in the timing of cash receipts, but our past due balance improved at year-end. We have not established a reserve for these Egyptian receivables because we continue to get paid, albeit late, and we have no indication that we will not be able to collect our receivable. The Company accrues a reserve on a receivable when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of any reserve may be reasonably estimated. As of December 31, 2004 and 2003, the Company had an allowance for doubtful accounts of $22 million and $30 million, respectively. MARKETABLE SECURITIES -- The Company accounts for investments in debt and equity securities in accordance with Statement of Financial Accounting Standards (SFAS) No. 115, "Accounting for Certain Investments in Debt and Equity Securities." Investments in debt securities classified as "held to maturity" are F-8 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) recorded at amortized cost. Investments in debt and equity securities classified as "available for sale" are recorded at fair value with unrealized gains and losses recognized in other comprehensive income, net of income taxes. The Company utilizes the average-cost method in computing realized gains and losses, which are included in Revenues and Other in the consolidated statements of operations. INVENTORIES -- Inventories consist principally of tubular goods and production equipment, stated at the lower of weighted-average cost or market, and oil produced but not sold, stated at the lower of cost (a combination of production costs and depreciation, depletion and amortization (DD&A) expense) or market. PROPERTY AND EQUIPMENT -- The Company uses the full-cost method of accounting for its investment in oil and gas properties. Under this method, the Company capitalizes all acquisition, exploration and development costs incurred for the purpose of finding oil and gas reserves, including salaries, benefits and other internal costs directly attributable to these activities. Historically, total capitalized internal costs in any given year have not been material to total oil and gas costs capitalized in such year. Apache capitalized $107 million, $65 million and $52 million of these internal costs in 2004, 2003 and 2002, respectively. Costs associated with production and general corporate activities, however, are expensed in the period incurred. Interest costs related to unproved properties and properties under development are also capitalized to oil and gas properties. Unless a significant portion of the Company's proved reserve quantities in a particular country are sold (greater than 25 percent), proceeds from the sale of oil and gas properties are accounted for as a reduction to capitalized costs, and gains and losses are not recognized. Apache computes the DD&A of oil and gas properties on a quarterly basis using the unit-of-production method based upon production and estimates of proved reserve quantities. Unproved properties are excluded from the amortizable base until evaluated. The cost of exploratory dry wells is transferred to proved properties and thus subject to amortization immediately upon determination that a well is dry in those countries where proved reserves exist. In countries where the Company has not booked proved reserves, all costs associated with a prospect or play are 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. Geological and geophysical (G&G) costs are recorded in proved property and therefore subject to amortization as incurred in mature basins. In exploration areas, G&G costs are capitalized in unproved property and evaluated as part of the total capitalized costs associated with a prospect or play. Future development costs and dismantlement, restoration and abandonment costs, net of estimated salvage values were added to the amortizable base until the end of 2002. Beginning in 2003, Apache changed its method of accounting for dismantlement, restoration and abandonment costs and the related effects on DD&A. The Company now includes the present value of its dismantlement, restoration and abandonment costs within the capitalized oil and gas property balance and, therefore, no longer reflects the recognized abandonment obligations within the future development costs added to the amortizable base (see Note 4, Asset Retirement Obligation). In performing its quarterly ceiling test, the Company limits, on a country-by-country basis, the capitalized costs of proved oil and gas properties, net of accumulated DD&A and deferred income taxes, to the estimated future net cash flows from proved oil and gas reserves discounted at 10 percent, net of related tax effects, plus the lower of cost or fair value of unproved properties included in the costs being amortized. If capitalized costs exceed this limit, the excess is charged as additional DD&A expense. The Company calculates future net cash flows by applying end-of-the-period prices except in those instances where future natural gas or oil sales are covered by physical contract terms providing for higher or lower amounts. Also, included in the estimated future net cash flows are Canadian provincial tax credits expected to be realized beyond the date at which the legislation, under its provisions, could be repealed. To date, the Canadian provincial governments have not indicated an intention to repeal this legislation. See Note 14, Supplemental F-9 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Oil and Gas Disclosures (Unaudited) "Future Net Cash Flows" for a discussion on calculation of estimated future net cash flows. In September 2004, the SEC issued Staff Accounting Bulletin (SAB) No. 106 to provide new guidance on how asset retirement obligations should impact the calculation of the ceiling test limitation on the amount of properties that can be capitalized. The new guidance is effective as of year-end 2004 and states that because asset retirement obligation costs are now reflected in the property balance, the future net cash flow calculation should omit the expected abandonment costs to provide for a comparable basis. Apache previously included abandonment costs in its future net cash flow calculation, but adjusted the capitalized amounts by the accrued abandonment obligation. The Company's adoption of SAB No. 106 did not have a material impact on financial results. Given the volatility of oil and gas prices, it is reasonably possible that the Company's estimate of discounted future net cash flows from proved oil and gas reserves could change in the near term. If oil and gas prices decline significantly, even if only for a short period of time, it is possible that write-downs of oil and gas properties could occur. Unproved properties are assessed quarterly for possible impairments or reductions in value. If a reduction in value has occurred, the impairment is transferred to proved properties. For international operations where a reserve base has not yet been established, the impairment is charged to earnings. Apache began impairing its unproved property costs in Poland in 2001, impairing $20 million ($12 million after tax) in 2002 and the remaining $13 million ($8 million after tax) in 2003. Buildings, equipment and gas gathering, transmission and processing facilities are depreciated on a straight-line basis over the estimated useful lives of the assets, which range from three to 20 years. Accumulated depreciation for these assets totaled $380 million and $309 million at December 31, 2004 and 2003, respectively. GOODWILL -- Goodwill totaled $189 million at December 31, 2004 and 2003, representing the excess of the purchase price over the estimated fair value of the assets acquired and liabilities assumed in the Fletcher Challenge Energy (Fletcher) and Repsol YPF (Repsol) 2001 acquisitions. Approximately $103 million and $86 million of goodwill remain in Canada and Egypt, respectively. Apache deemed the geographic areas to be the reporting unit. Goodwill of each reporting unit is tested for impairment on an annual basis, or more frequently if an event occurs or circumstances change that would reduce the fair value of the reporting unit below its carrying amount. No impairment of goodwill was recognized during 2004, 2003 and 2002. ACCOUNTS PAYABLE -- Included in accounts payable at December 31, 2004 and 2003, are liabilities of approximately $116 million and $78 million, respectively, representing the amount by which checks issued, but not presented to the Company's banks for collection, exceeded balances in applicable bank accounts. REVENUE RECOGNITION -- Oil and gas revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collectibility of the revenue is probable. Cash received relating to future revenues is deferred and recognized when all revenue recognition criteria are met. Apache uses the sales method of accounting for gas production imbalances. The volumes of gas sold may differ from the volumes to which Apache is entitled based on its interests in the properties. These differences create imbalances that are recognized as a liability only when the properties' estimated remaining reserves net to Apache will not be sufficient to enable the underproduced owner to recoup its entitled share through production. The Company's recorded liability of $6 million and $4 million for gas imbalances on December 31, 2004 and 2003, respectively, is reflected in other non-current liabilities. No receivables are recorded for those wells where Apache has taken less than its share of production. Gas imbalances are reflected as adjustments to proved gas reserves and future cash flows in the unaudited supplemental oil and gas disclosures. F-10 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Adjustments for gas imbalances totaled less than one percent of Apache's proved gas reserves as of December 31, 2004, 2003 and 2002. The Company's Egyptian operations are conducted pursuant to production sharing contracts under which contractor partners pay all operating and capital costs for exploring and developing the concessions. A percentage of the production, usually up to 40 percent, is available to the contractor partners to recover all operating and capital costs. The balance of the production is split among the contractor partners and EGPC on a contractually defined basis. Apache began marketing its domestic gas production in July 2003. As the Company's production fluctuates because of operational issues, it is occasionally necessary for the Company to purchase gas ("third-party gas") to fulfill sales obligations and commitments. The trading activities associated with the purchase and sale of the third-party gas are reported on a net basis in oil and gas production revenues. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES -- Apache periodically enters into derivative contracts to manage its exposure to foreign currency risk and commodity price risk. These derivative contracts, which are generally placed with major financial institutions that the Company believes are minimal credit risks, may take the form of forward contracts, futures contracts, swaps or options. The oil and gas reference prices upon which the commodity derivative contracts are based, reflect various market indices that have a high degree of historical correlation with actual prices received by the Company for its oil and gas production. Apache accounts for its derivative instruments in accordance with SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended. SFAS No. 133 establishes accounting and reporting standards requiring that all derivative instruments, other than those that meet the normal purchases and sales exception, be recorded on the balance sheet as either an asset or liability measured at fair value (which is generally based on information obtained from independent parties). SFAS No. 133 also requires that changes in fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Hedge accounting treatment allows unrealized gains and losses on cash flow hedges to be deferred in other comprehensive income. Realized gains and losses from the Company's oil and gas cash flow hedges, including terminated contracts, are generally recognized in oil and gas production revenues when the forecasted transaction occurs. Realized gains and losses on foreign currency cash flow hedges are generally recognized in lease operating expense when the forecasted transaction occurs. Gains and losses from the change in fair value of derivative instruments that do not qualify for hedge accounting are reported in current period income as "other." If at any time the likelihood of occurrence of a hedged forecasted transaction ceases to be "probable," hedge accounting under SFAS No. 133 will cease on a prospective basis and all future changes in the fair value of the derivative will be recognized directly in earnings. Amounts recorded in other comprehensive income prior to the change in the likelihood of occurrence of the forecasted transaction will remain in other comprehensive income until such time as the forecasted transaction impacts earnings. If it becomes probable that the original forecasted production will not occur, then the derivative gain or loss would be reclassified from accumulated other comprehensive income into earnings immediately. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time, and any ineffectiveness is immediately reported under Revenues and Other in the statement of consolidated operations. INCOME TAXES -- Our oil and gas exploration and production operations are currently located in seven 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 is reduced by a valuation allowance. We consider future taxable income in making such assessments. Numerous judgments and assumptions are inherent in the F-11 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and gas prices). Earnings from Apache's international operations are permanently reinvested; therefore, the Company does not recognize U.S. deferred taxes on the unremitted earnings of its international subsidiaries. If it becomes apparent that some or all of the unremitted earnings will be remitted, the Company would then reflect taxes on those earnings. FOREIGN CURRENCY TRANSLATION -- The U.S. dollar has been determined to be the functional currency for each of Apache's international operations. The functional currency is determined country-by-country based on relevant facts and circumstances of the cash flows, commodity pricing environment, and financing arrangements in each country. In light of the continuing transformation of the U.S. and Canadian energy markets into a single energy market, the Company adopted the U.S. dollar as the functional currency in Canada, effective October 1, 2002. Prior to this, our Canadian subsidiaries' functional currency was the Canadian dollar. Translation adjustments resulting from translating the Canadian subsidiaries' foreign currency financial statements into U.S. dollar equivalents were reported separately and accumulated in other comprehensive income. Some of the Company's Canadian subsidiaries had intercompany debt denominated in U.S. dollars. Prior to conversion, these transactions were long-term investments, and therefore, foreign currency gains and losses were recognized in other comprehensive income. Currency translation adjustments held in other comprehensive income on the balance sheet will remain there indefinitely unless there is a substantially complete liquidation of the Company's Canadian operations. The Company accounts for foreign currency gains and losses in accordance with SFAS No. 52 "Foreign Currency Translation." Foreign currency translation gains and losses related to deferred taxes are recorded as a component of its provision for income taxes, while all other foreign currency gains and losses are reflected in Revenues and Other. The Company recorded additional deferred tax expense of $58 million and $172 million in 2004 and 2003, respectively, and a minimal impact in 2002 as a result of the weaker U.S. dollar (see Note 6, Income Taxes). Foreign currency gains and losses netted to a loss of $5 million, $2 million and a gain of $1 million in 2004, 2003 and 2002, respectively. NET INCOME PER COMMON SHARE -- Diluted net income per common share reflects the potential dilution that could occur if outstanding stock awards were issued, outstanding stock options were exercised or if convertible equity securities were converted into common stock. These potentially dilutive securities are excluded from the computation when their effect is antidilutive. Diluted net income per common share for the years ending December 31, 2004 reflects the potential dilution that could occur if the Company's outstanding Share Appreciation Plan shares and Restricted Stock Plan shares were issued and if the Company's dilutive outstanding stock options were exercised (using the average common stock price for the period). Share Appreciation Plan awards became effective during the 2004 period. Diluted net income per common share for the year ending December 31, 2003 reflects the potential dilution that could occur if the Company's dilutive outstanding Restricted Stock Plan shares were issued and if the Company's dilutive outstanding stock options were exercised (using the average common stock price for the period). Diluted net income per common share for the year ending December 31, 2002 reflects the potential dilution that could occur if the Company's outstanding Restricted Stock Plan shares were issued and if the Company's dilutive outstanding stock options were exercised (using the average common stock price for the period) and if the Company's 6.5% Automatically Convertible Equity Securities, Conversion Preferred Stock, F-12 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Series C (Series C Preferred Stock) were converted to common stock, using the conversion rate in effect during the period. The Series C Preferred Stock converted to Apache common stock on May 15, 2002. STOCK-BASED COMPENSATION -- On December 31, 2004, the Company had several stock-based employee compensation plans, which include the Stock Option Plans, the Performance Plan, the 2000 Share Appreciation Plan and restricted stock. These plans are defined and described more fully in Note 8, Capital Stock. Prior to 2003, the Company accounted for these plans under the recognition and measurement provisions of Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees," and related Interpretations (APB No. 25). No material stock-based employee compensation cost is reflected in 2002 net income, as all options granted under those plans had an exercise price equal to the market value of the underlying common stock on the date of grant. Effective January 1, 2003, the Company adopted the fair value recognition provisions of SFAS No. 123, "Accounting for Stock-Based Compensation," as amended by SFAS No. 148, prospectively to all employee awards granted, modified, or settled after January 1, 2003. By adopting SFAS No. 123 on a prospective basis, only the options granted under the plans in 2003 and later were expensed by the Company. Options granted prior to 2003 were still reflected in the income statement based on APB No. 25 and therefore no material expense was recognized. During the fourth quarter of 2004, the Financial Accounting Standards Board (FASB) issued SFAS No. 123-R, a revision to SFAS No. 123, which requires all companies to expense stock-based compensation. The rule is effective for the first interim period that begins after June 15, 2005. Apache early adopted this statement in 2004 electing to transition under the "Modified Retrospective Approach" as allowed under SFAS No. 123-R. Under this approach, the Company is required to expense all options and stock-based compensation that vested in the year of adoption based on the fair value of the stock compensation determined at the date of grant. Stock vesting in years prior to 2004 was expensed in accordance with the rules applied by the Company during such period. Had the Company not early adopted SFAS No. 123-R, net income would have been lower by $89 million ($56 million after tax), or $.17 per share on both a basic and diluted per share basis. Normally, net income would be negatively impacted by adopting SFAS No. 123-R. However, the Company's 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 base cost of approximately $175 million that would have been recorded under the old APB No. 25 accounting. In addition to the expensing provisions discussed above, SFAS No. 123-R requires the Company to begin estimating expected future forfeitures under each stock compensation plan and to start valuing the Company's liability-based compensation plan (Stock Appreciation Rights) under a fair value approach instead of the previously applied intrinsic valuation. The effects of changing the forfeiture estimates on existing stock plans and the valuation methodology for the Company's liability plans resulted in Apache recording a Cumulative Effect of Change in Accounting Principle of $2.1 million ($1.3 million after tax). SFAS No. 123-R also requires the benefits of tax deductions in excess of recognized compensation cost to be reported as a financing cash flow rather than as an operating cash flow as historically reported. This requirement will reduce net operating cash flows and increase net financing cash flows in periods after adoption. In accordance with SFAS No. 123, Apache has historically reflected the pro-forma impact to net income had all stock-based compensation been expensed under the provisions of SFAS No. 123. Upon adoption of SFAS No. 123-R, all stock-based compensation vesting in 2004 has now been reflected in the Company's net income for 2004. 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 following table illustrates the effect on income attributable to common stock and earnings per share for the prior periods had the fair-value based provisions F-13 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) of SFAS No. 123-R been applied to all outstanding and unvested awards for the Stock Option Plans, the Performance Plan, the 2000 Share Appreciation Plan and restricted stock.
FOR THE YEAR ENDED DECEMBER 31, ---------------------- 2003 2002 ---------- -------- (IN THOUSANDS) Income attributable to Common Stock, as reported............ $1,116,205 $543,514 Add: Stock-based employee compensation expense included in reported net income, net of related tax effects........... 2,644 1,208 Deduct: Total stock-based employee compensation expense determined under fair-value based method for all stock-based awards (see Note 8), net of related tax effects................................................... (15,311) (13,574) ---------- -------- Pro forma Income Attributable to Common Stock............... $1,103,538 $531,148 ========== ======== Net Income per Common Share: Basic: As reported............................................ $ 3.46 $ 1.83 Pro forma.............................................. 3.42 1.79 Diluted: As reported............................................ $ 3.43 $ 1.80 Pro forma.............................................. 3.39 1.76
The amounts reflected in the table above are net of amounts capitalized in accordance with the Company's policy regarding salaries and benefits directly attributable to acquisition, exploration and development activities. The pro forma table in prior years did not reflect such costs net of capitalized amounts; however, management does not believe that restating the prior year presentation had a material impact. The stock appreciation rights, described in Note 8, Capital Stock, are not included in the table above because it is a cash-based liability plan already reflected in net income attributable to common stock. USE OF ESTIMATES -- The preparation of financial statements in conformity with accounting principles generally accepted in the U.S., requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and related disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. Apache evaluates its estimates and assumptions on a regular basis. The Company bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of its financial statements. Significant estimates with regard to these financial statements include the estimate of proved oil and gas reserve quantities and the related present value of estimated future net cash flows therefrom. See Note 14, Supplemental Oil and Gas Disclosure (Unaudited). TREASURY STOCK -- The Company follows the weighted-average-cost method of accounting for treasury stock transactions. IMPACT OF RECENTLY ISSUED ACCOUNTING STANDARDS -- On December 21, 2004, the FASB issued Staff Position 109-1 (FSP No. 109-1), Application of FASB Statement No. 109 (SFAS No. 109) "Accounting for Income Taxes," to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004 (the Act). FSP No. 109-1 clarifies guidance that applies to the new tax deduction for F-14 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) qualified domestic production activities. When fully phased-in, the deduction will be up to nine percent of the lesser of "qualified production activities income" or taxable income. FSP No. 109-1 clarifies that the deduction should be accounted for as a special deduction under SFAS No. 109 and will reduce tax expense in the period or periods that the amounts are deductible on the tax return because the deduction is contingent on performing activities identified in the Act. As a result, companies qualifying for the special deduction will not have a one-time adjustment to deferred tax assets and liabilities in the period the Act is enacted. Any tax benefits resulting from the new deduction will be effective for the Company's fiscal year ending December 31, 2005. The Company is in the process of assessing the impact, if any, the new deduction will have on its financial statements. The Act also includes a special one-time dividends received deduction on the repatriation of certain foreign earnings to U.S. taxpayers, provided certain conditions are met. On December 21, 2004, the FASB issued staff position Accounting and Disclosure Guidance for the Foreign Earnings Repatriation Provision within the American Jobs Creation Act of 2004 (FSP No. 109-2). FSP No. 109-2 allows companies additional time to evaluate the effect of the Act as to whether unrepatriated foreign earnings continue to qualify for the SFAS No. 109 exception regarding non-recognition of deferred tax liabilities and requires explanatory disclosure from those who need additional time. The Company is currently assessing the cash needs in all of its operational areas and may decide on a formal plan for repatriation later in 2005. The Company could accrue charges for taxes in future periods depending on the timing of the Company's decisions related to the repatriation. RECLASSIFICATIONS -- Certain other prior period amounts have been reclassified to conform with current year presentations. 2. ACQUISITIONS AND DIVESTITURES 2004 ACQUISITIONS EXXONMOBIL During the third quarter of 2004, Apache entered into separate arrangements with Exxon Mobil Corporation and its affiliates (ExxonMobil) that provided for property transfers and joint operating and exploration activity across a broad range of prospective and mature properties in (1) Western Canada, (2) West Texas and New Mexico, and (3) onshore Louisiana and the Gulf of Mexico-Outer Continental Shelf. Apache's participation included cash payments of approximately $347 million, subject to normal post closing adjustments. The following details these transactions: ExxonMobil -- Western Canada In August 2004, Apache signed a farm-in agreement with ExxonMobil covering approximately 380,000 gross acres of undeveloped properties in the Western Canadian Province of Alberta. Under the agreement, Apache has the right to earn acreage sections by drilling an initial well on each such section. By drilling at least 250 wells during the initial two year earning period under the agreement, Apache will receive a one-year extension in which to earn additional sections. As to any sections earned by Apache, ExxonMobil will retain a 37.5 percent royalty on fee lands and 35 percent of its working interest on leasehold acreage. Under certain circumstances, ExxonMobil has the right to convert its retained 35 percent working interest into a 12.5 percent overriding royalty. In addition, during the term of this agreement, Apache is required to carry ExxonMobil's retained working interest with respect to certain drilling, capping, completion, equipping and tie-in costs associated with wells drilled on leasehold acreage. ExxonMobil -- West Texas and New Mexico In September 2004, Apache acquired interests from ExxonMobil in 23 mature producing oil and gas fields in West Texas and New Mexico for $318 million. Apache separately contributed approximately $29 million into a partnership to obtain additional interests in the properties. ExxonMobil will retain interests in the properties through the partnership, including the right to F-15 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) receive, on certain fields, 60 percent of the oil proceeds above $30 per barrel in 2004, $29 per barrel in 2005 and $28 per barrel during the period from 2006 thru 2009. The partnership is subject to the provisions of FASB Interpretation 46 "variable interest entities" (FIN 46). Apache has concluded that it is not the primary beneficiary of the partnership as defined in that interpretation and will proportionately consolidate its partnership portion of the oil and gas properties. Apache's maximum exposure to loss as a result of its involvement with the partnership is equal to the Company's contribution to the partnership, which is currently $29 million. Under the partnership agreement, the Company's subsidiaries are also subject to environmental and legal claims that could arise in the ordinary course of business. Apache will operate the oil and gas properties under contract for the partnership. ExxonMobil -- Louisiana and Gulf of Mexico-Outer Continental Shelf Also in September 2004, Apache and ExxonMobil entered into joint exploration agreements to explore Apache's acreage in South Louisiana and the Gulf of Mexico-Outer Continental Shelf. The agreements provide for an initial term of five years, with the potential for an additional five years based on expenditures by ExxonMobil. Pursuant to the agreement covering South Louisiana, Apache leased 50 percent of its interests below certain producing or productive formations in the acreage to ExxonMobil, subject to retention of a 20 percent royalty interest. Pursuant to the agreement covering the Gulf of Mexico-Outer Continental Shelf, no assignments will be made until a prospect has been proposed and the initial well has been drilled. Apache will retain all rights in each prospect above certain producing or productive formations and further will retain a three percent overriding royalty interest in any property assigned to ExxonMobil. ANADARKO PETROLEUM On August 20, 2004, Apache signed a definitive agreement to acquire all of Anadarko Petroleum Corporation's (Anadarko) Gulf of Mexico-Outer Continental Shelf properties (excluding certain deepwater properties) for $537 million, subject to normal post-closing adjustments, including preferential rights. The transaction was effective as of October 1, 2004, and included interests in 74 fields covering 232 offshore blocks (approximately 664,000 acres) and 104 platforms. Eighty-nine of the blocks were undeveloped at the time of the acquisition. Apache operates 49 of the fields with approximately 70 percent of the production. Prior to Apache's purchase from Anadarko, Morgan Stanley Capital Group, Inc. (Morgan Stanley) paid Anadarko $646 million to acquire an overriding royalty interest in these properties. Anadarko's sale of an overriding royalty interest to Morgan Stanley is commonly known in the industry as a volumetric production payment (VPP), the obligations of which Apache assumed along with its purchase. Under the terms of the VPP, Morgan Stanley is to receive a fixed volume of oil and natural gas production (20 MMboe) over four years beginning in October 2004. The VPP represents a non-operating interest that is free of costs incurred for operations and production. Morgan Stanley is entitled to first production and may receive up to 90 percent of the production from the assets encumbered by the VPP, but Morgan Stanley may look only to the acquired properties for delivery of the scheduled volumes. The VPP is scheduled to terminate on August 31, 2008, but may be extended if all scheduled VPP volumes have not been delivered to Morgan Stanley and the properties are still producing. The VPP includes restrictions on the Company's ability to sell the properties subject to the VPP or resign as operator of VPP properties it currently operates. Upon termination of the VPP, all rights, titles and interests revert back to Apache. The Company does not record the reserves and production volumes attributable to the VPP. The $537 million purchase price agreed to in the definitive agreement was subsequently adjusted for the exercise of preferential rights by third parties and other normal post-closing adjustments. After adjusting for these items, Apache paid $532 million for the properties and recorded estimated proved reserves of 60 million barrels of oil equivalent (boe), of which 50 percent was natural gas. In addition, an $84 million liability for the future cost to produce and deliver the VPP volumes was recorded by the Company. This liability will be amortized as the volumes are produced and delivered to Morgan Stanley. Apache also recorded abandonment F-16 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) obligations for the properties of approximately $134 million and other obligations assumed from Anadarko in the amount of $27 million. Apache allocated $122 million of the purchase price to unproved property. The purchase price was funded by borrowings under the Company's lines of credit and commercial paper program. In 2004, the Company also completed other acquisitions for $73 million. These acquisitions added approximately 11 MMboe to the Company's proved reserves. 