10-K/A 1 h11890e10vkza.txt APACHE CORPORATION - DATED 12/31/2003 ================================================================================ UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-K/A (AMENDMENT NO. 1) (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, 2002, 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:
TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED ------------------- ----------------------------------------- Common Stock, $0.625 par Value New York Stock Exchange Chicago Stock Exchange Preferred Stock Purchase Rights New York Stock Exchange Chicago Stock Exchange Automatically Convertible Equity Securities New York Stock Exchange Conversion Preferred Stock, 6.5% Series C Chicago Stock Exchange 9.25% Notes due 2002 New York 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: NONE 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 28, 2002................................................. $8,212,561,395 Number of shares of registrant's common stock outstanding as of February 28, 2003.......................................... 323,085,284
DOCUMENTS INCORPORATED BY REFERENCE: Portions of registrant's proxy statement relating to registrant's 2003 annual meeting of stockholders have been incorporated by reference into Part III hereof. ================================================================================ EXPLANATORY NOTE We are filing this Amendment No. 1 to our Annual Report on Form 10-K/A for the year ended December 31, 2002 to respond to certain comments received by us from the Staff of the Securities and Exchange Commission ("SEC") in connection with its review of our Registration Statement on Form S-3 (File No. 333-105536). Our consolidated financial position and consolidated results of operations for the periods presented have not been restated from the consolidated financial position and consolidated results of operations originally reported. Except where otherwise indicated, all share amounts and per share amounts have been adjusted to reflect the effects of the two-for-one stock split for our common stock declared in September 2003. For convenience and ease of reference we are filing this Annual Report in its entirety with the applicable changes. Unless otherwise stated, all information contained in this amendment is as of March 25, 2003, the filing date of our Annual Report on Form 10-K for the year ended December 31, 2002. Accordingly, this Amendment No. 1 to the Annual Report on Form 10-K/A should be read in conjunction with our subsequent filings with the SEC. TABLE OF CONTENTS DESCRIPTION
ITEM PAGE ---- ---- PART I 1. BUSINESS.................................................... 2 2. PROPERTIES.................................................. 15 3. LEGAL PROCEEDINGS........................................... 15 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS......... 15 PART II 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS......................................... 15 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........................................................ 36 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA................. 38 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.................................... 38 PART III 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.......... 38 11. EXECUTIVE COMPENSATION...................................... 38 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.................................................. 38 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.............. 39 14. CONTROLS AND PROCEDURES..................................... 39 PART IV 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K......................................................... 39
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. 1 PART I ITEM 1. BUSINESS 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 Western Australia, offshore and onshore Egypt, offshore The People's Republic of China and onshore Argentina, and exploration interests in Poland. Our common stock, par value $0.625 per share, has been listed on the New York Stock Exchange since 1969, and on the Chicago Stock Exchange since 1960. Through our website, http://www.apachecorp.com, you can access electronic copies of 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 and any amendments to these reports. Access to these electronic filings is available as soon as practicable after filing with the SEC. We hold interests in many of our U.S., Canadian and 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. 2002 RESULTS Apache posted a very good year. Rising prices and production within one percent of 2001's record levels combined to make 2002 our third best year in terms of earnings and cash flow. Strong financial performance coupled with curtailed capital spending enabled us to achieve our primary 2002 objective of enhancing our financial flexibility. Our conservative approach to capital spending through most of 2002 enabled us to further strengthen our balance sheet and maintain a senior unsecured long-term debt rating of A3 from Moody's, and A- from Standard and Poor's and Fitch rating agencies, all of which were reaffirmed by those agencies after the announcement of our largest acquisition to-date following year-end from BP p.l.c. (BP). Our 2002 income attributable to common stock totaled $544 million on total revenues of $2.6 billion, while cash provided by operating activities was $1.4 billion, a 28 percent decrease from 2001. Our average daily production for the year was 161 Mbbls of oil and natural gas liquids and 1,080 MMcf of natural gas. We increased our total reserves by four percent, compared with the end of 2001, resulting in 1,313 MMboe of estimated proved reserves at year-end, 51 percent of which were natural gas. Even though Apache did not pursue an active acquisition program for most of 2002, at the end of the year we began seeking acquisitions of additional properties. We completed two acquisitions of producing properties in Canada and one in South Louisiana, described below in the discussion of our U.S. and Canadian operations. In January 2003, we agreed to purchase properties from subsidiaries of BP in the Gulf of Mexico and in the North Sea offshore the United Kingdom for $1.3 billion (subject to normal closing adjustments and the exercise of preferential rights by third parties), which will be our largest acquisition to-date. The Company closed the Gulf of Mexico portion on March 13, 2003 at an adjusted price of $509 million, which has estimated proved reserves of 72.2 MMboe. The price was adjusted from the originally announced $670 million to account for the exercise of preferential rights by third parties involved in some of the properties (a reduction of $70 million), production and expenses since January 1, 2003, the effective date of the transaction, and other minor adjustments. The North Sea portion is expected to close early in the second quarter of 2003. The acquisition is being funded by a combination of proceeds from the equity offering we completed in January 2003, cash from our operations and debt. Per share results have been adjusted for the two-for-one stock split distributed on January 14, 2004 to our shareholders of record on December 31, 2003, the 10 percent common stock dividend paid on January 21, 2002, to our shareholders of record on December 31, 2001, and the five percent common stock dividend paid on April 2, 2003, to our shareholders of record on March 12, 2003. The stock split and stock dividends reflect 2 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 Throughout our 48-year history, Apache has been and continues to be driven to grow. It is a constant pursuit and part of our culture. However, it is tempered by the desire to grow economically rather than to grow at any price. At this point in our progression we have developed our abilities to grow through drilling, through acquisitions, or through a combination of both, depending on what the environment gives us. As indicated in this section a year ago, early in 2002, we planned to reduce spending on both drilling and acquisition opportunities in favor of paying down debt and adding financial flexibility. This was not motivated by a weak balance sheet (in fact we believe our balance sheet was strong, as evidenced by our single-A debt rating and low debt-to-capitalization ratio, both of which are discussed below). It was driven by a highly uncertain industry and economic environment in which drilling costs were relatively high and prices, for natural gas in particular, were relatively low and extremely volatile. In addition, our assessment was that with reasonably priced properties unavailable for purchase, it was prudent to curtail capital expenditures and wait for better opportunities to present themselves. As drilling costs came down and product prices rose during 2002, Apache authorized incremental drilling and operating capital increases. For example, when quality properties became available in South Louisiana at year-end from a privately-held company at a reasonable price, we acted. Despite these drilling and acquisition capital increases, Apache's 2002 capital expenditures approximated half those of the prior year, driving a reduction in debt as a percent of capitalization. Using a strict definition to calculate debt as a percentage of capitalization, Apache's ratio dropped to 30 percent at year-end 2002 from 34 percent a year earlier. However, the strict measurement ignores two important considerations particular to Apache's situation. Our balance sheet includes preferred interests of subsidiaries ($437 million and $441 million at December 31, 2002 and 2001, respectively) which, although not debt, are redeemable under certain circumstances and, in our opinion, should be included in the calculation. We also occasionally have short-term investments and cash balances ($52 million and $139 million at December 31, 2002 and 2001, respectively), both of which are available to pay down debt and, in our opinion, should be subtracted from debt. Allowing for both of these factors, Apache's adjusted debt-to-capitalization ratio was 34 percent at year-end, higher than the strict formula, but below the comparable 37 percent ratio at the end of 2001. We believe this is a more conservative way of expressing this ratio. Apache's financial discipline paid off. Not only were our 2002 finding and acquisition costs quite competitive within our industry sector, our financial strength left us as the only publicly traded independent in the U.S. with a single-A rating by both Moody's and Standard and Poor's. Our strategy provided us with the financial wherewithal sufficient to pursue the asset acquisition from BP. This transaction took only 35 days from initial discussions on December 9, 2002 to the signing of a purchase and sale agreement and announcement on January 13, 2003. With completion of this purchase, and based on our planned capital expenditures, production forecasts and reserve estimates, we believe Apache's production and reserves will grow in 2003 over 2002 levels. Of course, our forward looking statements are dependent upon events which can be impacted by risk and uncertainties that may be outside the Company's control as discussed in Item 7A -- Quantitative and Qualitative Disclosures About Market Risk, "Forward-Looking Statements and Risk." For a discussion of risks, refer to "Risk Factors related to Our Business and Operations" below. Looking ahead, we will continue to pursue growth that is economic, whether it is through drilling, acquisitions, or both. Although we review industry conditions and our capital expenditures constantly, present conditions are quite attractive for both drilling and acquisitions and are likely to lead to increases in drilling and acquisition expenditures in 2003. 3 REVIEW OF COMPANY'S WORLDWIDE OPERATING AREAS Our portfolio approach provides diversity in terms of hydrocarbon mix (oil or gas), geologic risk and geographic location. 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 our core areas. We currently have interests in seven countries: the United States, Canada, Egypt, Australia, China, Poland and Argentina. After closing the BP transaction, we will add a new core area, the U.K. North Sea. In the U.S., our exploration and production activities are divided into two regions: Gulf Coast and Central. In 2001, Apache had three domestic regions, which were reconfigured into the current two in April 2002. At year-end, approximately 78 percent of our estimated proved reserves were located in North America. Outside North America, our exploration and production activities are focused primarily in Egypt and Australia. Additionally, we have a development project underway in China that is expected to commence production in 2003, and we have a small production interest in Argentina. We also own exploration acreage in Poland. The table below sets out a brief comparative summary of certain 2002 data for our core geographic areas. More detailed information regarding the natural gas, oil, and natural gas liquids (NGLs) production and average prices received in 2002, 2001 and 2000 for the core geographic areas is available in Management's Discussion and Analysis of Financial Condition and Results of Operations in Item 7 of 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 same geographic areas, see Note 15, Supplemental Oil and Gas Disclosures (Unaudited), and Note 14, Business Segment Information, both in Item 15 of this Form 10-K.
12/31/02 PERCENTAGE 2002 2002 ESTIMATED OF TOTAL 2002 GROSS NEW 2002 PRODUCTION PROVED ESTIMATED GROSS NEW PRODUCING PRODUCTION REVENUE RESERVES PROVED WELLS WELLS (IN MMBOE) (IN MILLIONS) (IN MMBOE) RESERVES DRILLED COMPLETED ---------- -------------- ----------- ---------- --------- --------- Region/Country: Gulf Coast................. 32.2 $ 699.5 276.3 21.0% 56 41 Central.................... 20.2 401.9 354.4 27.0 138 127 ----- -------- ------- ----- ----- -------- Total U.S. .............. 52.4 1,101.4 630.7 48.0 194 168 ----- -------- ------- ----- ----- -------- Canada..................... 29.9 557.7 386.8 29.5 836 799 ----- -------- ------- ----- ----- -------- Total North America...... 82.3 1,659.1 1,017.5 77.5 1,030 967 ----- -------- ------- ----- ----- -------- Egypt...................... 23.4 560.1 136.6 10.4 59 45 Australia.................. 18.2 334.0 145.2 11.1 25 10 China...................... -- -- 11.3 0.9 -- -- Poland..................... -- -- -- -- -- -- Argentina.................. 0.7 6.5 1.9 0.1 -- -- ----- -------- ------- ----- ----- -------- Total International...... 42.3 900.6 295.0 22.5 84 55 ----- -------- ------- ----- ----- -------- Total.................... 124.6 $2,559.7 1,312.5 100.0% 1,114 1,022 ===== ======== ======= ===== ===== ========
The following core area discussions include references to the 2003 Plan. These represent initial estimates only and will be reviewed and revised throughout the year in light of changing industry conditions. UNITED STATES In the U.S. we completed one significant acquisition during the year with the purchase of 234,000 net acres in South Louisiana, holding estimated net proved reserves of 178 Bcf of gas equivalent, together with access to 849 square miles of 3-D seismic data and fee interests in most of the acreage, for $259 million. Anticipated net daily production from these properties is expected to approximate 55 MMcf of natural gas and 2,100 barrels of oil in 2003. The transaction was effective December 1, 2002. We also entered into a separate exploration joint venture with the seller under which the seller will generate exploration prospects on certain 4 South Louisiana acreage for a total cost of $25 million over two years. The new properties are in our Gulf Coast region. Our curtailment of capital spending in the first half of the year did not stop us from having a busy year in the U.S.: we completed 168 out of 194 total wells and replaced 71 percent of our domestic production through drilling. A continuing goal is to drill quality prospects in and around our large domestic reserve and production bases. 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. In 2002, the Gulf Coast region was our leading region for production volumes and revenues. This region performed 586 workover and recompletion operations during 2002 and completed 41 out of 56 total wells drilled. As of year-end 2002, Gulf Coast accounted for 21 percent of our estimated proved reserves. In 2003, we currently plan on spending approximately $350 million drilling an estimated 90 wells and continuing our production enhancement program and exploiting the properties acquired from BP in March 2003. Central -- The Central region includes assets in the Permian Basin of west Texas and New Mexico, the San Juan Basin of New Mexico, east Texas and the Anadarko Basin of western Oklahoma. At year-end 2002, the Central region accounted for 27 percent of our estimated proved reserves, the second largest in the company. During 2002, we participated in 138 wells, 127 of which were completed as productive wells, replacing 96 percent of the region's production from drilling. Apache performed 519 workovers and recompletions in the region during the year. In 2003, we currently plan to spend approximately $100 million drilling an estimated 200 wells and continuing our production enhancement programs. Marketing -- In July 1998, we entered into a gas purchase agreement with Cinergy Marketing and Trading, LLC (Cinergy) to market most of our U.S. natural gas production for a 10-year period, with an option by either party, after prior notice, to terminate after six years. We also agreed to work with Cinergy to develop terms for the marketing of most of our Canadian gas production. In December 1998, however, Apache and Cinergy agreed to postpone the negotiation of Canadian gas sales terms. During the period of the gas purchase agreement, we are generally obligated to deliver our domestic gas production to Cinergy and, under certain circumstances, may have to make payments to Cinergy if certain gas throughput thresholds are not met. All throughput thresholds have been met to date. The prices received for our gas production under this agreement are based on published indexes. Disputes have arisen between Cinergy and Apache concerning various matters, including Cinergy's claim to market our Canadian gas production. As a result, in September 2001, Cinergy commenced an arbitration proceeding seeking, among other things, specific performance to require us to sell our Canadian gas production to Cinergy or pay damages. We are disputing Cinergy's assertions (including their claim to market our Canadian production), filing a general denial and counterclaim against Cinergy for amounts arising from, among other things, an audit commenced in 2001. We do not believe the arbitration outcome will be material to our financial position or results of operations. We continue to market most of our U.S. gas production through Cinergy, although we are actively discussing with Cinergy our gas marketing arrangements and a resolution of our disputes (See Note 11 of this Form 10-K). We used long-term, fixed-price physical contracts to lock in a portion of our domestic future natural gas production at a fixed price. These contracts represented approximately 11 percent of our 2002 domestic natural gas production. The contracts provide protection to the Company in the event of decreasing natural gas prices. We market our own U.S. crude oil with most of it sold through lease-level marketing to refiners, traders and transporters. Contracts are generally less than 30 days and renew automatically until canceled. The oil contracts provide for sales at specified prices, or at prices that change with market conditions. CANADA 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 30 percent of 5 our estimated proved reserves, the largest in the Company. We hold over four million net acres in Canada, the largest of the North American regions. 2002 -- We completed two acquisitions in Alberta, Canada; purchasing properties in August from Burlington Resources affiliates with estimated proved reserves of 4.8 MMboe for $26 million and completing the purchase of properties from Canadian affiliates of ConocoPhillips in October with estimated proved reserves of 10.7 MMboe for $60 million. Canada was our most active region for drilling in 2002, with Apache participating in 836 gross wells, 799 of which were completed as producers. We also conducted 707 workover and recompletion projects. We replaced 144 percent of our Canadian production through drilling and another 54 percent through acquisition. 2003 -- We currently plan to spend approximately $400 million drilling an estimated 900 wells, continuing the exploration program, the exploitation of the acquired properties and developing our gas processing infrastructure. Marketing -- Our Canadian natural gas sales include sales to supply aggregators, to whom we dedicate reserves, and direct sales to brokers and end-users in the United States and Canada. Seventeen percent of our natural gas was sold to aggregators, four percent to end users, and 79 percent to brokers in 2002. With the expansion of pipeline transport capacity out of Canada in recent years, Canadian prices have strengthened and become more closely correlated to United States domestic prices. To diversify our market exposure, we transport natural gas via our firm transportation contracts to California (12 MMcf/d), the Chicago area (40 MMcf/d), and Eastern Canada (2 MMcf/d), see Note 11, under Item 15 of this Form 10-K. Pursuant to an agreement entered into in 1994, we are also selling 5 MMcf/d of natural gas to the Hermiston Cogeneration Project, located in the Pacific Northwest of the United States. In 1996, we entered an agreement to sell 5 MMcf/d into Michigan over a 10-year term. In 2002, with the acquisition from ConocoPhillips, we entered into two agreements to sell 5 MMcf/d each into the Northeastern U.S. with one terminating in 2007 and the other in 2008, 3 MMcf/d to an Eastern Canadian Cogeneration project until 2011, and 5 MMcf/d to a broker netback pool until 2005. The prices we receive under these contracts are generally based on market indices. Oil and NGLs produced from our Canadian properties are sold to crude oil purchasers or refiners at market prices, which depend on worldwide crude prices adjusted for transportation and crude quality. EGYPT In Egypt, our operations are generally conducted pursuant to production sharing contracts under which contractor partners pay all operating and capital 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 costs. The balance of the production is allocated between this 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. As of December 31, 2002, we held over 6.9 million net acres encompassing 13 concessions (12 operated). Apache is the largest producer of liquid hydrocarbons and the second largest producer of natural gas in the Western Desert and operates 11 percent of Egypt's daily oil and gas output. 2002 -- Egypt accounted for 22 percent of production revenues on 19 percent of total production for the year and accounted for 10 percent of total proved reserves at December 31, 2002. During the year we increased production significantly in Egypt. Net oil production grew by 12 percent and net gas production by 28 percent over the prior year. The production growth occurred in most of our concessions, with the most significant increases being in the South Umbarka concession, where gross oil and condensate production increased from 2,520 b/d to 9,650 b/d (a 283 percent increase), and the Umbarka concession, where gross oil production increased from 1,277 b/d to 7,127 b/d or 458 percent. Also, three concessions (Ras Kanayes, Matruh, and Northeast Abu Gharadig) commenced production in 2002. Apache had an active onshore drilling program in Egypt, completing 45 of 55 gross wells, for a success rate of 82 percent. The onshore program was weighted more than 75 percent to development activity with the 6 remaining to exploration drilling. Apache also drilled four successful exploration wells in the deepwater portion of the West Mediterranean block, including the first deepwater oil discovered in the Nile Delta at the El King-1X well. On March 4, 2003, we announced that the fifth deepwater well had successfully appraised the earlier discoveries. No reserves have been recorded to-date for the deepwater wells. Reserve recognition and proper scaling of the significant future development infrastructure are pending negotiation and completion of a sales contract for this gas with EGPC. Apache made six new field discoveries onshore in 2002. The most significant were Selkit 1X in the South Umbarka concession, which flowed 5,103 b/d from Kharita sands; Emerald 1X in the Ras El Hekma concession, which flowed 16.9 MMcf/d and 4,285 b/d of condensate from the AEB 6 sand; and the Tut 52 in the Khalda concession, which flowed 29.2 MMcf/d and 781 b/d of condensate from Khatatba sands. In addition to these larger discoveries, Apache also had three new field discoveries in its East Bahariya concession and drilled 10 consecutive successful development wells. 2003 -- We currently plan to spend approximately $250 million to drill more than 100 wells and continue exploitation. Marketing -- In 1996, we and our partners in the Khalda Block entered into a take-or-pay contract with EGPC, which obligates EGPC to pay for 75 percent of 200 MMcf/d of future production of gas from the Khalda Block. In late 1997, the same partners entered into a supplement to the contract with EGPC to sell an additional 50 MMcf/d. In connection with our acquisition of interests from Repsol YPF (Repsol) in 2001, we acquired rights under an existing gas sales contract for 25 MMcf/d from the South Umbarka area. Gas sales from the contracts are based on a price that is the energy equivalent of 85 percent of the price of Suez Blend crude oil, FOB Mediterranean port. Sales of gas under the contract began in 1999 upon completion of a gas pipeline from the Khalda Block. In 2000, other producers agreed to accept a negotiated price with a group of industry players for an alternative gas pricing formula for certain quantities of gas purchased from 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. These latest agreements do not impact our existing gas sales contracts in the Khalda Block or at Qarun. However, we have entered into new gas sales contracts containing "Industry Pricing" at our Matruh, Ras Kanayes, Ras El Hekma, and Akik development leases. In Egypt, 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. At the discretion of Arab Petroleum Pipeline Company, the operator of the SUMED pipelines, oil from the Qarun Block is pumped into the 42-inch diameter pipelines, which transport significant quantities of Egyptian and other crude oil from the Gulf of Suez to Sidi Kerir on the Mediterranean Coast. Alternatively, oil can be transported via pipeline owned by Petroleum Pipeline Company (PPC) to the Mostorad Refinery south of Cairo. In Egypt, all our oil production is sold to EGPC on a spot basis at a "Western Desert" price (indexed to Brent Crude Oil). We have the right to export our Egyptian crude oil production, however, EGPC has first call on the purchase of our Egyptian crude oil and has exercised this right. We expect EGPC to continue to exercise its call right. Deteriorating economic conditions during 2001 and 2002 in Egypt have lessened the availability of U.S. dollars, resulting in a one to two month delay in receipts from EGPC. While the delay in payment has not significantly improved or deteriorated in 2002, continuation of the hard currency shortage in Egypt could lead to further delays, deferrals of payment or non-payment in the future. AUSTRALIA 2002 -- We produced 18.2 MMboe in Australia (15 percent of our total) generating $334 million of production revenues. Estimated proved reserves in Australia were 11 percent of our year-end total. During the year we participated in drilling 25 wells, 10 completed as producers, and in five workover and recompletion projects. We had a successful exploration year in Australia, with discoveries at Double Island, Victoria, Pedirka, and Little Sandy in the first quarter of the year. Production from the Victoria, Pedirka, and Little Sandy oil fields commenced in November 2002, eight months from discovery, while the Double Island oil development 7 began production in February 2003, 12 months after discovery. There were three additional discoveries over the remainder of the year at Hoover, South Simpson, and Endymion. On the development side, we had six new oil fields and one new gas field that commenced production during 2002 in the Carnarvon Basin offshore Western Australia. The Gibson and South Plato oil fields (68.5 percent interest) were developed from a common facility and brought on-line in June 2002 at a combined initial average rate of 10,400 gross barrels of oil per day. The South Simpson oil field (68.5 percent interest) was placed on production in October at an average initial rate of 3,000 gross barrels of oil per day. The Victoria, Pedirka, and Little Sandy oil fields (68.5 percent interest) were developed from a common facility and commenced production in November at a combined average rate of 10,000 barrels of oil per day. The Endymion gas field (68.5 percent interest) commenced production in November at an average initial rate of 18 MMcf/d. 2003 -- In February 2003, Apache brought the Double Island oil development (68.5 percent interest) on-line at an average rate of 8,000 barrels of oil per day. For 2003, we have budgeted expenditures of $100 million for an estimated 30 exploration wells, five development wells, and various production development, enhancement and other capital projects. Marketing -- In Australia we entered into two new gas sales contracts and extended two existing gas sales contracts during 2002, bringing our total to 25 contracts. In aggregate, we committed a further 655 Bcf for delivery. Under the largest contract, we will supply more than 600 Bcf over a 25-year period commencing in July 2005. Our total Australian delivery rates are expected to average approximately 100 MMcf/d in 2003. Generally, natural gas is sold in Western Australia by AEL under long-term contracts, many of which contain escalation clauses that provide for an annual increase in the contract price based on the Australian consumer price index. The contract price escalates at an average of 80 percent of the index. These contracts reduce gas price volatility in Australia. OTHER INTERNATIONAL We have exploration and production interests offshore China and in Argentina, and exploration interests in Poland. We are the operator, with a 24.5 percent interest, of the Zhao Dong Block in Bohai Bay, offshore China. In 1994 and 1995, discovery wells tested at rates between 1,300 and 4,000 b/d of oil. In early 1997, one well tested at rates up to 11,571 b/d of oil and another tested at rates up to 15,359 b/d. An overall development plan for the C and D Fields in the Zhao Dong Block was approved by Chinese authorities in December 2000. Work commenced in 2001 with the awarding of contracts for development drilling and the construction of production facilities in accordance with the approved overall development plan. We currently plan to spend an estimated $25 million this year. First production is expected in the second half of 2003. We obtained our first acreage position in Poland in 1997 when we assumed operatorship and a 50 percent interest in over 5.5 million gross acres from FX Energy, Inc. At year-end 2002, we had 1,353,307 net undeveloped acres in Poland. In 2002, we recorded additional impairments to our properties in Poland, as described in Item 7 of this Form 10-K. At December 31, 2002, the Company had $13 million of unproved property costs remaining. Apache is considering various alternatives for maximizing the value of the Poland assets, including sale to a third party. This evaluation may result in additional impairments in 2003. In 2001, we acquired exploration and production assets of Fletcher Challenge and Anadarko Petroleum in Argentina. After these transactions, we held interests in a number of blocks in Argentina's Neuquen basin. We are the operator, with a 100 percent interest, of the Lindero de Piedra and El Santiagueno Blocks. We also hold interests in the following blocks: Agua Salada (30 percent), Faro Virgenes (20 percent), CNQ-16 (seven percent) and CNQ-16A (25 percent). For the year, these interests held less than one percent of our proved reserves and generated small amounts of production and revenue. Our total net acreage in Argentina is 367,690 acres, with 324,790 developed and 42,900 undeveloped at year-end 2002. In light of the social and economic turmoil in Argentina, we have limited our investments. Hence, our 2003 Plan does not presently contemplate any drilling activity. Our staff will concentrate on identifying opportunities and strategies for growth that might be implemented in anticipation of improved political and economic conditions. 8 DRILLING STATISTICS Worldwide, in 2002, we participated in drilling 1,114 gross new wells, with 1,022 (92 percent) completed as producers. Canada was our most active region, drilling 836 gross new wells, 599 of which were shallow development wells drilled in the Hatton field. Canada's success rate was 96 percent. We also performed over 2,066 major workovers and recompletions during the year. Our drilling activities in the United States generally concentrate on exploitation of existing, producing fields rather than exploration. As a general matter, our international and Canadian drilling activities focus more on exploration drilling. In addition to our completed wells at year-end, we were participating in several wells that had not yet reached completion: four in the U.S. (2.5 net); three in Canada (2.1 net); nine in Egypt (7.2 net); and one in Australia (0.7 net). The following table shows the results of the oil and gas wells drilled and tested for each of the last three fiscal years:
NET EXPLORATORY NET DEVELOPMENT TOTAL NET WELLS ------------------------- ------------------------- ------------------------- PRODUCTIVE DRY TOTAL PRODUCTIVE DRY TOTAL PRODUCTIVE DRY TOTAL ---------- ---- ----- ---------- ---- ----- ---------- ---- ----- 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 ==== ==== ==== ===== ==== ===== ===== ==== ===== 2001 United States........ 5.9 4.4 10.3 202.9 32.0 234.9 208.8 36.4 245.2 Canada............... 0.7 7.0 7.7 348.4 17.2 365.6 349.1 24.2 373.3 Egypt................ 4.5 4.5 9.0 25.0 7.5 32.5 29.5 12.0 41.5 Australia............ 1.4 5.2 6.6 5.0 2.6 7.6 6.4 7.8 14.2 Other International...... -- 3.4 3.4 0.3 -- 0.3 0.3 3.4 3.7 ---- ---- ---- ----- ---- ----- ----- ---- ----- Total.............. 12.5 24.5 37.0 581.6 59.3 640.9 594.1 83.8 677.9 ==== ==== ==== ===== ==== ===== ===== ==== ===== 2000 United States........ 5.8 9.1 14.9 201.0 41.6 242.6 206.8 50.7 257.5 Canada............... 1.0 7.0 8.0 58.7 11.7 70.4 59.7 18.7 78.4 Egypt................ 5.0 5.8 10.8 9.7 1.6 11.3 14.7 7.4 22.1 Australia............ 1.4 13.7 15.1 4.3 -- 4.3 5.7 13.7 19.4 Other International...... -- 0.9 0.9 -- -- -- -- 0.9 0.9 ---- ---- ---- ----- ---- ----- ----- ---- ----- Total.............. 13.2 36.5 49.7 273.7 54.9 328.6 286.9 91.4 378.3 ==== ==== ==== ===== ==== ===== ===== ==== =====
9 PRODUCTIVE OIL AND GAS WELLS The number of productive oil and gas wells, operated and non-operated, in which we had an interest as of December 31, 2002, is set forth below:
GAS OIL TOTAL ------------- ------------- -------------- GROSS NET GROSS NET GROSS NET ----- ----- ----- ----- ------ ----- Gulf Coast............................. 895 560 995 690 1,890 1,250 Central................................ 2,488 1,233 3,242 1,992 5,730 3,225 Canada................................. 4,445 3,858 2,555 1,037 7,000 4,895 Egypt.................................. 23 21 201 185 224 206 Australia.............................. 9 5 38 19 47 24 Argentina.............................. 23 6 31 20 54 26 ----- ----- ----- ----- ------ ----- Total................................ 7,883 5,683 7,062 3,943 14,945 9,626 ===== ===== ===== ===== ====== =====
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.......................... 1,092,822 632,970 2,116,100 1,232,026 Canada................................. 3,225,171 2,493,056 2,686,271 1,853,500 Egypt.................................. 9,406,675 5,957,898 1,106,823 992,516 Australia.............................. 8,518,240 4,179,110 467,770 274,470 China.................................. 5,314 2,657 5,911 1,448 Poland................................. 1,471,524 1,353,307 -- -- Argentina.............................. 191,418 42,900 520,572 324,790 ---------- ---------- --------- --------- Total Company........................ 23,911,164 14,661,898 6,903,447 4,678,750 ========== ========== ========= =========
10 PRODUCTION AND PRICING DATA The following table describes, for each of the last three fiscal years, oil, natural gas liquids (NGLs) and gas production for the Company, average production costs and average sales prices.