2003 ACQUISITIONS On January 13, 2003, Apache announced that it had entered into agreements to purchase producing properties in the North Sea and Gulf of Mexico from subsidiaries of BP p.l.c. (BP) for $1.3 billion, with $670 million allocated to the Gulf of Mexico properties and $630 million allocated to properties in the North Sea. The properties included estimated proved reserves of 233.2 million barrels of oil equivalent (MMboe), 147.6 MMboe located in the North Sea with the balance in the Gulf of Mexico. Both purchase agreements were effective as of January 1, 2003. As is customary, Apache assumed BP's abandonment obligation for the properties, which was considered in determining the purchase price. Both the Gulf of Mexico and North Sea assets acquired from BP were funded with net proceeds of approximately $554 million from the issuance of 19.8 million shares of common stock in January 2003, and proceeds from additional debt of approximately $604 million borrowed under existing lines of credit and commercial paper. Apache and BP closed the above referenced acquisition of the Gulf of Mexico properties on March 13, 2003, which included BP's interest in 56 producing fields, and 104 blocks. At closing, the $670 million purchase price was adjusted for normal closing items and preferential rights exercised by third parties. The exercise of preferential rights by third parties reduced the purchase price by $73 million and estimated reserves by 9.6 MMboe. The purchase price was further adjusted for various normal closing items, including revenues and expenditures related to the properties for the period between the effective and closing dates. As a result, cash consideration of $509 million was paid by Apache upon closing. In a separate transaction closed February 21, 2003, Apache purchased BP's interest in several other Gulf of Mexico properties with estimated proved reserves of 2.1 MMboe for an adjusted purchase price of $15 million. Including $4 million of transaction costs, total cash consideration for the two acquisitions of Gulf of Mexico properties from BP totaled $528 million. The acquisition of the North Sea properties closed on April 2, 2003, at which time Apache paid a purchase price, adjusted for normal closing and working capital adjustments, of $630 million. The acquisition of the North Sea properties included a 96 percent interest in the Forties Field and established a new core area for the Company. In conjunction with the Forties acquisition, Apache may be required to issue a letter of credit to BP to cover the present value of related asset retirement obligations if the rating of the Company's senior unsecured debt is lowered by both Moody's and Standard and Poor's from its current ratings of A3 and A-, respectively. Should this occur, the letter of credit amount would be 136 million British pounds. Apache agreed to sell all of the North Sea production through December 2004 to BP at a combination of fixed and market sensitive prices pursuant to a contract entered into in connection with the North Sea purchase agreement. F-17 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The BP purchase prices were allocated to the assets acquired and liabilities assumed based upon their estimated fair values as of the date of acquisition, as follows:
U.S. -- U.K. -- GULF OF MEXICO NORTH SEA TOTAL* -------------- --------- ---------- (IN THOUSANDS) Proved property......................................... $539,110 $ 854,835 $1,393,945 Unproved property....................................... 57,500 65,000 122,500 Working capital acquired, net........................... -- 10,957 10,957 Asset retirement obligation............................. (69,000) (250,887) (319,887) Deferred income tax liability........................... -- (50,381) (50,381) -------- --------- ---------- Cash consideration...................................... $527,610 $ 629,524 $1,157,134 ======== ========= ==========
* Property balance includes $12 million of transaction costs (U.S. -- $4 million; North Sea -- $8 million). - --------------- On July 3, 2003, Apache announced that it had completed the acquisition of producing properties on the outer Continental Shelf of the Gulf of Mexico from Shell Exploration and Production Company (Shell) for $200 million, subject to normal post-closing adjustments, including preferential rights. The acquisition included interests in 26 fields and interest in two onshore gas plants, and was effective July 1, 2003. Apache became operator of 15 of the fields with 91 percent of the production. At the time of the acquisition, Apache recorded estimated proved recoverable reserves of 124.6 billion cubic feet (Bcf) of natural gas and 6.6 million barrels of oil. Prior to Apache's transaction with Shell, Morgan Stanley paid Shell $300 million to acquire an overriding royalty interest in a portion of the reserves to be produced and delivered under a VPP agreement. Under the terms of the VPP obligation which Apache assumed, Morgan Stanley is to receive a total of 11.4 MMboe of production from the properties over the period from August 2003 through October 2007. Morgan Stanley may receive up to 90 percent of production associated with Apache's interest, but may look only to the properties for delivery of the scheduled volumes. The VPP may be extended beyond October 2007 if all scheduled VPP volumes have not been delivered to Morgan Stanley and the acquired properties are still producing. The VPP represents a non-operating interest that is free of all costs related to operations and production. As a result of this VPP obligation, Apache assumed and recorded a $60 million liability for the future cost to produce and deliver volumes subject to the VPP. This liability is being amortized as the volumes are produced and delivered to Morgan Stanley. Apache does not record the reserves or production attributable to the VPP volumes. Apache's purchase price was funded by borrowings under the Company's lines of credit and commercial paper program. In 2003, the Company also completed other acquisitions for $126 million. These acquisitions added approximately 28 MMboe to the Company's proved reserves. 2002 ACQUISITIONS On December 17, 2002, Apache announced the acquisition of certain South Louisiana properties comprising 234,000 net acres (366 square miles) with net proved reserves of approximately 29.8 MMboe, 88 percent of which is natural gas, from a private company. The acquisition included 135 producing wells, access to 849 square miles of 3-D seismic covering the relatively contiguous acreage position and ownership of the surface and mineral rights on most of the acreage, for approximately $259 million, subject to post-closing adjustments. Apache also entered into a separate exploration joint venture with the seller whereby the seller was to have actively generated prospects on certain South Louisiana acreage for a total cost of $25 million. This obligation was fulfilled during 2004. F-18 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) In 2002, the Company also completed other acquisitions for $95 million. These acquisitions added approximately 19.5 MMboe to the Company's proved reserves. ACQUISITION PRO FORMA The following unaudited pro forma information shows the effect on the Company's consolidated results of operations as if the acquisition from BP occurred on January 1, 2002. The pro forma information includes numerous assumptions, and is not necessarily indicative of future results of operations:
FOR THE YEAR ENDED DECEMBER 31, ------------------------------------------------------ 2003 2002 ------------------------- ------------------------- AS REPORTED PRO FORMA AS REPORTED PRO FORMA ----------- ---------- ----------- ---------- (UNAUDITED) (IN THOUSANDS, EXCEPT PER COMMON SHARE DATA) Revenues and other............................ $4,190,229 $4,428,261 $2,559,873 $3,490,487 Net income.................................... 1,121,885 1,195,082 554,329 683,284 Preferred stock dividends..................... 5,680 5,680 10,815 10,815 Income attributable to common stock........... 1,116,205 1,189,402 543,514 672,469 Net income per common share: Basic....................................... $ 3.46 $ 3.68 $ 1.83 $ 2.12 Diluted..................................... 3.43 3.64 1.80 2.09 Average common shares outstanding(1).......... 322,498 323,583 297,234 317,036
(1) Pro forma shares assume the issuance of 19.8 million common shares as of January 1, 2002. - --------------- Each transaction described above has been accounted for using the purchase method of accounting and has been included in the consolidated financial statements of Apache since the date of acquisition. DIVESTITURES During 2004, Apache sold marginal properties containing .5 MMboe of proved reserves, for $4 million. Apache used the sales proceeds to reduce bank debt. During 2003, Apache sold marginal properties containing 6.9 MMboe of proved reserves, for $59 million. Apache used the sales proceeds to reduce bank debt. During 2002, Apache sold marginal properties containing 1.8 MMboe of proved reserves, for $7 million. Apache used the sales proceeds to reduce bank debt. 3. HEDGING AND DERIVATIVE INSTRUMENTS Apache uses a variety of strategies to manage its exposure to fluctuations in crude oil and natural gas commodity prices. As established by the Company's hedging policy, Apache primarily enters into cash flow hedges in connection with selected acquisitions to protect against commodity price volatility. The success of these acquisitions is significantly influenced by Apache's ability to achieve targeted production at forecasted prices. These hedges effectively reduce price risk on a portion of the production from the acquisitions. Apache entered into, and designated as cash flow hedges, various fixed-price swaps, option collars and puts in conjunction with the Anadarko, ExxonMobil, BP and certain South Louisiana property acquisitions. These positions were entered into in accordance with the Company's hedging policy and involved several F-19 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) counterparties, all of which are rated A+ or better. As of December 31, 2004, the outstanding positions of our natural gas and crude oil cash flow hedges were as follows:
TOTAL WEIGHTED FAIR VALUE VOLUMES AVERAGE ASSET/ PRODUCTION PERIOD INSTRUMENT TYPE (MMBTU/BBL) FLOOR/CEILING (LIABILITY) - ----------------- -------------------- ----------- ------------- -------------- (IN THOUSANDS) 2005........................... Gas Collars 34,600,000 $5.28/$6.36 $ (9,337) Gas Fixed-Price Swap 8,292,000 6.25 220 Oil Collars 3,577,000 33.51/41.72 (11,718) Oil Fixed-Price Swap 358,000 41.36 (437) Oil Put Option 1,533,000 28.00 597 2006........................... Gas Collars 32,850,000 5.50/6.66 (7,116) Gas Fixed-Price Swap 4,404,000 5.87 (1,709) Oil Collars 4,307,000 32.07/40.66 (12,381) Oil Fixed-Price Swap 224,000 38.50 (376) Oil Put Option 1,533,000 28.00 1,678 2007........................... Gas Collars 24,570,000 5.25/6.20 (4,291) Gas Fixed-Price Swap 1,761,000 5.57 (574) Oil Collars 1,911,000 33.00/39.25 (4,822) Oil Fixed-Price Swap 78,000 36.89 (149)
The natural gas and crude oil prices shown in the above table are based on the NYMEX index and have been valued using actively quoted prices and quotes obtained from the counterparties to the derivative agreements. The above prices represent a weighted average of several contracts entered into and are on a per MMBtu or per barrel basis for gas and oil derivatives, respectively. Apache entered into a separate crude oil physical sales contract with BP in February 2003, which ended December 31, 2004. Under the terms of the agreement, Apache physically delivered 22.5 million barrels of crude oil at an average fixed Brent index price of $23.38 per barrel. The contract was designated as a normal purchase and sale under SFAS No. 133 and, therefore, the Company accounted for the contract under the accrual method. In November 2004, Apache began hedging a portion of its 2005 foreign currency exchange risk associated with its forecasted Canadian, Australian and North Sea lease operating expenditures by entering into forward purchase contracts. The Company purchased a total of $144 million Canadian dollars at an average exchange rate of .840, $22 million Australian dollars at an average exchange rate of .763 and 42 million British pounds at an average exchange rate of 1.853. The forward contracts mature from January through December 2005. The fair market value of these contracts as of December 31, 2004 was $1.2 million ($700,000 after tax). Future changes in market value are recorded in other comprehensive income (loss) and the fair values of the foreign exchange are based on quotes from either third parties or published indices. A reconciliation of the components of accumulated other comprehensive income (loss) in the statement of consolidated shareholders' equity related to Apache's commodity and foreign currency derivative activities is presented in the table below:
GROSS AFTER TAX -------- --------- (IN THOUSANDS) Unrealized loss on derivatives at December 31, 2003......... $(69,316) $(43,193) Net losses realized into earnings........................... 103,874 64,917 Net change in derivative fair value......................... (67,671) (42,456) -------- -------- Unrealized loss on derivatives at December 31, 2004......... $(33,113) $(20,732) ======== ========
F-20 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Differences between the fair values and the unrealized loss on derivatives before income taxes recognized in accumulated other comprehensive income (loss) are primarily related to premiums, recognition of unrealized gains and losses on certain derivatives that did not qualify for hedge accounting and hedge ineffectiveness. Based on applicable market prices as of year-end 2004, the Company recorded an unrealized loss in other comprehensive income (loss) of $33 million ($21 million after tax), primarily representing oil and gas derivative hedges. Any loss will be realized in future earnings contemporaneously with the related sales of natural gas and crude oil production applicable to specific hedges. Of the $33 million unrealized loss on derivatives at December 31, 2004, approximately $4 million ($3 million after tax) applies to the next 12 months. However, these amounts are likely to vary materially as a result of changes in market conditions. The contracts designated as hedges qualified and continue to qualify for hedge accounting in accordance with SFAS No. 133, as amended. 4. ASSET RETIREMENT OBLIGATION In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 requires that an asset retirement obligation (ARO) associated with the retirement of a tangible long-lived asset be recognized as a liability in the period in which a legal obligation is incurred and becomes determinable, with an offsetting increase in the carrying amount of the associated asset. The cost of the tangible asset, including the initially recognized ARO, is depleted such that the cost of the ARO is recognized over the useful life of the asset. The ARO is recorded at fair value, and accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. The fair value of the ARO is measured using expected future cash outflows discounted at the company's credit-adjusted risk-free interest rate. The Company adopted SFAS No. 143 on January 1, 2003, and recorded an increase to net oil and gas properties of $410 million and associated liabilities of $369 million. These amounts reflect the ARO of the company had the provisions of SFAS No. 143 been applied since inception and resulted in a non-cash cumulative effect increase to earnings of $27 million ($41 million pre-tax). In accordance with the provisions of SFAS No. 143, Apache records an abandonment liability associated with its oil and gas wells and platforms when those assets are placed in service, rather than its past practice of accruing the expected undiscounted abandonment costs on a unit-of-production basis over the productive life of the associated full-cost pool. Under SFAS No. 143, depletion expense is reduced since a discounted ARO is depleted in the property balance rather than the undiscounted value previously depleted under the old rules. The lower depletion expense under SFAS No. 143 is offset, however, by accretion expense, which is recognized over time as the discounted liability is accreted to its expected settlement value. Inherent in the fair value calculation of ARO 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 fair value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property balance. The $27 million ($41 million pre-tax) cumulative increase to earnings upon adoption did not take into consideration potential impacts of adopting SFAS No. 143 on previous full-cost property impairment tests. The Company chose not to re-calculate historical full-cost impairment tests (ceiling test) upon adoption even though historical oil and gas property balances would have been higher had the Company applied the provisions of the statement. Management believes this approach is appropriate because SFAS No. 143 is silent on this issue and was not effective during the prior ceiling test periods. Had the Company re-calculated the historical full-cost ceiling tests and included the impact as a component of the cumulative effect of adoption, the ultimate gain recognized would have potentially been reduced. A ceiling test calculation was performed F-21 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) upon adoption and at the end of each reporting period subsequent to adoption and no impairment was necessary. The following table is a reconciliation of the asset retirement obligation liability since adoption:
2004 2003 -------- -------- (IN THOUSANDS) Asset retirement obligation at beginning of period.......... $739,775 $368,537 Liabilities incurred........................................ 199,505 392,287 Liabilities settled......................................... (47,784) (35,315) Accretion expense........................................... 46,060 37,763 Revisions in estimated liabilities.......................... (5,552) (23,497) -------- -------- Asset retirement obligation at December 31,................. $932,004 $739,775 ======== ========
Liabilities incurred as of 2004 and 2003 primarily relate to asset retirement obligations assumed in connection with the Anadarko, ExxonMobil, BP Gulf of Mexico, BP North Sea, and Shell property acquisitions. Liabilities settled during the period relate to individual properties plugged and abandoned or sold during the period. The downward revisions to the estimated liability resulted from annual reassessments of the expected cash outflows and assumptions inherent in the ARO calculation. The pro forma effect of the implementation on the Company's Income Attributable to Common Stock and Net Income per Common Share had SFAS No. 143 been adopted by the Company on January 1, 2002 would not have been material. 5. DEBT Long-Term Debt
DECEMBER 31, ------------------------ 2004 2003 ---------- ---------- (IN THOUSANDS) Apache: Money market lines of credit.............................. $ 4,000 $ 5,200 Commercial paper.......................................... 392,000 130,000 6.25-percent debentures due 2012, net of discount......... 397,758 397,525 7-percent notes due 2018, net of discount................. 148,570 148,506 7.625-percent notes due 2019, net of discount............. 149,190 149,161 7.7-percent notes due 2026, net of discount............... 99,671 99,665 7.95-percent notes due 2026, net of discount.............. 178,659 178,636 7.375-percent debentures due 2047, net of discount........ 148,021 148,014 7.625-percent debentures due 2096, net of discount........ 149,175 149,175 ---------- ---------- 1,667,044 1,405,882 ---------- ---------- Subsidiary and other obligations: Fletcher notes............................................ 5,356 5,356 Apache Finance Australia 6.5-percent notes due 2007, net of discount............................................ 169,530 169,390 Apache Finance Australia 7-percent notes due 2009, net of discount............................................... 99,662 99,597 Apache Finance Canada 4.375-percent notes due 2015, net of discount............................................... 349,709 349,688 Apache Finance Canada 7.75-percent notes due 2029, net of discount............................................... 297,089 297,053 ---------- ---------- 921,346 921,084 ---------- ---------- Total debt.................................................. 2,588,390 2,326,966 Less: current maturities.................................... -- -- ---------- ---------- Long-term debt.............................................. $2,588,390 $2,326,966 ========== ==========
F-22 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Apache currently has $1.5 billion of syndicated bank credit facilities. These credit facilities consist of four separate committed bank facilities: a new $750 million five-year facility in the U.S. that matures on May 28, 2009; a $450 million facility in the U.S. that matures June 3, 2007; a $150 million facility in Australia that matures June 3, 2007 and a $150 million facility in Canada that matures June 3, 2007. On May 28, 2004, the Company's $750 million 364-day U.S. credit facility matured and was replaced with the new $750 million five-year facility noted above. Also on this date, the Company amended its existing $450 million facility and its two existing $150 million facilities in order to make their terms consistent with the new five-year facility. Significant changes included raising the cross-default threshold, increasing flexibility under the negative lien covenant and eliminating covenants which established minimum levels for tangible net worth and book values for assets of Apache and certain subsidiaries. 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, which approximated $775 million as of December 31, 2004. 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, 2004. The Company's debt-to-capitalization ratio as of December 31, 2004 was 24 percent. At the Company's option, the interest rate for the facilities is based on (i) the greater of (a) The JP Morgan Chase Bank prime rate or (b) the federal funds rate plus one-half of one percent or (ii) the London Interbank Offered Rate (LIBOR) plus a margin determined by the Company's senior long-term debt rating. The $750 million and the $450 million credit facilities (U.S. credit facilities) also allow the Company to borrow under competitive auctions. At December 31, 2004, the margin over LIBOR for committed loans was .27 percent on the $750 million facility and .30 percent on the other three facilities. If the total amount of the loans borrowed under the $750 million facility equals or exceeds 50 percent of the total facility commitments, then an additional .10 percent will be added to the margins over LIBOR. If the total amount of the loans borrowed under all of the other three facilities equals or exceeds 33 percent of the total facility commitments, then an additional .125 percent will be added to the margins over LIBOR. The Company also pays quarterly facility fees of .08 percent on the total amount of the $750 million facility and .10 percent on the total amount of the other three facilities. The facility fees vary based upon the Company's senior long-term debt rating. The U.S. credit facilities are used to support Apache's commercial paper program. The available borrowing capacity under the credit facilities at December 31, 2004 was $1.1 billion. At December 31, 2004, the Company also had certain uncommitted money market lines of credit which are used from time to time for working capital purposes, under which an aggregate of $4 million was outstanding as of December 31, 2004. Such borrowings are classified as long-term debt in the accompanying F-23 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) consolidated balance sheet as the Company has the ability and intent to refinance such amounts on a long-term basis through available borrowing capacity under its U.S. credit facilities. The Company has a $1.2 billion commercial paper program which enables Apache to borrow funds for up to 270 days at competitive interest rates. The commercial paper balances at December 31, 2004 and 2003 were classified as long-term debt in the accompanying consolidated balance sheet as the Company has the ability and intent to refinance such amounts on a long-term basis through either the rollover of commercial paper or available borrowing capacity under the U.S. credit facilities. The weighted-average interest rate for commercial paper was 1.79 percent in 2004 and 1.19 percent in 2003. On May 15, 2003, Apache Finance Canada Corporation (Apache Finance Canada) issued $350 million of 4.375 percent, 12-year, senior unsecured notes in a private placement. On March 4, 2004, the Company completed an exchange offer with the holders of the notes, issuing publicly traded, registered notes of the same principal amount and with the same interest rates, payment terms and maturity. The notes are irrevocably and unconditionally guaranteed by Apache and are redeemable, as a whole or in part, at Apache Finance Canada's option, subject to a make-whole premium. Interest is payable semi-annually on May 15 and November 15 of each year commencing on November 15, 2003. The proceeds of the original note offering were used to reduce bank debt and outstanding commercial paper and for general corporate purposes. The Company does not have the right to redeem any of its notes or debentures (other than the Apache Corporation 6.25-percent notes due April 15, 2012, the Apache Finance Australia 6.5-percent notes due 2007 and the Apache Finance Canada 4.375-percent notes due 2015) prior to maturity. Under certain conditions, the Company has the right to advance maturity on the 7.7-percent notes, 7.95-percent notes, 7.375-percent debentures and 7.625-percent debentures. The notes issued by Apache Finance Pty Ltd (Apache Finance Australia) and Apache Finance Canada are irrevocably and unconditionally guaranteed by Apache and, in the case of Apache Finance Australia, by Apache North America, Inc., an indirect wholly-owned subsidiary of the Company. Under certain conditions related to changes in relevant tax laws, Apache Finance Australia and Apache Finance Canada have the right to redeem the notes prior to maturity. The Apache Finance Australia 6.5-percent notes and the Apache Finance Canada 4.375-percent notes may be redeemed at the Company's option subject to a make-whole premium (see Note 16. Supplemental Guarantor Information). The $13 million of discounts on the Company's debt as of December 31, 2004, is being amortized over the life of the debt issuances as additional interest expense. As of December 31, 2004 and 2003, the Company had approximately $21 million and $22 million, respectively, of unamortized deferred loan costs associated with its various debt obligations. These costs are included in deferred charges and other in the accompanying consolidated balance sheet and are being amortized to expense over the life of the related debt. The indentures for the notes described above place certain restrictions on the Company, including limits on Apache's ability to incur debt secured by certain liens and its ability to enter into certain sale and leaseback transactions. Upon certain change in control, all of these debt instruments would be subject to mandatory repurchase, at the option of the holders. F-24 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Aggregate Maturities of Debt
(IN THOUSANDS) 2005........................................................ $ -- 2006........................................................ 274 2007........................................................ 172,530 2008........................................................ 353 2009........................................................ 496,492 Thereafter.................................................. 1,918,741 ---------- $2,588,390 ==========
The Company made cash payments for interest, net of amounts capitalized, of $107 million, $96 million and $99 million for the years ended December 31, 2004, 2003 and 2002, respectively. 6. INCOME TAXES Income before income taxes is composed of the following:
FOR THE YEAR ENDED DECEMBER 31, ------------------------------------ 2004 2003 2002 ---------- ---------- ---------- (IN THOUSANDS) United States............................................ $1,120,906 $ 918,432 $ 286,840 Foreign.................................................. 1,542,177 1,003,825 612,130 ---------- ---------- ---------- Total.................................................. $2,663,083 $1,922,257 $ 898,970 ========== ========== ==========
The total provision for income taxes consists of the following:
FOR THE YEAR ENDED DECEMBER 31, --------------------------------- 2004 2003 2002 --------- --------- --------- (IN THOUSANDS) Current taxes: Federal................................................... $145,164 $ 37,472 $ 25,657 State..................................................... 4,330 2,296 1,564 Foreign................................................... 398,612 240,879 179,748 Deferred taxes.............................................. 444,906 546,357 137,672 -------- -------- -------- Total..................................................... $993,012 $827,004 $344,641 ======== ======== ========
F-25 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) A reconciliation of the U.S. federal statutory income tax amounts to the effective amounts is shown below:
FOR THE YEAR ENDED DECEMBER 31, --------------------------------- 2004 2003 2002 --------- --------- --------- (IN THOUSANDS) Statutory income tax........................................ $932,079 $672,790 $314,639 State income tax, less federal benefit...................... 28,023 22,961 7,171 Taxes related to foreign operations......................... 86,263 49,657 35,283 Realized tax basis in investment............................ (16,923) (23,234) (16,321) Canadian tax rate reduction................................. (31,350) (71,340) -- Additional deferred taxes related to currency fluctuations.............................................. 58,049 171,930 -- Australian consolidation benefit from tax law change........ (50,713) -- -- Benefit of previously unrecognized Canadian losses.......... (18,226) -- -- All other, net.............................................. 5,810 4,240 3,869 -------- -------- -------- $993,012 $827,004 $344,641 ======== ======== ========
The net deferred tax liability is comprised of the following:
DECEMBER 31, ----------------------- 2004 2003 ---------- ---------- (IN THOUSANDS) Deferred tax assets: Deferred income........................................... $ (1,473) $ (1,446) Federal net operating loss carryforwards.................. -- (21,781) State net operating loss carryforwards.................... (9,500) (19,693) Statutory depletion carryforwards......................... -- (5,723) Alternative minimum tax credits........................... -- (9,141) Foreign net operating loss carryforwards.................. (224,137) (206,548) Accrued expenses and liabilities.......................... (5,465) (5,683) Other..................................................... (830) (5,401) ---------- ---------- Total deferred tax assets.............................. (241,405) (275,416) Valuation allowance....................................... -- -- ---------- ---------- Net deferred tax assets................................ (241,405) (275,416) ---------- ---------- Deferred tax liabilities: Depreciation, depletion and amortization.................. 2,388,042 1,972,654 ---------- ---------- Total deferred tax liabilities......................... 2,388,042 1,972,654 ---------- ---------- Net deferred income tax liability........................... $2,146,637 $1,697,238 ========== ==========
The Company has not recorded deferred income taxes on the undistributed earnings of its foreign subsidiaries as management intends to permanently reinvest such earnings. As of December 31, 2004, the undistributed earnings of the foreign subsidiaries amounted to approximately $4.7 billion. Upon distribution of these earnings in the form of dividends or otherwise, the Company may be subject to U.S. income taxes and foreign withholding taxes. It is not practical, however, to estimate the amount of taxes that may be payable on the eventual remittance of these earnings after consideration of available foreign tax credits. Presently, limited foreign tax credits are available to reduce the U.S. taxes on such amounts if repatriated. Refer to Note 1, Summary of Significant Accounting Policies, "Impact of Recently Issued Accounting Standards" for a discussion of the potential impact on repatriated earnings resulting from the American Jobs Creation Act of 2004. F-26 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) At December 31, 2004, the Company had state net operating loss carryforwards of $198 million and foreign net operating loss carryforwards of $14 million for China and $553 million for the United Kingdom. The state net operating losses will expire over the next 20 years, if they are not otherwise utilized. The foreign net operating loss for China has a five-year carryover period while the United Kingdom loss has an unlimited carryover period. The Company is currently under examination by the Internal Revenue Service for income tax years 2002 and 2003. The Company believes that it has adequately provided for income taxes. The Company made payments for income and other taxes, net of refunds, of $466 million, $309 million and $171 million for the years ended December 31, 2004, 2003 and 2002, respectively. 7. ADVANCES FROM GAS PURCHASERS In July 1998, Apache received $72 million from a purchaser as an advance payment for future natural gas deliveries ranging from 6,726 MMBtu per day to 24,669 MMBtu per day, for a total of 45,330,949 MMBtu, over a ten-year period commencing August 1998. In addition, the purchaser pays Apache a monthly fee of $.08 per MMBtu on the contracted volumes. Concurrent with this arrangement, Apache entered into three gas price swap contracts with a third party under which Apache became a fixed price payor for identical volumes at prices ranging from $2.34 per MMBtu to $2.56 per MMBtu. The net result of these related transactions was that gas delivered to the purchaser was reported as revenue at prevailing spot prices with Apache realizing a premium associated with the monthly fee paid by the purchaser. In August 1997, Apache received $115 million from a purchaser as an advance payment for future natural gas deliveries of 20,000 MMBtu per day over a ten-year period commencing September 1997. In addition, the purchaser pays Apache a monthly fee of $.07 per MMBtu on the contracted volumes. Concurrent with this arrangement, Apache entered into two gas price swap contracts with a third party under which Apache became a fixed price payor for identical volumes at average prices starting at $2.19 per MMBtu in 1997 and escalating to $2.59 per MMBtu in 2007. The net result of these related transactions was that gas delivered to the purchaser was reported as revenue at prevailing spot prices with Apache realizing a premium associated with the monthly fee paid by the purchaser. Contracted volumes relating to these arrangements are included in the Company's unaudited supplemental oil and gas disclosures. These advance payments have been classified as advances from gas purchasers and are being recognized in oil and gas production revenues as gas is delivered to the purchasers under the terms of the contracts. On December 31, 2004 and 2003, advances of $91 and $109 million, respectively, were outstanding. Gas volumes delivered to the purchaser are reported as revenue at prices used to calculate the amount advanced, before imputed interest, plus or minus amounts paid or received by Apache applicable to the price swap agreements. Interest expense is recorded based on a rate of eight percent. In October and November 2001, Apache terminated the gas price swap contracts associated with these advances and received proceeds of $78 million. The effect of terminating these derivative instruments reduces future price risk exposure to natural gas price volatility by establishing a fixed price for the remaining quantities of gas to be delivered under the terms of the contracts. Upon termination, Apache designated the remaining contractual volumes of gas that will be delivered to the purchasers as a normal fixed-price physical sale. The prices used in settling the derivatives represented an average 51 percent increase over the prices reflected in the original contracts. No gain or loss was recognized upon termination of the gas swap contract. The settlement is carried as advances from gas purchases on the consolidated balance sheet and will be recognized in monthly sales based on the portion of the proceeds applicable to each production month over the remaining life of the contracts. F-27 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 8. CAPITAL STOCK Common Stock Outstanding
2004 2003 2002 ----------- ----------- ----------- Balance, beginning of year............................. 324,497,176 302,506,424 287,916,676 Treasury shares issued (acquired), net................. 66,080 130,636 121,432 Shares issued for: Public offering (2).................................. -- 19,803,000 -- Conversion of Series C Preferred Stock (1)........... -- -- 13,109,730 Stock compensation plans............................. 2,897,327 2,101,844 1,358,586 Fractional shares repurchased........................ (3,080) (44,728) -- ----------- ----------- ----------- Balance, end of year (3)............................... 327,457,503 324,497,176 302,506,424 =========== =========== ===========
(1) In May 2002, we completed the mandatory conversion of our Series C preferred stock into approximately 13.1 million common shares. (2) On January 22, 2003, in conjunction with the BP transaction, we completed a public offering of 19.8 million shares of common stock, including 2.6 million shares for the underwriters' over-allotment option, raising net proceeds of $554 million. (3) On December 18, 2003, the Company announced that holders of its common stock approved a proposal to increase the number of authorized common shares to 430 million from 215 million in order to complete a previously announced two-for-one stock split. The record date for the stock split was December 31, 2003 and the additional shares were distributed on January 14, 2004. NET INCOME PER COMMON SHARE A reconciliation of the components of basic and diluted net income per common share for the years ended December 31, 2004, 2003 and 2002 is presented in the table below:
2004 2003 2002 -------------------------------- -------------------------------- ------------------------------ INCOME SHARES PER SHARE INCOME SHARES PER SHARE INCOME SHARES PER SHARE ---------- ------- --------- ---------- ------- --------- -------- ------- --------- (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) BASIC: Income attributable to common stock........... $1,663,074 326,046 $5.10 $1,116,205 322,498 $3.46 $543,514 297,234 $1.83 ========= ========= ========= EFFECT OF DILUTIVE SECURITIES: Stock options and other.................. -- 4,431 -- 2,832 -- 2,566 Series C Preferred Stock.................. -- -- -- -- 5,149 4,812 ---------- ------- ---------- ------- -------- ------- DILUTED: Income attributable to common stock, including assumed conversions.... $1,663,074 330,477 $5.03 $1,116,205 325,330 $3.43 $548,663 304,612 $1.80 ========== ======= ========= ========== ======= ========= ======== ======= =========
During 2002, Apache began modifying its stock compensation plans in order to reflect the cost of these plans in the Statement of Consolidated Operations. As part of this effort, Apache began issuing stock appreciation rights and restricted stock and, effective January 1, 2003, adopted the expense provisions of SFAS No. 123, as amended, on a prospective basis for all stock options granted under the Company's existing option plans. Consistent with the Company's desire to expense stock compensation plans, Apache early adopted the provisions of SFAS 123-R upon the FASBs issuance of the revision in the fourth quarter of 2004. See Note 1, Summary of Significant Accounting Policies. F-28 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) STOCK DIVIDENDS On December 18, 2002, the Company's Board of Directors declared a five percent stock dividend payable on April 2, 2003 to shareholders of record on March 12, 2003. As a result, in December 2002, the Company reclassified approximately $396 million from retained earnings to common stock and paid-in capital, which represents the fair market value at the date of declaration of the shares distributed. Since the Company's January 22, 2003 public offering of 19.8 million shares of common stock occurred prior to the record date, an additional $26 million was reclassified from retained earnings to common stock and paid-in capital. No fractional shares were issued and cash payments totaling $1 million were made in lieu of fractional shares. TWO-FOR-ONE STOCK SPLIT On December 18, 2003, the Company announced that holders of its common stock approved an increase in the number of authorized common shares to 430 million from 215 million in order to complete a previously announced two-for-one stock split. The record date for the stock split was December 31, 2003 and the additional shares were distributed on January 14, 2004. STOCK OPTION PLANS On December 31, 2004, officers and employees have options to purchase shares of the Company's common stock under one or more employee stock option plans adopted in 1995, 1998 and 2000 (collectively, the Stock Option Plans). Under the Stock Option Plans, the exercise price of each option equals the market price of Apache's common stock on the date of grant. Options generally become exercisable ratably over a four-year period and expire after 10 years. The 2000 Stock Option Plan also permits the Company to issue options with a reload provision, which has been included in certain options granted to officers and certain key employees of the Company. Options with reload provisions vest over two years, in equal installments every six months. The reload provision permits the granting of new options for shares with a current market value equal to any portion of the original option exercise price, or withholding taxes due on the exercise of the original option, paid by the optionee by means of the transfer or attestation of ownership of shares of the Company's common stock or units in the Company's Deferred Delivery Plan (if the income from the exercise is to be deferred into that plan). The Deferred Delivery Plan allows the executive officers and certain key employees of the Company to defer the receipt of income from equity compensation plans such as the Company's Stock Option Plans. The new option granted as a reload vests after six months, expiring on the same date as the original option. 1996 PERFORMANCE STOCK OPTION PLAN On October 31, 1996, the Company established the 1996 Performance Stock Option Plan (the Performance Plan) for substantially all full-time employees, excluding officers and certain key employees. Under the Performance Plan, the exercise price of each option equals the market price of Apache common stock on the date of grant. All options become exercisable after nine and one-half years and expire 10 years from the date of grant. Under the terms of the Performance Plan, no grants were made after December 31, 1998. F-29 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) A summary of the status of the plans described above as of December 31, 2004, 2003 and 2002, and changes during the years then ended, is presented in the table and narrative below (shares in thousands):
2004 2003 2002 ------------------ ------------------ ------------------ WEIGHTED WEIGHTED WEIGHTED SHARES AVERAGE SHARES AVERAGE SHARES AVERAGE UNDER EXERCISE UNDER EXERCISE UNDER EXERCISE OPTION PRICE OPTION PRICE OPTION PRICE ------- -------- ------- -------- ------- -------- Outstanding, beginning of year...... 9,141 $20.59 11,328 $19.53 11,544 $17.62 Granted............................. 290 44.73 280 30.97 1,786 27.99 Exercised........................... (1,913) 20.35 (2,198) 8.54 (1,544) 14.88 Forfeited........................... (176) 25.39 (269) 11.43 (458) 20.21 ------- ------- ------- Outstanding, end of year(3)......... 7,342 21.33 9,141 20.59 11,328 19.53 ======= ======= ======= Exercisable, end of year(3)......... 4,250 20.36 5,146 19.21 5,731 17.25 ======= ======= ======= Available for grant, end of year.... 2,819(2) 3,042 1,068 ======= ======= ======= Weighted average fair value of options granted during the year(1)........................... $ 14.45 $ 10.14 $ 10.14 ======= ======= =======
(1) The fair value of each option is estimated as of the date of grant using the Black-Scholes option-pricing model with the following weighted-average assumptions used for grants in 2004, 2003 and 2002, respectively: (i) risk-free interest rates of 3.65, 2.86 and 4.87 percent; (ii) expected lives of 4.5 years for 2004, 2003 and 2002 for the Stock Option Plans; (iii) historical volatility of 36.09, 36.60 and 37.17 percent; and (iv) expected dividend yields of .55, .66 and .68 percent. (2) As of February 10, 2005, the Company's authority to issue option grants under its existing Stock Option Plans terminated. At the time of termination, 2,537,877 shares of the Company's common stock that were previously authorized for new grants became unavailable for such purpose. The only provisions of these plans that are still effective are those governing grants previously made under the applicable plan. (3) As of December 31, 2004, the remaining contractual life for options outstanding and exercisable is 4.9 years and 5.0 years, respectively. The following table summarizes information about stock options covered by the plans described above that are outstanding as of December 31, 2004 (shares in thousands):
OPTIONS OUTSTANDING OPTIONS EXERCISABLE ------------------------------------ ---------------------- NUMBER OF WEIGHTED NUMBER OF SHARES AVERAGE WEIGHTED SHARES WEIGHTED UNDER REMAINING AVERAGE UNDER AVERAGE OUTSTANDING CONTRACTUAL EXERCISE EXERCISABLE EXERCISE RANGE OF EXERCISE PRICES OPTIONS LIFE PRICE OPTIONS PRICE ------------------------ ----------- ----------- -------- ----------- -------- $ 7.37 - $18.37......................... 3,463 2.79 $15.07 1,824 $14.81 19.68 - 28.78......................... 3,550 6.55 25.41 2,411 24.46 32.97 - 42.68......................... 223 9.15 40.45 15 36.23 45.30 - 54.06......................... 106 9.79 49.16 -- -- ----------- ----------- 7,342 4,250 =========== ===========
The Company expensed $8 million ($5 million after-tax), $1 million and $1 million for 2004, 2003 and 2002, respectively, for the stock option plans described above. In 2004, $4 million of the compensation cost was capitalized as part of oil and gas properties. The intrinsic value of options exercised during 2004 was approximately $46 million and the Company realized an additional tax benefit of approximately $14 million F-30 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) for the amount of intrinsic value in excess of compensation cost recognized. The aggregate intrinsic value of options outstanding and exercisable at year-end was $215 million and $128 million, respectively. STOCK APPRECIATION RIGHTS During 2003, the Company began issuing stock appreciation rights (SARs) to non-executive employees in lieu of stock options. A total of 1,328,400 and 1,802,210 SARs were issued during 2004 and 2003, respectively, and will be settled in cash upon exercise throughout the SARs 10-year life. The weighted-average exercise price of the SARs is $42.68 and $28.78 for those issued in 2004 and 2003, respectively. The vesting period is over four years and the Company records compensation expense on the vested SARs outstanding based on the fair value of the SARs at the end of each period. As of year-end, the weighted-average fair value of SARs outstanding was $23.37 based on the Black-Scholes valuation methodology. The number of SARs outstanding was 2,787,323, of which 314,525 were exercisable. In 2004 and 2003, the Company recorded expenses related to SARs issued, of $16.7 million ($10.4 million after tax) and $4 million ($2 million after tax), respectively. During 2004, 109,000 SARs were exercised and approximately 167,000 were forfeited. No material cash payments were made to settle SARs that were exercised. RESTRICTED STOCK In May 2002, Apache's Board of Directors approved an executive restricted stock plan for all executive officers and certain key employees in lieu of stock options. The Company awarded 87,500, 121,000 and 229,950 restricted shares at a market price of $42.68, $28.78 and $27.82 in 2004, 2003 and 2002, respectively. The value of the stock issued was established by the market price on the date of grant and will be recorded as compensation expense ratably over the four-year vesting terms. During 2004, 2003 and 2002, $2.8 million, $2 million and $538 thousand, respectively, was charged to expense. As of December 31, 2004, there was $7 million of total unrecognized compensation cost related to approximately 269,000 unvested shares. There were no material forfeitures or shares vesting during the year, and the weighted-average remaining life is 2.4 years. In December 1998, the Company entered into a conditional stock grant agreement with an executive of the Company which would award up to 230,992 shares of the Company's common stock in five annual installments. Each installment has a five-year vesting period, 40 percent of the conditional grants will be paid in cash at the market value of the stock on the date of payment and the balance (138,594 shares) will be issued in Apache common stock. In 2001, the Company modified the conditional stock grant agreement to allow for immediate vesting upon a change in control of ownership. This modification did not require recognition of any compensation expense. SHARE APPRECIATION PLAN In October 2000, the Company adopted the Share Appreciation Plan under which grants were made to substantially all full-time employees, including officers. The Share Appreciation Plan provided for issuance of up to an aggregate of 8.08 million shares of Apache common stock, based on attainment of one or more of three share price goals (Share Price Goals) and/or a separate production goal (Production Goal). Generally, shares are issued in three installments over 24 months after achievement of each goal. The shares of Apache common stock contingently issuable under the Share Appreciation Plan were excluded from the computation of income per common share until the stated goals were met as described below. The Share Price Goals were based on achieving a closing price of $43.29, $51.95 and $77.92 per share on any 10 days out of any 30 consecutive trading days prior to January 1, 2005. Apache's share price exceeded the first threshold ($43.29) under this plan on April 28, 2004. As such, the Company will issue approximately F-31 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 900,000 shares of its common stock, after minimum tax withholding requirements, which will be distributed in three annual installments. The first installment was issued in May 2004. The second and third installments will be issued in 2005 and 2006 to employees remaining with the Company during those periods. Also, on October 26, 2004, Apache's share price exceeded the second threshold ($51.95) of the Company's 2000 Share Appreciation Plan. Accordingly, Apache will issue approximately 2.2 million additional shares of its common stock, after minimum tax withholding requirements, in three equal installments. The first installment was issued in November 2004. The second and third installments will be issued in 2005 and 2006 to employees remaining with the Company during those periods. The third share-price threshold ($77.92) did not trigger and the related shares were cancelled as of December 31, 2004. A summary of the number of shares contingently issued under the Share Price Goals as of December 31, 2004, 2003 and 2002 is presented in the table below:
SHARES SUBJECT TO CONDITIONAL GRANTS --------------------------- 2004 2003 2002 ------- ------ ------ (IN THOUSANDS) Outstanding, beginning of year.............................. 6,324 6,234 6,390 Granted..................................................... 15 522 436 Issued...................................................... (1,531) -- -- Forfeited or cancelled...................................... (1,800) (432) (592) ------- ------ ------ Outstanding, end of year(1)................................. 3,008 6,324 6,234 ======= ====== ====== Weighted-average fair value of conditional grants -- Share Price Goals(2).................................................. $ 19.74 $ 6.75 $ 7.98 ======= ====== ======
(1) The outstanding shares at the end of 2004 represent those shares remaining to be issued in 2005 and 2006 as a result of attainment of the $43.29 and $51.95 per share price goals. These outstanding shares will be issued net of minimum tax withholding as employees fulfill the two-year service period requirement. The outstanding shares shown at the end of 2003 and 2002 represent shares that would have been issued, had the $43.29, $51.95 and $77.92 been attained, 1,370,624 shares, 3,431,250 shares and 1,522,818 shares, respectively for 2003, and 1,351,792 shares, 3,381,050 shares and 1,501,398 shares, respectively for 2002. (2) The fair value of each Share Price Goal conditional grant is estimated as of the date of grant using a Monte Carlo simulation with the following weighted-average assumptions used for grants in 2004, 2003 and 2002, respectively: (i) risk-free interest rate of 3.04, 2.77 and 2.90 percent; (ii) expected volatility of 35.97, 36.69 and 38.77 percent; and (iii) expected dividend yield of .96, .70 and .70 percent. - --------------- Timing of expense recognition under the 2000 Share Appreciation Plan was based on the accounting policies in place for each year the plan was outstanding and vesting (See Note 1, Summary of Significant Accounting Policies). The shares were initially granted in 2000 and were not expensed under APB Opinion No. 25. In 2004, Apache adopted SFAS 123-R retrospectively, to January 1, 2004, and expensed stock based compensation vesting during the year. Under SFAS No. 123-R expense amounts are determined based on the fair value of the plan on the date of grant and for 2004, the Company recorded $13.1 million ($8.2 million after-tax) of expense, net of capitalized amounts for this plan of $6.5 million. Additional expense will be recorded in 2005 and 2006 as the initial service period is completed. The Production Goal would have been attained if and when the Company's average daily production equaled or exceeded .67 barrels of oil equivalent per diluted share (calculated on an annualized basis) during any fiscal quarter ending before January 1, 2005. This level of production was approximately twice the Company's level of production at the time the Share Appreciation Plan was adopted. The Production Goal was not obtained prior to January 1, 2005 and, therefore, no shares will be issued under that goal. F-32 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) In February, 2005, the Company's Board of Directors voted to present to the stockholders of the Company for approval a new plan that provides incentives for employees to double the share price again, to $108, by the end of 2008, with an interim goal of $81 to be achieved by the end of 2007. Preferred Stock The Company has five million shares of no par preferred stock authorized, of which 25,000 shares have been designated as Series A Junior Participating Preferred Stock (the Series A Preferred Stock), 100,000 shares have been designated as the 5.68 percent Series B Cumulative Preferred Stock (the Series B Preferred Stock) and, from May 13, 1999 until December 16, 2003, 140,000 shares were designated as Series C Preferred Stock. The shares of Series A Preferred Stock are authorized for issuance pursuant to certain rights that trade with Apache common stock outstanding and are reserved for issuance upon the exercise of the Rights as defined and discussed below. RIGHTS TO PURCHASE SERIES A PREFERRED STOCK In December 1995, the Company declared a dividend of one right (a Right) for each 2.31 shares (adjusted for the 10 percent and five percent stock dividends and the two-for-one stock split) of Apache common stock outstanding on January 31, 1996. Each full Right entitles the registered holder to purchase from the Company one ten-thousandth (1/10,000) of a share of Series A Preferred Stock at a price of $100 per one ten-thousandth of a share, subject to adjustment. The Rights are exercisable 10 calendar days following a public announcement that certain persons or groups have acquired 20 percent or more of the outstanding shares of Apache common stock or 10 business days following commencement of an offer for 30 percent or more of the outstanding shares of Apache common stock. In addition, if a person or group becomes the beneficial owner of 20 percent or more of Apache's outstanding common stock (flip in event), each Right will become exercisable for shares of Apache's common stock at 50 percent of the then market price of the common stock. If a 20 percent shareholder of Apache acquires Apache, by merger or otherwise, in a transaction where Apache does not survive or in which Apache's common stock is changed or exchanged (flip over event), the Rights become exercisable for shares of the common stock of the company acquiring Apache at 50 percent of the then market price for Apache common stock. Any Rights that are or were beneficially owned by a person who has acquired 20 percent or more of the outstanding shares of Apache common stock and who engages in certain transactions or realizes the benefits of certain transactions with the Company will become void. If an offer to acquire all of the Company's outstanding shares of common stock is determined to be fair by Apache's Board of Directors, the transaction will not trigger a flip in event or a flip over event. The Company may also redeem the Rights at $.01 per Right at any time until 10 business days after public announcement of a flip in event. The Rights will expire on January 31, 2006, unless earlier redeemed by the Company. Unless the Rights have been previously redeemed, all shares of Apache common stock issued by the Company after January 31, 1996 will include Rights. Unless and until the Rights become exercisable, they will be transferred with and only with the shares of Apache common stock. SERIES B PREFERRED STOCK In August 1998, Apache issued 100,000 shares ($100 million) of Series B Preferred Stock in the form of one million depositary shares, each representing one-tenth (1/10) of a share of Series B Preferred Stock, for net proceeds of $98 million. The Series B Preferred Stock has no stated maturity, is not subject to a sinking fund and is not convertible into Apache common stock or any other securities of the Company. Apache has the option to redeem the Series B Preferred Stock at $1,000 per preferred share on or after August 25, 2008. Holders of the shares are entitled to receive cumulative cash dividends at an annual rate of $5.68 per depositary share when, and if, declared by Apache's board of directors. F-33 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) SERIES C PREFERRED STOCK In May 1999, Apache issued 140,000 shares ($217 million) of Series C Preferred Stock in the form of seven million depositary shares each representing one-fiftieth (1/50) of a share of Series C Preferred Stock, for net proceeds of $211 million. Holders of the shares were entitled to receive cumulative cash dividends at an annual rate of 6.5 percent, or $2.015 per depositary share when, and if, declared by Apache's board of directors. In 2000, Apache bought back 75,900 depositary shares at an average price of $34.42 per share. The excess of the purchase price to reacquire the depositary shares over the original issuance price is reflected as a preferred stock dividend. The remaining depositary shares converted into 13,109,730 shares of Apache common stock in 2002. COMPREHENSIVE INCOME Components of accumulated other comprehensive income (loss) consist of the following:
FOR THE YEAR ENDED DECEMBER 31, ----------------------------------- 2004 2003 2002 --------- --------- --------- (IN THOUSANDS) Currency translation adjustments................... $(108,750) $(108,750) $(108,750) Unrealized gain (loss) on derivatives (Note 3)..... (20,732) (43,193) (4,186) --------- --------- --------- Accumulated other comprehensive loss............... $(129,482) $(151,943) $(112,936) ========= ========= =========
9. FINANCIAL INSTRUMENTS The following table presents the carrying amounts and estimated fair values of the Company's financial instruments at December 31, 2004 and 2003. See Note 3, Hedging and Derivative Instruments for a discussion of the Company's derivative instruments.