PRODUCTION AVERAGE SALES PRICE --------------------------- AVERAGE ------------------------------------ OIL NGLs GAS PRODUCTION OIL NGLs GAS YEAR ENDED DECEMBER 31, (Mbbls) (Mbbls) (MMcf) COST PER Boe (PER bbl) (PER bbl) (PER Mcf) ----------------------- ------- ------- ------- ------------ ---------- ---------- ---------- 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 -- 0.42 ------ ----- ------- Total......................... 55,837 3,083 394,341 4.12 24.78 14.69 2.87 ====== ===== ======= 2001 United States................... 21,353 2,803 224,600 4.46 24.39 16.60 4.15 Canada.......................... 9,451 464 108,925 3.41 19.22 17.45 3.81 Egypt........................... 14,322 -- 35,010 2.45 23.59 -- 3.51 Australia....................... 8,595 -- 42,684 2.77 23.89 -- 1.22 Other International............. 43 -- 236 4.71 17.90 -- 1.20 ------ ----- ------- Total......................... 53,764 3,267 411,455 3.69 23.18 16.72 3.70 ====== ===== ======= 2000 United States................... 20,687 2,207 199,361 3.82 27.85 20.04 4.02 Canada.......................... 5,387 441 47,758 2.39 22.25 18.36 3.65 Egypt........................... 10,155 -- 17,372 2.17 27.81 -- 4.51 Australia....................... 5,691 -- 39,489 2.49 29.99 -- 1.34 ------ ----- ------- Total......................... 41,920 2,648 303,980 3.22 27.41 19.76 3.64 ====== ===== =======
ESTIMATED PROVED RESERVES AND FUTURE NET CASH FLOWS As of December 31, 2002, Apache had total estimated proved reserves of 637 million barrels of crude oil, condensate and NGLs and 4.1 Tcf of natural gas. Combined, these total estimated proved reserves are equivalent to 1.3 billion barrels of oil or 7.9 Tcf of gas. The company's reserves have grown for the 17th consecutive year. Estimated proved developed reserves comprise 72 percent of our total estimated proved reserves on a boe basis. The Company's estimates of proved reserves and proved developed reserves at December 31, 2002, 2001 and 2000, changes in proved reserves during the last three years, and estimates of future net cash flows and discounted future net cash flows from proved reserves are contained in Note 15, Supplemental Oil and Gas Disclosures (Unaudited), in the Apache Corporation 2002 Consolidated Financial Statements of Item 15 of this Form 10-K. 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. Reserves are considered proved if economical producibility is supported by either actual production or conclusive formation tests. 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 installed program in the reservoir provides support for the engineering analysis on which the project or program is based. Proved developed oil and gas reserves can be expected to be recovered through existing wells with existing equipment and operating methods. 11 Apache emphasizes that the volumes of 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. We engage an independent petroleum engineering firm to review our estimates of proved hydrocarbon liquid and gas reserves. During 2002, 2001 and 2000, their review covered 68, 61 and 72 percent of the reserve value, respectively. This value, which represents estimated future net cash flows, is based on prices at year-end and is calculated in accordance with SFAS No. 69, "Disclosures about Oil and Gas producing Activities." Disclosure of this value and related reserves has been prepared in accordance with the Securities and Exchange Commission (SEC) Regulation S-X Rule 4-10 and is presented in Note 15 to the accompanying financial statements. RISK FACTORS RELATED TO OUR BUSINESS AND OPERATIONS 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 proved reserves, conduct successful exploration and development activities or, through engineering studies, identify additional behind-pipe zones or secondary recovery reserves, our 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. COSTS INCURRED TO CONFORM TO GOVERNMENT REGULATION OF THE OIL AND GAS INDUSTRY Our exploration, production and marketing operations are regulated extensively at the federal, state and local levels, as well as by other countries in which we do business. We have made and will continue to make all necessary expenditures in our efforts to comply with the requirements of environmental and other regulations. Further, the oil and gas regulatory environment could change in ways that might substantially increase these costs. Hydrocarbon-producing states regulate conservation practices and the protection of correlative rights. These regulations affect our operations and limit the quantity of hydrocarbons we may produce and sell. In addition, at the U.S. federal level, the Federal Energy Regulatory Commission regulates interstate transportation of natural gas under the Natural Gas Act. Other regulated matters include marketing, pricing, transportation and valuation of royalty payments. COSTS INCURRED RELATED TO ENVIRONMENTAL MATTERS We, as an owner or lessee and operator of oil and gas properties, are subject to various federal, provincial, state, local and foreign country laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution clean-up resulting from operations, subject the lessee to liability for pollution damages, and require suspension or cessation of operations in affected areas. We maintain insurance coverage, which we believe is customary in the industry, although we are not fully insured against all environmental risks. We are not aware of any environmental claims existing as of December 31, 2002, which would have a material impact upon our financial position or results of operations. 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 on 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. 12 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 directly 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. As of December 31, 2002, we had an accrued liability of $10 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 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. COMPETITION WITH OTHER COMPANIES COULD HARM US The oil and gas industry is highly competitive. Our business could be harmed by competition with other companies. Because oil and gas are fungible commodities, one form of competition is price competition. We strive to maintain the lowest finding and production costs possible in order to maximize profits. In addition, as an independent oil and gas company, we frequently compete for reserve acquisitions, exploration leases, licenses, concessions and marketing agreements against companies with financial and other resources substantially larger than those we possess. Many of our competitors have established strategic long-term positions and maintain strong governmental relationships in countries in which we may seek new entry. 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. RISKS ARISING FROM THE FAILURE TO FULLY IDENTIFY POTENTIAL PROBLEMS RELATED TO ACQUIRED RESERVES OR TO PROPERLY ESTIMATE THOSE RESERVES One of our primary growth strategies is the acquisition of oil and gas properties. Although we perform a review of the acquired properties that we believe is consistent with industry practices, such reviews are inherently incomplete. It generally is not feasible to review in depth every individual property involved in each acquisition. Ordinarily, we will focus our review efforts on the higher-value properties and will sample the remainder. However, even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it 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 13 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. 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, 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 to serve as our new independent auditors for 2002. However, included in this annual report on Form 10-K, are financial data and other information for 2001 and 2000 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. ISSUES RELATED TO ARTHUR ANDERSEN LLP MAY IMPEDE OUR ABILITY TO ACCESS THE CAPITAL MARKETS In the unlikely event that the SEC ceases accepting financial statements audited by Arthur Andersen LLP, we would be unable to access the public capital markets unless Ernst & Young LLP, our current independent accounting firm, or another independent accounting firm, is able to audit the financial statements originally audited by Arthur Andersen. In addition, investors in any subsequent offerings for which we use Arthur Andersen's audit reports will not be entitled to recovery against Arthur Andersen under Section 11 of the Securities Act of 1933, as amended, for any material misstatements or omissions in those financial statements. Furthermore, Arthur Andersen will be unable to participate in the "due diligence" process that would customarily be performed by potential investors in our securities, which process includes having Arthur Andersen perform procedures to assure the continued accuracy of its report on our audited financial statements and to confirm its review of unaudited interim periods presented for comparative purposes. As a result, we may not be able to bring to the market successfully an offering of our securities in a timely and efficient manner. Consequently, our financing costs may increase or we may miss attractive market opportunities. EMPLOYEES On December 31, 2002, we had 1,958 employees. None of our employees is 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 2002, we maintained regional exploration and/or production offices in Tulsa, Oklahoma; Houston, Texas; Calgary, Alberta; Cairo, Egypt; Perth, Western Australia; Beijing, China; Warsaw, Poland; and Buenos Aires, Argentina. We established an office in Aberdeen, Scotland early in 2003. Apache leases all of its primary office space. The current lease on our principal executive offices runs through April 30, 2007. 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 Item 15, Note 11 -- "Operating Leases and Other Commitments." 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 14 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, easements and restrictions, none of which detract substantially from the value of the interests or materially interfere with their use in our operations. ITEM 2. PROPERTIES For information on our domestic and international properties, see the discussions in Item 1 of this Form 10-K under Review of Company's Worldwide Operating Areas as identified by country. For tables setting out a description of our drilling activities, well counts and acreage positions, see the information in Item 1 under Drilling Statistics, Productive Oil and Gas Wells and Gross and Net Undeveloped Acreage. ITEM 3. LEGAL PROCEEDINGS See the information set forth under the caption "Commitments and Contingencies" in Note 11 to our financial statements under Item 15 of this Form 10-K. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS No matters were submitted for a vote of security holders during the fourth quarter of 2002. PART II ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS Apache common stock, par value $0.625 per share, is traded on the New York Stock Exchange and the Chicago Stock Exchange under the symbol APA. The table below provides certain information regarding our common stock for 2002 and 2001. Prices were obtained from the New York Stock Exchange 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 and the 10 percent and five percent stock dividends, all of which are described below. Per share prices and dividends shown below have been rounded to the indicated decimal place.
2002 2001 ------------------------------------- ------------------------------------- PRICE RANGE DIVIDENDS PER SHARE PRICE RANGE DIVIDENDS PER SHARE --------------- ------------------- --------------- ------------------- HIGH LOW DECLARED PAID HIGH LOW DECLARED PAID ------ ------ --------- ------- ------ ------ -------- ------ First Quarter......... $27.72 $21.13 $.0475 $.0475 $31.55 $23.47 $ -- $ -- Second Quarter........ 28.62 25.04 .0475 .0475 28.92 20.80 -- -- Third Quarter......... 28.57 21.46 .0475 .0475 23.55 16.56 .121 -- Fourth Quarter........ 28.88 23.55 .0475 .0475 23.87 17.57 .0475 .121
The closing price per share of our common stock, as reported on the New York Stock Exchange Composite Transactions Reporting System for February 28, 2003, was $65.28 ($31.09 adjusted for the five percent stock dividend and two-for-one stock split). At February 28, 2003, there were 153,850,136 shares of our common stock outstanding (323,085,284 shares adjusted for the five percent stock dividend and two-for-one stock split) held by approximately 8,000 shareholders of record and approximately 104,000 beneficial owners. We have paid cash dividends on our common stock for 36 consecutive years through December 31, 2002. During 2000, we implemented a change in the payment schedule for dividends on our common stock from a quarterly basis to an annual basis; however, we later implemented a return to a quarterly dividend payment 15 schedule beginning in 2002. 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, our board of directors adopted a stockholder rights plan to replace the former plan adopted in 1986. Under our stockholder rights plan, each of our common stockholders received a dividend of one "preferred stock purchase right" for each 2.31 outstanding shares of common stock (adjusted for the 10 percent and five percent stock dividends and two-for-one stock split) that the stockholder owned. We refer to these preferred stock purchase rights as the "rights." Unless the rights have been previously redeemed, all shares of Apache common stock are issued with rights. The rights trade automatically with our shares of common stock. Certain triggering events will give the holders of the rights the ability to purchase shares of our common stock, or the equivalent stock of a person that acquires us, at a discount. The triggering events relate to persons or groups acquiring an amount of our common stock in excess of a set percentage, or attempting to or actually acquiring us. The details of how the rights operate are set out in our certificate of incorporation and the Rights Agreement, dated January 31, 1996, between Apache and Wells Fargo Bank Minnesota, N.A. (formerly Norwest Bank Minnesota, N.A.). Both of those documents have been filed as exhibits to this Form 10-K and you should review them to fully understand the effects of the rights. The purpose of the rights is to encourage potential acquirors to negotiate with our board of directors before attempting a takeover bid and to provide our board of directors with leverage in negotiating on behalf of our stockholders the terms of any proposed takeover. The rights may have certain anti-takeover effects. They should not, however, interfere with any merger or other business combination approved by our board of directors. In May 1999, we issued 140,000 shares of 6.5 percent Automatically Convertible Equity Securities, Conversion Preferred Stock, Series C (Series C Preferred Stock) in the form of seven million depositary shares each representing 1/50th of a share of Series C Preferred Stock. The depositary shares were traded on the New York Stock Exchange and the Chicago Stock Exchange. The Series C Preferred Stock was not subject to a sinking fund or mandatory redemption. 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, $330,000, is reflected as a preferred stock dividend in the accompanying statement of consolidated operations. The remaining depositary shares converted into 6,554,865 shares (13,109,730 shares adjusted for the two-for-one stock split) of Apache common stock in 2002. On September 13, 2001, our board of directors declared a 10 percent dividend on our shares of common stock payable in common stock on January 21, 2002 to shareholders of record on December 31, 2001. Pursuant to the terms of the declared 10 percent stock dividend, we issued 13,070,068 shares (26,140,136 shares adjusted for the two-for-one stock split) of our common stock on January 21, 2002 to the holders of the 130,888,270 shares (261,776,540 shares adjusted for the two-for-one stock split) of common stock outstanding on December 31, 2001. No fractional shares were issued in connection with the stock dividend and cash payments totaling $891,132 were made in lieu of fractional shares. 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 expect to issue approximately 7,868,000 shares (15,736,000 shares adjusted for the two-for-one stock split) of our common stock on April 2, 2003 to the holders of the 153,867,875 shares (307,735,750 shares adjusted for the two-for-one stock split) of common stock outstanding on March 12, 2003. No fractional shares will be issued in connection with the stock dividend and we expect to make cash payments totaling approximately $1,437,000 in lieu of fractional shares. On January 22, 2003, in conjunction with the BP acquisition, the Company completed the public offering of 9.9 million shares (19.8 million shares adjusted for the two-for-one stock split) of Apache common stock, including 1.3 million shares (2.6 million shares adjusted for the two-for-one stock split) for the underwriters' over-allotment option, at $58.10 per share ($29.05 adjusted for the two-for-one stock split). 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 BP acquisition. 16 On September 11, 2003 our board of directors declared a two-for-one stock split, which was distributed on January 14, 2004 to shareholders of record on December 31, 2003. 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, 2002, which information has been derived from the Company's audited financial statements. Our financial statements for the years 1998 through 2001 were audited by Arthur Andersen LLP, independent public accountants. For a discussion of the risks relating to Arthur Andersen's audit of our financial statements, please see discussion of risks related to Arthur Andersen in Item 1 of this Form 10-K "Factors That May Affect Future Results -- Risks Relating to Arthur Andersen LLP." 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 in Item 15 of this Form 10-K.
AS OF OR FOR THE YEAR ENDED DECEMBER 31, -------------------------------------------------------------- 2002 2001 2000 1999 1998 ---------- ---------- ---------- ---------- ---------- (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) INCOME STATEMENT DATA Total revenues................... $2,559,873 $2,809,391 $2,301,978 $1,161,697 $ 772,791 Income (loss) attributable to common stock................... 543,514 703,798 693,068 186,406 (131,391) Net income (loss) per common share: Basic.......................... 1.83 2.44 2.54 .75 (.58) Diluted........................ 1.80 2.37 2.46 .74 (.58) Cash dividends declared per common share................... .19 .17 .09 .12 .12 BALANCE SHEET DATA Total assets..................... 9,459,851 8,933,656 7,481,950 5,502,543 3,996,062 Long-term debt................... 2,158,815 2,244,357 2,193,258 1,879,650 1,343,258 Preferred interests of subsidiaries................... 436,626 440,683 -- -- -- Shareholders' equity............. 4,924,280 4,418,483 3,754,640 2,669,427 1,801,833 Common shares outstanding........ 302,506 287,916 285,596 263,332 225,846
For a discussion of significant acquisitions, see Note 3 to the Company's consolidated financial statements in Item 15 of this Form 10-K. During 1998, the Company recorded a $243 million pre-tax ($158 million net of tax) non-cash write-down of the carrying value of the Company's U.S. proved oil and gas properties in compliance with full-cost accounting rules (refer to Critical Accounting Policies in Item 7 of this Form 10-K). ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS OVERVIEW In 2002, Apache reported another very satisfactory year of growth and progress in our mission to build Apache incrementally to last. We finished the year with strong results, the third-best year on a per-share basis over our 48-year history. Our strong cash flow provided us the flexibility to make necessary and appropriate investments in continuation of our long-term incremental growth strategy. On the back of a strong fourth quarter, we ended the year with a solid $544 million of net income attributable to common stock and $1.4 billion in cash from operating activities. We exited 2002 with our best quarter of the year and a strong financial position. Thirteen days into the new year, we announced the acquisition of $1.3 billion (subject to normal closing adjustments and the exercise of preferential rights by third parties) in properties from BP p.l.c. (BP), setting the stage for an exciting 2003. 17 Facing 2002 with the prospect of continued volatility in commodity prices, high service costs (including drilling, materials and contracted geophysical surveys) and unattractive acquisition prices, we exercised patience and discipline, restricting capital spending and focusing efforts on maintaining our competitive position by strengthening our balance sheet, growing our reserve base and maintaining production levels. As the year progressed, improving commodity prices and declining drilling costs placed us in an ideal position where we could continue increasing financial flexibility while simultaneously increasing capital spending, which we did beginning in the third quarter. Our worldwide capital expenditures for exploratory and development drilling of $860 million were 46 percent higher than our initial plan, but still well below the $1.3 billion we spent in 2001. Ultimately, this strategy manifested itself in lower drilling costs, one of the lowest debt-to-capitalization ratios in our peer group, and our 17th consecutive year of reserve growth, ending with 1.3 billion barrels of oil equivalent. It also left us positioned to acquire the BP properties in 2003 while maintaining our financial flexibility. Our capital expenditure reductions in the first half of 2002 were selective, both by region and by type of drilling. Rather than decrease exploration drilling, we increased it in the areas of Canada, Egypt, and Australia, all core producing areas that saw production growth in 2002. We had a successful exploration drilling program in 2002, reporting 16 discoveries worldwide. Production remained within one percent of prior-year levels despite our capital spending curtailment in the first half of the year and back-to-back hurricanes, which forced us to shut-in all of our Gulf of Mexico production for a brief period in late September and then again in early October. The foundation of Apache's strategy is a portfolio approach that was developed to provide diversity in terms of hydrocarbon product (oil or gas), geologic risk and geographic location. In 2002, 58 percent of our equivalent production came from outside the U.S., up from 51 percent in 2001. At year-end 2002, our reserves were 49 percent oil and 51 percent gas, compared with 47 percent and 53 percent at year-end 2001. In each of our core producing areas, our front line teams have the technical knowledge, sense of urgency and drive necessary to wring more value from Apache's assets. Building local expertise also provides a platform to compete and expand in our core areas through both operations and acquisitions. In the latter half of 2001, we felt that acquisition prices had reached exorbitant levels, relative to commodity prices, leading us to the sidelines until appropriate opportunities arose at reasonable prices, which began late in 2002. We spent approximately $355 million on acquisitions in 2002, compared with $1.2 billion in 2001 and $1.4 billion in 2000. The most significant of the 2002 activity came in December, when we announced the acquisition of properties in South Louisiana. As we have done in the past, and what has become a cornerstone of our acquisition strategy, we entered into hedges to protect the economics of the transaction, while at the same time preserving the potential for significantly higher gas realizations. See Note 4, in Item 15 of this Form 10-K. In January 2003, we announced that we had entered into a definitive agreement with BP to purchase producing properties in the North Sea and Gulf of Mexico for $1.3 billion (subject to normal closing adjustments and the exercise of preferential rights by third parties), the largest single acquisition in Apache's history. The acquisition from BP is significant in many respects: it extends our relationship to one of the world's premier integrated major oil companies; it adds production and reserves and a new exploitation portfolio in North America's strongest gas market; and it establishes a new core area in the North Sea, which fits our balanced-portfolio business model and further diversifies our reserves and production. The Gulf properties are synergistic with our existing properties and made Apache the fourth-largest producer and the second-largest acreage holder in Gulf of Mexico waters to 1,200 feet deep. We will also become the ninth-largest oil producer in the North Sea. The effective date of the transaction is January 1, 2003; the Gulf portion closed on March 13, 2003; the North Sea portion is projected to close early in the second quarter. The acquisition is being financed through a combination of internally generated funds, the issuance in January 2003 of common equity, and debt. Oil and gas production for the first two years has been hedged to provide Apache with fixed prices on expected production to protect against commodity price volatility (see Note 4 of Item 15 in this Form 10-K). On January 22, 2003, in conjunction with the BP transaction, we completed a public offering of 9.9 million shares (19.8 million shares adjusted for the two-for-one stock split) of common stock, including 18 1.3 million shares (2.6 million shares adjusted for the two-for-one stock split) for the underwriters' over-allotment option, raising net proceeds of $554 million. After announcing the BP acquisition, all three rating agencies reaffirmed Apache's single-A credit ratings, a testament to our strong financial position, our conservative financial strategy, where we employ hedges to protect acquisition economics, and our three-pronged approach to finance large-scale transactions with internally generated funds, equity and debt. We believe that this reaffirmation of our credit ratings further establishes Apache's financial wherewithal and reputation as a reliable purchaser of major companies' assets as they sell assets in the future. In December 2002, to recognize the Company's continued progress on both the financial and operational fronts, Apache's board of directors declared a special five percent common stock dividend payable on April 2, 2003, to shareholders of record on March 12, 2003. On September 11, 2003, our board of directors declared a two-for-one stock split, which was distributed on January 14, 2004 to shareholders of record on December 31, 2003. All of the share and per share information included in this filing has been adjusted to reflect this stock dividend and the two-for-one stock split except where otherwise indicated. CRITICAL ACCOUNTING POLICIES The discussion and analysis of our financial condition and results of operations are based upon the consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. 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. We evaluate our estimates and assumptions on a regular basis. We base our 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 the 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 our financial statements. Below, we have provided expanded discussion of our more significant accounting policies, estimates and judgments. We discussed the development, selection and disclosure of each of these with our audit committee. We believe these accounting policies reflect our more significant estimates and assumptions used in preparation of our financial statements. See Results of Operations and Note 1 of Item 15 of this Form 10-K for a discussion of additional accounting policies and estimates made by management. 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, cost 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 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 at the end of the reporting period. 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 activities. Although some of these costs will ultimately result in no additional reserves, we expect the 19 benefits of successful wells to more than offset the costs of any unsuccessful ones. 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. The Company has taken note of a July 2003 inquiry to the Financial Accounting Standards Board regarding whether or not contract-based oil and gas mineral rights held by lease or contract ("mineral rights") should be recorded or disclosed as intangible assets. The inquiry presents a view that these mineral rights are intangible assets as defined in SFAS No. 141, "Business Combinations," and, therefore, should be classified separately on the balance sheet as intangible assets. SFAS No. 141, and SFAS No. 142, "Goodwill and Other Intangible Assets," became effective for transactions subsequent to June 30, 2001 with the disclosure requirements of SFAS No. 142 required as of January 1, 2002. SFAS No. 141 requires that all business combinations initiated after June 30, 2001 be accounted for using the purchase method and that intangible assets be disaggregated and reported separately from goodwill. SFAS No. 142 established new accounting guidelines for both finite lived intangible assets and indefinite lived intangible assets. Under the statement, intangible assets should be separately reported on the face of the balance sheet and accompanied by disclosure in the notes to financial statements. SFAS No. 142 scopes out accounting utilized by the oil and gas industry as prescribed by SFAS No. 19, and is silent about whether or not its disclosure provisions apply to oil and gas companies. Apache does not believe that SFAS No. 141 or 142 change the classification of oil and gas mineral rights and the Company continues to classify these assets as part of oil and gas properties. The Emerging Issues Task Force (EITF) has added the treatment of oil and gas mineral rights to an upcoming agenda, which may result in a change in how Apache classifies these assets. Should such a change be required, the amounts related to business combinations and major asset purchases after June 30, 2001 that would be classified as "intangible undeveloped mineral interest" was $9 million and $78 million as of December 31, 2001 and December 31, 2002, respectively. The amounts related to business combinations and major asset purchases after June 30, 2001 that would be classified as "intangible developed mineral interest" was $88 million and $332 million as of December 31, 2001 and December 31, 2002, respectively. Intangible developed mineral interest amounts are presented net of accumulated depletion, depreciation and amortization (DD&A). Accumulated DD&A was estimated using historical depletion rates applied proportionately to the costs of the acquisitions to be classified as "intangible developed mineral interest". The amounts noted above only include mineral rights acquired in business combinations or major asset purchases, and exclude those acquired individually or in groups as we have not historically tracked these in this manner. The Company has also not historically tracked the amount of mineral rights in the proved property balances related to producing leases or relinquished leases. We are currently identifying a methodology to do so for transactions subsequent to June 30, 2001. The numbers above are based on our understanding of the issue before the EITF, if all mineral rights associated with unevaluated property and producing reserves were deemed to be intangible assets: - mineral rights with proved reserves that were acquired after June 30, 2001 and mineral rights with no proved reserves would be classified as intangible assets and would not be included in oil and gas properties on our consolidated balance sheet; - results of operations and cash flows would not be materially affected because mineral rights would continue to be amortized in accordance with full cost accounting rules; and - disclosures required by SFAS Nos. 141 and 142 relative to intangibles would be included in the notes to our financial statements. If the accounting for mineral rights is ultimately changed, transitional guidance for intangible assets permits the reclassification of only amounts acquired after the effective date of SFAS Nos. 141 and 142 if records were not previously maintained to track acquisition costs based on their intangible or tangible nature. Lack of these records prior to the effective date could result in the loss of comparability between historical balances of tangible and intangible asset balances and among companies in the industry. 20 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. 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 depreciation, depletion and amortization (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 2002, 2001 and 2000, their review covered 68, 61 and 72 percent of the reserve value, respectively. BAD DEBT EXPENSE 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. Generally, our crude oil and natural gas receivables are typically collected within two months. In Egypt, however, we have experienced a gradual decline in the timeliness of receipts from Egyptian General Petroleum Corporation (EGPC). Deteriorating economic conditions during 2001 and 2002 in Egypt have lessened the availability of U.S. dollars, resulting in an additional one to two month delay in receipts from EGPC. Continuation of the hard currency shortage in Egypt could lead to further delays, deferrals of payment or non-payment in the future. 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. 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. Under the full-cost method of accounting, as described in the preceding critical accounting policy sections, the estimated undiscounted costs of the abandonment obligations, net of salvage, are currently included as a component of our depletion base and expensed over the production life of the oil and gas properties. Estimating the future asset 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 well as regulatory, political, environmental, safety and public relations considerations. In 2001, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 143 ("SFAS No. 143"), "Accounting for Asset Retirement Obligations." Apache adopted this statement effective January 1, 2003, as discussed in Note 2 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. 21 Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property balance. In addition, increases in the discounted ARO liability resulting from the passage of time will be reflected as accretion expense in the consolidated statement of operations. SFAS No. 143 requires a cumulative adjustment to reflect the impact of implementing the statement had the rule been in effect since inception. The Company, therefore, calculated the cumulative accretion expense on the ARO liability and the cumulative depletion expense on the corresponding property balance. The sum of these cumulative expenses was compared to the depletion expense originally recorded. Because the historically recorded depletion expense was higher than the cumulative expense calculated under SFAS No. 143, the difference resulted in a gain which the Company recorded as cumulative effect of change in accounting principle on January 1, 2003. Upon implementation, the Company also had to determine if the statement required us to recalculate our historical full-cost ceiling tests (see Note 1 of Item 15 of this Form 10-K). The Company chose not to re-calculate its historical full-cost ceiling tests even though its historical oil and gas property balances would have been higher had we applied the statement from inception. We believe this approach is appropriate because SFAS No. 143 is silent on this issue and was not effective during the prior impairment test periods. Had a recalculation of the historical full-cost ceiling test resulted in impairment, the charge would have reduced the gain recorded upon adoption. Going forward, our depletion expense will be reduced since we will deplete a discounted ARO rather than the undiscounted value previously depleted. The lower depletion expense under SFAS No. 143 is offset, however, by higher accretion expense, which reflects increases in the discounted asset retirement obligation over time. Also going forward, 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 of Item 15 of this Form 10-K). SFAS No. 143 is silent with respect to this issue and, although there are various views, the Company elected to continue including the undiscounted ARO as part of future development costs, essentially reducing the present value of its future net revenues and full-cost ceiling limit. To compare the property balance, which included the ARO component, to the full-cost ceiling limit, which has been reduced by a similar abandonment cost, we netted the ARO liability against the property balance. The Company believes its view is appropriate since there must be a comparable basis between the net book value of the properties and the full-cost ceiling limitation. Another widely contemplated view is to exclude the ARO from future development costs when calculating the full-cost ceiling limitation and not reduce the carrying amount of capitalized costs by the related liability. This approach would result in a higher full-cost ceiling limitation and a higher net oil and gas property balance. INCOME TAXES Oil and gas exploration and production is a global business. 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). We intend to permanently reinvest earnings from our international operations; therefore, we do not recognize deferred taxes on the unremitted earnings of our international subsidiaries. If it becomes apparent that some or all of the unremitted earnings will be remitted, we would then reflect taxes on those earnings. 22 DERIVATIVES Apache uses commodity derivative contracts on a limited basis to manage its exposure to oil and gas price volatility. Apache accounts for its commodity derivative contracts in accordance with SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS 133). Realized gains and losses from the Company's cash flow hedges, including terminated contracts, are generally recognized in oil and gas production revenues when the forecasted transaction occurs. The Company does not enter into derivative or other financial instruments for trading purposes. SFAS 133 requires that gains and losses from the change in fair value of derivative instruments that do not qualify for hedge accounting be reported in current period income, rather than in the period in which the hedged transaction is settled. This may result in significant volatility to current period income. SFAS 133 is complex and subject to a potentially wide range of interpretations in its application. As such, in 1998 the FASB established the Derivative Implementation Group (DIG) task force specifically to consider and to publish official interpretations of issues arising from the implementation of SFAS 133. The potential exists for additional issues to be brought under review, therefore, if subsequent interpretations of SFAS 133 are different than our current policy, it is possible that our policy, as stated above, would be modified. RESULTS OF OPERATIONS This section includes a discussion of our 2002 and 2001 results of operations. Apache has five reportable segments, which are the United States, Canada, Australia, Egypt and Other International. These segments are primarily in the business of crude oil and natural gas exploration and production. Please refer to Note 14 of Item 15 of this Form 10-K for segment information. ACQUISITIONS AND DIVESTITURES In 2002, we elected to exercise patience on the acquisition front, waiting for the frenzy that drove acquisition prices to unreasonable levels to ebb. We focused our attention on managing our financial structure by building equity and paying down debt so we would be in a position to act quickly when attractive assets became available at reasonable prices. Our oil and gas acquisitions in 2002 totaled approximately $350 million, adding 49 MMboe to our reserve base, far short of the $880 million and $1.3 billion we expended during 2001 and 2000, respectively, which added 213 MMboe and 254 MMboe of proved reserves. In addition, the acquisitions added $3 million, $146 million and $94 million of production, processing and transportation facilities in 2002, 2001 and 2000, respectively, and $197 million of goodwill in 2001. These acquisitions strengthened our position in core areas and provided promising prospects for future exploration and development activities. We will continue our strategy of finding additional reserves on the acquired properties and accelerating the production of those already identified while endeavoring to lower costs. Seventy-five percent of our 2002 acquisition activity occurred in the U.S. and was related to the acquisition of properties primarily located in two Southern Louisiana parishes. The balance of our 2002 acquisitions primarily related to two acquisitions in Canada. In connection with our 2002 South Louisiana acquisition, we entered into costless-collar hedges to protect Apache from the potential for falling gas prices and to protect the economics of the transaction. These hedges are consistent with some of our 2001 and 2000 acquisitions whereby we entered into and assumed fixed-price commodity swaps and costless-collars that protected Apache from falling commodity prices. This enabled us to better predict the financial performance of our acquisitions. See Note 4 of Item 15 for the terms of the Company's hedging activity. Over ninety percent of our 2001 activity was spent on three acquisitions, one in Canada and two in Egypt. The Fletcher acquisition in Canada totaled 55 percent while the Repsol and Novus acquisitions in Egypt totaled 37 percent of our acquisition activity. All three acquisitions added significant reserves and production. Over ninety percent of our 2000 activity involved four North American transactions, three in the U.S. and one in Canada. The U.S. acquisitions, which totaled 56 percent of our acquisition outlays, included properties acquired from Occidental Petroleum Corporation, Collins & Ware, Inc. and Repsol YPF. Our Canadian 23 acquisition from Phillips Petroleum Company represented 36 percent of the year's activity. These four transactions added significant reserves and production. Our acquisitions over the last three years helped us maintain diversity in terms of hydrocarbon product (oil or gas), geologic risk and geographic location. As shown in Note 15 of this Form 10-K, our 2002 year-end international reserves as a percentage of total reserves climbed to 52 percent from 41 percent at year-end 2000. Similarly, our international average daily production in 2002 rose to 58 percent of our total production versus 41 percent in 2000. Our hydrocarbon product mix on a boe basis has remained relatively constant at 53 percent natural gas and 47 percent oil. While the U.S., a highly stable environment, remains our largest core area, Apache will continue to evaluate acquisition opportunities in existing core areas and in new areas should they arise. Note that, in light of the uncertainty of how the collapse of Enron Corp. would impact the derivatives markets, we closed all of our derivatives positions in October and November 2001, most of which were associated with prior acquisitions, recognizing a net gain of $10 million. A net gain of $24 million was recognized in 2002 and a $4 million net loss will be recognized in 2003 as the originally hedged volumes are produced. These, as well as the unwinding of our gas price swaps associated with advances from gas purchasers, increased the Company's average natural gas price by $.04 per Mcf during 2002, $.09 per Mcf during 2001 and $.05 per Mcf during 2000. They increased our average crude oil price by $.15 per bbl during 2002, and reduced our average crude oil price by $.42 per bbl during 2001 and $1.62 per bbl during 2000. We routinely evaluate our property portfolio and divest those that are marginal or no longer fit into our strategic growth program. We divested $7 million, $348 million and $26 million of properties during 2002, 2001 and 2000, 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. Imbalances in the supply and demand for oil and natural gas can have dramatic effects on the prices we receive for our production. Political instability and availability of alternative fuels could impact worldwide supply, while economic factors such as the current U.S. recession 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. Apache 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. 2) Australia, which has a local market with limited demand and infrastructure. 3) Egypt, which has a local market and where the price received for the majority of our production is currently indexed to a weighted-average Dated-Brent crude oil price. For specific marketing arrangements by segment, please refer to Item 1, Business of this Form 10-K. 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. 24 The following table presents each segment's oil revenues and gas revenues as a percentage of total oil revenues and gas revenues, respectively.
OIL REVENUES GAS REVENUES --------------------------------- --------------------------------- FOR THE YEAR ENDED DECEMBER 31, FOR THE YEAR ENDED DECEMBER 31, --------------------------------- --------------------------------- 2002 2001 2000 2002 2001 2000 ------- ------- ------- --------- --------- --------- United States..................... 35% 40% 47% 51% 61% 72% Canada............................ 16% 17% 13% 29% 27% 16% ---- ---- ---- ------- ------- ------- North America..................... 51% 57% 60% 80% 88% 88% Egypt............................. 29% 27% 25% 15% 8% 7% Australia......................... 20% 16% 15% 5% 4% 5% Other International............... -- -- -- -- -- -- ---- ---- ---- ------- ------- ------- Total........................... 100% 100% 100% 100.00% 100.00% 100.00% ==== ==== ==== ======= ======= =======
Crude Oil Contribution In 2002, oil revenues outside the U.S. reached approximately 65 percent of consolidated oil revenues, up from 60 percent in 2001. This increase primarily occurred in Egypt and Australia where crude oil revenues rose to 28 percent and 20 percent of total oil revenues, respectively. Canada contributed 16 percent of oil revenue, down from 17 percent in 2001. In 2001, oil revenues outside the U.S. totaled 60 percent of consolidated oil revenues, up from 53 percent in 2000. This increase was spread among Egypt, Canada and Australia. Egypt's contribution totaled 27 percent, while Canada and Australia contributed 17 percent and 16 percent, respectively. Natural Gas Contribution The preponderance of consolidated natural gas revenues come from our North American operations. In 2002, 80 percent of Apache's natural gas revenues came from the North American market, 51 percent from the U.S. and 29 percent from Canada. The remaining 20 percent was split between Egypt, 15 percent, and Australia, 5 percent. In 2001, 88 percent of Apache's natural gas revenues came from the North American market, 61 percent from the U.S. and 27 percent from Canada. The remaining natural gas revenues were primarily split between Egypt, 8 percent, and Australia, 3 percent. 25 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, ------------------------------------ 2002 2001 2000 ---------- ---------- ---------- Revenues (in thousands): Natural gas............................................ $1,130,692 $1,521,959 $1,107,486 Oil.................................................... 1,383,749 1,246,384 1,149,028 Natural gas liquids.................................... 45,307 54,616 52,319 ---------- ---------- ---------- Total............................................... $2,559,748 $2,822,959 $2,308,833 ========== ========== ========== Natural Gas Volume -- Mcf per day: United States.......................................... 503,310 615,341 544,703 Canada................................................. 329,344 298,424 130,485 Egypt.................................................. 122,655 95,918 47,464 Australia.............................................. 117,802 116,943 107,894 Argentina.............................................. 7,276 648 -- ---------- ---------- ---------- Total............................................... 1,080,387 1,127,274 830,546 ========== ========== ========== Average Natural Gas Price -- Per Mcf: United States.......................................... $ 3.15 $ 4.15 $ 4.02 Canada................................................. 2.74 3.81 3.65 Egypt.................................................. 3.71 3.51 4.51 Australia.............................................. 1.28 1.22 1.34 Argentina.............................................. .42 1.20 -- Total............................................... 2.87 3.70 3.64 Oil Volume -- Barrels per day: United States.......................................... 53,009 58,501 56,521 Canada................................................. 25,220 25,895 14,720 Egypt.................................................. 43,772 39,238 27,745 Australia.............................................. 30,361 23,548 15,551 Argentina.............................................. 617 117 -- ---------- ---------- ---------- Total............................................... 152,979 147,299 114,537 ========== ========== ========== Average Oil Price -- Per barrel: United States.......................................... $ 25.31 $ 24.39 $ 27.85 Canada................................................. 23.46 19.22 22.25 Egypt.................................................. 24.65 23.59 27.81 Australia.............................................. 25.17 23.89 29.99 Argentina.............................................. 23.90 17.90 -- Total............................................... 24.78 23.18 27.41 NGL Volume -- Barrels per day: United States.......................................... 6,691 7,679 6,030 Canada................................................. 1,756 1,272 1,204 ---------- ---------- ---------- Total............................................... 8,447 8,951 7,234 ========== ========== ========== Average NGL Price -- Per barrel: United States.......................................... $ 15.29 $ 16.60 $ 20.04 Canada................................................. 12.41 17.45 18.36 Total............................................... 14.69 16.72 19.76
26 Natural Gas Revenues Consolidated natural gas revenues declined $391 million in 2002, consistent with an $.83 per Mcf decline in the weighted-average realized price for natural gas and a four percent decline in production. The price decline reduced revenues by $342 million, while lower gas production reduced revenues by another $49 million. A gas production decline of 18 percent was experienced in the U.S., with declines of 21 percent and 13 percent in the Gulf Coast and Central regions respectively. The Gulf Coast region, which contributed 61.5% of Apache's U.S. 2002 production, is characterized by reservoirs which demonstrate high initial rates followed by steep declines when compared to other U.S. producing regions. This attribute coupled with capital curtailments, property sales in late 2001 and back-to-back hurricanes in September and October 2002 contributed to the production decline in the U.S. Collectively, Canada, Egypt, Australia and Argentina saw a 13 percent increase in natural gas production. Canada's increase was the result of previous acquisitions and subsequent drilling activity, coupled with successful results at Ladyfern, which offset natural decline at Zama. Egypt's increase also came from previous acquisitions and subsequent drilling activity. See Note 3 of Item 15 of this 10-K for further discussion of acquisition and divestiture activity. A 36 percent increase in our natural gas production contributed $390 million to 2001 revenues. Canada's increase was primarily driven by our acquisition of producing properties from Phillips Petroleum Company (Phillips) in December 2000 and Fletcher Challenge in March 2001 as well as strong exploration and development results from the Ladyfern area. A full year of production from the properties we acquired from Occidental Petroleum Corporation (Occidental) in August 2000 and Collins & Ware, Inc. (Collins & Ware) in June 2000 helped boost our domestic production by 13 percent, while properties acquired from Repsol helped double our Egyptian production. See Note 3 of Item 15 of this Form 10-K for further discussion of acquisition and divestiture activity. We have used long-term, fixed-price physical contracts to lock in a small portion of our domestic future natural gas production. The contracts provide protection to the Company in the event of decreasing natural gas prices and represented approximately 11 percent of our 2002 and 2001 domestic natural gas production. In 2002, these contracts positively impacted our average realized price by $.01 per Mcf. Historically high prices in the first half of 2001 resulted in a negative impact of $.06 per Mcf in that year. Additionally, substantially all of our natural gas production sold in Australia is subject to long-term fixed-price contracts. Crude Oil Revenues Oil revenues improved $137 million in 2002 with both a higher realized price and higher production. The weighted-average realized price for oil improved $1.60 per barrel, adding $86 million to oil revenues, while oil production gains added another $51 million. The price improvement was across-the-board, while production gains of 29 percent and 12 percent occurred in Australia and Egypt, respectively. The Legendre, Simpson and Gibson/South Plato developments drove Australia's gain, while Egypt's increase was related to the Repsol acquisition and subsequent drilling. U.S. production declined nine percent related to natural decline, back-to-back hurricanes in late September and early October and property sales. See Note 3 of Item 15 of this Form 10-K for further discussion of acquisition and divestiture activity. Our crude oil revenues increased in 2001 despite a 15 percent drop in the average realized price, as crude oil production increased 29 percent. The acquisition and subsequent exploitation of properties acquired from Repsol, in March 2001, contributed to a 41 percent increase in our year-over-year Egyptian production. Strong results on properties acquired from Fletcher Challenge in March 2001 and Phillips in December 2000 helped us increase our Canadian oil production by 76 percent. We also had success on the drilling front, increasing our Australian production by nearly 51 percent with successful development of the Legendre, Gipsy/North Gipsy and Simpson fields. 27 OPERATING EXPENSES The table below presents a detail of our expenses.