2004 2003 -------------------- -------------------- CARRYING FAIR CARRYING FAIR AMOUNT VALUE AMOUNT VALUE -------- -------- -------- -------- (IN THOUSANDS) Long-term debt: Apache Money market lines of credit................... $ 4,000 $ 4,000 $ 5,200 $ 5,200 Commercial paper............................... 392,000 392,000 130,000 130,000 6.25-percent debentures........................ 397,758 445,960 397,525 445,600 7-percent notes................................ 148,570 179,040 148,506 175,725 7.625-percent notes............................ 149,190 189,780 149,161 183,660 7.7-percent notes.............................. 99,671 124,100 99,665 121,840 7.95-percent notes............................. 178,659 228,960 178,636 224,910 7.375-percent debentures....................... 148,021 188,385 148,014 179,640 7.625-percent debentures....................... 149,175 188,187 149,175 179,220 Subsidiary and other obligations Fletcher notes................................. 5,356 5,719 5,356 5,731 Apache Finance Australia 6.5-percent notes..... 169,530 183,260 169,390 189,431 Apache Finance Australia 7-percent notes....... 99,662 111,010 99,597 115,440 Apache Finance Canada 4.375-percent notes...... 349,709 338,838 349,688 329,770 Apache Finance Canada 7.75-percent notes....... 297,089 387,960 297,053 374,730
F-34 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The fair value of the notes and debentures is based upon an estimate provided to the Company by an independent investment banking firm. The carrying amount of the commercial paper and money market lines of credit approximated fair value because the interest rates are variable and reflective of market rates. The Company's trade receivables and trade payables are by their very nature short-term. The carrying values included in the accompanying consolidated balance sheet approximate fair value at December 31, 2004 and December 31, 2003. 10. COMMITMENTS AND CONTINGENCIES LITIGATION TEXACO CHINA B.V. Apache recorded a reserve in the second quarter of 2004 to fully reflect a pre-tax $71 million international arbitration award to Texaco China B.V. (Texaco China). The arbitration specifies that the award is subject to interest at nine percent. Apache accrued $3 million of interest expense in 2004. In September 2001, Texaco China initiated an arbitration proceeding against Apache China Corporation LDC (Apache China), later adding Apache Bohai Corporation LDC (Apache Bohai) to the arbitration. In the arbitration Texaco China claimed damages, plus interest, arising from Apache Bohai's alleged failure to drill three wells, prior to re-assignment of the interest to Texaco China. Apache believes that the finding of the arbitrator is unsupported by the facts and the law, and Apache has filed and is pursuing an application to vacate the award in federal court. Texaco China has filed an application to confirm the award in the same court. In January 2005, while awaiting the decision of the U.S. federal courts, Texaco China also filed a proceeding against Apache China and Apache Bohai in the People's Republic of China to recognize the arbitral award, apparently seeking the same relief as sought in U.S. federal court. Apache China has been served. Apache Bohai has not been served. In February 2005, a federal magistrate appointed to hear the case has made a recommendation to the federal court that the arbitration award should be confirmed, as requested by Texaco China. If the court enters a judgment against Apache China based on the magistrate's recommendation, the Company plans to appeal the judgment to the circuit court of appeals. PREDATOR In December 2000, certain subsidiaries of the Company and Murphy Oil Corporation (Murphy) filed a lawsuit in Canada charging The Predator Corporation Ltd. (Predator) and others with misappropriation and misuse of confidential well data to obtain acreage offsetting a significant natural gas discovery made by Apache and Murphy during 2000 in the Ladyfern area of northeast British Columbia. In February 2001, Predator filed a counterclaim seeking more than C$6 billion and later reduced this amount to no more than C$4 billion. In September 2004, the court in Canada that is hearing this counterclaim granted Apache Canada's motion for summary judgment and dismissed more than C$3 billion of Predator's claims against the Company and Murphy, and dismissed all claims against both Murphy's president and Apache Canada's president. Predator has appealed the dismissal. Only Predator's claims against Murphy and Apache Canada for mismanaging operations survive in the trial court at this time. Those claims total approximately C$365 million, plus interest and attorneys' fees. While management believes that Predator's claim against Apache Canada is without merit, an adverse judgment is possible. Exposure related to this lawsuit is not currently determinable. Apache and Murphy's claims against Predator, filed in December 2000, are still pending. GRYNBERG In 1997, Jack Grynberg began filing lawsuits against other natural gas producers, gatherers, and pipelines claiming that the defendants have under paid royalty to the federal government and Indian tribes by mis-measurement of the volume and heating content of natural gas and are responsible for acts of others who mis- F-35 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) measured natural gas. In 2004, Grynberg filed suit against Apache making the same claims he had made previously against others in the industry. With the addition of Apache, there are more than 300 defendants to these actions. Other plaintiffs have made or may be expected to make similar claims. Although Grynberg purports to be acting on behalf of the government, the federal government has declined to join in the cases. While an adverse judgment against Apache is possible, Apache does not believe the plaintiff's claims have merit and plans to vigorously pursue its defenses against these claims. Exposure related to this lawsuit is not currently determinable. EGYPT TAX AUTHORITY The Egyptian Tax Authority (ETA) has issued claims for back taxes against various Apache subsidiaries in Egypt totaling $106 million (at current exchange rates) relating to periods as far back as 1994. While an adverse judgment against Apache is possible, Egyptian Concession agreements clearly provide that the Egyptian General Petroleum Corporation is responsible for the payment of all taxes related to the operation of the concessions. Apache believes that the claims of the ETA are unsupported by either the facts or the language of the concession agreements, which have the force of law in Egypt. Apache's subsidiaries have, therefore, contested liability with respect to these claims by filing actions in Egyptian civil court. Apache plans to vigorously pursue its remedies with respect to these claims. A civil court ruling with respect to the claims is expected sometime in the second quarter of 2005. LOUISIANA RESTORATION Numerous surface owners have filed claims or sent demand letters to various oil and gas companies, including Apache, claiming that, under either expressed or implied lease terms or Louisiana law, they are liable for damage measured by the cost of restoration of leased premises to their original condition. Any exposure related to these lawsuits and claims is not currently determinable. While an adverse judgment against Apache is possible, Apache has denied liability and intends to actively defend the cases. GENERAL The Company is involved in other litigation and is subject to governmental and regulatory controls arising in the ordinary course of business. The Company has an accrued liability of approximately $10 million for other legal contingencies that are probable of occurring and can be reasonably estimated. It is management's opinion that the loss for any such other litigation matters and claims that are reasonably possible to occur will not have a material adverse affect on the Company's financial position or results of operations. OTHER COMMITMENTS AND CONTINGENCIES ENVIRONMENTAL The Company, as an owner or lessee and operator of oil and gas properties, is subject to various federal, provincial, state, local and foreign country laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution clean-up resulting from operations and subject the lessee to liability for pollution damages. In some instances, the Company may be directed to suspend or cease operations in the affected area. We maintain insurance coverage, which we believe is customary in the industry, although we are not fully insured against all environmental risks. Apache manages its exposure to environmental liabilities on properties to be acquired by identifying existing problems and assessing the potential liability. The Company also conducts periodic reviews, on a company-wide basis, to identify changes in its environmental risk profile. These reviews evaluate whether there is a probable liability, its amount, and the likelihood that the liability will be incurred. The amount of F-36 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) any potential liability is determined by considering, among other matters, incremental direct costs of any likely remediation and the proportionate cost of employees who are expected to devote a significant amount of time directly to any possible remediation effort. As it relates to evaluations of purchased properties, depending on the extent of an identified environmental problem, the Company may exclude a property from the acquisition, require the seller to remediate the property to Apache's satisfaction, or agree to assume liability for the remediation of the property. The Company's general policy is to limit any reserve additions to any incidents or sites that are considered probable to result in an expected remediation cost exceeding $100,000. Any environmental costs and liabilities that are not reserved for are treated as an expense when actually incurred. In our estimation, neither these expenses nor expenses related to training and compliance programs, are likely to have a material impact on our financial condition. As of December 31, 2004, the Company had an undiscounted reserve for environmental remediation of approximately $11 million. Apache is not aware of any environmental claims existing as of December 31, 2004, which have not been provided for or would otherwise have a material impact on its financial position or results of operations. There can be no assurance, however, that current regulatory requirements will not change, or past non-compliance with environmental laws will not be discovered on the Company's properties. INTERNATIONAL LEASE CONCESSIONS The Company, through its subsidiaries, has acquired or has been conditionally or unconditionally granted exploration rights in Australia, Egypt, China and the North Sea. In order to comply with the contracts and agreements granting these rights, the Company, through various wholly-owned subsidiaries, is committed to expend approximately $180 million through 2009. OPERATING LEASE AND OTHER COMMITMENTS The Company has leases for buildings, facilities and equipment with varying expiration dates through 2013. Net rental expense was $17 million for 2004 and 2003, and $16 million for 2002. As of December 31, 2004, minimum rental commitments under long-term operating leases, net of sublease rental income, drilling rigs and long-term pipeline transportation commitments, ranging from one to 19 years, are as follows:
NET MINIMUM COMMITMENTS ------------------------------------------------- PIPELINE TOTAL LEASES DRILLING RIGS TRANSMISSION -------- ------- ------------- ------------ (IN THOUSANDS) 2005............................................. $127,592 $11,852 $ 88,071 $ 27,669 2006............................................. 72,566 10,990 36,739 24,837 2007............................................. 47,579 9,622 14,003 23,954 2008............................................. 31,273 8,641 588 22,044 2009............................................. 17,257 8,638 -- 8,619 Thereafter....................................... 64,176 31,364 -- 32,812 -------- ------- -------- -------- $360,443 $81,107 $139,401 $139,935 ======== ======= ======== ========
RETIREMENT AND DEFERRED COMPENSATION PLANS The Company provides a 401(k) savings plan for employees which allows participating employees to elect to contribute up to 25 percent of their salaries, with Apache making matching contributions up to a maximum of six percent of each employee's salary. In addition, the Company annually contributes six percent of each participating employee's compensation, as defined, to a money purchase retirement plan. The 401(k) F-37 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) plan and the money purchase retirement plan are subject to certain annually-adjusted, government-mandated restrictions which limit the amount of each employee's contributions. For certain eligible employees, the Company also provides a non-qualified retirement/savings plan which allows the deferral of up to 50 percent of each employee's salary, and which accepts employee contributions and the Company's matching contributions in excess of the above-referenced restrictions on the 401(k) savings plan and money purchase retirement plan. Additionally, Apache Energy Limited, Apache Canada Ltd. and Apache North Sea Limited maintain separate retirement plans, as required under the laws of Australia, Canada and the United Kingdom, respectively. Vesting in the Company's contributions to the 401(k) savings plan, the money purchase retirement plan and the non-qualified retirement/savings plan occurs at the rate of 20 percent per year. Upon a change in control of ownership, vesting is immediate. Total costs under all plans were $31 million, $25 million and $18 million for 2004, 2003 and 2002, respectively. Effective July 1, 2003, as part of the BP North Sea acquisition, Apache assumed a funded noncontributory defined benefit pension plan (U.K. Pension Plan) covering existing BP North Sea employees hired by the Company as part of the acquisition. Contributions made by Apache to BP's plan were immaterial prior to Apache's plan becoming effective. The pension plan provides defined benefits based on years of service and final average salary. The plan is closed to newly hired employees. Apache also has a postretirement benefit plan covering substantially all of its U.S. employees. The postretirement benefit plan provides for medical benefits up until the age of 65. The plan is contributory with participants' contributions adjusted annually. The postretirement benefit plan does not pay benefits once participants become eligible for Medicare and is not affected by the Medicare Modernization Act of 2003. The following tables set forth the benefit obligation, fair value of plan assets and funded status as of December 31, 2004 and 2003 and the underlying weighted average actuarial assumptions used for the U.K. Pension Plan and U.S. postretirement benefit plan. Apache uses a measurement date of December 31 for its pension and postretirement benefit plans.
2004 2003 ------------------------- ------------------------- PENSION POSTRETIREMENT PENSION POSTRETIREMENT BENEFITS BENEFITS BENEFITS BENEFITS -------- -------------- -------- -------------- (IN THOUSANDS) CHANGE IN PROJECTED BENEFIT OBLIGATION Projected benefit obligation beginning of period.................................... $63,642 $ 9,439 $ 60,190 $ 7,117 Service cost................................. 5,507 969 2,668 780 Interest cost................................ 3,661 628 1,562 525 Foreign currency exchange rate changes....... 7,132 -- 3,185 -- Amendments................................... -- -- -- -- Actuarial losses/(gains)..................... 8,793 91 (3,963) 1,115 Effect of curtailment and settlements........ -- -- -- -- Benefits paid................................ (9) (177) -- (172) Retiree contributions........................ -- 89 -- 74 ------- -------- -------- ------- Projected benefit obligation at end of year...................................... $88,726 $ 11,039 $ 63,642 $ 9,439 ------- -------- -------- -------
F-38 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
2004 2003 ------------------------- ------------------------- PENSION POSTRETIREMENT PENSION POSTRETIREMENT BENEFITS BENEFITS BENEFITS BENEFITS -------- -------------- -------- -------------- (IN THOUSANDS) CHANGE IN PLAN ASSETS Fair value of plan assets at beginning of period.................................... $52,420 $ -- $ 47,572 $ -- Actual return on plan assets................. 6,529 -- 688 -- Foreign currency exchange rate changes....... 6,752 -- 2,628 -- Employer contributions....................... 16,330 88 1,532 98 Benefits paid................................ (9) (177) -- (172) Retiree contributions........................ -- 89 -- 74 ------- -------- -------- ------- Fair value of plan assets at end of year..... 82,022 -- 52,420 -- ------- -------- -------- ------- RECONCILIATION OF FUNDED STATUS Funded status of plan........................ (6,704) (11,039) (11,222) (9,439) Unrecognized actuarial (gain)/loss........... 2,219 3,913 (3,576) 4,072 Unrecognized prior service cost.............. -- -- -- -- Unrecognized net transition obligation....... -- 529 -- 573 ------- -------- -------- ------- Plan benefit asset/(obligation).............. $(4,485) $ (6,597) $(14,798) $(4,794) ======= ======== ======== ======= WEIGHTED AVERAGE ASSUMPTIONS USED AS OF DECEMBER 31 Discount rate................................ 5.30% 5.75% 5.50% 6.25% Salary increases............................. 3.80% N/A 3.75% N/A Expected return on assets.................... 6.25% N/A 6.50% N/A Healthcare cost trend -- Initial in 2004........................ N/A 9.00% N/A 10.00% -- Ultimate in 2009....................... N/A 5.00% N/A 5.00%
As of December 31, 2004 and 2003, the accumulated benefit obligation for the pension plan was $65 million and $47 million, respectively. Apache's defined benefit pension plan assets are held by a non-related Trustee who has been instructed to invest the assets in an equal blend of equity securities and low-risk debt securities. The Company believes this blend of investments will provide a reasonable rate of return and ensure that the benefits promised to members are provided. The plan's assets do not include any equity or debt securities of Apache. A breakout of previous allocations for plan asset holdings and the target allocation for the Company's plan assets are summarized below.
PERCENTAGE OF PLAN ASSETS AT YEAR-END TARGET ALLOCATION ------------------------------------- 2004 2004 2003 ----------------- ----------------- ----------------- ASSET CATEGORY Equity securities............................. 50% 49% 50% Debt securities............................... 50% 51% 50% --- --- --- Total...................................... 100% 100% 100% === === ===
F-39 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The following tables set forth the components of the net periodic cost and the underlying weighted average actuarial assumptions used for the pension and postretirement benefit plans for the 12-month and 6-month periods ended December 31, 2004 and 2003, respectively.
2004 2003 ------------------------- ------------------------- PENSION POSTRETIREMENT PENSION POSTRETIREMENT BENEFITS BENEFITS BENEFITS BENEFITS -------- -------------- -------- -------------- (IN THOUSANDS) COMPONENTS OF NET PERIODIC BENEFIT COSTS Service cost.................................. $ 5,507 $ 969 $ 2,668 $ 780 Interest cost................................. 3,661 628 1,562 525 Expected return on assets..................... (3,589) -- (1,260) -- Amortization of: Prior service cost......................... -- -- -- -- Transition obligation...................... -- 44 -- 44 Actuarial (gain)/loss...................... -- 250 -- 203 Effect of curtailment and settlements......... -- -- -- -- ------- ------ ------- ------ Net periodic benefit cost..................... $ 5,579 $1,891 $ 2,970 $1,552 ======= ====== ======= ====== WEIGHTED AVERAGE ASSUMPTIONS USED TO DETERMINE NET PERIODIC BENEFIT COSTS FOR THE YEARS ENDED DECEMBER 31 Discount rate................................. 5.50% 6.25% 5.50% 6.75% Salary increases.............................. 3.75% N/A 3.75% N/A Expected return on assets..................... 6.25% N/A 6.50% N/A Healthcare cost trend -- Initial................................. N/A 10.00% N/A 10.00% -- Ultimate in 2009........................ N/A 5.00% N/A 5.00%
Assumed health care cost trend rates affect amounts reported for postretirement benefits. A one-percentage-point change in assumed health care cost trend rates would have the following effects:
POSTRETIREMENT BENEFITS -------------------------- 1% INCREASE 1% DECREASE ----------- ----------- (IN THOUSANDS) Effect on service and interest cost components.............. $ 181 $ (160) Effect on postretirement benefit obligation................. 1,154 (1,025)
Apache expects to contribute $5 million to its pension plan and $318,000 to its postretirement benefit plan in 2005. The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:
PENSION POSTRETIREMENT BENEFITS BENEFITS -------- -------------- (IN THOUSANDS) 2005........................................................ $ 106 $ 318 2006........................................................ 144 421 2007........................................................ 480 552 2008........................................................ 845 686 2009........................................................ 941 831 Years 2010 -- 2014.......................................... 12,326 6,800
F-40 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 11. PREFERRED INTERESTS OF SUBSIDIARIES In August 2001, Apache entered into a series of financing transactions, described below, to pay down existing debt and increase financial flexibility. Apache contributed interests in various fields valued at $923 million to new subsidiaries in connection with the financing transactions. Additionally, Apache contributed $116 million in U.S. Government Agency Notes. Unrelated institutional investors contributed $443 million ($441 million, net of issuance costs) to the various subsidiaries in exchange for preferred stock ($82 million) of the subsidiaries and a limited partner interest ($361 million) in one of the entities. The third party investors were entitled to receive a weighted average return of 123 basis points above the prevailing LIBOR interest rate. The preferred stock and limited partner interests were repayable from the assets of the subsidiaries. Apache retained credit risks related to collection of proceeds from product sales and intercompany loans. Apache also had an obligation to contribute an aggregate amount not to exceed $250 million to fund present and future business operations of the subsidiaries. However, the investors were not entitled to receive more than their $443 million original investment, plus the agreed-upon return. One of the subsidiaries also issued $37 million of senior floating rate notes, which matured and were repaid in August 2003 (see Note 5, Debt). The limited partnership was scheduled to terminate as of August 9, 2021. However, the general partner, an Apache subsidiary, could elect to retire all or part of the limited partner's interest at any time without penalty. On September 26, 2003, Apache repurchased and retired the preferred interests issued by three of its subsidiaries for approximately $443 million, plus an additional $1 million for accrued dividends and distributions. The transactions involved the purchase of preferred stock issued by two of the Company's subsidiaries for approximately $82 million and the retirement of a limited partnership interest in a partnership controlled by a subsidiary of the Company for approximately $361 million. Apache funded the transactions with available cash on hand and by issuing commercial paper under its existing commercial paper facility. Prior to the early repurchase, the assets and liabilities of the subsidiaries were included in Apache's consolidated financial statements at historical costs, with the preferred stock and limited partner interests of the subsidiaries reflected as a preferred interests of subsidiaries in the consolidated balance sheet. The dividends paid on the preferred stock and distributions paid on the limited partner interests were reflected as preferred interests of subsidiaries in the statement of consolidated operations. 