YEAR ENDED DECEMBER 31, ------------------------ 2002 2001 2000 ------ ------ ------ (IN MILLIONS) Depreciation, depletion and amortization: Oil and gas property and equipment........................ $ 784 $ 760 $ 548 Other assets.............................................. 60 61 36 International impairments................................... 20 65 -- Lease operating costs....................................... 462 405 254 Gathering and transportation costs.......................... 38 35 19 Severance and other taxes................................... 63 70 59 General and administrative expenses......................... 105 89 76 Financing costs, net........................................ 113 118 106 ------ ------ ------ Total.................................................. $1,645 $1,603 $1,098 ====== ====== ======
Depreciation, Depletion and Amortization Apache's full-cost DD&A expense is driven by many factors including certain costs incurred in the exploration, development, and acquisition of producing reserves, production levels, and estimates of proved reserve quantities and future developmental costs. In 2002, our full-cost DD&A expense increased $24 million. Areas outside the U.S. saw an increase in their expense, while DD&A expense decreased in the U.S. The areas experiencing the largest increase in absolute costs were Egypt, up $29 million and Australia, up $24 million (consistent with their overall increase in production), while the U.S. experienced a $39 million decline in full-cost DD&A expense on lower production levels. Canada also had higher DD&A expense of $7 million relating to higher production levels. On a boe basis our 2002 full-cost DD&A rate rose $.24 to $6.29. The U.S. contributed $.13 to the increase in rate, driven by higher finding costs and higher future development costs. The remaining increase in the consolidated rate is split between Egypt and Australia. The impact from Egypt is related to higher finding and development costs. The impact from Australia is primarily related to higher future development costs. In 2001, our full-cost DD&A expense increased $212 million. The higher expense was spread among Canada, up $87 million, the U.S., up $63 million, Egypt, up $43 million and Australia, up $19 million, which is consistent with their overall increase in production. On a boe basis our 2001 full-cost DD&A rate rose $.30 to $6.05. The U.S. contributed two-thirds to the increase in rate, related to higher finding costs and negative reserve revisions associated with declining prices. Canada contributed $.04 to the increase in the overall rate, reflecting the impact of higher future development costs. Australia also contributed $.04 to the increase in the overall rate, reflecting higher future development costs during 2001. Depreciation on other assets remained flat in 2002 after increasing $25 million in 2001 associated with additional facilities acquired in March 2001 from Fletcher in Canada, and Repsol in Egypt, and the amortization of goodwill. In connection with the adoption of a new accounting principle effective January 1, 2002, we no longer amortize our goodwill. Instead, it is assessed for periodic impairment, as discussed in the impairment section below. Impairments We periodically assess all of our unproved properties for possible impairment based on geological trend analysis, dry holes or relinquishment of acreage. When an impairment occurs, costs associated with these 28 properties are generally transferred to our proved property base where they become subject to amortization. In some of our international exploration plays, however, we have not yet established proved reserves. As such, any impairments in these areas are immediately charged to earnings. During 2001, we impaired a portion of our unproved property costs in Poland and China by $65 million ($41 million after-tax). In 2002, we impaired an additional $20 million in Poland ($12 million after-tax). At December 31, 2002, the Company had $13 million of unproved property costs remaining in Poland. We are continuing to evaluate our operations in Poland, which may result in additional impairments in 2003. Goodwill is subject to a periodic fair-value-based impairment assessment beginning in 2002. Goodwill totals $189 million at December 31, 2002 and no impairment was recorded in 2002. For further discussion, see Note 1 of Item 15 of this Form 10-K. Lease Operating Costs Lease operating costs (LOE) is generally comprised of several components; direct operating costs, repair and maintenance costs, workover costs and ad valorem 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. They enable us to exploit our existing reserves by accelerating production and taking advantage of high pricing environments. Repair and maintenance costs are higher on offshore properties and in areas with plants and facilities. During 2002, LOE was $3.71 per boe, a $.49 increase from 2001. Higher absolute costs accounted for 94 percent, $.46 per boe, of this rate increase, with lower production accounting for the remaining $.03 per boe. We experienced higher absolute costs in the Gulf Coast region, Egypt and Canada. In the Gulf Coast region increased repairs and maintenance, related to both routine operations and hurricane repairs, generally higher costs on properties operated by others on offshore Gulf of Mexico properties and increased workover activity in the region, contributed to higher LOE. In Egypt, higher workover activity on the Khalda, South Umbarka and East Bahariya concessions drove up LOE. In Canada, the increased costs reflect the impact of the Fletcher, Conoco and Burlington acquisitions, which carry higher production costs than our other operations, and increased workover activity, with the heaviest activity at House Mountain, Hatton, Zama and Simonette fields. In 2001, LOE was $3.22 per boe, a $.56 increase from 2000. This increase was driven by our acquisitions of Canadian and offshore Gulf of Mexico oil properties, higher service costs and increased workover activity in the U.S. and Canada. Gathering and Transportation Costs During 2002, the Company adopted Emerging Issues Task Force Issue 00-10, "Accounting for Shipping and Handling Fees and Costs." Prior to adoption, amounts paid to third parties for transportation had been reported as a reduction of revenue instead of an increase in operating expenses. Recent property acquisitions and their associated transportation arrangements have increased the significance of transportation costs paid to third parties. For comparative purposes, previously reported transportation costs paid to third parties were reclassified as corresponding increases to oil and gas production revenues and operating expenses with no impact on income attributable to common stock. These costs are primarily related to the transportation of natural gas in our North American operations. In 2002, the costs totaled $21 million in Canada and $17 million in the U.S., relatively flat to the prior year. In 2001, these costs totaled $19 million in Canada and $16 million in the U.S., up from $12 million in Canada and $8 million in the U.S. The increase over the 2000 period is related to higher volumes subject to such rates, principally from properties acquired from Fletcher in Canada, and Gulf of Mexico properties acquired from Occidental Petroleum Corporation in August 2000. 29 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 2002 and 2001, these severance taxes, which are generally based on a percentage of oil and gas production revenues, represented over 80 percent of the total severance and other taxes expense incurred in each period. The other tax component is primarily made up of the Australian Petroleum Resources Rent Tax (PRRT), to which Apache first became subject in 2002, and the Canadian Large Corporation Tax, Saskatchewan Capital Tax and Saskatchewan Resource Surtax. Oil and gas production revenues generated from Egypt and Canada are not subject to severance taxes. In 2002, severance and other taxes totaled $63 million, comprised of U.S., $35 million, Australia, $23 million and Canada, $5 million. Overall, severance and other taxes decreased $7 million. A $14 million decline in U.S. severance taxes, and a $3 million decline in Canada Saskatchewan Resource Surtax were partially offset by initial PRRT of $4 million and a $7 million increase in Australian severance taxes. The decrease in U.S. severance taxes reflects the impact of lower gas price realizations. The increase in Australia's severance taxes was attributable to higher oil price realizations and a change in production mix as a higher portion of production was from properties in provincial waters, such as Legendre and Harriet, relative to production from federal waters. Canada's decline was primarily related to a refund of the Saskatchewan Resource Surtax. In 2001, severance and other taxes totaled $70 million ($50 million in the U.S., $12 million in Australia and $8 million in Canada). Severance and other taxes increased $11 million from the prior year. The increase related to higher severance taxes in Australia and, collectively, a $3 million increase in Canada's Large Corporation Tax and Saskatchewan Resource Surtax. The increase in Australia's severance taxes was attributable to higher production-driven oil and gas revenues. Canada's increase was related to properties acquired from Fletcher in March 2001 and Phillips Petroleum Company in December 2000. U.S. severance and other taxes were up $2 million over the prior year. Higher production-driven oil and gas revenues and a higher effective production tax rate accounted for the majority of the increase in the U.S. Available incentives granted by the state of Oklahoma decline with rising commodity prices, increasing the effective tax rate. General and Administrative Expenses Overall, general and administrative expenses (G&A) trended higher in 2002, rising $.13 to $.84 per boe. Thirty-eight percent of the increase is tied to rising medical costs, a sharp increase in premiums on business insurance policies renewed subsequent to the September 11, 2001 terrorist attacks and the addition of a sizeable political risk insurance package added in mid-2001. The remaining increase is related to non-recurring employee separation costs, a consequence of our region realignment in the U.S., higher outside legal support costs related to arbitration proceedings with our gas marketer, Cinergy and litigation with Predator (see Note 11 of this Form 10-K), costs associated with the implementation of and compliance with various sections of Sarbanes-Oxley, and a full year of expense related to additional staff and office costs incurred with the acquisition of Canadian subsidiaries of Fletcher during 2001. Realignment of our three U.S. regions into two involved both reassignment and reduction of personnel. All corresponding costs were expensed as incurred. During 2001 absolute G&A increased as the size of our company grew from acquisitions. However, 2001 G&A on an equivalent-barrel basis declined 10 percent from 2000 to $.71 as the incremental production was added at a lower G&A rate. Financing Costs, Net Net financing costs decreased by five percent in 2002. The major components of net financing costs are interest expense and capitalized interest. Lower average debt outstanding during 2002 resulted in a decrease in interest expense of $23 million. A reduction in capitalized interest of $16 million, associated with lower unproved property balances, partially offset this decrease. Net financing costs increased 11 percent in 2001, related to higher average outstanding borrowings coupled with lower capitalized interest, partially offset by lower average effective interest rates. Our weighted-average cost of borrowing on December 31, 2002 was 30 6.3 percent compared to 5.9 percent on December 31, 2001. The rate is higher at year-end 2002 as a lower percentage of our debt is at floating rates, which carry a lower rate than fixed-rate debt. OIL AND GAS CAPITAL EXPENDITURES
YEAR ENDED DECEMBER 31, ---------------------------------- 2002 2001 2000 -------- ---------- ---------- (IN THOUSANDS) Exploration and Development: United States........................................... $302,611 $ 699,180 $ 495,803 Canada.................................................. 258,191 410,345 135,627 Egypt................................................... 171,160 127,603 84,949 Australia............................................... 89,813 85,169 73,835 Other international..................................... 38,409 20,838 18,077 -------- ---------- ---------- $860,184 $1,343,135 $ 808,291 ======== ========== ========== Capitalized Interest...................................... $ 40,691 $ 56,749 $ 62,000 ======== ========== ========== Gas Gathering Transmission and Processing Facilities...... $ 32,155 $ 28,759 $ 121,294 ======== ========== ========== Acquisitions: Oil and gas properties.................................. $351,707 $ 880,286 $1,324,427 Gas gathering, transmission and processing facilities... 2,875 146,295 94,000 Goodwill................................................ -- 197,200 -- -------- ---------- ---------- $354,582 $1,223,781 $1,418,427 ======== ========== ==========
In 2002, Apache added 172.1 MMboe of proved reserves through acquisitions, drilling and revisions, replacing 138 percent of production. The preliminary capital expenditure budget for 2003 is approximately $1.3 billion (excluding acquisitions), including $850 million for North America. Preliminary North American capital expenditures include $350 million in the Gulf Coast region, $100 million in the Central region and $400 million in Canada. The Company has estimated its international capital expenditures in 2003 at $400 million. Capital expenditures will be reviewed periodically, and possibly adjusted throughout the year in light of changing industry conditions. CASH DIVIDEND PAYMENTS Apache paid a total of $13 million in dividends during 2002 on its Series B Preferred Stock issued in August 1998 and its Series C Preferred Stock issued in May 1999. Dividends on the Series C Preferred Stock were paid through May 15, 2002, when the shares automatically converted to common stock (see Note 9, under Item 15 of this Form 10-K). Common dividends paid during 2002 rose 61 percent to $56 million, reflecting the increase in common shares outstanding and the higher common stock dividend rate. The Company has paid cash dividends on its common stock for 36 consecutive years through 2002. Future dividend payments will depend on the Company's level of earnings, financial requirements and other relevant factors. CAPITAL RESOURCES Apache's primary needs for cash are for exploration, development and acquisition of oil and gas properties, repayment of principal and interest on outstanding debt and payment of dividends. The Company funds its exploration and development activities primarily through internally generated cash flows and budgets capital expenditures based on projected cash flows. Apache routinely adjusts capital expenditures in response to changes in oil and natural gas prices, drilling and acquisition costs, and cash flow. The Company has 31 historically utilized net cash provided by operating activities, debt, preferred interests of subsidiaries and equity as capital resources to obtain necessary funding for all other cash needs. NET CASH PROVIDED BY OPERATING ACTIVITIES Apache's net cash provided by operating activities during 2002 totaled $1.4 billion, a decrease of 28 percent from 2001 driven by lower oil and gas production revenues and slightly higher operating expenses. Oil and gas production revenues fell with a 22 percent decline in gas prices, which was partially offset by a seven percent improvement in oil prices. The impact of lower gas production was partially offset by rising oil production. Net cash provided by operating activities during 2001 increased 26 percent to a record $1.9 billion from $1.5 billion in 2000. The primary reason for the increase is attributed to the additional oil and gas revenues from production on properties acquired during 2000 and 2001. DEBT At December 31, 2002, Apache had outstanding debt of $280 million under its commercial paper program and uncommitted lines of credit and a total of $1.9 billion of other debt. This other debt included notes and debentures maturing in the years 2003 through 2096. Based on our current plan for capital spending and projections of debt and interest rates, interest payments on the Company's debt for 2003 are projected to be $157 million (using weighted-average balances for floating rate obligations). On June 3, 2002, Apache entered into a new $1.5 billion global credit facility to replace its existing global and 364-day credit facilities. The new global credit facility consists of four separate bank facilities: a $750 million 364-day facility in the United States; a $450 million five-year facility in the United States; a $150 million five-year facility in Australia; and a $150 million five-year facility in Canada. Loans under the global credit facility do not require the Company to maintain a minimum credit rating. The five-year facilities are scheduled to mature on June 3, 2007 and the 364-day facility is scheduled to mature on June 1, 2003. The 364-day facility allows the Company the option to convert outstanding revolving loans at maturity into one-year term loans. The Company may request extensions of the maturity dates subject to approval of the lenders. Please see Note 6 -- Debt of Item 15 for a summary of the financial covenants of the global credit facility. 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), 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 the debt of entities not within our consolidated group. 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, 2002 and 2001 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. five-year facility and the 364-day facility. If the Company is unable to issue commercial paper following a significant credit downgrade or dislocation in the market, the Company's U.S. five-year credit facility and 364-day credit facility are available as a 100 percent backstop. The weighted-average interest rate for commercial paper was 1.85 percent in 2002 and 4.10 percent in 2001. PREFERRED INTERESTS OF SUBSIDIARIES During 2001, several of our subsidiaries issued a total of $443 million ($441 million, net of issuance costs) of preferred stock and limited partner interests to unrelated institutional investors, adding to the Company's financial liquidity. We pay a weighted-average return to the investors of 123 basis points above the prevailing LIBOR interest rate. These subsidiaries are consolidated in the accompanying financial statements with the $437 million and $441 million at December 31, 2002 and 2001, respectively, reflected as preferred interests of subsidiaries on the balance sheet. 32 STOCK TRANSACTIONS In December 2002, our board of directors declared a five percent stock dividend, payable on April 2, 2003, to shareholders of record on March 12, 2003. No fractional shares will be issued and cash payments will be made in lieu of fractional shares. In connection with the declaration of this stock dividend, a reclassification was made to transfer $396 million from retained earnings to common stock and additional paid-in-capital in the accompanying consolidated balance sheet. On May 15, 2002, we completed the mandatory conversion of our Series C Preferred Stock into approximately 6.6 million (13.1 million shares adjusted for the two-for-one stock split) common shares. In September 2001, our Board of Directors declared a 10 percent stock dividend, which was paid on January 21, 2002, to shareholders of record on December 31, 2001. No fractional shares were issued and cash payments were made in lieu of fractional shares. In connection with the declaration of this stock dividend, a reclassification was made to transfer $545 million from retained earnings to common stock and additional paid-in-capital in the accompanying consolidated balance sheet. On January 22, 2003, we completed a public offering of approximately 9.9 million shares (19.8 million shares adjusted for the two-for-one stock split) of common stock, including 1.3 million shares (2.6 million shares adjusted for the two-for-one stock split) for the underwriters' over-allotment option, for net proceeds of $554 million. LIQUIDITY During 2002, we strengthened our financial flexibility and continued to build upon the solid financial performances of previous years. Cash will be required to fund expenditures necessary to offset the inherent declines in production and proven reserves typical in an extractive industry like ours. Future success in growing reserves and production will be highly dependent on capital resources available and our success in acquiring or finding additional reserves. We believe that cash on hand, net cash generated from operating activities, and unused committed borrowing capacity under our global credit facility will be adequate to satisfy future financial obligations and liquidity needs. Net cash generated from operating activities is a function of commodity prices, which are inherently volatile and unpredictable, production and capital spending. 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, as stated in Item 1, "Risk Factors Related to Our Business and Operations". Based on the year-end reserve life index, the Company's overall decline is approximately nine percent per year. This projection assumes the capital investment, prices, costs and taxes reflected in our standardized measure in Item 15 -- Note 15, of this Form 10-K. Less predictable than production declines from our proved reserves is the impact of constantly changing oil and natural gas prices on cash flows and, therefore, capital budgets. For these reasons, we only forecast, for internal use by management, an annual cash flow. These annual forecasts are revised monthly and capital budgets are reviewed by management and adjusted as warranted by market conditions. Longer term cash flow and capital spending projections are neither developed nor used by management to operate our business. As of December 31, 2002, available borrowing capacity under our global credit facility was $1.2 billion. We had $52 million in cash and cash equivalents on hand at December 31, 2002, an increase from $36 million at the prior year-end. In addition, the ratio of current assets to current liabilities increased from 1.34 at the end of last year to 1.44 at December 31, 2002. In August 2001, we purchased $116 million in U.S. Government Agency Notes and subsequently sold $13 million of the notes in 2001. Of the remaining balance, $17 million were designated as "available for sale" securities and were sold for approximately $17 million in January 2002. The remaining $86 million were designated as "held to maturity" and carried at amortized cost until they matured on October 15, 2002. The sales proceeds were used to pay down on our commercial paper balance. 33 We have assumed 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, preferred interests of subsidiaries, 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, 2002. Please see the indicated Note to the Company's consolidated financial statements, under Item 15 of this Form 10-K for further information regarding these obligations.