12. TRANSACTIONS WITH RELATED PARTIES AND MAJOR CUSTOMERS Cinergy Corp. In 1995, Apache and other natural gas producers formed Producers Energy Marketing LLC (ProEnergy), to market substantially all of its members' domestic natural gas. In June 1998, Apache sold its 57 percent interest in ProEnergy to Cinergy Corp. and contracted with Cinergy Corp. to market substantially all the Company's natural gas production from the U.S. and agreed to develop terms for the marketing of most of Apache's Canadian production under an amended and restated gas purchase agreement effective July 1, 1998. Apache received 771,258 shares of Cinergy Corp. common stock for its interest, which the Company subsequently sold for $26 million. In December 1998, Apache and Cinergy Corp. agreed to postpone the negotiation of terms to market most of Apache's Canadian production. Under the terms of the original gas purchase agreement, ProEnergy, renamed Cinergy Marketing and Trading LLC (Cinergy), was to market Apache's North American natural gas production until June 30, 2008, with an option, following prior notice, to terminate on June 30, 2004. During this period, Apache was generally obligated to deliver most of its U.S. gas production to Cinergy and, under certain circumstances, reimburse Cinergy if certain gas throughput thresholds were not met. The prices received for its gas production under this agreement approximated market prices. F-41 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) In June 2003, Apache and Cinergy agreed to terminate their agreement concerning marketing of Apache's U.S. natural gas production and to dismiss the arbitration between them. The parties reached an amicable settlement, the amounts of which were immaterial to Apache's financial position and results of operations. Consequently, the Company began marketing its U.S. natural gas production previously marketed by Cinergy beginning with July 2003 production. Related Parties George D. Lawrence, a member of the Company's board of directors and the former President and Chief Executive Officer of Phoenix Resource Companies, Inc. (Phoenix), joined Apache's board in conjunction with the Company's acquisition of Phoenix by a merger (the "Merger") on May 20, 1996, through which Phoenix became a wholly-owned subsidiary of Apache. Merger consideration totaled $396.3 million, consisting of approximately 12,190,000 shares of Apache's common stock (28,158,900 shares after adjustment for the stock dividends and the two-for-one stock split) valued at $26.00 per share ($11.2554 after adjustment), $14.9 million of net value associated with Phoenix stock options assumed by Apache, and $64.5 million in cash. Upon consummation of the Merger, Apache assumed Phoenix stock options that remained outstanding on May 20, 1996, including those granted to Mr. Lawrence pursuant to Phoenix's 1990 Employee Stock Option Plan. In March 2003, Mr. Lawrence received 8,291 shares of Apache common stock (16,582 shares after adjustment for the stock split) as a result of the exercise of all of his remaining stock options from the Phoenix 1990 Employee Stock Option Plan. Such exercise was for 21,656 shares of Apache common stock at an exercise price of $21.50 per share (43,312 shares of Apache common stock at an exercise price of $10.75 per share after adjustment for the stock split). Mr. Lawrence paid the net exercise price of $466,000 and required taxes of $345,000 by surrendering 13,365 shares of Apache common stock valued at $60.65 per share (26,730 shares at $30.33 after adjustment for the stock split). In the ordinary course of business, Cimarex Energy, Co. (Cimarex), formerly Key Production Company, Inc., paid to Apache $6 million during 2004, $4 million during 2003 and $2 million during 2002 for Cimarex's proportionate share of drilling and workover costs, mineral interests and routine expenses relating to oil and gas wells in which Cimarex owns interests and of which Apache is the operator. Cimarex was paid approximately $5 million in 2004, $6 million in 2003, and $4 million in 2002 directly by Apache or related entities for its proportionate share of revenues from wells in which Cimarex marketed its revenues with Apache as operator. Apache paid to Cimarex approximately $5 million during 2004 and $1 million during 2003 for Apache's proportionate share of drilling and workover costs, mineral interests and routine expenses relating to oil and gas wells in which Apache owns interests and of which Cimarex is the operator. Apache was paid approximately $3 million in 2004 and $2 million in 2003 directly by Cimarex for its proportionate share of revenues from wells in which Apache marketed its revenues with Cimarex as operator. F. H. Merelli, a member of Apache's Board of Directors, is chairman of the board, chief executive officer and president of Cimarex. In the ordinary course of business, Matador Petroleum Corporation or related entities (Matador) paid to Apache approximately $793,000 during 2003 and $708,000 during 2002 for Matador's proportionate share of drilling and workover costs, mineral interests and routine expenses relating to oil and gas wells in which Matador owns interests and of which Apache is the operator. Matador was paid approximately $1 million in 2003 and 2002 directly by Apache for its proportionate share of revenues from wells in which Matador marketed its revenues with Apache as operator. Apache paid to Matador during 2003 and 2002 approximately $654,000 and $2 million, respectively, for Apache's proportionate share of drilling and workover costs, mineral interests and routine expenses relating to oil and gas wells in which Apache owns interests and of which Matador is the operator. Apache was paid approximately $915,000 and $621,000 in 2003 and 2002, respectively, directly by Matador for its proportionate share of revenues from wells in which Apache marketed F-42 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) its revenues with Matador as operator. Eugene C. Fiedorek, a member of Apache's board of directors, was a member of the board of directors of Matador until its acquisition by Tom Brown, Inc. in March 2003. Apache and its subsidiaries made donations of $103,000 and $201,000, in cash, property and services, to the Ucross Foundation in 2004 and 2003, respectively. In February 2004, Apache purchased Clear Creek Hunting Preserve, Inc. (CCHP) from Ucross Foundation for a total purchase price of $77,000. Apache also paid $22,000 during 2004 to the Ucross Foundation for food, lodging and other expenses incurred in connection with executive and board meetings held by Apache at the Ucross Foundation's facilities, and $34,000 to the Ucross Foundation for the lease of land and other services utilized by CCHP. The Ucross Foundation was founded in 1981 as a non-profit organization whose primary objectives include the restoration of the historic Clear Fork headquarters of the Pratt and Ferris Cattle Company of Wyoming, the promotion of the preservation of other historical sites in the area, and the maintenance of an artists-in-residence program for writers and other artists. To help ensure that the accomplishments of the Ucross Foundation are reasonably secure, Apache's board of directors has approved a conditional charitable contribution of $10,000,000 to be made to the Ucross Foundation upon a change of control of the Company, as defined in the Company's income continuance plan. Raymond Plank, chairman of Apache's Board of Directors, is chairman of the Board of Trustees of Ucross Foundation, and G. Steven Farris, a director and officer of Apache, George D. Lawrence, a member of the Company's Board of Directors, and Roger B. Plank, an officer of Apache, are trustees of Ucross Foundation. During 2004, 2003 and 2002, Apache and its subsidiaries made donations of $5,033,000, $500,000 and $300,000, in cash, property and services, to The Fund for Teachers: A Foundation to Recognize, Stimulate and Enhance, which is a Texas non-profit corporation. In addition, during 2004, Apache made a pledge to the Fund for Teachers for $5,000,000 in cash, property and services that will be paid in 2005. The Fund for Teachers seeks to provide resources directly to teachers to support learning experiences of their own design to increase their effectiveness with students, and is currently focused on funding summer sabbaticals for selected applicants. The Company's board of directors also authorized additional donations to The Fund for Teachers of up to $5,000,000 in cash, property and services for 2005 that may be funded through the end of 2006. If a change of control of the Company occurs, as defined in the Company's income continuance plan, any and all of the donations that have not yet been made to the Fund for Teachers will become immediately due and payable to the Fund for Teachers. Raymond Plank, chairman of Apache's Board of Directors, is chairman of the board and president of The Fund for Teachers. In the ordinary course of business, Apache paid to Maralo, LLC or related entities ("Maralo") during 2002 approximately $9,000 in revenues relating to four oil and gas wells in which Maralo owns an interest and of which Apache is operator. Maralo paid Apache approximately $1,000 in 2002 for Maralo's share of routine expenses relating to such wells. Also during 2002, Maralo sub-leased certain office space from Apache, for which Maralo paid Apache approximately $95,000. Mary Ralph Lowe, a member of Apache's Board of Directors through December 19, 2003, is president, chief executive officer and the sole stockholder of Maralo. During 2002, in the ordinary course of business, Aquila, Inc. ("Aquila") and related companies paid to Apache approximately $33 million for natural gas produced by Apache, primarily in Canada. Aquila was paid approximately $348,000 by Apache for gathering, transportation and compression services provided by Aquila. Janine McArdle, vice-president, Oil and Gas Marketing of Apache since October 2002, previously was employed by Aquila Europe. Major Customers In 2004, purchases by EGPC and BP accounted for 17 percent and 15 percent, respectively, of the Company's oil and gas production revenues. F-43 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) In 2003, purchases by Cinergy, EGPC and BP accounted for 12 percent, 16 percent and 15 percent of the Company's oil and gas production revenues, respectively. In 2002, purchases by Cinergy and EGPC accounted for 19 percent and 22 percent of the Company's oil and gas production revenues, respectively. No other purchaser has accounted for more than 10 percent of revenues for 2004, 2003 or 2002. Concentration of Credit Risk The Company's revenues are derived principally from uncollateralized sales to customers in the oil and gas industry; therefore, customers may be similarly affected by changes in economic and other conditions within the industry. Apache has not experienced significant credit losses on such sales. Apache sells practically all of its Egyptian crude oil and natural gas to EGPC for U.S. dollars. Beginning in 2001, we experienced a gradual decline in timeliness of receipts from EGPC for our Egyptian oil and gas sales. Deteriorating economic conditions during 2001 in Egypt lessened the availability of U.S. dollars, resulting in a one to two month delay in receipts from EGPC. During 2004, we experienced variability in the timing of cash receipts, but our past due balance improved at year-end. 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. 13. BUSINESS SEGMENT INFORMATION Apache has six reportable segments which are primarily in the business of crude oil and natural gas exploration and production. The accounting policies of the segments are the same as those described in the summary of significant accounting policies. The Company evaluates performance based on profit or loss from oil and gas operations before income and expense items incidental to oil and gas operations and income taxes. F-44 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Apache's reportable segments are managed separately based on their geographic locations. Financial information by operating segment is presented below:
OTHER UNITED STATES CANADA EGYPT AUSTRALIA NORTH SEA INTERNATIONAL TOTAL ------------- ---------- ---------- ---------- ---------- ------------- ----------- (IN THOUSANDS) 2004 Oil and gas production revenues................ $2,332,064 $1,014,097 $ 932,767 $ 458,006 $ 472,091 $ 98,992 $ 5,308,017 Operating Expenses: Depreciation, depletion and amortization...... 554,598 204,181 176,307 118,183 126,667 42,216 1,222,152 Asset retirement obligation accretion............. 25,531 6,078 -- 2,277 12,048 126 46,060 Lease operating costs... 376,608 186,043 92,791 52,309 143,453 13,174 864,378 Gathering and transportation costs................. 28,324 30,741 -- -- 22,619 577 82,261 Severance and other taxes................. 67,544 22,766 -- 64,345 (61,361) 454 93,748 ---------- ---------- ---------- ---------- ---------- -------- ----------- Operating Income (Loss)... $1,279,459 $ 564,288 $ 663,669 $ 220,892 $ 228,665 $ 42,445 2,999,418 ========== ========== ========== ========== ========== ======== Other Income (Expense): Other................... 24,560 General and administrative........ (173,194) Financing costs, net.... (116,485) China litigation provision............. (71,216) ----------- Income Before Income Taxes................... $ 2,663,083 =========== Net Property and Equipment............... $6,754,515 $3,338,990 $1,573,639 $ 951,704 $1,112,451 $129,060 $13,860,359 ========== ========== ========== ========== ========== ======== =========== Total Assets.............. $7,394,542 $3,633,469 $1,948,833 $1,131,026 $1,244,419 $150,191 $15,502,480 ========== ========== ========== ========== ========== ======== =========== Additions to Net Property and Equipment........... $2,042,033 $ 816,198 $ 392,300 $ 178,280 $ 369,542 $ 26,587 $ 3,824,940 ========== ========== ========== ========== ========== ======== ===========
F-45 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
OTHER UNITED STATES CANADA EGYPT AUSTRALIA NORTH SEA INTERNATIONAL TOTAL ------------- ---------- ---------- ---------- ---------- ------------- ----------- (IN THOUSANDS) 2003 Oil and gas production revenues................ $2,023,492 $ 823,273 $ 652,913 $ 391,968 $ 273,044 $ 34,230 $ 4,198,920 Operating Expenses: Depreciation, depletion and amortization...... 512,691 172,056 182,209 120,322 72,053 13,955 1,073,286 Asset retirement obligation accretion............. 18,861 5,275 -- 2,239 11,282 106 37,763 International impairments........... -- -- -- -- -- 12,813 12,813 Lease operating costs... 302,095 153,598 82,558 44,395 109,140 7,877 699,663 Gathering and transportation costs................. 21,128 28,154 -- -- 11,178 -- 60,460 Severance and other taxes................. 52,651 20,183 -- 28,245 19,591 1,123 121,793 ---------- ---------- ---------- ---------- ---------- -------- ----------- Operating Income (Loss)... $1,116,066 $ 444,007 $ 388,146 $ 196,767 $ 49,800 $ (1,644) 2,193,142 ========== ========== ========== ========== ========== ======== Other Income (Expense): Other................... (8,621) General and administrative........ (138,524) Financing costs, net.... (115,072) Preferred interests of subsidiaries.......... (8,668) ----------- Income Before Income Taxes................... $ 1,922,257 =========== Net Property and Equipment............... $5,268,990 $2,727,620 $1,357,646 $ 891,567 $ 869,574 $144,688 $11,260,085 ========== ========== ========== ========== ========== ======== =========== Total Assets.............. $5,621,681 $2,961,111 $1,744,164 $ 970,764 $ 941,577 $176,829 $12,416,126 ========== ========== ========== ========== ========== ======== =========== Additions to Net Property and Equipment........... $1,486,895 $ 630,436 $ 276,293 $ 159,923 $ 941,629 $ 33,426 $ 3,528,602 ========== ========== ========== ========== ========== ======== ===========
F-46 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
OTHER UNITED STATES CANADA EGYPT AUSTRALIA NORTH SEA INTERNATIONAL TOTAL ------------- ---------- ---------- ---------- ---------- ------------- ----------- (IN THOUSANDS) 2002 Oil and gas production revenues................ $1,101,388 $ 557,720 $ 560,099 $ 334,039 $ -- $ 6,502 $ 2,559,748 Operating Expenses: Depreciation, depletion and amortization...... 387,187 182,584 163,648 107,993 -- 2,467 843,879 International impairments........... -- -- -- -- -- 19,600 19,600 Lease operating costs... 239,837 110,078 69,160 37,107 -- 1,721 457,903 Gathering and transportation costs................. 17,311 21,256 -- -- -- -- 38,567 Severance and other taxes................. 34,792 9,710 -- 22,807 -- -- 67,309 ---------- ---------- ---------- ---------- ---------- -------- ----------- Operating Income (Loss)... $ 422,261 $ 234,092 $ 327,291 $ 166,132 $ -- $(17,286) 1,132,490 ========== ========== ========== ========== ========== ======== Other Income (Expense): Other................... 125 General and administrative........ (104,588) Financing costs, net.... (112,833) Preferred interests of subsidiaries.......... (16,224) ----------- Income Before Income Taxes................... $ 898,970 =========== Net Property and Equipment............... $4,068,362 $2,190,029 $1,263,560 $ 807,332 $ -- $136,302 $ 8,465,585 ========== ========== ========== ========== ========== ======== =========== Total Assets.............. $4,309,736 $2,401,319 $1,713,267 $ 883,704 $ -- $151,825 $ 9,459,851 ========== ========== ========== ========== ========== ======== =========== Additions to Net Property and Equipment........... $ 597,954 $ 379,413 $ 196,975 $ 100,761 $ -- $ 37,767 $ 1,312,870 ========== ========== ========== ========== ========== ======== ===========
F-47 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 14. SUPPLEMENTAL OIL AND GAS DISCLOSURES (UNAUDITED) Oil and Gas Operations The following table sets forth revenue and direct cost information relating to the Company's oil and gas exploration and production activities. Apache has no long-term agreements to purchase oil or gas production from foreign governments or authorities.
UNITED NORTH OTHER STATES CANADA EGYPT AUSTRALIA SEA INTERNATIONAL TOTAL ---------- ---------- -------- --------- -------- ------------- ---------- (IN THOUSANDS) 2004 Oil and gas production revenues.................... $2,332,064 $1,014,097 $932,767 $458,006 $472,091 $ 98,992 $5,308,017 ---------- ---------- -------- -------- -------- -------- ---------- Operating costs: Depreciation, depletion and amortization(1)........... 531,593 200,155 176,307 117,098 126,237 42,186 1,193,576 Asset retirement obligation accretion(3).............. 25,531 6,078 -- 2,277 12,048 126 46,060 Lease operating expenses.... 376,608 186,043 92,791 52,309 143,453 13,174 864,378 Gathering and transportation costs..................... 28,324 30,741 -- -- 22,619 577 82,261 Production taxes(2)......... 62,791 9,551 -- 64,345 (61,361) 454 75,780 Income tax.................. 490,206 233,949 318,561 75,472 98,511 14,060 1,230,759 ---------- ---------- -------- -------- -------- -------- ---------- 1,515,053 666,517 587,659 311,501 341,507 70,577 3,492,814 ---------- ---------- -------- -------- -------- -------- ---------- Results of operations......... $ 817,011 $ 347,580 $345,108 $146,505 $130,584 $ 28,415 $1,815,203 ========== ========== ======== ======== ======== ======== ========== Amortization rate per boe..... $ 7.88 $ 6.28 $ 5.60 $ 6.53 $ 6.49 $ 13.12 $ 7.01 ========== ========== ======== ======== ======== ======== ========== 2003 Oil and gas production revenues.................... $2,023,492 $ 823,273 $652,913 $391,968 $273,044 $ 34,230 $4,198,920 ---------- ---------- -------- -------- -------- -------- ---------- Operating costs: Depreciation, depletion and amortization(1)........... 489,969 169,029 182,209 119,455 71,956 13,914 1,046,532 Asset retirement obligation accretion(3).............. 18,861 5,275 -- 2,239 11,282 106 37,763 International impairments... -- -- -- -- -- 12,813 12,813 Lease operating expenses.... 302,095 153,598 82,558 44,395 109,140 7,877 699,663 Gathering and transportation costs..................... 21,128 28,154 -- -- 11,178 -- 60,460 Production taxes(2)......... 50,615 4,180 -- 28,245 19,591 1,123 103,754 Income tax.................. 427,809 201,421 186,310 67,196 21,456 (1,077) 903,115 ---------- ---------- -------- -------- -------- -------- ---------- 1,310,477 561,657 451,077 261,530 244,603 34,756 2,864,100 ---------- ---------- -------- -------- -------- -------- ---------- Results of operations......... $ 713,015 $ 261,616 $201,836 $130,438 $ 28,441 $ (526) $1,334,820 ========== ========== ======== ======== ======== ======== ========== Amortization rate per boe..... $ 7.13 $ 5.43 $ 6.62 $ 6.13 $ 6.67 $ 8.36 $ 6.59 ========== ========== ======== ======== ======== ======== ==========
F-48 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
UNITED NORTH OTHER STATES CANADA EGYPT AUSTRALIA SEA INTERNATIONAL TOTAL ---------- ---------- -------- --------- -------- ------------- ---------- (IN THOUSANDS) 2002 Oil and gas production revenues.................... $1,101,388 $ 557,720 $560,099 $334,039 $ -- $ 6,502 $2,559,748 ---------- ---------- -------- -------- -------- -------- ---------- Operating costs: Depreciation, depletion and amortization(1)........... 369,864 181,087 163,648 107,194 -- 2,455 824,248 International impairments... -- -- -- -- -- 19,600 19,600 Lease operating expenses.... 239,837 110,078 69,160 37,107 -- 1,721 457,903 Gathering and transportation costs..................... 17,311 21,256 -- -- -- -- 38,567 Production taxes(2)......... 33,336 4,221 -- 22,808 -- -- 60,365 Income tax.................. 165,390 104,869 157,100 56,756 -- (6,536) 477,579 ---------- ---------- -------- -------- -------- -------- ---------- 825,738 421,511 389,908 223,865 -- 17,240 1,878,262 ---------- ---------- -------- -------- -------- -------- ---------- Results of operations......... $ 275,650 $ 136,209 $170,191 $110,174 $ -- $(10,738) $ 681,486 ========== ========== ======== ======== ======== ======== ========== Amortization rate per boe..... $ 7.06 $ 5.71 $ 6.10 $ 5.36 $ -- $ 3.68 $ 6.29 ========== ========== ======== ======== ======== ======== ==========
(1) This amount only reflects DD&A of capitalized costs of oil and gas proved properties and, therefore, does not agree with DD&A reflected on Note 13, Business Segment Information. (2) This amount only reflects amounts directly related to oil and gas producing properties and, therefore, does not agree with severance and other taxes reflected on Note 13, Business Segment Information. (3) Effective January 1, 2003, Apache adopted SFAS No. 143 "Asset Retirement Obligations." These amounts reflect current year activity only, as prior periods were adjusted through a one-time cumulative adjustment as described in Note 4, Asset Retirement Obligation. - --------------- F-49 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Costs Incurred In Oil And Gas Property Acquisition, Exploration, And Development Activities
UNITED OTHER STATES CANADA EGYPT AUSTRALIA NORTH SEA INTERNATIONAL TOTAL ---------- -------- -------- --------- --------- ------------- ---------- (IN THOUSANDS) 2004 Acquisitions: Proved....................... $ 926,088 $ 9,839 $ -- $ -- $ 1,154 $ -- $ 937,081 Unproved..................... 126,770 -- -- -- -- -- 126,770 Purchase of non-producing leases....................... 19,717 46,085 -- -- -- -- 65,802 Exploration.................... 65,658 142,753 62,651 51,988 8,717 4,277 336,044 Development.................... 669,681 568,074 239,261 86,706 353,337 22,216 1,939,275 Capitalized interest........... 21,000 15,152 6,563 1,748 6,285 -- 50,748 ---------- -------- -------- -------- -------- ------- ---------- COSTS EXPENDED IN 2004......... 1,828,914 781,903 308,475 140,442 369,493 26,493 3,455,720 ---------- -------- -------- -------- -------- ------- ---------- Plus: Asset retirement obligation costs(1).......... 175,923 10,681 -- -- (643) -- 185,961 ---------- -------- -------- -------- -------- ------- ---------- COSTS INCURRED................. $2,004,837 $792,584 $308,475 $140,442 $368,850 $26,493 $3,641,681 ========== ======== ======== ======== ======== ======= ========== Property sales................. $ (3,210) $ (832) $ -- $ -- $ -- $ -- $ (4,042) 2003 Acquisitions: Proved....................... $ 728,486 $ 5,272 $ -- $ 27,105 $622,899 $ -- $1,383,762 Unproved..................... 118,250 1,094 -- -- 65,000 -- 184,344 Purchase of non-producing leases....................... 5,795 44,939 -- -- -- -- 50,734 Exploration.................... 32,020 114,924 54,305 68,493 4,314 3,669 277,725 Development.................... 379,886 408,993 188,347 59,768 55,890 31,429 1,124,313 Capitalized interest........... 16,150 23,934 7,568 1,973 3,266 -- 52,891 ---------- -------- -------- -------- -------- ------- ---------- COSTS EXPENDED IN 2003......... 1,280,587 599,156 250,220 157,339 751,369 35,098 3,073,769 ---------- -------- -------- -------- -------- ------- ---------- Plus: Asset retirement obligation costs(1).......... 162,812 17,386 -- (3,589) 189,190 154 365,953 ---------- -------- -------- -------- -------- ------- ---------- COSTS INCURRED................. $1,443,399 $616,542 $250,220 $153,750 $940,559 $35,252 $3,439,722 ========== ======== ======== ======== ======== ======= ========== Property sales................. $ (45,678) $(13,266) $ -- $ -- $ -- $ -- $ (58,944) 2002 Acquisitions: Proved....................... $ 201,662 $ 79,817 $ -- $ -- $ -- $ -- $ 281,479 Unproved..................... 65,875 4,353 -- -- -- -- 70,228 Purchase of non-producing leases....................... 2,264 20,150 -- -- -- -- 22,414 Exploration.................... 19,805 2,833 55,580 50,327 -- 2,330 130,875 Development.................... 280,542 235,208 115,580 39,486 -- 36,079 706,895 Capitalized interest........... 13,200 14,392 8,875 4,224 -- -- 40,691 ---------- -------- -------- -------- -------- ------- ---------- COSTS INCURRED................. $ 583,348 $356,753 $180,035 $ 94,037 $ -- $38,409 $1,252,582 ========== ======== ======== ======== ======== ======= ========== Property sales................. $ 873 $ 84 $ (8,000) $ -- $ -- $ -- $ (7,043)
(1) Effective January 1, 2003, Apache adopted SFAS No. 143 "Asset Retirement Obligations." The asset retirement obligation costs reflect abandonment obligations assumed during the year and related revisions. Actual retirement expenditures reflect plugging and abandonment costs during the year that are included in exploration and development activity. Prior periods presentation was not changed to reflect SFAS No. 143 because the amounts were adjusted through a one-time cumulative adjustment as described in Note 4, Asset Retirement Obligation. F-50 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Capitalized Costs The following table sets forth the capitalized costs and associated accumulated depreciation, depletion and amortization, including impairments, relating to the Company's oil and gas production, exploration and development activities:
OTHER UNITED STATES CANADA EGYPT AUSTRALIA NORTH SEA INTERNATIONAL TOTAL ------------- ---------- ---------- ---------- ---------- ------------- ----------- (IN THOUSANDS) 2004 Proved properties...... $11,378,189 $3,929,136 $1,836,436 $1,292,165 $1,252,911 $ 244,204 $19,933,041 Unproved properties.... 313,009 220,340 129,303 38,450 56,498 20,090 777,690 ----------- ---------- ---------- ---------- ---------- --------- ----------- 11,691,198 4,149,476 1,965,739 1,330,615 1,309,409 264,294 20,710,731 Accumulated DD&A....... (5,051,373) (964,454) (817,100) (555,797) (198,193) (133,957) (7,720,874) ----------- ---------- ---------- ---------- ---------- --------- ----------- $ 6,639,825 $3,185,022 $1,148,639 $ 774,818 $1,111,216 $ 130,337 $12,989,857 =========== ========== ========== ========== ========== ========= =========== 2003 Proved properties...... $ 9,412,413 $3,131,369 $1,514,104 $1,159,205 $ 844,679 $ 216,160 $16,277,930 Unproved properties.... 277,159 226,355 143,161 30,968 95,878 21,640 795,161 ----------- ---------- ---------- ---------- ---------- --------- ----------- 9,689,572 3,357,724 1,657,265 1,190,173 940,557 237,800 17,073,091 Accumulated DD&A....... (4,521,062) (775,101) (663,224) (448,522) (71,956) (91,771) (6,571,636) ----------- ---------- ---------- ---------- ---------- --------- ----------- $ 5,168,510 $2,582,623 $ 994,041 $ 741,651 $ 868,601 $ 146,029 $10,501,455 =========== ========== ========== ========== ========== ========= ===========
Costs Not Being Amortized The following table sets forth a summary of oil and gas property costs not being amortized at December 31, 2004, by the year in which such costs were incurred. There are no individually significant properties or significant development projects included in costs not being amortized. The majority of the evaluation activities are expected to be completed within five to ten years.
2001 AND TOTAL 2004 2003 2002 PRIOR -------- -------- -------- -------- --------- (IN THOUSANDS) Property acquisition costs............... $520,594 $181,816 $174,367 $ 98,249 $66,162 Exploration and development.............. 231,315 157,016 34,501 22,200 17,598 Capitalized interest..................... 25,781 3,243 3,186 6,933 12,419 -------- -------- -------- -------- ------- Total.................................. $777,690 $342,075 $212,054 $127,382 $96,179 ======== ======== ======== ======== =======
F-51 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Oil and Gas Reserve Information Proved oil and gas reserve quantities are based on estimates prepared by the Company's engineers in accordance with Rule 4-10 of Regulation S-X. The Company engages Ryder Scott Company, L.P. Petroleum Consultants as independent petroleum engineers, to review the Company's estimates of proved hydrocarbon liquid and gas reserves and provide an opinion letter on the reasonableness of Apache's internal projections. During this review, they prepare independent projections for each reviewed property and determine if the Company's estimates are within engineering tolerance by geographical area. The independent reviews typically cover a large percentage of major value fields, international properties and new wells drilled during the year. During 2004, 2003, and 2002, their review covered 79, 78 and 68 percent of the Apache's estimated reserve value, respectively. There are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and timing of development expenditures. The following reserve data only represents estimates and should not be construed as being exact.