NOTE CONTRACTUAL OBLIGATIONS REFERENCE TOTAL 2003 2004 2005 2006 2007 THEREAFTER ----------------------- --------- ---------- -------- ------- ------- ------- -------- ---------- (IN THOUSANDS) Long-term debt........ Note 6 $2,158,815 $ -- $ -- $ 830 $ 274 $489,559 $1,668,152 Preferred interests of subsidiaries........ Note 12 436,626 -- -- -- -- -- 436,626 Operating leases and other commitments... Note 11 310,143 107,234 49,735 33,769 31,158 23,096 65,151 International lease commitments......... Note 11 71,456 40,780 17,099 7,010 6,567 -- -- Exploration agreement........... Note 11 25,000 12,500 12,500 -- -- -- -- Properties acquired requiring future payments to Occidental Petroleum Corporation......... Note 3 20,478 10,609 9,869 -- -- -- -- Operating costs associated with a pre-existing volumetric production payment of acquired properties.......... Note 3 13,879 4,502 3,770 3,047 2,530 30 -- ---------- -------- ------- ------- ------- -------- ---------- Total Contractual Obligations(a)...... $3,036,397 $175,625 $92,973 $44,656 $40,529 $512,685 $2,169,929 ========== ======== ======= ======= ======= ======== ==========
--------------- (a) Note that this table does not include the liability for dismantlement, abandonment and restoration costs of oil and gas properties. The Company currently includes such costs in the amortizable base of its 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 2, under Item 15 of this Form 10-K for further discussion. Apache is also subject to various contingent obligations that become payable only if certain events or rulings were to occur. The inherent uncertainty surrounding the timing of and monetary impact associated with these events or rulings prevents any meaningful accurate measurement, which is necessary to assess any impact on future liquidity. Such obligations include environmental contingencies and potential settlements resulting from litigation. Apache's management feels that it has adequately reserved for its contingent obligations. The Company has reserved approximately $10 million for environmental remediation. The Company's exposure to other contingent liabilities is estimated at less than $8 million and is fully reserved. The Company does not believe it has any material exposure for any contingencies (see Note 11 under Item 15 of this Form 10-K). Upon closing of our acquisition of the North Sea properties, Apache will assume BP's abandonment obligation for those properties and such costs were considered in determining the purchase price. The purchase of the properties, however, does not relieve BP of its liabilities if Apache does not satisfy the abandonment obligation. Although not currently required, to ensure Apache's payments of these costs, Apache agreed to 34 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 obligated to provide a letter of credit, it will expire if either rating agency restores its rating to the present level. The initial letter of credit amount would be $282 million. This amount represents the letter of credit requirement through March 2004, and will be negotiated annually based on Apache's future abandonment obligation estimates. In addition, under Apache's long-term oil physical sales contract with BP, related to the BP acquisition, Apache may be required to post margin if the mark-to-market exposure, as defined, exceeds the credit threshold limits. In addition to the letter of credit requirements covering BP's abandonment obligations, our liquidity could be further impacted by a downgrade of the credit rating for our senior unsecured long-term debt by Standard and Poor's to BBB- or lower and by Moody's to Baa3 or lower; however, we do not believe that such a sharp downgrade is reasonably likely. If our debt were to receive such a downgrade, our subsidiaries that issued the preferred interests could be in violation of their covenants which may require them to redeem some of the preferred interests (see Note 12, under Item 15 of this Form 10-K). In addition, generally under our commodity hedge agreements, Apache may be required to post margin or terminate outstanding positions if the Company's credit ratings decline significantly. OFF-BALANCE SHEET ARRANGEMENTS Apache does not currently utilize any off-balance sheet arrangements with unconsolidated entities to enhance liquidity and capital resource positions, or any other purpose. Any future transactions involving off-balance sheet arrangements will be scrutinized and disclosed by the Company's management. FUTURE TRENDS Apache's strategy is to increase its oil and gas reserves, production, cash flow and earnings through a balanced growth program that involves: - exploiting our existing asset base; - acquiring properties to which we can add incremental value; and - investing in high-potential exploration prospects. Apache's present plans are to increase 2003 worldwide capital expenditures for exploratory and development drilling to approximately $1.3 billion from $860 million in 2002. We will continue to monitor commodity prices and adjust our capital expenditures accordingly. We will also continue to evaluate and pursue acquisition opportunities should they become available at reasonable prices. EXPLOITING EXISTING ASSET BASE Apache seeks to maximize the value of our existing asset base by increasing production and reserves while reducing operating costs per unit. In order to achieve these objectives, we rigorously pursue production enhancement opportunities such as workovers, recompletions and moderate-risk drilling, while divesting marginal and non-strategic properties and identifying other activities to reduce costs. We expended a lot of effort in 2002 identifying exploitation opportunities which, when combined with our South Louisiana property purchase and our acquisition from BP, give us a large inventory at a time of high commodity prices. ACQUIRING PROPERTIES TO WHICH WE CAN ADD INCREMENTAL VALUE Apache seeks to purchase reserves at appropriate prices by generally avoiding auction processes where we are competing against other buyers. Our aim is to follow each acquisition with a cycle of reserve enhancement, property consolidation and cash flow acceleration, facilitating asset growth and debt reduction. Exorbitant acquisition prices caused Apache to sideline its 2002 acquisition activities early in the year until appropriate opportunities arose at reasonable prices, which began at the end of the year. 35 INVESTING IN HIGH-POTENTIAL EXPLORATION PROSPECTS Apache seeks to concentrate its exploratory investments in a select number of international areas and to become the dominant operator in those regions. We believe that these investments, although generally higher-risk, offer potential for attractive investment returns and significant reserve additions. Our international investments and exploration activities are a significant component of our long-term growth strategy. They complement our North American operations, which are more development oriented. A critical component in implementing our three-pronged growth strategy is maintenance of significant financial flexibility. All three rating agencies recently reaffirmed "A-credit ratings" on Apache's senior unsecured long-term debt, a testament to our conservative financial structure and commitment to preserving a strong balance sheet while building a solid foundation and competitive advantage with which to pursue our growth initiatives. 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 ranged from a low of $18.85 per barrel to a high of $28.79 per barrel during 2002. Average gas price realizations ranged from a monthly low of $2.11 per Mcf to a monthly high of $3.62 per Mcf during the same period. Based on the Company's 2002 worldwide oil production levels, a $1.00 per barrel change in the weighted-average realized price of oil would increase or decrease revenues by $56 million. Based on the Company's 2002 worldwide gas production levels, a $.10 per Mcf change in the weighted-average realized price of gas would increase or decrease revenues by $39 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 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 Notes 3 and 4, under Item 15 of this Form 10-K, the Company entered into several derivative positions in conjunction with the South Louisiana acquisition in December 2002 and following year-end, with the acquisition from BP. 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 hedged at anticipated production. At December 31, 2002, the Company had natural gas commodity collars with a negative fair value of $4 million. A 10 percent increase in gas prices would change the fair values of the gas collars by $(5) million. A 10 percent decrease in gas prices would change the fair values of the gas collars by $5 million. The model 36 used to arrive at the fair values for the commodity collars is based on a third-party option pricing model. Changes in fair value, assuming 10 percent price changes, assume non-constant volatility with volatility based on prevailing market parameters at December 31, 2002. The natural gas and crude oil fixed-price swaps and crude oil fixed-price physical contracts entered into during the first quarter 2003 involved substantially more oil and gas volumes than the 2002 collars. For additional detail on our 2003 derivative positions, see Notes 3 and 4 of Item 15 of this Form 10-K. We sell all of our Egyptian crude oil and natural gas to the EGPC for U.S. dollars. Deteriorating economic conditions in Egypt during 2001 and 2002 have lessened the availability of U.S. dollars resulting in a one to two month delay in receipts from EGPC. Continuation of the hard currency shortage in Egypt could lead to further delays, deferrals of payment or non-payment in the future. INTEREST RATE RISK Approximately 85 percent of the Company's debt is issued at fixed interest rates, minimizing the Company's exposure to fluctuations in short-term interest rates. At December 31, 2002, the Company had $317 million of floating-rate debt and $437 million of preferred interests of subsidiaries, both of which are subject to fluctuations in short-term interest rates. A 10 percent change in the floating interest rate (approximately 22 basis points) on these year-end balances, would be approximately $2 million. The Company did not have any open derivative contracts relating to interest rates at December 31, 2002 or 2001. 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. Australian gas production is sold under fixed-price Australian dollar contracts and over half the costs incurred are paid in Australian dollars. Revenue and disbursement transactions denominated in Australian dollars 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. This unrealized adjustment was 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 dollar will result in a foreign currency net loss of approximately $31 million. The Company did not have any open derivative contracts relating to foreign currencies at December 31, 2002, or 2001. 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, 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, 37 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-54 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 year ended December 31, 2002, included in this report, have been audited by Ernst & Young LLP, independent public auditors, as stated in their audit report appearing herein. The financial statements for the fiscal years ended December 31, 2001, and December 31, 2000, included in this report, have been audited by Arthur Andersen LLP, independent public accountants, as stated in their audit report appearing herein. Arthur Andersen has not consented to the inclusion of their audit report in this report. For a discussion of the risks relating to Arthur Andersen's audit of our financial statements, please see "Risks relating to Arthur Andersen LLP" in Item 1. Arthur Andersen's audit reports on our consolidated financial statements for each of the fiscal years ended December 31, 2001, and December 31, 2000, included elsewhere in this report, did not contain an adverse opinion or disclaimer of opinion, nor were they qualified or modified as to uncertainty, audit scope or accounting principles. During the years ended December 31, 2001 and December 31, 2000, and through the date we dismissed Arthur Andersen LLP, there were no disagreements with Arthur Andersen on any matter of accounting principle or practice, financial statement disclosure, or auditing scope or procedure which, if not resolved by Arthur Andersen's satisfaction, would have caused them to make reference to the subject matter in connection with their report on our consolidated financial statements for such years; and there were no reportable events as set forth in applicable SEC regulations. We provided Arthur Andersen LLP with a copy of the above disclosures on April 2, 2002. In a letter dated April 2, 2002, Arthur Andersen confirmed its agreement with these statements. 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 2003 annual meeting of stockholders (the Proxy Statement) is incorporated herein by reference. ITEM 11. EXECUTIVE COMPENSATION The information set forth under the captions "Summary Compensation Table", "Option/SAR Exercises and Year-End Value 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. 38 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. 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 within the last 90 days preceding the date of this report. Based on that review and as of the date of that evaluation, these officers found the company's disclosure controls to be adequate, providing effective means to insure that we timely and accurately disclose the information we are required to disclose under applicable laws and regulations. We also made no significant changes in internal controls or any other factors that could affect our internal controls since our most recent internal controls evaluation. 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. 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 Auditors.............................. F-2 Reports of independent public accountants................... F-4 Statement of consolidated operations for each of the three years in the period ended December 31, 2002............... F-5 Statement of consolidated cash flows for each of the three years in the period ended December 31, 2002............... F-6 Consolidated balance sheet as of December 31, 2002 and 2001...................................................... F-7 Statement of consolidated shareholders' equity for each of the three years in the period ended December 31, 2002..... F-8 Notes to consolidated financial statements.................. F-9
2. Financial Statement Schedules Financial statement schedules have been omitted because they are either not required, not applicable or the information required to be presented is included in the Company's financial statements and related notes. 39 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, 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, filed January 13, 2003, SEC File No. 1-4300). 3.1 -- Restated Certificate of Incorporation of Registrant, dated December 16, 1999, as filed with the Secretary of State of Delaware on December 17, 1999 (incorporated by reference to Exhibit 99.1 to Registrant's Current Report on Form 8-K, filed February 7, 2000, SEC File No. 1-4300). 3.2 -- Bylaws of Registrant, as amended May 2, 2002 (incorporated by reference to Exhibit 3.1 to Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, 2002, 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 Annual Report on Form 10-K for year ended December 31, 1995, 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, filed August 25, 1998, to Registrant's Current Report on Form 8-K, filed August 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, filed May 12, 1999, to Registrant's Current Report on Form 8-K, 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 -- Credit Agreement, dated June 12, 1997, among Registrant, the lenders named therein, Morgan Guaranty Trust Company, as Global Documentation Agent and U.S. Syndication Agent, The First National Bank of Chicago, as U.S. Documentation Agent, NationsBank of Texas, N.A., as Co-Agent, Union Bank of Switzerland, Houston Agency, as Co-Agent, and The Chase Manhattan Bank, as Global Administrative Agent (incorporated by reference to Exhibit 10.1 to Registrant's Current Report on Form 8-K, filed June 25, 1997, SEC File No. 1-4300). 10.2 -- 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).