CRUDE OIL, CONDENSATE AND NATURAL GAS LIQUIDS -------------------------------------------------------------------- (THOUSANDS OF BARRELS) UNITED NORTH OTHER STATES CANADA EGYPT AUSTRALIA SEA INT'L TOTAL ------- ------- ------- --------- ------- ------ ------- PROVED DEVELOPED RESERVES: December 31, 2001.......................... 230,017 76,250 59,188 45,628 -- 699 411,782 December 31, 2002.......................... 240,880 89,554 51,162 31,746 -- 1,033 414,375 December 31, 2003.......................... 265,135 91,501 54,881 26,999 147,880 7,293 593,689 December 31, 2004.......................... 320,752 87,914 57,084 18,919 172,260 5,721 662,650 TOTAL PROVED RESERVES: Balance December 31, 2001................... 321,437 136,905 80,986 59,003 -- 1,057 599,388 Extensions, discoveries and other additions................................ 20,082 31,366 18,227 4,221 -- 11,793 85,689 Purchases of minerals in-place............. 7,109 5,055 -- -- -- -- 12,164 Revisions of previous estimates............ 6,630 159 (8,140) 106 -- 40 (1,205) Production................................. (21,790) (9,846) (15,977) (11,082) -- (225) (58,920) Sales of properties........................ (46) -- (305) -- -- -- (351) ------- ------- ------- ------- ------- ------ ------- Balance December 31, 2002................... 333,422 163,639 74,791 52,248 -- 12,665 636,765 Extensions, discoveries and other additions................................ 35,378 15,649 15,090 11,712 14,489 640 92,958 Purchases of minerals in-place............. 48,886 574 -- 309 144,071 -- 193,840 Revisions of previous estimates............ 953 12 648 (2) -- (113) 1,498 Production................................. (28,098) (9,776) (17,356) (11,165) (10,680) (1,230) (78,305) Sales of properties........................ (1,176) (1,692) -- -- -- -- (2,868) ------- ------- ------- ------- ------- ------ ------- Balance December 31, 2003................... 389,365 168,406 73,173 53,102 147,880 11,962 843,888 Extensions, discoveries and other additions................................ 26,600 1,106 26,865 10,422 45,261 186 110,440 Purchases of minerals in-place............. 84,375 165 -- -- 389 -- 84,929 Revisions of previous estimates............ (13,588) (1,207) (2,955) 2 (4) (348) (18,100) Production................................. (27,867) (10,209) (19,099) (9,214) (19,338) (2,982) (88,709) Sales of properties........................ (408) -- -- -- -- -- (408) ------- ------- ------- ------- ------- ------ ------- Balance December 31, 2004................... 458,477 158,261 77,984 54,312 174,188 8,818 932,040 ======= ======= ======= ======= ======= ====== ======= NATURAL GAS TOTAL ------------------------------------------------------------------------ ----------- (THOUSAND (MILLIONS OF CUBIC FEET) BARRELS OF UNITED NORTH OTHER OIL STATES CANADA EGYPT AUSTRALIA SEA INT'L TOTAL EQUIVALENT) --------- --------- ------- --------- ----- ------ --------- ----------- PROVED DEVELOPED RESERVES: December 31, 2001.......................... 1,407,561 1,148,516 338,707 307,509 -- 1,524 3,203,817 945,751 December 31, 2002.......................... 1,444,677 1,255,068 246,529 256,790 -- 3,469 3,206,533 948,797 December 31, 2003.......................... 1,565,855 1,411,877 337,844 218,745 3,902 2,750 3,540,973 1,183,851 December 31, 2004.......................... 1,722,803 1,479,271 474,028 158,789 6,804 2,364 3,844,059 1,303,327 TOTAL PROVED RESERVES: Balance December 31, 2001................... 1,675,794 1,301,882 453,233 571,689 -- 2,733 4,005,331 1,266,943 Extensions, discoveries and other additions................................ 102,050 70,066 6,123 28,943 -- 3,355 210,537 120,779 Purchases of minerals in-place............. 154,459 66,113 -- -- -- -- 220,572 48,926 Revisions of previous estimates............ 37,944 20,900 (37,480) 22 -- 37 21,423 2,366 Production................................. (183,708) (120,210) (44,769) (42,998) -- (2,656) (394,341) (124,644) Sales of properties........................ (2,446) -- (6,440) -- -- -- (8,886) (1,832) --------- --------- ------- ------- ----- ------ --------- --------- Balance December 31, 2002................... 1,784,093 1,338,751 370,667 557,656 -- 3,469 4,054,636 1,312,538 Extensions, discoveries and other additions................................ 113,552 387,533 217,455 127,516 105 2,084 848,245 234,333 Purchases of minerals in-place............. 391,510 4,510 -- 38,638 4,423 -- 439,081 267,019 Revisions of previous estimates............ 6,073 (8,177) 4,292 -- -- 1 2,189 1,863 Production................................. (242,782) (116,263) (41,447) (40,537) (626) (2,607) (444,262) (152,349) Sales of properties........................ (23,054) (671) -- -- -- (196) (23,921) (6,855) --------- --------- ------- ------- ----- ------ --------- --------- Balance December 31, 2003................... 2,029,392 1,605,683 550,967 683,273 3,902 2,751 4,875,968 1,656,549 Extensions, discoveries and other additions................................ 291,303 542,779 452,509 54,272 3,575 1,007 1,345,445 334,681 Purchases of minerals in-place............. 268,386 17,273 -- -- 12 -- 285,671 132,541 Revisions of previous estimates............ 53,816 (61,695) (18,572) 1 -- 1 (26,449) (22,508) Production................................. (236,660) (119,669) (50,412) (43,228) (685) (1,395) (452,049) (164,050) Sales of properties........................ (657) -- -- -- -- -- (657) (518) --------- --------- ------- ------- ----- ------ --------- --------- Balance December 31, 2004................... 2,405,580 1,984,371 934,492 694,318 6,804 2,364 6,027,929 1,936,695 ========= ========= ======= ======= ===== ====== ========= =========
As of December 31, 2004, 2003 and 2002, on a barrel of equivalent basis 32.7, 28.5 and 27.7 percent of our estimated worldwide reserves, respectively, were classified as proved undeveloped. Approximately 23 percent of our year-end 2004 estimated proved developed reserves are classified as proved not producing. These reserves relate to zones that are either behind pipe, or that have been completed but not yet produced, or zones that have been produced in the past, but are not now producing because of mechanical reasons. These reserves may be regarded as less certain than producing reserves because they are frequently based on volumetric calculations rather than performance data. Future production associated with behind pipe reserves is scheduled to follow depletion of the currently producing zones in the same wellbores. It should be noted that additional capital may have to be spent to access these reserves. The capital and economic impact of production timing are reflected in this Note 14, under "Future Net Cash Flows." F-52 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Future Net Cash Flows Future cash inflows are based on year-end oil and gas prices except in those instances where future natural gas or oil sales are covered by physical contract terms providing for higher or lower amounts. Operating costs, production and ad valorem taxes and future development costs are based on current costs with no escalation. The following table sets forth unaudited information concerning future net cash flows for oil and gas reserves, net of income tax expense. Income tax expense has been computed using expected future tax rates and giving effect to tax deductions and credits available, under current laws, and which relate to oil and gas producing activities. This information does not purport to present the fair market value of the Company's oil and gas assets, but does present a standardized disclosure concerning possible future net cash flows that would result under the assumptions used.
UNITED OTHER STATES CANADA(1) EGYPT AUSTRALIA NORTH SEA INTERNATIONAL TOTAL ----------- ----------- ----------- ---------- ----------- ------------- ------------ (IN THOUSANDS) 2004 Cash inflows......... $32,557,246 $17,140,078 $ 6,233,328 $3,065,332 $ 6,783,414 $323,963 $ 66,103,361 Production costs..... (8,185,633) (7,451,626) (818,876) (891,117) (4,098,870) (89,280) (21,535,402) Development costs.... (1,620,421) (584,160) (596,249) (422,045) (569,435) (25,220) (3,817,530) Income tax expense... (7,342,348) (2,461,911) (1,790,617) (423,263) (617,244) (42,314) (12,677,697) ----------- ----------- ----------- ---------- ----------- -------- ------------ Net cash flows....... 15,408,844 6,642,381 3,027,586 1,328,907 1,497,865 167,149 28,072,732 10 percent discount rate............... (7,414,246) (3,177,411) (1,165,331) (568,722) (418,169) (32,775) (12,776,654) ----------- ----------- ----------- ---------- ----------- -------- ------------ Discounted future net cash flows(2)...... $ 7,994,598 $ 3,464,970 $ 1,862,255 $ 760,185 $ 1,079,696 $134,374 $ 15,296,078 =========== =========== =========== ========== =========== ======== ============ 2003 Cash inflows......... $23,117,256 $12,533,197 $ 3,999,829 $2,737,289 $ 4,193,438 $378,032 $ 46,959,041 Production costs..... (6,012,893) (3,049,847) (545,505) (658,132) (2,622,103) (63,384) (12,951,864) Development costs.... (1,152,182) (451,491) (397,493) (397,206) (593,778) (17,431) (3,009,581) Income tax expense... (4,834,389) (2,595,286) (997,847) (433,667) (195,756) (59,616) (9,116,561) ----------- ----------- ----------- ---------- ----------- -------- ------------ Net cash flows....... 11,117,792 6,436,573 2,058,984 1,248,284 781,801 237,601 21,881,035 10 percent discount rate............... (5,222,609) (3,353,451) (726,933) (536,921) (204,248) (59,029) (10,103,191) ----------- ----------- ----------- ---------- ----------- -------- ------------ Discounted future net cash flows(2)...... $ 5,895,183 $ 3,083,122 $ 1,332,051 $ 711,363 $ 577,553 $178,572 $ 11,777,844 =========== =========== =========== ========== =========== ======== ============
F-53 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
UNITED OTHER STATES CANADA(1) EGYPT AUSTRALIA NORTH SEA INTERNATIONAL TOTAL ----------- ----------- ----------- ---------- ----------- ------------- ------------ (IN THOUSANDS) 2002 Cash inflows......... $17,550,514 $ 9,597,042 $ 3,820,016 $2,436,477 $ -- $402,311 $ 33,806,360 Production costs..... (4,442,214) (1,955,401) (501,511) (463,282) -- (61,905) (7,424,313) Development costs.... (662,686) (312,194) (421,454) (235,318) -- (19,600) (1,651,252) Income tax expense... (3,875,478) (2,288,073) (963,906) (482,883) -- (59,164) (7,669,504) ----------- ----------- ----------- ---------- ----------- -------- ------------ Net cash flows....... 8,570,136 5,041,374 1,933,145 1,254,994 -- 261,642 17,061,291 10 percent discount rate............... (4,170,620) (2,633,601) (651,524) (373,032) -- (80,894) (7,909,671) ----------- ----------- ----------- ---------- ----------- -------- ------------ Discounted future net cash flows(2)...... $ 4,399,516 $ 2,407,773 $ 1,281,621 $ 881,962 $ -- $180,748 $ 9,151,620 =========== =========== =========== ========== =========== ======== ============
(1) Included in the estimated future net cash flows are Canadian provincial tax credits expected to be realized beyond the date at which the legislation, under its provisions, could be repealed. To date, the Canadian provincial government has not indicated an intention to repeal this legislation. (2) Estimated future net cash flows before income tax expense, discounted at 10 percent per annum, totaled approximately $22.2 billion, $16.4 billion and $13.2 billion as of December 31, 2004, 2003 and 2002, respectively. F-54 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The following table sets forth the principal sources of change in the discounted future net cash flows:
FOR THE YEAR ENDED DECEMBER 31, --------------------------------------- 2004 2003 2002 ----------- ----------- ----------- (IN THOUSANDS) Sales, net of production costs........................ $(4,383,289) $(3,312,728) $(1,994,631) Net change in prices and production costs............. 1,119,906 224,609 4,767,785 Discoveries and improved recovery, net of related costs............................................... 4,404,964 2,808,283 1,885,266 Change in future development costs.................... 103,481 48,531 222,160 Revision of quantities................................ (242,005) 22,807 (15,400) Purchases of minerals in-place........................ 2,051,068 2,743,936 603,608 Accretion of discount................................. 1,660,486 1,317,894 737,112 Change in income taxes................................ (2,091,187) (795,143) (2,200,925) Sales of properties................................... (5,825) (90,263) (14,502) Change in production rates and other.................. 900,635 (341,703) (382,314) ----------- ----------- ----------- $ 3,518,234 $ 2,626,223 $ 3,608,159 =========== =========== ===========
Impact of Pricing The estimates of cash flows and reserve quantities shown above are based on year-end oil and gas prices, except in those cases where future natural gas or oil sales are covered by physical contracts at specified prices. Forward price volatility is largely attributable to supply and demand perceptions for natural gas and oil. Under full-cost accounting rules, the Company reviews the carrying value of its proved oil and gas properties each quarter on a country-by-country basis. Under these rules, capitalized costs of proved oil and gas properties, net of accumulated DD&A and deferred income taxes, may not exceed the present value of estimated future net cash flows from proved oil and gas reserves, 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 (the "ceiling"). These rules generally require pricing future oil and gas production at the unescalated oil and gas prices at the end of each fiscal quarter and require a write-down if the "ceiling" is exceeded. Given the volatility of oil and gas prices, it is reasonably possible that the Company's estimate of discounted future net cash flows from proved oil and gas reserves could change in the near term. If oil and gas prices decline significantly, even if only for a short period of time, it is possible that write-downs of oil and gas properties could occur in the future. F-55 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 15. SUPPLEMENTAL QUARTERLY FINANCIAL DATA (UNAUDITED)
FIRST SECOND THIRD FOURTH TOTAL ---------- ---------- ---------- ---------- ---------- (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) 2004(3) Revenues......................... $1,149,939 $1,240,733 $1,407,002 $1,534,903 $5,332,577 Expenses, net.................... 803,614 857,207 976,527 1,025,158 3,662,506 ---------- ---------- ---------- ---------- ---------- Income before change in accounting principle........... 346,325 383,526 430,475 509,745 1,670,071 Cumulative effect of change in accounting principle, net of income tax..................... -- -- -- (1,317) (1,317) ---------- ---------- ---------- ---------- ---------- Net income....................... $ 346,325 $ 383,526 $ 430,475 $ 508,428 $1,668,754 ========== ========== ========== ========== ========== Income attributable to common stock.......................... $ 344,905 $ 382,106 $ 429,055 $ 507,008 $1,663,074 ========== ========== ========== ========== ========== Net income per common share(1)(2): Basic.......................... $ 1.06 $ 1.17 $ 1.31 $ 1.55 $ 5.10 ========== ========== ========== ========== ========== Diluted........................ $ 1.05 $ 1.16 $ 1.30 $ 1.52 $ 5.03 ========== ========== ========== ========== ========== 2003 Revenues......................... $ 966,609 $1,054,356 $1,104,541 $1,064,793 $4,190,299 Expenses, net.................... 654,312 809,975 827,580 803,179 3,095,046 ---------- ---------- ---------- ---------- ---------- Income before change in accounting principle........... 312,297 244,381 276,961 261,614 1,095,253 Cumulative effect of change in accounting principle, net of income tax..................... 26,632 -- -- -- 26,632 ---------- ---------- ---------- ---------- ---------- Net income....................... $ 338,929 $ 244,381 $ 276,961 $ 261,614 $1,121,885 ========== ========== ========== ========== ========== Income attributable to common stock.......................... $ 337,509 $ 242,961 $ 275,541 $ 260,194 $1,116,205 ========== ========== ========== ========== ========== Net income per common share(1)(2): Basic.......................... $ 1.06 $ .75 $ .85 $ .80 $ 3.46 ========== ========== ========== ========== ========== Diluted........................ $ 1.05 $ .75 $ .84 $ .80 $ 3.43 ========== ========== ========== ========== ==========
(1) The sum of the individual quarterly net income per common share amounts may not agree with year-to-date net income per common share as each quarterly computation is based on the weighted average number of common shares outstanding during that period. All potentially dilutive securities were included in each quarterly computation of diluted net income per common share, as none were antidilutive. (2) Earnings per share have been restated to reflect the five percent stock dividend declared December 18, 2002, payable April 2, 2003 to shareholders of record on March 12, 2003, and the two-for-one stock split declared September 11, 2003, paid January 14, 2004, to shareholders of record on December 31, 2003. (3) The first, second and third-quarter totals for 2004 will not agree to the applicable Form 10-Q filing because interim amounts have been restated to reflect the early adoption of SFAS No. 123-R, refer to Note 1, Summary of Significant Accounting Policies. F-56 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 16. SUPPLEMENTAL GUARANTOR INFORMATION Prior to 2001, Apache Finance Australia was a finance subsidiary of Apache with no independent operations. In this capacity, it issued approximately $270 million of publicly traded notes that are fully and unconditionally guaranteed by Apache and, beginning in 2001, Apache North America, Inc. The guarantors of Apache Finance Australia have joint and several liability. Similarly, Apache Finance Canada was also a finance subsidiary of Apache and had issued approximately $300 million of publicly traded notes that were fully and unconditionally guaranteed by Apache. Generally, the issuance of publicly traded securities would subject those subsidiaries to the reporting requirements of the Securities and Exchange Commission. Since these subsidiaries had no independent operations and qualified as "finance subsidiaries," they were exempted from these requirements. During 2001, Apache contributed stock of its Australian and Canadian operating subsidiaries to Apache Finance Australia and Apache Finance Canada, respectively. As a result of these contributions, they no longer qualify as finance subsidiaries. As allowed by the SEC rules, the following condensed consolidating financial statements are provided as an alternative to filing separate financial statements. Each of the companies presented in the condensed consolidating financial statements is wholly owned and has been consolidated in Apache Corporation's consolidated financial statements for all periods presented. As such, the condensed consolidating financial statements should be read in conjunction with the financial statements of Apache Corporation and subsidiaries and notes thereto of which this note is an integral part. F-57 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS FOR THE YEAR ENDED DECEMBER 31, 2004
ALL OTHER APACHE SUBSIDIARIES APACHE APACHE FINANCE APACHE OF APACHE CORPORATION NORTH AMERICA AUSTRALIA FINANCE CANADA CORPORATION ----------- ------------- --------- -------------- ------------ (IN THOUSANDS) Revenues and Other: Oil and gas production revenues......... $2,313,901 $ -- $ -- $ -- $3,295,849 Equity in net income of affiliates...... 978,881 51,888 63,859 152,823 33,641 Other................................... 47,321 -- (25) -- (22,736) ---------- ------- ------- -------- ---------- 3,340,103 51,888 63,834 152,823 3,306,754 ---------- ------- ------- -------- ---------- Operating Expenses: Depreciation, depletion and amortization......................... 551,057 -- -- -- 671,095 Asset retirement obligation accretion... 25,531 -- -- -- 20,529 Lease operating costs................... 375,894 -- -- -- 790,217 Gathering and transportation costs...... 28,317 -- -- -- 53,944 Severance and other taxes............... 65,559 -- -- (208) 28,397 Administrative, selling and other....... 138,058 -- -- -- 35,136 China litigation provision.............. -- -- -- -- 71,216 Financing costs, net.................... 86,980 -- 18,047 40,363 (28,905) ---------- ------- ------- -------- ---------- 1,271,396 -- 18,047 40,155 1,641,629 ---------- ------- ------- -------- ---------- Income (Loss) Before Income Taxes......... 2,068,707 51,888 45,787 112,668 1,665,125 Provision (benefit) for income taxes.... 398,636 -- (6,101) (85,767) 686,244 ---------- ------- ------- -------- ---------- Income (Loss) Before Change in Accounting Principle............................... 1,670,071 51,888 51,888 198,435 978,881 Cumulative effect of change in accounting principle, net of income tax.................................. (1,317) -- -- -- -- ---------- ------- ------- -------- ---------- Net Income................................ 1,668,754 51,888 51,888 198,435 978,881 Preferred stock dividends............... 5,680 -- -- -- -- ---------- ------- ------- -------- ---------- Income Attributable to Common Stock....... $1,663,074 $51,888 $51,888 $198,435 $ 978,881 ========== ======= ======= ======== ========== RECLASSIFICATIONS & ELIMINATIONS CONSOLIDATED ----------------- ------------ (IN THOUSANDS) Revenues and Other: Oil and gas production revenues......... $ (301,733) $5,308,017 Equity in net income of affiliates...... (1,281,092) -- Other................................... -- 24,560 ----------- ---------- (1,582,825) 5,332,577 ----------- ---------- Operating Expenses: Depreciation, depletion and amortization......................... -- 1,222,152 Asset retirement obligation accretion... -- 46,060 Lease operating costs................... (301,733) 864,378 Gathering and transportation costs...... -- 82,261 Severance and other taxes............... -- 93,748 Administrative, selling and other....... -- 173,194 China litigation provision.............. -- 71,216 Financing costs, net.................... -- 116,485 ----------- ---------- (301,733) 2,669,494 ----------- ---------- Income (Loss) Before Income Taxes......... (1,281,092) 2,663,083 Provision (benefit) for income taxes.... -- 993,012 ----------- ---------- Income (Loss) Before Change in Accounting Principle............................... (1,281,092) 1,670,071 Cumulative effect of change in accounting principle, net of income tax.................................. -- (1,317) ----------- ---------- Net Income................................ (1,281,092) 1,668,754 Preferred stock dividends............... -- 5,680 ----------- ---------- Income Attributable to Common Stock....... $(1,281,092) $1,663,074 =========== ==========
F-58 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS FOR THE YEAR ENDED DECEMBER 31, 2003
ALL OTHER APACHE SUBSIDIARIES APACHE APACHE FINANCE APACHE OF APACHE CORPORATION NORTH AMERICA AUSTRALIA FINANCE CANADA CORPORATION ----------- ------------- --------- -------------- ------------ (IN THOUSANDS) Revenues and Other: Oil and gas production revenues...... $1,687,609 $ -- $ -- $ -- $2,729,966 Equity in net income of affiliates... 597,020 21,189 33,117 111,274 (37,160) Other................................ (4,250) -- (25) -- (4,346) ---------- ------- ------- -------- ---------- 2,280,379 21,189 33,092 111,274 2,688,460 ---------- ------- ------- -------- ---------- Operating Expenses: Depreciation, depletion and amortization...................... 374,534 -- -- -- 698,752 Asset retirement obligation accretion......................... 15,944 -- -- -- 21,819 International impairments............ -- -- -- -- 12,813 Lease operating costs................ 264,311 -- -- -- 654,007 Gathering and transportation costs... 19,558 -- -- -- 40,902 Severance and other taxes............ 50,899 -- -- 63 70,831 Administrative, selling and other.... 111,984 -- -- -- 26,540 Financing costs, net................. 102,142 -- 18,047 40,064 (45,181) ---------- ------- ------- -------- ---------- 939,372 -- 18,047 40,127 1,480,483 ---------- ------- ------- -------- ---------- Preferred Interests of Subsidiaries.... (592) -- -- -- 9,260 ---------- ------- ------- -------- ---------- Income (Loss) Before Income Taxes...... 1,341,599 21,189 15,045 71,147 1,198,717 Provision (benefit) for income taxes............................. 239,471 -- (6,144) (14,895) 608,572 ---------- ------- ------- -------- ---------- Income (Loss) Before Change in Accounting Principle................. 1,102,128 21,189 21,189 86,042 590,145 Cumulative effect of change in accounting principle, net of income tax........................ 19,757 -- -- -- 6,875 ---------- ------- ------- -------- ---------- Net Income............................. 1,121,885 21,189 21,189 86,042 597,020 Preferred stock dividends............ 5,680 -- -- -- -- ---------- ------- ------- -------- ---------- Income Attributable To Common Stock.... $1,116,205 $21,189 $21,189 $ 86,042 $ 597,020 ========== ======= ======= ======== ========== RECLASSIFICATIONS & ELIMINATIONS CONSOLIDATED ----------------- ----------------- (IN THOUSANDS) Revenues and Other: Oil and gas production revenues...... $(218,655) $4,198,920 Equity in net income of affiliates... (725,440) -- Other................................ -- (8,621) --------- ---------- (944,095) 4,190,299 --------- ---------- Operating Expenses: Depreciation, depletion and amortization...................... -- 1,073,286 Asset retirement obligation accretion......................... -- 37,763 International impairments............ -- 12,813 Lease operating costs................ (218,655) 699,663 Gathering and transportation costs... -- 60,460 Severance and other taxes............ -- 121,793 Administrative, selling and other.... -- 138,524 Financing costs, net................. -- 115,072 --------- ---------- (218,655) 2,259,374 --------- ---------- Preferred Interests of Subsidiaries.... -- 8,668 --------- ---------- Income (Loss) Before Income Taxes...... (725,440) 1,922,257 Provision (benefit) for income taxes............................. -- 827,004 --------- ---------- Income (Loss) Before Change in Accounting Principle................. (725,440) 1,095,253 Cumulative effect of change in accounting principle, net of income tax........................ -- 26,632 --------- ---------- Net Income............................. (725,440) 1,121,885 Preferred stock dividends............ -- 5,680 --------- ---------- Income Attributable To Common Stock.... $(725,440) $1,116,205 ========= ==========
F-59 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS FOR THE YEAR ENDED DECEMBER 31, 2002
ALL OTHER APACHE SUBSIDIARIES APACHE APACHE FINANCE APACHE OF APACHE CORPORATION NORTH AMERICA AUSTRALIA FINANCE CANADA CORPORATION ----------- ------------- --------- -------------- ------------ (IN THOUSANDS) Revenues and Other: Oil and gas production revenues......... $ 814,225 $ -- $ -- $ -- $1,906,009 Equity in net income of affiliates...... 391,295 20,976 32,905 76,707 (37,036) Other................................... 7,909 -- (25) -- (7,759) ---------- ------- ------- -------- ---------- 1,213,429 20,976 32,880 76,707 1,861,214 ---------- ------- ------- -------- ---------- Operating Expenses: Depreciation, depletion and amortization......................... 211,291 -- -- -- 632,588 International impairments............... -- -- -- -- 19,600 Lease operating costs................... 198,052 -- -- -- 420,337 Gathering and transportation costs...... 15,896 -- -- -- 22,671 Severance and other taxes............... 34,015 -- -- 270 33,024 Administrative, selling and other....... 87,860 -- -- -- 16,728 Financing costs, net.................... 72,721 -- 18,050 41,058 (18,996) ---------- ------- ------- -------- ---------- 619,835 -- 18,050 41,328 1,125,952 ---------- ------- ------- -------- ---------- Preferred Interests of Subsidiaries....... -- -- -- -- 16,224 ---------- ------- ------- -------- ---------- Income (Loss) Before Income Taxes......... 593,594 20,976 14,830 35,379 719,038 Provision (benefit) for income taxes.... 39,265 -- (6,146) (16,221) 327,743 ---------- ------- ------- -------- ---------- Net Income................................ 554,329 20,976 20,976 51,600 391,295 Preferred stock dividends............... 10,815 -- -- -- -- ---------- ------- ------- -------- ---------- Income Attributable to Common Stock....... $ 543,514 $20,976 $20,976 $ 51,600 $ 391,295 ========== ======= ======= ======== ========== RECLASSIFICATIONS & ELIMINATIONS CONSOLIDATED ----------------- ------------ (IN THOUSANDS) Revenues and Other: Oil and gas production revenues......... $(160,486) $2,559,748 Equity in net income of affiliates...... (484,847) -- Other................................... -- 125 --------- ---------- (645,333) 2,559,873 --------- ---------- Operating Expenses: Depreciation, depletion and amortization......................... -- 843,879 International impairments............... -- 19,600 Lease operating costs................... (160,486) 457,903 Gathering and transportation costs...... -- 38,567 Severance and other taxes............... -- 67,309 Administrative, selling and other....... -- 104,588 Financing costs, net.................... -- 112,833 --------- ---------- (160,486) 1,644,679 --------- ---------- Preferred Interests of Subsidiaries....... -- 16,224 --------- ---------- Income (Loss) Before Income Taxes......... (484,847) 898,970 Provision (benefit) for income taxes.... -- 344,641 --------- ---------- Net Income................................ (484,847) 554,329 Preferred stock dividends............... -- 10,815 --------- ---------- Income Attributable to Common Stock....... $(484,847) $ 543,514 ========= ==========
F-60 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS FOR THE YEAR ENDED DECEMBER 31, 2004
ALL OTHER APACHE SUBSIDIARIES APACHE APACHE FINANCE APACHE OF APACHE CORPORATION NORTH AMERICA AUSTRALIA FINANCE CANADA CORPORATION ----------- ------------- --------- -------------- ------------ (IN THOUSANDS) Cash Provided by (Used in) Operating Activities........ $ 1,486,100 $ -- $(17,500) $(356,371) $ 2,119,290 ----------- -------- -------- --------- ----------- Cash Flows from Investing Activities: Additions to property and equipment.................. (900,464) -- -- -- (1,556,024) Acquisitions......................................... (880,136) -- -- -- -- Proceeds from sales of oil and gas properties........ 3,210 -- -- -- 832 Investment in and advances to subsidiaries, net...... 62,069 (18,050) -- -- (373,353) Other, net........................................... (27,003) -- -- -- (51,428) ----------- -------- -------- --------- ----------- Net Cash Used in Investing Activities.................. (1,742,324) (18,050) -- -- (1,979,973) ----------- -------- -------- --------- ----------- Cash Flows From Financing Activities: Long-term borrowings................................. 544,561 -- (550) 347,550 (184,717) Payments on long-term debt........................... (283,400) -- -- -- -- Dividends paid....................................... (90,369) -- -- -- -- Common stock activity................................ 21,595 18,050 18,050 8,823 122,391 Treasury stock activity, net......................... 12,472 -- -- -- -- Cost of debt and equity transactions................. (2,303) -- -- -- -- Other................................................ 54,265 -- -- -- -- ----------- -------- -------- --------- ----------- Net Cash Provided by Financing Activities.............. 256,821 18,050 17,500 356,373 (62,326) ----------- -------- -------- --------- ----------- Net Increase (Decrease) in Cash and Cash Equivalents... 597 -- -- 2 76,991 Cash and Cash Equivalents at Beginning of Year......... -- -- 2 1 33,500 ----------- -------- -------- --------- ----------- Cash and Cash Equivalents at End of Year............... $ 597 $ -- $ 2 $ 3 $ 110,491 =========== ======== ======== ========= =========== RECLASSIFICATIONS & ELIMINATIONS CONSOLIDATED ----------------- ------------ (IN THOUSANDS) Cash Provided by (Used in) Operating Activities........ $ -- $ 3,231,519 ----------- ----------- Cash Flows from Investing Activities: Additions to property and equipment.................. -- (2,456,488) Acquisitions......................................... -- (880,136) Proceeds from sales of oil and gas properties........ -- 4,042 Investment in and advances to subsidiaries, net...... 329,334 -- Other, net........................................... -- (78,431) ----------- ----------- Net Cash Used in Investing Activities.................. 329,334 (3,411,013) ----------- ----------- Cash Flows From Financing Activities: Long-term borrowings................................. (162,020) 544,824 Payments on long-term debt........................... -- (283,400) Dividends paid....................................... -- (90,369) Common stock activity................................ (167,314) 21,595 Treasury stock activity, net......................... -- 12,472 Cost of debt and equity transactions................. -- (2,303) Other................................................ -- 54,265 ----------- ----------- Net Cash Provided by Financing Activities.............. (329,334) 257,084 ----------- ----------- Net Increase (Decrease) in Cash and Cash Equivalents... -- 77,590 Cash and Cash Equivalents at Beginning of Year......... -- 33,503 ----------- ----------- Cash and Cash Equivalents at End of Year............... $ -- $ 111,093 =========== ===========
F-61 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS FOR THE YEAR ENDED DECEMBER 31, 2003
ALL OTHER APACHE SUBSIDIARIES APACHE APACHE FINANCE APACHE OF APACHE CORPORATION NORTH AMERICA AUSTRALIA FINANCE CANADA CORPORATION ----------- ------------- --------- -------------- ------------ (IN THOUSANDS) Cash Provided by (Used in) Operating Activities.................................... $ 1,136,019 $ -- $(19,604) $(39,675) $ 1,629,160 ----------- -------- -------- -------- ----------- Cash Flows from Investing Activities: Additions to property and equipment........... (494,941) -- -- -- (1,099,995) Acquisitions.................................. (736,651) -- -- -- (628,538) Proceeds from sales of oil and gas properties.................................. 45,678 -- -- -- 13,266 Investment in and advances to subsidiaries, net......................................... (480,105) (18,113) -- -- (76,689) Other, net.................................... (33,763) -- -- -- (23,813) ----------- -------- -------- -------- ----------- Net Cash Used in Investing Activities........... (1,699,782) (18,113) -- -- (1,815,769) ----------- -------- -------- -------- ----------- Cash Flows from Financing Activities: Long-term borrowings.......................... 1,555,361 -- 1,491 2,102 (404,380) Payments on long-term debt.................... (1,419,788) -- -- -- (193,574) Dividends paid................................ (72,832) -- -- -- -- Common stock activity......................... 582,865 18,113 18,113 37,447 1,127,530 Treasury stock activity, net.................. 5,350 -- -- -- -- Cost of debt and equity transactions.......... (5,417) -- -- -- -- Repurchase of preferred interests of subsidiaries................................ (82,000) -- -- -- (361,000) ----------- -------- -------- -------- ----------- Net Cash Provided by Financing Activities....... 563,539 18,113 19,604 39,549 168,576 ----------- -------- -------- -------- ----------- Net Increase (Decrease) in Cash and Cash Equivalents................................... (224) -- -- (126) (18,033) Cash and Cash Equivalents at Beginning of Year.......................................... 224 -- 2 127 51,533 ----------- -------- -------- -------- ----------- Cash and Cash Equivalents at End of Year........ $ -- $ -- $ 2 $ 1 $ 33,500 =========== ======== ======== ======== =========== RECLASSIFICATIONS & ELIMINATIONS CONSOLIDATED ----------------- ------------ (IN THOUSANDS) Cash Provided by (Used in) Operating Activities.................................... $ -- $ 2,705,900 ----------- ----------- Cash Flows from Investing Activities: Additions to property and equipment........... -- (1,594,936) Acquisitions.................................. -- (1,365,189) Proceeds from sales of oil and gas properties.................................. -- 58,944 Investment in and advances to subsidiaries, net......................................... 574,907 -- Other, net.................................... -- (57,576) ----------- ----------- Net Cash Used in Investing Activities........... 574,907 (2,958,757) ----------- ----------- Cash Flows from Financing Activities: Long-term borrowings.......................... 626,296 1,780,870 Payments on long-term debt.................... -- (1,613,362) Dividends paid................................ -- (72,832) Common stock activity......................... (1,201,203) 582,865 Treasury stock activity, net.................. -- 5,350 Cost of debt and equity transactions.......... -- (5,417) Repurchase of preferred interests of subsidiaries................................ -- (443,000) ----------- ----------- Net Cash Provided by Financing Activities....... (574,907) 234,474 ----------- ----------- Net Increase (Decrease) in Cash and Cash Equivalents................................... -- (18,383) Cash and Cash Equivalents at Beginning of Year.......................................... -- 51,886 ----------- ----------- Cash and Cash Equivalents at End of Year........ $ -- $ 33,503 =========== ===========
F-62 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS FOR THE YEAR ENDED DECEMBER 31, 2002
ALL OTHER SUBSIDIARIES APACHE APACHE APACHE APACHE OF APACHE CORPORATION NORTH AMERICA FINANCE AUSTRALIA FINANCE CANADA CORPORATION ----------- ------------- ----------------- -------------- ------------ (IN THOUSANDS) Cash Provided by (Used in) Operating Activities................................. $ 474,784 $ -- $(18,687) $(43,819) $ 968,440 ----------- -------- -------- -------- ----------- Cash Flows from Investing Activities: Additions to property and equipment........ (249,971) -- -- -- (787,397) Acquisitions............................... (269,885) -- -- -- -- Proceeds from sales of oil and gas properties............................... -- -- -- -- 7,043 Purchase of U.S. Government Agency Notes... -- -- -- -- 101,723 Investment in and advances to subsidiaries, net...................................... (168,481) (18,050) -- -- (408,837) Other, net................................. (15,105) -- -- -- (22,415) ----------- -------- -------- -------- ----------- Net Cash Used in Investing Activities........ (703,442) (18,050) -- -- (1,109,883) ----------- -------- -------- -------- ----------- Cash Flows from Financing Activities: Long-term borrowings....................... 1,628,207 -- 637 2,826 225,518 Payments on long-term debt................. (1,362,800) -- -- -- (190,671) Dividends paid............................. (68,879) -- -- -- -- Common stock activity...................... 30,708 18,050 18,050 41,120 128,889 Treasury stock activity, net............... 1,991 -- -- -- -- Cost of debt and equity transactions....... (6,728) -- -- -- -- ----------- -------- -------- -------- ----------- Net Cash Provided by Financing Activities.... 222,499 18,050 18,687 43,946 163,736 ----------- -------- -------- -------- ----------- Net Increase (Decrease) in Cash and Cash Equivalents................................ (6,159) -- -- 127 22,293 Cash and Cash Equivalents at Beginning of Year....................................... 6,383 -- 2 -- 29,240 ----------- -------- -------- -------- ----------- Cash and Cash Equivalents at End of Year..... $ 224 $ -- $ 2 $ 127 $ 51,533 =========== ======== ======== ======== =========== RECLASSIFICATIONS & ELIMINATIONS CONSOLIDATED ----------------- ------------ (IN THOUSANDS) Cash Provided by (Used in) Operating Activities................................. $ -- $ 1,380,718 --------- ----------- Cash Flows from Investing Activities: Additions to property and equipment........ -- (1,037,368) Acquisitions............................... -- (269,885) Proceeds from sales of oil and gas properties............................... -- 7,043 Purchase of U.S. Government Agency Notes... -- 101,723 Investment in and advances to subsidiaries, net...................................... 595,368 -- Other, net................................. -- (37,520) --------- ----------- Net Cash Used in Investing Activities........ 595,368 (1,236,007) --------- ----------- Cash Flows from Financing Activities: Long-term borrowings....................... (389,259) 1,467,929 Payments on long-term debt................. -- (1,553,471) Dividends paid............................. -- (68,879) Common stock activity...................... (206,109) 30,708 Treasury stock activity, net............... -- 1,991 Cost of debt and equity transactions....... -- (6,728) --------- ----------- Net Cash Provided by Financing Activities.... (595,368) (128,450) --------- ----------- Net Increase (Decrease) in Cash and Cash Equivalents................................ -- 16,261 Cash and Cash Equivalents at Beginning of Year....................................... -- 35,625 --------- ----------- Cash and Cash Equivalents at End of Year..... $ -- $ 51,886 ========= ===========
F-63 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) CONDENSED CONSOLIDATING BALANCE SHEET FOR THE YEAR ENDED DECEMBER 31, 2004
ALL OTHER APACHE SUBSIDIARIES APACHE APACHE NORTH FINANCE APACHE FINANCE OF APACHE CORPORATION AMERICA AUSTRALIA CANADA CORPORATION ----------- ------------- --------- -------------- ------------ (IN THOUSANDS) ASSETS Current Assets: Cash and cash equivalents....................... $ 597 $ -- $ 2 $ 3 $ 110,491 Receivables, net of allowance................... 367,359 -- -- -- 572,377 Inventories..................................... 28,000 -- -- -- 129,293 Drilling advances and other..................... 82,837 -- -- -- 57,823 ----------- -------- -------- ---------- ---------- 478,793 -- 2 3 869,984 ----------- -------- -------- ---------- ---------- Property and Equipment, Net....................... 6,683,499 -- -- -- 7,176,860 ----------- -------- -------- ---------- ---------- Other Assets: Intercompany receivable, net.................... 1,107,286 -- (1,205) (253,724) (852,357) Goodwill, net................................... -- -- -- -- 189,252 Equity in affiliates............................ 4,173,788 258,437 506,806 1,250,590 (1,178,450) Deferred charges and other...................... 43,460 -- -- 4,617 56,010 ----------- -------- -------- ---------- ---------- $12,486,826 $258,437 $505,603 $1,001,486 $6,261,299 =========== ======== ======== ========== ========== LIABILITIES AND SHAREHOLDERS' EQUITY Current Liabilities: Accounts payable................................ $ 280,754 $ -- $ -- $ -- $ 261,320 Other accrued expenses.......................... 306,511 -- 3,335 29,946 401,025 ----------- -------- -------- ---------- ---------- 587,265 -- 3,335 29,946 662,345 ----------- -------- -------- ---------- ---------- Long-Term Debt.................................... 1,667,044 -- 269,192 646,798 5,356 ----------- -------- -------- ---------- ---------- Deferred Credits and Other Noncurrent Liabilities: Income taxes.................................... 1,132,618 -- (25,361) 4,233 1,035,147 Advances from gas purchasers.................... 90,876 -- -- -- -- Asset retirement obligation..................... 568,862 -- -- -- 363,142 Oil and gas derivative instruments.............. 31,417 -- -- -- -- Other........................................... 204,323 -- -- -- 21,521 ----------- -------- -------- ---------- ---------- 2,028,096 -- (25,361) 4,233 1,419,810 ----------- -------- -------- ---------- ---------- Commitments and Contingencies Shareholders' Equity.......................................... 8,204,421 258,437 258,437 320,509 4,173,788 ----------- -------- -------- ---------- ---------- $12,486,826 $258,437 $505,603 $1,001,486 $6,261,299 =========== ======== ======== ========== ========== RECLASSIFICATIONS & ELIMINATIONS CONSOLIDATED ----------------- ------------ (IN THOUSANDS) ASSETS Current Assets: Cash and cash equivalents....................... $ -- $ 111,093 Receivables, net of allowance................... -- 939,736 Inventories..................................... -- 157,293 Drilling advances and other..................... -- 140,660 ----------- ----------- -- 1,348,782 ----------- ----------- Property and Equipment, Net....................... -- 13,860,359 ----------- ----------- Other Assets: Intercompany receivable, net.................... -- -- Goodwill, net................................... -- 189,252 Equity in affiliates............................ (5,011,171) -- Deferred charges and other...................... -- 104,087 ----------- ----------- $(5,011,171) $15,502,480 =========== =========== LIABILITIES AND SHAREHOLDERS' EQUITY Current Liabilities: Accounts payable................................ $ -- $ 542,074 Other accrued expenses.......................... -- 740,817 ----------- ----------- -- 1,282,891 ----------- ----------- Long-Term Debt.................................... -- 2,588,390 ----------- ----------- Deferred Credits and Other Noncurrent Liabilities: Income taxes.................................... -- 2,146,637 Advances from gas purchasers.................... -- 90,876 Asset retirement obligation..................... -- 932,004 Oil and gas derivative instruments.............. -- 31,417 Other........................................... -- 225,844 ----------- ----------- -- 3,426,778 ----------- ----------- Commitments and Contingencies Shareholders' Equity.......................................... (5,011,171) 8,204,421 ----------- ----------- $(5,011,171) $15,502,480 =========== ===========
F-64 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) CONDENSED CONSOLIDATING BALANCE SHEET FOR THE YEAR ENDED DECEMBER 31, 2003
ALL OTHER APACHE SUBSIDIARIES APACHE APACHE NORTH FINANCE APACHE FINANCE OF APACHE CORPORATION AMERICA AUSTRALIA CANADA CORPORATION ----------- ------------- --------- -------------- ------------ (IN THOUSANDS) ASSETS Current Assets: Cash and cash equivalents.......................... $ -- $ -- $ 2 $ 1 $ 33,500 Receivables, net of allowance...................... 204,078 -- -- -- 434,977 Inventories........................................ 17,646 -- -- -- 108,221 Drilling advances and other........................ 60,159 -- -- -- 40,488 ---------- -------- -------- ---------- ----------- 281,883 -- 2 1 617,186 ---------- -------- -------- ---------- ----------- Property and Equipment, Net.......................... 5,235,717 -- -- -- 6,024,368 ---------- -------- -------- ---------- ----------- Other Assets: Intercompany receivable, net....................... 1,291,503 -- (1,961) 93,768 (1,383,310) Goodwill, net...................................... -- -- -- -- 189,252 Equity in affiliates............................... 3,077,152 183,617 437,860 1,084,711 (803,409) Deferred charges and other......................... 36,672 -- -- 4,767 26,278 ---------- -------- -------- ---------- ----------- $9,922,927 $183,617 $435,901 $1,183,247 $ 4,670,365 ========== ======== ======== ========== =========== LIABILITIES AND SHAREHOLDERS' EQUITY Current Liabilities: Accounts payable................................... $ 189,031 $ -- $ -- $ -- $ 111,567 Other accrued expenses............................. 238,555 -- 1,621 1,803 277,801 ---------- -------- -------- ---------- ----------- 427,586 -- 1,621 1,803 389,368 ---------- -------- -------- ---------- ----------- Long-Term Debt....................................... 1,405,882 -- 268,987 646,741 5,356 ---------- -------- -------- ---------- ----------- Deferred Credits and Other Noncurrent Liabilities: Income taxes....................................... 879,044 -- (18,324) (842) 837,360 Advances from gas purchasers....................... 109,207 -- -- -- -- Asset retirement obligation........................ 401,349 -- -- -- 338,426 Oil and gas derivative instruments................. 5,931 -- -- -- -- Other.............................................. 161,130 -- -- -- 22,703 ---------- -------- -------- ---------- ----------- 1,556,661 -- (18,324) (842) 1,198,489 ---------- -------- -------- ---------- ----------- Preferred Interests of Subsidiaries.................. -- -- -- -- -- ---------- -------- -------- ---------- ----------- Commitments and Contingencies Shareholders' Equity............................... 6,532,798 183,617 183,617 535,545 3,077,152 ---------- -------- -------- ---------- ----------- $9,922,927 $183,617 $435,901 $1,183,247 $ 4,670,365 ========== ======== ======== ========== =========== RECLASSIFICATIONS & ELIMINATIONS CONSOLIDATED ----------------- ------------ (IN THOUSANDS) ASSETS Current Assets: Cash and cash equivalents.......................... $ -- $ 33,503 Receivables, net of allowance...................... -- 639,055 Inventories........................................ -- 125,867 Drilling advances and other........................ -- 100,647 ----------- ----------- -- 899,072 ----------- ----------- Property and Equipment, Net.......................... -- 11,260,085 ----------- ----------- Other Assets: Intercompany receivable, net....................... -- -- Goodwill, net...................................... -- 189,252 Equity in affiliates............................... (3,979,931) -- Deferred charges and other......................... -- 67,717 ----------- ----------- $(3,979,931) $12,416,126 =========== =========== LIABILITIES AND SHAREHOLDERS' EQUITY Current Liabilities: Accounts payable................................... $ -- $ 300,598 Other accrued expenses............................. -- 519,780 ----------- ----------- -- 820,378 ----------- ----------- Long-Term Debt....................................... -- 2,326,966 ----------- ----------- Deferred Credits and Other Noncurrent Liabilities: Income taxes....................................... -- 1,697,238 Advances from gas purchasers....................... -- 109,207 Asset retirement obligation........................ -- 739,775 Oil and gas derivative instruments................. -- 5,931 Other.............................................. -- 183,833 ----------- ----------- -- 2,735,984 ----------- ----------- Preferred Interests of Subsidiaries.................. -- -- ----------- ----------- Commitments and Contingencies Shareholders' Equity............................... (3,979,931) 6,532,798 ----------- ----------- $(3,979,931) $12,416,126 =========== ===========
F-65 BOARD OF DIRECTORS FREDERICK M. BOHEN(3)(5) Executive Vice President and Chief Operating Officer, The Rockefeller University G. STEVEN FARRIS(1) President, Chief Executive Officer and Chief Operating Officer, Apache Corporation RANDOLPH M. FERLIC, M.D.(1)(2) Founder and Former President, Surgical Services of the Great Plains, P.C. EUGENE C. FIEDOREK(2) Private Investor, Former Managing Director, EnCap Investments L.C. A. D. FRAZIER, JR.(3)(5) Chairman, WolfCreek Broadcasting, Inc. PATRICIA ALBJERG GRAHAM(4) Charles Warren Research Professor of the History of American Education, Harvard University JOHN A. KOCUR(1)(3) Attorney at Law; Former Vice Chairman of the Board, Apache Corporation GEORGE D. LAWRENCE(1)(3) Private Investor; Former Chief Executive Officer, The Phoenix Resource Companies, Inc. F. H. MERELLI(1)(2) Chairman of the Board, Chief Executive Officer and President, Cimarex Energy Co. RODMAN D. PATTON(2) Former Managing Director, Merrill Lynch Energy Group CHARLES J. PITMAN(4) Former Regional President -- Middle East/Caspian/ Egypt/India, BP Amoco plc; Sole Member, Shaker Mountain Energy Associates, LLC RAYMOND PLANK(1) Chairman of the Board, Apache Corporation JAY A. PRECOURT(4) Chairman of the Board and Chief Executive Officer, Scissor Tail Energy LLC Chairman of the Board, Hermes Consolidated, Inc. OFFICERS RAYMOND PLANK Chairman of the Board G. STEVEN FARRIS President, Chief Executive Officer and Chief Operating Officer MICHAEL S. BAHORICH Executive Vice President -- Exploration and Production Technology JOHN A. CRUM Executive Vice President and Managing Director, Apache North Sea Ltd. RODNEY J. EICHLER Executive Vice President and General Manager, Apache Egypt Companies ROGER B. PLANK Executive Vice President and Chief Financial Officer FLOYD R. PRICE Executive Vice President -- Eurasia, Latin America and New Ventures JON A. JEPPESEN Senior Vice President P. ANTHONY LANNIE Senior Vice President and General Counsel JEFFREY M. BENDER Vice President -- Human Resources MICHAEL J. BENSON Vice President -- Security THOMAS P. CHAMBERS Vice President -- Corporate Planning JOHN J. CHRISTMANN Vice President -- Business Development MATTHEW W. DUNDREA Vice President and Treasurer ROBERT J. DYE Vice President -- Investor Relations JANICE K. HARTRICK Vice President and Associate General Counsel ANTHONY R. LENTINI, JR. Vice President -- Public and International Affairs JANINE J. MCARDLE Vice President -- Oil and Gas Marketing THOMAS L. MITCHELL Vice President and Controller W. KREGG OLSON Vice President -- Corporate Reservoir Engineering JON W. SAUER Vice President -- Tax CHERI L. PEPER Corporate Secretary - --------------- (1) Executive Committee (2) Audit Committee (3) Management Development and Compensation Committee (4) Corporate Governance and Nominating Committee (5) Stock Option Plan Committee SHAREHOLDER INFORMATION Stock Data
Dividends Price Range* per Share* --------------- ----------------- HIGH LOW DECLARED PAID ------ ------ -------- ------ 2004 First Quarter........ $43.49 $36.79 $.0600 $.0600 Second Quarter....... 45.99 38.53 .0600 .0600 Third Quarter........ 57.00 42.45 .0800 .0600 Fourth Quarter....... 55.16 47.77 .0800 .0800 2003 First Quarter........ $32.15 $26.26 $.0500 $.0475 Second Quarter....... 34.60 28.13 .0500 .0500 Third Quarter........ 35.04 30.41 .0600 .0500 Fourth Quarter....... 41.68 34.05 .0600 .0600
* Per share prices and dividend amounts have been adjusted to reflect the effects of the two-for-one stock split in 2003. The Company has paid cash dividends on its common stock for 40 consecutive years through December 31, 2004. Future dividend payments will depend upon the Company's level of earnings, financial requirements and other relevant factors. Apache common stock is listed on the New York and Chicago stock exchanges and the NASDAQ National Market (symbol APA). At December 31, 2004, the Company's shares of common stock outstanding were held by approximately 8,000 shareholders of record and 226,000 beneficial owners. Also listed on the New York Stock Exchange are: - Apache Finance Canada's 7.75% notes, due 2029 (symbol APA 29) CORPORATE OFFICES One Post Oak Central 2000 Post Oak Boulevard Suite 100 Houston, Texas 77056-4400 (713) 296-6000 INDEPENDENT PUBLIC ACCOUNTANTS Ernst & Young LLP Five Houston Center 1401 McKinney Street, Suite 1200 Houston, Texas 77010-2007 STOCK TRANSFER AGENT AND REGISTRAR Wells Fargo Bank, N.A. Attn: Shareowner Services P.O. Box 64854 South St. Paul, Minnesota 55164-0854 (651) 450-4064 or (800) 468-9716 Communications concerning the transfer of shares, lost certificates, dividend checks, duplicate mailings or change of address should be directed to the stock transfer agent. Shareholders can access account information on the website: http://www.shareowneronline.com. DIVIDEND REINVESTMENT PLAN Shareholders of record may invest their dividends automatically in additional shares of Apache common stock at the market price. Participants may also invest up to an additional $25,000 in Apache shares each quarter through this service. All bank service fees and brokerage commissions on purchases are paid by Apache. A prospectus describing the terms of the Plan and an authorization form may be obtained from the Company's stock transfer agent, Wells Fargo Bank, N.A. DIRECT REGISTRATION Shareholders of record may hold their shares of Apache common stock in book-entry form. This eliminates costs related to safekeeping or replacing paper stock certificates. In addition, shareholders of record may request electronic movement of book-entry shares between your account with the Company's stock transfer agent and your broker. Stock certificates may be converted to book-entry shares at any time. Questions regarding this service may be directed to the Company's stock transfer agent, Wells Fargo Bank, N.A. ANNUAL MEETING Apache will hold its annual meeting of shareholders on Thursday, May 5, 2005, at 10 a.m. in the Ballroom, Hilton Houston Post Oak (formerly Doubletree Hotel Houston -- Post Oak), 2001 Post Oak Boulevard, Houston, Texas. Apache plans to web cast the annual meeting live; connect through the Apache web site: http://www.apachecorp.com STOCK HELD IN "STREET NAME" The Company maintains a direct mailing list to ensure that shareholders with stock held in brokerage accounts receive information on a timely basis. Shareholders wanting to be added to this list should direct their requests to Apache's Public and International Affairs Department, 2000 Post Oak Boulevard, Suite 100, Houston, Texas, 77056-4400, by calling (713) 296-6157 or by registering on Apache's web site: http://www.apachecorp.com. FORM 10-K REQUEST Shareholders and other persons interested in obtaining, without cost, a copy of the Company's Form 10-K filed with the Securities and Exchange Commission may do so by writing to Cheri L. Peper, Corporate Secretary, 2000 Post Oak Boulevard, Suite 100, Houston, Texas, 77056-4400. INVESTOR RELATIONS Shareholders, brokers, securities analysts or portfolio managers seeking information about the Company are welcome to contact Robert J. Dye, Vice President of Investor Relations, at (713) 296-6662. Members of the news media and others seeking information about the Company should contact Apache's Public and International Affairs Department at (713) 296-6107. WEB SITE: HTTP://WWW.APACHECORP.COM INDEX TO 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. 1-4300). 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. 1-4300). 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. 1-4300). 3.2 -- Bylaws of Registrant, as amended February 5, 2004 (incorporated by reference to Exhibit 3.2 to Registrant's Annual Report on Form 10-K for year ended December 31, 2003, SEC File No. 1-4300). 4.1 -- Form of Certificate for Registrant's Common Stock (incorporated by reference to Exhibit 4.1 to Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, 2004, SEC File No. 1-4300). 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. 1-4300). 4.3 -- Form of Certificate for Registrant's Automatically Convertible Equity Securities, Conversion Preferred Stock, Series C (incorporated by reference to Exhibit 99.8 to Amendment No. 1 on Form 8-K/A to Registrant's Current Report on Form 8-K, dated and filed April 29, 1999, SEC File No. 1-4300). 4.4 -- 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. 1-4300). 10.1 -- 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. 1-4300). 10.2 -- 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. 1-4300).
EXHIBIT NO. DESCRIPTION - ------- ----------- 10.3 -- Form of Credit Agreement, dated as of June 3, 2002, among Registrant, the Lenders named therein, JPMorgan Chase Bank, as Global Administrative Agent, Bank of America, N.A., as Global Syndication Agent, Citibank, N.A., as Global Documentation Agent, Bank of America, N.A. and Wachovia Bank, National Association, as U.S. Co-Syndication Agents, and Citibank, N.A. and Union Bank of California, N.A., as U.S. Co-Documentation Agents (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, 2002, SEC File No. 1-4300). 10.4 -- Form of 364-Day Credit Agreement, dated as of June 3, 2002, among Registrant, the Lenders named therein, JPMorgan Chase Bank, as Global Administrative Agent, Bank of America, N.A., as Global Syndication Agent, Citibank, N.A., as Global Documentation Agent, Bank of America, N.A. and BNP Paribas, as 364-Day Co-Syndication Agents, and Deutsche Bank AG, New York Branch, and Societe Generale, as 364-Day Co-Documentation Agents (excluding exhibits and schedules) (incorporated by reference to Exhibit 10.3 to Registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2002, SEC File No. 1-4300). 10.5 -- Form of Credit Agreement, dated as of June 3, 2002, among Apache Canada Ltd, a wholly-owned subsidiary of Registrant, the Lenders named therein, JPMorgan Chase Bank, as Global Administrative Agent, Bank of America, N.A., as Global Syndication Agent, Citibank, N.A., as Global Documentation Agent, Royal Bank of Canada, as Canadian Administrative Agent, The Bank of Nova Scotia and The Toronto-Dominion Bank, as Canadian Co-Syndication Agents, and BNP Paribas (Canada) and Bayerische Landesbank Girozentrale, as Canadian Co-Documentation Agents (excluding exhibits and schedules) (incorporated by reference to Exhibit 10.4 to Registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2002, SEC File No. 1-4300). 10.6 -- Form of Credit Agreement, dated as of June 3, 2002, among Apache Energy Limited, a wholly-owned subsidiary of Registrant, the Lenders named therein, JPMorgan Chase Bank, as Global Administrative Agent, Bank of America, N.A., as Global Syndication Agent, Citibank, N.A., as Global Documentation Agent, Citisecurities Limited, as Australian Administrative Agent, Bank of America, N.A., Sydney Branch, and Deutsche Bank AG, Sydney Branch, as Australian Co- Syndication Agents, and Royal Bank of Canada and Bank One, N.A., Australia Branch, as Australian Co-Documentation Agents (excluding exhibits and schedules) (incorporated by reference to Exhibit 10.5 to Registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2002, SEC File No. 1-4300). 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). 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).
EXHIBIT NO. DESCRIPTION - ------- ----------- 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 Exploracion Egipto 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. 1-4300). 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. 1-4300). +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. 1-4300). +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. 1-4300). +10.16 -- Apache Corporation 401(k) Savings Plan, dated August 1, 2002 (incorporated by reference to Exhibit 10.1 to Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2002, SEC File No. 1-4300). +10.17 -- Amendment to Apache Corporation 401(k) Savings Plan, dated January 27, 2003, effective January 1, 2003 (incorporated by reference to Exhibit 10.18 to Registrant's Annual Report on Form 10-K, as amended by Form 10-K/A, for year ended December 31, 2002, SEC File No. 1-4300). +10.18 -- Apache Corporation Money Purchase Retirement Plan, dated August 1, 2002 (incorporated by reference to Exhibit 10.2 to Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2002, SEC File No. 1-4300). +10.19 -- Amendment to Apache Corporation Money Purchase Retirement Plan, dated January 27, 2003, effective January 1, 2003 (incorporated by reference to Exhibit 10.20 to Registrant's Annual Report on Form 10-K for year ended December 31, 2002, SEC File No. 1-4300). +10.20 -- Non-Qualified Retirement/Savings Plan of Apache Corporation, restated January 1, 1997, and amendments effective January 1, 1997, January 1, 1998 and January 1, 1999 (incorporated by reference to Exhibit 10.17 to Registrant's Annual Report on Form 10-K for year ended December 31, 1998, SEC File No. 1-4300). +10.21 -- Amendment to Non-Qualified Retirement/Savings Plan of Apache Corporation, dated February 22, 2000, effective January 1, 1999 (incorporated by reference to Exhibit 4.7 to Registrant's Registration Statement on Form S-8, Registration No. 333-31092, filed February 25, 2000); and Amendment dated July 27, 2000 (incorporated by reference to Exhibit 4.8 to Amendment No. 1 to Registrant's Registration Statement on Form S-8, Registration No. 333-31092, filed August 18, 2000). +10.22 -- Amendment to Non-Qualified Retirement/Savings Plan of Apache Corporation, dated August 3, 2001, effective September 1, 2000 and July 1, 2001 (incorporated by reference to Exhibit 10.13 to Registrant's Quarterly Report on Form 10-Q, as amended by Form 10-Q/A, for the quarter ended June 30, 2001, SEC File No. 1-4300).
EXHIBIT NO. DESCRIPTION - ------- ----------- +10.23 -- Amendment to Non-Qualified Retirement/Savings Plan of Apache Corporation, dated December 18, 2003, effective January 1, 2004 (incorporated by reference to Exhibit 10.24 to Registrant's Annual Report on Form 10-K for year ended December 31, 2003, SEC File No. 1-4300). +10.24 -- 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. 1-4300). +10.25 -- Apache Corporation 1995 Stock Option Plan, as amended and restated September 13, 2001 (incorporated by reference to Exhibit 10.02 to Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2001, as amended by Form 10-Q/A, SEC File No. 1-4300). +10.26 -- Apache Corporation 2000 Share Appreciation Plan, as amended and restated February 5, 2004 (incorporated by reference to Exhibit 10.27 to Registrant's Annual Report on Form 10-K for year ended December 31, 2003, SEC File No. 1-4300). +10.27 -- 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. 1-4300). +10.28 -- Apache Corporation 1998 Stock Option Plan, as amended and restated September 13, 2001 (incorporated by reference to Exhibit 10.04 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. 1-4300). +10.29 -- Apache Corporation 2000 Stock Option Plan, as amended and restated March 5, 2003 (incorporated by reference to Exhibit 4.5 to Registrant's Registration Statement on Form S-8, Registration No. 333-103758, filed March 12, 2003). +10.30 -- 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. 1-4300). +10.31 -- 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. 1-4300). +10.32 -- 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. 1-4300). +10.33 -- Apache Corporation Deferred Delivery Plan, as amended and restated December 18, 2002, effective May 2, 2002 (incorporated by reference to Exhibit 4.5 to Post-Effective Amendment No. 2 to Registrant's Registration Statement on Form S-8, Registration No. 333-31092, filed March 11, 2003). +10.34 -- Apache Corporation Executive Restricted Stock Plan, as amended and restated December 18, 2002, effective May 2, 2002 (incorporated by reference to Exhibit 4.5 to Post-Effective Amendment No. 1 to Registrant's Registration Statement on Form S-8, Registration No. 333-97403, filed December 30, 2002). +10.35 -- Apache Corporation Non-Employee Directors' Compensation Plan, as amended and restated May 1, 2003, effective July 1, 2003 (incorporated by reference to Exhibit 10.1 to Registrant's Quarterly Report on Form 10-Q, as amended by Form 10-Q/A, for the quarter ended June 30, 2003, SEC File No. 1-4300). +10.36 -- Apache Corporation Outside Directors' Retirement Plan, as amended and restated May 3, 2001 (incorporated by reference to Exhibit 10.08 to Registrant's Quarterly Report on Form 10-Q, as amended by Form 10-Q/A, for the quarter ended June 30, 2001, SEC File No. 1-4300).
EXHIBIT NO. DESCRIPTION - ------- ----------- +10.37 -- 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. 1-4300). +10.38 -- 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. 1-4300). +10.39 -- 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. 1-4300). +10.40 -- 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. 1-4300). +10.41 -- 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. 1-4300). +10.42 -- Amended and Restated Conditional Stock Grant Agreement, dated June 6, 2001, between Registrant and G. Steven Farris (incorporated by reference to Exhibit 10.10 to Registrant's Quarterly Report on Form 10-Q, as amended by Form 10-Q/A, for the quarter ended June 30, 2001, SEC File No. 1-4300). 10.43 -- 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. 1-4300). 10.44 -- 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. 1-4300). *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. 1-4300). *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. EX-12.1 2 h23217exv12w1.txt COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES EXHIBIT 12.1 APACHE CORPORATION STATEMENT OF COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES AND COMBINED FIXED CHARGES, PREFERRED STOCK DIVIDENDS AND PREFERRED INTERESTS OF SUBSIDIARIES (IN THOUSANDS, EXCEPT RATIO DATA)
(UNAUDITED) 2004 2003 2002 2001 2000 ---------- ---------- ---------- ---------- ---------- EARNINGS Pretax income from continuing operations before preferred interests of subsidiaries .................. $2,663,083 $1,930,925 $ 915,194 $1,206,863 $1,203,681 Add: Fixed charges excluding capitalized interest and preferred interests requirements of consolidated subsidiaries ......................................... 134,797 132,820 128,730 134,484 116,190 ---------- ---------- ---------- ---------- ---------- Adjusted Earnings ...................................... $2,797,880 $2,063,745 $1,043,924 $1,341,347 $1,319,871 ========== ========== ========== ========== ========== FIXED CHARGES AND PREFERRED STOCK DIVIDENDS Interest expense including capitalized interest (1) .... $ 168,090 $ 173,045 $ 155,667 $ 178,915 $ 168,121 Amortization of debt expense ........................... 2,471 2,163 1,859 2,460 2,726 Interest component of lease rental expenditures (2) .... 14,984 14,458 11,895 9,858 7,343 Preferred interest requirements of consolidated subsidiaries (3) ..................................... -- 11,805 19,581 8,608 -- ---------- ---------- ---------- ---------- ---------- Fixed charges .......................................... 185,545 201,471 189,002 199,841 178,190 Preferred stock dividend requirements (4) .............. 9,058 9,968 17,540 32,495 33,386 ---------- ---------- ---------- ---------- ---------- Combined Fixed Charges and Preferred Stock Dividends ....... $ 194,603 $ 211,439 $ 206,542 $ 232,336 $ 211,576 ========== ========== ========== ========== ========== Ratio of Earnings to Fixed Charges ......................... 15.08 10.24 5.52 6.71 7.41 ========== ========== ========== ========== ========== Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends .......................................... 14.38 9.76 5.05 5.77 6.24 ========== ========== ========== ========== ==========
- ---------- (1) The Company did not receive a tax benefit for $5 million of transaction costs written off to interest expense when the Company retired its preferred interests of subsidiaries in September 2003. Given the non-deductibility of the charge, $9 million of pre-tax income was required to cover the $5 million write-off. Accordingly, interest expense has been grossed up by $4 million. (2) Represents the portion of rental expense assumed to be attributable to interest factors of related rental obligations determined at interest rates appropriate for the period during which the rental obligations were incurred. Approximately 32 to 34 percent of rental payments applies for all periods presented. (3) The Company did not receive a tax benefit for a portion of its preferred interests of consolidated subsidiaries. This amount represents the pre-tax earnings that would be required to cover preferred interests requirements of consolidated subsidiaries. In September 2003, the Company retired its preferred interests of subsidiaries. (4) The Company does not receive a tax benefit for its preferred stock dividends. This amount represents the pre-tax earnings that would be required to cover its preferred stock dividends. EX-21.1 3 h23217exv21w1.txt SUBSIDIARIES OF REGISTRANT . . . EXHIBIT 21.1 APACHE CORPORATION (A DELAWARE CORPORATION) PAGE 1 OF 3 LISTING OF SUBSIDIARIES AS OF FEBRUARY 28, 2005
EXACT NAME OF SUBSIDIARY AND NAME JURISDICTION OF UNDER WHICH SUBSIDIARY DOES BUSINESS INCORPORATION OR ORGANIZATION - ------------------------------------ ----------------------------- Apache Corporation (New Jersey) New Jersey Apache Aviation, Inc. Delaware Apache Delaware LLC Delaware Apache Delaware Holdings LLC Delaware Apache Delaware Investment LLC Delaware Apache Donard Corporation LDC Cayman Islands Apache Energy Limited Western Australia Apache Northwest Pty Ltd. Western Australia Apache Carnarvon Pty Ltd. Western Australia Apache Dampier Pty Ltd. Western Australia Apache East Spar Pty Limited Western Australia Apache Harriet Pty Limited Victoria, Australia Apache Kersail Pty Ltd Victoria, Australia Apache Miladin Pty Ltd Victoria, Australia Apache Nasmah Pty Ltd Victoria, Australia Apache Oil Australia Pty Limited New South Wales, Australia Apache Airlie Pty Limited New South Wales, Australia Apache Varanus Pty Limited Queensland, Australia Apache Pipeline Pty Ltd Western Australia Apache Finance Louisiana Corporation Delaware Apache Foundation Minnesota Apache Gathering Company Delaware Apache Hadda Corporation LDC Cayman Islands Apache Holdings, Inc. Delaware Apache International, Inc. Delaware Apache North America, Inc. Delaware Apache Finance Australia Pty Limited Australian Capital Territory Apache Finance Pty Limited Australian Capital Territory Apache Australia Management Pty Limited Victoria, Australia Apache Australia Holdings Pty Limited Western Australia Apache Qarun Corporation LDC Cayman Islands Apache Khalda Corporation LDC Cayman Islands Apache Kultarr Corporation LDC Cayman Islands Apache Libya Corporation LDC Cayman Islands Apache Louisiana Holdings, LLC Delaware Apache Louisiana Minerals, Inc. Delaware Apache Oil Corporation Texas Apache Overseas, Inc. Delaware Apache Abu Gharadig Corporation LDC Cayman Islands Apache Argentina Corporation LDC Cayman Islands Apache Petrolera Argentina S.A. Argentina Apache Asyout Corporation LDC Cayman Islands Apache Bohai Corporation LDC Cayman Islands Apache China Management LDC Cayman Islands Apache China Holdings LDC Cayman Islands Apache Darag Corporation LDC Cayman Islands Apache East Bahariya Corporation LDC Cayman Islands Apache El Diyur Corporation LDC Cayman Islands Apache Enterprises LDC Cayman Islands
1 EXHIBIT 21.1 APACHE CORPORATION (A DELAWARE CORPORATION) PAGE 2 OF 3 LISTING OF SUBSIDIARIES AS OF FEBRUARY 28, 2005
EXACT NAME OF SUBSIDIARY AND NAME JURISDICTION OF UNDER WHICH SUBSIDIARY DOES BUSINESS INCORPORATION OR ORGANIZATION - ------------------------------------ ----------------------------- Apache Faiyum Corporation LDC Cayman Islands Apache FC Argentina Company LDC Cayman Islands Apache Madera Corporation LDC Cayman Islands Apache Matruh Corporation LDC Cayman Islands Apache Mediterranean Corporation LDC Cayman Islands Apache North Sea Holdings LDC Cayman Islands Apache North Sea Management LDC Cayman Islands Apache International Holdings LLC Delaware Apache China Corporation LDC Cayman Islands Apache International Finance S.a r.l. Luxembourg Apache International Holdings II LLC Delaware Apache North Sea Investment England and Wales Apache North Sea Limited England and Wales Apache North Tarek Corporation LDC Cayman Islands Apache Poland Holding Company Delaware Apache Eastern Europe B.V. Netherlands Apache Poland Sp. z o.o. Poland Apache Shushan Corporation LDC Cayman Islands Apache South Umbarka Corporation LDC Cayman Islands Apache Umbarka Corporation LDC Cayman Islands Apache West Kalabsha Corporation LDC Cayman Islands Apache West Kanayis Corporation LDC Cayman Islands Apache Qarun Exploration Company LDC Cayman Islands Apache Ravensworth Corporation LDC Cayman Islands Apache Shady Lane Ranch Inc. Wyoming Apache Transfer Company Delaware Apache West Australia Holdings Limited Island of Guernsey Apache UK Limited England and Wales Apache Lowendal Pty Limited Victoria, Australia Apache West Texas Acquisition Corporation Delaware Texas and New Mexico Exploration LLC Delaware Apache West Texas Holdings, Inc. Delaware Apache West Texas Investment LLC Delaware Burns Manufacturing Company Minnesota Clear Creek Hunting Preserve, Inc. Wyoming DEK Energy Company Delaware DEK Energy Texas, Inc. Delaware DEK Exploration Inc. Delaware Apache Finance Canada Corporation Nova Scotia, Canada Apache Canada Management Ltd Alberta, Canada Apache Canada Holdings Ltd Alberta, Canada Apache Canada Management II Ltd Alberta, Canada Apache Finance Canada II Corporation Nova Scotia, Canada DEK Petroleum Corporation Illinois Apache Canada Ltd. Alberta, Canada Apache Canada Properties Ltd. Alberta, Canada Apache FC Capital Canada Inc. Alberta, Canada Apache FC Canada Enterprises Inc. Alberta, Canada DEPCO, Inc. Texas
2 EXHIBIT 21.1 APACHE CORPORATION (A DELAWARE CORPORATION) PAGE 3 OF 3 LISTING OF SUBSIDIARIES AS OF FEBRUARY 28, 2005
EXACT NAME OF SUBSIDIARY AND NAME JURISDICTION OF UNDER WHICH SUBSIDIARY DOES BUSINESS INCORPORATION OR ORGANIZATION - ------------------------------------ ----------------------------- Heinold Holdings, Inc. Delaware GOM Shelf, LLC Delaware Nagasco, Inc. Delaware Apache Crude Oil Marketing, Inc. Delaware Apache Marketing, Inc. Delaware Apache Transmission Corporation - Texas Texas Nagasco Marketing, Inc. Delaware Nile Weavers, Inc Delaware Phoenix Exploration Resources, Ltd. Delaware TEI Arctic Petroleum (1984) Ltd. Alberta, Canada Texas International Company Delaware
3 EX-23.1 4 h23217exv23w1.txt CONSENT OF ERNST & YOUNG LLP EXHIBIT 23.1 CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM We consent to the incorporation by reference in the Registration Statements (Form S-3 Nos. 333-57785, 333-75633, 333-32580, and 333-105536 and Form S-4 No. 333-107934 and Form S-8 Nos. 33-31407, 33-37402, 33-53442, 33-59721, 33-59723, 33-63817, 333-04059, 333-25201, 333-26255, 333-32557, 333-36131, 333-53961, 333-31092, 333-48758, 333-97403, 333-102330, 333-103758, 333-105871, and 333-106213) of Apache Corporation and in the related Prospectuses, of our report dated March 11, 2005, with respect to the consolidated financial statements of Apache Corporation, Apache Corporation management's assessment of the effectiveness of internal control over financial reporting, and the effectiveness of internal control over financial reporting of Apache Corporation, included in this Annual Report (Form 10-K) for the year ended December 31, 2004. /s/ Ernst & Young LLP ERNST & YOUNG LLP Houston, Texas March 11, 2005 EX-23.2 5 h23217exv23w2.txt CONSENT OF RYDER SCOTT COMPANY L.P. [Ryder Scott Company, L.P. Letterhead] EXHIBIT 23.2 Consent of Ryder Scott Company, L.P. As independent petroleum engineers, we hereby consent to the incorporation by reference in this Form 10-K of Apache Corporation to our Firm's name and our Firm's review of the proved oil and gas reserve quantities of Apache Corporation as of January 1, 2005, and to the incorporation by reference of our Firm's name and review into Apache Corporation's previously filed Registration Statements on Form S-3 (Nos. 333-57785, 333-75633, 333-32580, and 333-105536), on Form S-4 (No. 333-107934), and on Form S-8 (Nos. 33-31407, 33-37402, 33-53442, 33-59721, 33-59723, 33-63817, 333-04059, 333-25201, 333-26255, 333-32557, 333-36131, 333-53961, 333-31092, 333-48758, 333-97403, 333-102330, 333-103758, 333-105871, and 333-106213). /s/ Ryder Scott Company, L.P. Ryder Scott Company, L.P. Houston, Texas March 11, 2005 EX-31.1 6 h23217exv31w1.txt CERTIFICATION OF CEO EXHIBIT 31.1 CERTIFICATIONS I, G. Steven Farris, certify that: 1. I have reviewed this annual report on Form 10-K of Apache Corporation; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; (c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. /s/ G. Steven Farris - -------------------------------------- G. Steven Farris President, Chief Executive Officer and Chief Operating Officer Date: March 11, 2005 EX-31.2 7 h23217exv31w2.txt CERTIFICATION OF CFO EXHIBIT 31.2 CERTIFICATIONS I, Roger B. Plank, certify that: 1. I have reviewed this annual report on Form 10-K of Apache Corporation; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; (c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. /s/ Roger B. Plank - ---------------------------------------------------- Roger B. Plank Executive Vice President and Chief Financial Officer Date: March 11, 2005 EX-32.1 8 h23217exv32w1.txt CERTIFICATION OF CEO & CFO EXHIBIT 32.1 APACHE CORPORATION CERTIFICATION OF CHIEF EXECUTIVE OFFICER AND CHIEF FINANCIAL OFFICER I, G. Steven Farris, certify that the Annual Report of Apache Corporation on Form 10-K for the year ended December 31, 2004, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. Section 78m or Section 78o (d)) and that information contained in such report fairly represents, in all material respects, the financial condition and results of operations of Apache Corporation. /s/ G. Steven Farris - ------------------------------------------- By: G. Steven Farris Title: President, Chief Executive Officer and Chief Operating Officer I, Roger B. Plank, certify that the Annual Report of Apache Corporation on Form 10-K for the year ending December 31, 2004, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. Section 78m or Section 78o (d)) and that information contained in such report fairly represents, in all material respects, the financial condition and results of operations of Apache Corporation. /s/ Roger B. Plank - ------------------------------------------- By: Roger B. Plank Title: Executive Vice President and Chief Financial Officer -----END PRIVACY-ENHANCED MESSAGE-----