40
EXHIBIT NO. DESCRIPTION ------- ----------- 10.3 -- 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). 10.4 -- Credit Agreement, dated June 12, 1997, among Apache Canada Ltd., a wholly-owned subsidiary of the Registrant, the Lenders named therein, Morgan Guaranty Trust Company, as Global Documentation Agent, Royal Bank of Canada, as Canadian Documentation Agent, The Chase Manhattan Bank of Canada, as Canadian Syndication Agent, Bank of Montreal, as Canadian Administrative Agent, and The Chase Manhattan Bank, as Global Administrative Agent (incorporated by reference to Exhibit 10.2 to Registrant's Current Report on Form 8-K, filed June 25, 1997, 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 -- Credit Agreement, dated June 12, 1997, among Apache Energy Limited and Apache Oil Australia Pty Limited, wholly-owned subsidiaries of the Registrant, the Lenders named therein, Morgan Guaranty Trust Company, as Global Documentation Agent, Bank of America National Trust and Savings Association, Sydney Branch, as Australian Documentation Agent, The Chase Manhattan Bank, as Australian Syndication Agent, Citisecurities Limited, as Australian Admin- istrative Agent, and The Chase Manhattan Bank, as Global Administrative Agent (incorporated by reference to Exhibit 10.3 to Registrant's Current Report on Form 8-K, filed June 25, 1997, SEC File No. 1-4300). 10.7 -- 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, NA, 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). 10.8 -- 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). 10.9 -- 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).
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EXHIBIT NO. DESCRIPTION ------- ----------- 10.10 -- 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). 10.11 -- 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). 10.12 -- 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). 10.13 -- 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). 10.14 -- 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). +10.15 -- 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). +10.16 -- 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). +10.17 -- 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). +**10.18 -- Amendment to Apache Corporation 401(k) Savings Plan, dated January 27, 2003, effective as January 1, 2003. +10.19 -- 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). +**10.20 -- Amendment to Apache Corporation Money Purchase Retirement Plan, dated January 27, 2003, effective as of January 1, 2003. +10.21 -- Non-Qualified Retirement/Savings Plan of Apache Corporation, restated as of January 1, 1997, and amendments effective as of 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). +10.22 -- Amendment to Non-Qualified Retirement/Savings Plan of Apache Corporation, dated February 22, 2000, effective as of 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 Post-Effective Amendment No. 1 to Registrant's Registration Statement on Form S-8, Registration No. 333-31092, filed August 18, 2000).
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EXHIBIT NO. DESCRIPTION ------- ----------- +10.23 -- Amendment to Non-Qualified Retirement/Savings Plan of Apache Corporation, dated August 3, 2001, effective as of 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). +10.24 -- 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, as amended by Form 10-Q/A, for the quarter ended September 30, 2001, SEC File No. 1-4300). +**10.26 -- Apache Corporation 2000 Share Appreciation Plan, as amended and restated February 5, 2003, effective as of March 12, 2003. +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 -- 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). +10.31 -- 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). +10.32 -- Apache Corporation Deferred Delivery Plan, as amended and restated December 18, 2002, effective as of May 2, 2002 (incorporated by reference o 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). +10.33 -- Apache Corporation Executive Restricted Stock Plan, as amended and restated December 18, 2002, effective as of 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). +10.34 -- Apache Corporation Non-Employee Directors' Compensation Plan, as amended and restated December 17, 1998 (incorporated by reference to Exhibit 10.26 to Registrant's Annual Report on Form 10-K for year ended December 31, 1998, SEC File No. 1-4300). +10.35 -- 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). +10.36 -- Apache Corporation Equity Compensation Plan for Non-Employee Directors, as amended and restated May 3, 2001 (incorporated by reference to Exhibit 10.09 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 -- 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).
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EXHIBIT NO. DESCRIPTION ------- ----------- +10.38 -- 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). +10.39 -- 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). +10.40 -- 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). +10.41 -- 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). 10.42 -- 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, filed June 23, 1998, SEC File No. 1-4300). 10.43 -- Deed of Guaranty and Indemnity, dated January 11, 2003, made by Registrant in favor of BP Exploration Operating Company Limited (incorporated by reference to Exhibit 10.1 to Regis- trant's Current Report on Form 8-K, 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 **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. ** Previously filed. + 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. 44 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this amended 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: January 23, 2004 POWER OF ATTORNEY Pursuant to the requirements of the Securities Exchange Act of 1934, this amended 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 January 23, 2004 -------------------------------------- Executive Officer and Chief G. Steven Farris Operating Officer (Principal Executive Officer) /s/ ROGER B. PLANK Executive Vice President and January 23, 2004 -------------------------------------- Chief Financial Officer Roger B. Plank (Principal Financial Officer) /s/ THOMAS L. MITCHELL Vice President and Controller January 23, 2004 -------------------------------------- (Principal Accounting Officer) Thomas L. Mitchell * Chairman of the Board January 23, 2004 -------------------------------------- Raymond Plank * Director January 23, 2004 -------------------------------------- Frederick M. Bohen * Director January 23, 2004 -------------------------------------- Randolph M. Ferlic * Director January 23, 2004 -------------------------------------- Eugene C. Fiedorek * Director January 23, 2004 -------------------------------------- A. D. Frazier, Jr.
NAME TITLE DATE ---- ----- ---- * Director January 23, 2004 -------------------------------------- Patricia Albjerg Graham * Director January 23, 2004 -------------------------------------- John A. Kocur * Director January 23, 2004 -------------------------------------- George D. Lawrence * Director January 23, 2004 -------------------------------------- F. H. Merelli * Director January 23, 2004 -------------------------------------- Rodman D. Patton * Director January 23, 2004 -------------------------------------- Charles J. Pitman * Director January 23, 2004 -------------------------------------- Jay A. Precourt *By /s/ ROGER B. PLANK January 23, 2004 ------------------------------ Roger B. Plank Attorney-in-Fact
REPORT OF MANAGEMENT The financial statements and related financial information of Apache Corporation and subsidiaries were prepared by and are the responsibility of management. The statements have been 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 maintains and places reliance on systems of internal control designed to provide reasonable assurance, weighing the costs with the benefits sought, that all transactions are properly recorded in the Company's books and records, that policies and procedures are adhered to, and that assets are safeguarded. The systems of internal controls are supported by written policies and guidelines, internal audits and the selection and training of qualified personnel. The consolidated financial statements of Apache Corporation and subsidiaries have been audited by the independent auditors, Ernst & Young LLP for 2002 and Arthur Andersen LLP for 2001 and 2000. Their audits included developing an overall understanding of the Company's accounting systems, procedures and internal controls and conducting tests and other auditing procedures sufficient to support their opinion on the fairness of the consolidated financial statements. The Apache Corporation Board of Directors exercises its oversight responsibility for the financial statements through its Audit Committee, composed solely of outside directors who are not current employees of Apache or who have not been employees of Apache within the past ten years. The Audit Committee meets periodically with management, internal auditors and the independent auditors to ensure that they are successfully completing designated responsibilities. The internal auditors and independent auditors have open access to the Audit Committee to discuss auditing and financial reporting issues. Houston, Texas March 14, 2003 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) F-1 REPORT OF INDEPENDENT AUDITORS To the Shareholders of Apache Corporation: We have audited the accompanying consolidated balance sheet of Apache Corporation (a Delaware corporation) and subsidiaries as of December 31, 2002 and the related consolidated statements of operations, shareholders' equity, and cash flows for the year then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit. The financial statements of Apache Corporation as of December 31, 2001, and for each of the two years in the period then ended, were audited by other auditors who have ceased operations and whose report dated March 12, 2002 expressed an unqualified opinion on those financial statements before the adjustments described in Note 1. Their report, however, had an explanatory paragraph indicating that the Company, as described in Note 1 to the consolidated financial statements, changed its method of accounting for crude oil inventories effective January 1, 2000, and as discussed in Notes 1 and 4 to the consolidated financial statements changed its method of accounting for derivative instruments effective January 1, 2001. We conducted our audit in accordance with auditing standards generally accepted in the 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 consolidated financial statements referred to above present fairly, in all material respects, the financial position of Apache Corporation and subsidiaries as of December 31, 2002 and the results of their operations and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United States. As discussed above, the financial statements of Apache Corporation as of December 31, 2001, and for each of the two years in the period then ended, were audited by other auditors who have ceased operations. As described in Note 1, these financial statements have been revised to reflect third party gathering and transportation costs as an operating cost instead of a reduction of revenues as previously reported. We audited the adjustments described in Note 1 that were applied to revise the 2001 and 2000 consolidated statement of operations. As described in Note 1, in 2002 the Company's Board of Directors approved a five percent stock dividend, and all references to number of shares and per share information in the financial statements have been adjusted to reflect the stock dividend on a retroactive basis. We audited the adjustments that were applied to restate the number of shares and per share information reflected in the 2002 financial statements. Our procedures included (a) agreeing the authorization for the five percent stock dividend to the Company's underlying records obtained from management, and (b) testing the mathematical accuracy of the restated number of shares, basic and diluted earnings per share. In our opinion, such adjustments are appropriate and have been properly applied. However, we were not engaged to audit, review, or apply any procedures to the 2001 and 2000 financial statements of Apache Corporation other than with respect to such adjustments and the adjustments described below related to the two-for-one stock split; accordingly, we do not express an opinion or any other form of assurance on the 2001 and 2000 financial statements taken as a whole. Since the date of completion of our audit of the financial statements and initial issuance of our report thereon dated March 14, 2003, as described in Note 1, the Company's Board of Directors approved a two-for-one stock split distributed in the form of a stock dividend, and all references to number of shares and per share information in the financial statements have been adjusted to reflect the stock split on a retroactive basis. As discussed above, the financial statements of Apache Corporation as of December 31, 2001, and for each of the two years in the period then ended, were audited by other auditors who have ceased operations. We audited the adjustments that were applied to restate the number of shares and per share information reflected in the 2002 financial statements. Our procedures included (a) agreeing the authorization for the two-for-one stock split to the Company's underlying records obtained from Management, and (b) testing the mathematical accuracy of the restated number of shares, basic and diluted earnings per share. In our opinion, such F-2 adjustments are appropriate and have been properly applied. However, we were not engaged to audit, review, or apply any procedures to the 2001 and 2000 financial statements of Apache Corporation other than with respect to such adjustments and the adjustments described in the preceding paragraph relating to the five percent stock dividend and, accordingly, we do not express an opinion or any other form of assurance on the 2001 and 2000 financial statements taken as a whole. ERNST & YOUNG LLP Houston, Texas March 14, 2003 Except for the two-for-one stock split discussed in Note 1 and the Statement of Financial Accounting Standards No. 141 and 142 disclosure discussed in Note 1 for which the date is January 16, 2004. F-3 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Shareholders of Apache Corporation: We have audited the accompanying consolidated balance sheet of Apache Corporation (a Delaware corporation) and subsidiaries as of December 31, 2001 and 2000, and the related consolidated statements of operations, shareholders' equity, and cash flows for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Apache Corporation and subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States. As discussed in Note 1 to the consolidated financial statements, effective January 1, 2000, the Company changed its method of accounting for crude oil inventories. In addition, as discussed in Notes 1 and 4 to the consolidated financial statements, effective January 1, 2001, the Company changed its method of accounting for derivative instruments. ARTHUR ANDERSEN LLP Houston, Texas March 12, 2002 THIS IS A COPY OF AN ACCOUNTANTS' REPORT PREVIOUSLY ISSUED BY ARTHUR ANDERSEN LLP, AND HAS NOT BEEN REISSUED BY ARTHUR ANDERSEN. SEE ITEM 9 OF THIS FORM 10-K FOR FURTHER INFORMATION. F-4 APACHE CORPORATION AND SUBSIDIARIES STATEMENT OF CONSOLIDATED OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, --------------------------------------------- 2002 2001 2000 ------------- ------------- ------------- (IN THOUSANDS, EXCEPT PER COMMON SHARE DATA) REVENUES AND OTHER: Oil and gas production revenues........................ $2,559,748 $2,822,959 $2,308,833 Other.................................................. 125 (13,568) (6,855) ---------- ---------- ---------- 2,559,873 2,809,391 2,301,978 ---------- ---------- ---------- OPERATING EXPENSES: Depreciation, depletion and amortization............... 843,879 820,831 583,546 International impairments.............................. 19,600 65,000 -- Lease operating costs.................................. 462,124 404,814 253,709 Gathering and transportation costs..................... 38,567 34,584 19,616 Severance and other taxes.............................. 63,088 69,827 59,173 General and administrative............................. 104,588 88,710 75,615 Financing costs: Interest expense.................................... 155,667 178,915 168,121 Amortization of deferred loan costs................. 1,859 2,460 2,726 Capitalized interest................................ (40,691) (56,749) (62,000) Interest income..................................... (4,002) (5,864) (2,209) ---------- ---------- ---------- 1,644,679 1,602,528 1,098,297 ---------- ---------- ---------- PREFERRED INTERESTS OF SUBSIDIARIES...................... 16,224 7,609 -- ---------- ---------- ---------- INCOME BEFORE INCOME TAXES............................... 898,970 1,199,254 1,203,681 Provision for income taxes............................. 344,641 475,855 483,086 ---------- ---------- ---------- INCOME BEFORE CHANGE IN ACCOUNTING PRINCIPLE............. 554,329 723,399 720,595 Cumulative effect of change in accounting principle, net of income tax................................... -- -- (7,539) ---------- ---------- ---------- NET INCOME............................................... 554,329 723,399 713,056 Preferred stock dividends.............................. 10,815 19,601 19,988 ---------- ---------- ---------- INCOME ATTRIBUTABLE TO COMMON STOCK...................... $ 543,514 $ 703,798 $ 693,068 ========== ========== ========== BASIC NET INCOME PER COMMON SHARE: Before change in accounting principle.................. $ 1.83 $ 2.44 $ 2.57 Cumulative effect of change in accounting principle.... -- -- (.03) ---------- ---------- ---------- $ 1.83 $ 2.44 $ 2.54 ========== ========== ========== DILUTED NET INCOME PER COMMON SHARE: Before change in accounting principle.................. $ 1.80 $ 2.37 $ 2.49 Cumulative effect of change in accounting principle.... -- -- (.03) ---------- ---------- ---------- $ 1.80 $ 2.37 $ 2.46 ========== ========== ==========
The accompanying notes to consolidated financial statements are an integral part of this statement. F-5 APACHE CORPORATION AND SUBSIDIARIES STATEMENT OF CONSOLIDATED CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31, --------------------------------------- 2002 2001 2000 ----------- ----------- ----------- (IN THOUSANDS) CASH FLOWS FROM OPERATING ACTIVITIES: Net income................................................ $ 554,329 $ 723,399 $ 713,056 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion and amortization................ 843,879 820,831 583,546 Provision for deferred income taxes..................... 137,672 305,214 350,703 Amortization of deferred loan costs..................... 1,859 2,460 2,726 International impairments............................... 19,600 65,000 -- Cumulative effect of change in accounting principle, net of income tax......................................... -- -- 7,539 Other................................................... 9,531 10,469 9,719 Changes in operating assets and liabilities, net of effects of acquisitions: (Increase) decrease in receivables...................... (122,830) 199,160 (253,721) (Increase) decrease in advances to oil and gas ventures and other............................................. (26,116) (14,474) (6,167) (Increase) decrease in product inventory................ 717 (3,005) 722 (Increase) decrease in deferred charges and other....... 496 (922) 5,967 Increase (decrease) in payables......................... 32,219 (143,969) 111,841 Increase (decrease) in accrued expenses................. (16,595) 10,065 33,263 Increase (decrease) in advances from gas purchasers..... (14,574) (13,079) (27,850) Increase (decrease) in deferred credits and noncurrent liabilities........................................... (39,469) (56,149) (13,976) ----------- ----------- ----------- NET CASH PROVIDED BY OPERATING ACTIVITIES............. 1,380,718 1,905,000 1,517,368 ----------- ----------- ----------- CASH FLOWS FROM INVESTING ACTIVITIES: Additions to property and equipment....................... (1,037,368) (1,528,984) (955,576) Acquisition of Louisiana properties....................... (258,885) -- -- Acquisition of Fletcher subsidiaries, net of cash acquired................................................ -- (465,018) -- Acquisition of Repsol properties, net of cash acquired.... -- (446,933) (118,678) Acquisition of Phillips properties........................ -- -- (490,250) Acquisition of Occidental properties...................... (11,000) (11,000) (321,206) Acquisition of Collins & Ware properties.................. -- -- (320,682) Proceeds from sales of oil and gas properties............. 7,043 348,296 26,271 Proceeds from (purchase of ) short-term investments, net..................................................... 101,723 (103,863) -- Other, net................................................ (37,520) (76,835) (36,875) ----------- ----------- ----------- NET CASH USED IN INVESTING ACTIVITIES................. (1,236,007) (2,284,337) (2,216,996) ----------- ----------- ----------- CASH FLOWS FROM FINANCING ACTIVITIES: Long-term borrowings...................................... 1,467,929 2,759,740 1,125,981 Payments on long-term debt................................ (1,553,471) (2,733,641) (793,531) Dividends paid............................................ (68,879) (54,492) (52,945) Preferred stock activity.................................. -- -- (2,613) Common stock activity..................................... 30,708 10,205 465,306 Treasury stock activity, net.............................. 1,991 (42,959) (17,730) Cost of debt and equity transactions...................... (6,728) (1,718) (838) Proceeds from preferred interests of subsidiaries......... -- 440,654 -- ----------- ----------- ----------- NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES... (128,450) 377,789 723,630 ----------- ----------- ----------- NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS........ 16,261 (1,548) 24,002 CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR.............. 35,625 37,173 13,171 ----------- ----------- ----------- CASH AND CASH EQUIVALENTS AT END OF YEAR.................... $ 51,886 $ 35,625 $ 37,173 =========== =========== ===========
The accompanying notes to consolidated financial statements are an integral part of this statement. F-6 APACHE CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEET
DECEMBER 31, ------------------------- 2002 2001 ----------- ----------- (IN THOUSANDS) ASSETS CURRENT ASSETS: Cash and cash equivalents................................. $ 51,886 $ 35,625 Receivables, net of allowance............................. 527,687 404,793 Inventories............................................... 109,204 102,536 Drilling advances......................................... 45,298 26,438 Prepaid assets and other.................................. 32,706 25,407 Short-term investments.................................... -- 102,950 ----------- ----------- 766,781 697,749 ----------- ----------- PROPERTY AND EQUIPMENT: Oil and gas, on the basis of full cost accounting: Proved properties....................................... 12,827,459 11,390,692 Unproved properties and properties under development, not being amortized.................................... 656,272 839,921 Gas gathering, transmission and processing facilities..... 784,271 748,675 Other..................................................... 194,685 168,915 ----------- ----------- 14,462,687 13,148,203 Less: Accumulated depreciation, depletion and amortization............................................ (5,997,102) (5,135,131) ----------- ----------- 8,465,585 8,013,072 ----------- ----------- OTHER ASSETS: Goodwill, net............................................. 189,252 188,812 Deferred charges and other................................ 38,233 34,023 ----------- ----------- $ 9,459,851 $ 8,933,656 =========== =========== LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES: Accounts payable.......................................... $ 214,288 $ 179,778 Accrued operating expense................................. 47,382 50,584 Accrued exploration and development....................... 146,871 175,943 Accrued compensation and benefits......................... 32,680 30,947 Accrued interest.......................................... 30,880 28,592 Accrued income taxes...................................... 44,256 40,030 Other..................................................... 15,878 16,584 ----------- ----------- 532,235 522,458 ----------- ----------- LONG-TERM DEBT.............................................. 2,158,815 2,244,357 ----------- ----------- DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES: Income taxes.............................................. 1,120,609 991,723 Advances from gas purchasers.............................. 125,453 140,027 Oil and gas derivative instruments........................ 3,507 -- Other..................................................... 158,326 175,925 ----------- ----------- 1,407,895 1,307,675 ----------- ----------- PREFERRED INTERESTS OF SUBSIDIARIES......................... 436,626 440,683 ----------- ----------- COMMITMENTS AND CONTINGENCIES (Note 11) 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 Series C, 6.5% Conversion Preferred Stock, 138,482 shares issued and outstanding for 2001................. -- 208,207 Common stock, $0.625 par, 430,000,000 shares authorized, 310,929,080 and 296,460,766 shares issued, respectively............................................ 194,331 185,288 Paid-in capital........................................... 3,427,450 2,803,825 Retained earnings......................................... 1,427,607 1,336,478 Treasury stock, at cost, 8,422,656 and 8,544,090 shares, respectively............................................ (110,559) (111,885) Accumulated other comprehensive loss...................... (112,936) (101,817) ----------- ----------- 4,924,280 4,418,483 ----------- ----------- $ 9,459,851 $ 8,933,656 =========== ===========
The accompanying notes to consolidated financial statements are an integral part of this statement. F-7 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, 1999.................. $98,387 $ 210,490 $168,057 $1,694,474 $ 558,721 Comprehensive income (loss): Net income................................ $713,056 -- -- -- -- 713,056 Currency translation adjustments.......... (31,389) -- -- -- -- -- Marketable securities..................... (397) -- -- -- -- -- -------- Comprehensive income........................ $681,270 ======== Cash dividends: Preferred................................. -- -- -- -- (19,658) Common ($.09 per share)................... -- -- -- -- (25,258) Preferred stock repurchased................. -- (2,283) -- -- (330) Common shares issued........................ -- -- 14,579 453,771 -- Treasury shares purchased, net.............. -- -- -- 428 -- ------- --------- -------- ---------- ---------- BALANCE AT DECEMBER 31, 2000.................. 98,387 208,207 182,636 2,148,673 1,226,531 Comprehensive income (loss): Net income................................ $723,399 -- -- -- -- 723,399 Currency translation adjustments.......... (74,028) -- -- -- -- -- Commodity hedges.......................... 12,136 -- -- -- -- -- Marketable securities..................... 307 -- -- -- -- -- -------- Comprehensive income........................ $661,814 ======== Cash dividends: Preferred................................. -- -- -- -- (19,601) Common ($.17 per share)................... -- -- -- -- (48,980) Ten percent common stock dividend........... -- -- -- 544,848 (544,871) Common shares issued........................ -- -- 2,652 109,086 -- Treasury shares purchased, net.............. -- -- -- 1,218 -- ------- --------- -------- ---------- ---------- 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 ======= ========= ======== ========== ========== ACCUMULATED OTHER TOTAL TREASURY COMPREHENSIVE SHAREHOLDERS' STOCK INCOME (LOSS) EQUITY --------- ------------- ------------- (IN THOUSANDS) BALANCE AT DECEMBER 31, 1999.................. $ (52,256) $ (8,446) $2,669,427 Comprehensive income (loss): Net income................................ -- -- 713,056 Currency translation adjustments.......... -- (31,389) (31,389) Marketable securities..................... -- (397) (397) Comprehensive income........................ Cash dividends: Preferred................................. -- -- (19,658) Common ($.09 per share)................... -- -- (25,258) Preferred stock repurchased................. -- -- (2,613) Common shares issued........................ -- -- 468,350 Treasury shares purchased, net.............. (17,306) -- (16,878) --------- --------- ---------- BALANCE AT DECEMBER 31, 2000.................. (69,562) (40,232) 3,754,640 Comprehensive income (loss): Net income................................ -- -- 723,399 Currency translation adjustments.......... -- (74,028) (74,028) Commodity hedges.......................... -- 12,136 12,136 Marketable securities..................... -- 307 307 Comprehensive income........................ Cash dividends: Preferred................................. -- -- (19,601) Common ($.17 per share)................... -- -- (48,980) Ten percent common stock dividend........... -- -- (23) Common shares issued........................ -- -- 111,738 Treasury shares purchased, net.............. (42,323) -- (41,105) --------- --------- ---------- BALANCE AT DECEMBER 31, 2001.................. (111,885) (101,817) 4,418,483 Comprehensive income (loss): Net income................................ -- -- 554,329 Currency translation adjustments.......... -- 5,328 5,328 Commodity hedges.......................... -- (16,322) (16,322) Marketable securities..................... -- (125) (125) Comprehensive income........................ Cash dividends: Preferred................................. -- -- (10,815) Common ($.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 ========= ========= ==========
The accompanying notes to consolidated financial statements are an integral part of this statement. F-8 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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 78 percent of the Company's proved reserves are located in North America. Internationally, Apache has exploration and production interests in Egypt, offshore Western Australia and in Argentina, a development project underway offshore The People's Republic of China (China) that is expected to commence production in 2003 and exploration interests 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. Stock Split -- On September 11, 2003, the Company's board of directors declared a two-for-one common stock split which was distributed on January 14, 2004 to shareholders of record on December 31, 2003. Stock Dividends -- On September 13, 2001, the Company's Board of Directors declared a 10 percent stock dividend payable on January 21, 2002 to shareholders of record on December 31, 2001. As a result, the Company reclassified approximately $545 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. No fractional shares were issued and cash payments totaling $891,000 were made in lieu of fractional shares. 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. No fractional shares will be issued and cash payments will be made in lieu of fractional shares. All share and per share information in these financial statements and notes thereto have been restated to reflect both the 10 percent and five percent stock dividends, and the two-for-one stock split. 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. 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 of which the Company is the operator. 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 typically collected within two months. In Egypt, however, the Company has experienced a gradual decline in the timeliness of receipts from the Egyptian General Petroleum Corporation (EGPC). Deteriorating economic conditions during 2001 and 2002 in Egypt have lessened the availability of U.S. dollars, resulting in an additional one to two month delay in receipts from F-9 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) EGPC. Continuation of the hard currency shortage in Egypt could lead to further delays, deferrals of payment or non-payment in the future. 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, 2002 and 2001, the Company had an allowance for doubtful accounts of $31 million and $24 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 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. Exclusive of field-level costs, Apache capitalized $22 million, $20 million and $23 million of these internal costs in 2002, 2001 and 2000, 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, are added to the amortizable base. These future costs are generally estimated by engineers employed by Apache. Beginning in 2003, Apache changed its method of accounting for dismantlement, restoration and abandonment costs (see Note 2.) 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 to additional DD&A expense. Included in the estimated future net cash flows are Canadian provincial tax credits expected to be realized beyond the date at F-10 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) which the legislation, under its provisions, could be repealed. To date, the Canadian provincial governments have not indicated an intention to repeal this legislation. Please see Note 15 "Future Net Cash Flows" for a discussion on calculation of estimated future net cash flows. 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. Unproved properties that are individually insignificant are generally amortized over an average holding period. For international operations where a reserve base has not yet been established, the impairment is charged to earnings. During 2002, the Company recorded approximately $20 million ($12 million after tax) in impairments of unproved property costs in Poland. The Company will continue to evaluate its operations in Poland, which may result in additional impairments in 2003. During 2001, the Company recorded a $65 million ($41 million after tax) impairment of unproved property costs in China and Poland. The Company has taken note of a July 2003 inquiry to the Financial Accounting Standards Board regarding whether or not contract-based oil and gas mineral rights held by lease or contract ("mineral rights") should be recorded or disclosed as intangible assets. The inquiry presents a view that these mineral rights are intangible assets as defined in SFAS No. 141, "Business Combinations," and, therefore, should be classified separately on the balance sheet as intangible assets. SFAS No. 141, and SFAS No. 142, "Goodwill and Other Intangible Assets," became effective for transactions subsequent to June 30, 2001 with the disclosure requirements of SFAS No. 142 required as of January 1, 2002. SFAS No. 141 requires that all business combinations initiated after June 30, 2001 be accounted for using the purchase method and that intangible assets be disaggregated and reported separately from goodwill. SFAS No. 142 established new accounting guidelines for both finite lived intangible assets and indefinite lived intangible assets. Under the statement, intangible assets should be separately reported on the face of the balance sheet and accompanied by disclosure in the notes to financial statements. SFAS No. 142 scopes out accounting utilized by the oil and gas industry as prescribed by SFAS No. 19, and is silent about whether or not its disclosure provisions apply to oil and gas companies. Apache does not believe that SFAS No. 141 or 142 change the classification of oil and gas mineral rights and the Company continues to classify these assets as part of oil and gas properties. The Emerging Issues Task Force (EITF) has added the treatment of oil and gas mineral rights to an upcoming agenda, which may result in a change in how Apache classifies these assets. Should such a change be required, the amounts related to business combinations and major asset purchases after June 30, 2001 that would be classified as "intangible undeveloped mineral interest" was $9 million and $78 million as of December 31, 2001 and December 31, 2002, respectively. The amounts related to business combinations and major asset purchases after June 30, 2001 that would be classified as "intangible developed mineral interest" was $88 million and $332 million as of December 31, 2001 and December 31, 2002, respectively. Intangible developed mineral interest amounts are presented net of accumulated depletion, depreciation and amortization (DD&A). Accumulated DD&A was estimated using historical depletion rates applied proportionately to the costs of the acquisitions to be classified as "intangible developed mineral interest". The amounts noted above only include mineral rights acquired in business combinations or major asset purchases, and exclude those acquired individually or in groups as we have not historically tracked these in this manner. The Company has also not historically tracked the amount of mineral rights in the proved property balances related to producing leases or relinquished leases. We are currently identifying a methodology to do so for transactions subsequent to June 30, 2001. F-11 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The numbers above are based on our understanding of the issue before the EITF, if all mineral rights associated with unevaluated property and producing reserves were deemed to be intangible assets: - mineral rights with proved reserves that were acquired after June 30, 2001 and mineral rights with no proved reserves would be classified as intangible assets and would not be included in oil and gas properties on our consolidated balance sheet; - results of operations and cash flows would not be materially affected because mineral rights would continue to be amortized in accordance with full cost accounting rules; and - disclosures required by SFAS Nos. 141 and 142 relative to intangibles would be included in the notes to our financial statements. If the accounting for mineral rights is ultimately changed, transitional guidance for intangible assets permits the reclassification of only amounts acquired after the effective date of SFAS Nos. 141 and 142 if records were not previously maintained to track acquisition costs based on their intangible or tangible nature. Lack of these records prior to the effective date could result in the loss of comparability between historical balances of tangible and intangible asset balances and among companies in the industry. 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 $240 million and $182 million at December 31, 2002 and 2001, respectively. Goodwill -- The Company adopted SFAS No. 142 "Goodwill and Other Intangible Assets" effective January 1, 2002. SFAS No. 142 addresses financial accounting and reporting for acquired goodwill and other intangible assets and supersedes Accounting Principles Board (APB) Opinion No. 17 "Intangible Assets." As a result of this pronouncement, goodwill is no longer subject to amortization. Rather, 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. Goodwill totaled $189 million at December 31, 2002, 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) acquisitions, adjusted for currency fluctuations. Approximately $103 million and $86 million of goodwill was recorded in Canada and Egypt, respectively, because Apache deemed the geographic areas to be the reporting unit. Apache has recognized no impairment of goodwill as of December 31, 2002. Had the principles of SFAS No. 142 been applied to prior years, goodwill amortization of $7 million ($4 million after tax) expensed during 2001 would not have been incurred. Income attributable to common stock for the comparative period, adjusted to exclude the effect of goodwill amortization, would have increased diluted earnings per share by $.01. Accounts Payable -- Included in accounts payable at both December 31, 2002 and 2001, are liabilities of approximately $37 million 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. Apache uses the sales method of accounting for gas production imbalances. Apache uses the sales method of accounting for natural gas revenues. Under this method, revenues are recognized based on actual volumes of gas sold to purchasers. 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 estimated remaining reserves will not be sufficient to enable the underproduced owner to recoup its entitled share through production. In both years ended December 31, 2002 and 2001, the Company recorded liabilities of $4 million for gas imbalances, which are reflected in other non- F-12 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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. Adjustments for gas imbalances totaled less than one percent of Apache's proved gas reserves at December 31, 2002, 2001 and 2000. Cash received relating to future revenues is deferred and recognized when all revenue recognition criteria are met. 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. Derivative Instruments and Hedging Activities -- Apache periodically enters into commodity derivative contracts to manage its exposure to oil and gas price volatility. Commodity derivative contracts, which are usually placed with major financial institutions that the Company believes are minimal credit risks, may take the form of futures contracts, swaps or options. The oil and gas reference prices upon which these 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. Effective January 1, 2001, Apache adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended. SFAS No. 133, as amended, establishes accounting and reporting standards requiring that all derivative instruments be recorded in the balance sheet as either an asset or liability measured at fair value (which is generally based on information obtained from independent parties) and 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 cash flow hedges, including terminated contracts, are generally recognized in oil and gas production revenues when the forecasted transaction occurs. If at any time the likelihood of occurrence of a hedged forecasted transaction ceases to be "probable," hedge accounting 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 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 in other revenue (losses) in the statement of consolidated operations. Upon adoption, Apache formally documented and designated all hedging relationships and verified that its hedging instruments were effective in offsetting changes in actual prices received by the Company. Prior to the adoption of SFAS No. 133, as amended, derivative instruments were not reflected as derivative assets and liabilities and, therefore, had no carrying value. The contracts designated as hedges qualified and continue to qualify for hedge accounting in accordance with SFAS No. 133, as amended. Income Taxes -- Oil and gas exploration and production is a global business. As a result, Apache is subject to taxation on our income in numerous jurisdictions. The Company records deferred tax assets and liabilities to account for the expected future tax consequences of events that have been recognized in its financial statements and tax returns. Apache routinely assesses the realizability of its deferred tax assets. If the Company concludes 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. The Company considers future taxable income in making such assessments. Numerous judgments and assumptions are F-13 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) inherent in the 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 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. In respect to the U.S. dollar denominated debt issued by our Canadian subsidiaries, the Company believes any deferred tax asset generated because of fluctuations in the U.S./Canadian dollar exchange rates is not realizable and, consequently, no deferred tax asset should be recognized. Any potential future deferred tax liabilities will be recognized as appropriate. 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, the 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. Transaction gains and losses are recognized in Revenues and Other. 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. Net Income Per Common Share -- Basic net income per common share is computed by dividing income attributable to common stock by the weighted-average number of common shares outstanding during the period. Diluted net income per common share reflects the potential dilution that could occur 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, Series C (Series C Preferred Stock) was 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. These potentially dilutive securities are excluded from the computation of dilutive earnings per share when their effect is antidilutive. Contingently issuable shares under the 2000 Share Appreciation Plan (Share Appreciation Plan) will be excluded from the calculation of income per common share until the stated goals are met (see Note 9). Stock-Based Compensation -- At December 31, 2002, the Company had several stock-based employee compensation plans, which are defined and described more fully in Note 9. The Company accounts for those plans under the recognition and measurement principles of APB Opinion No. 25, "Accounting for Stock Issued to Employees," and related interpretations. Under this method, the Company records no compensation expense for stock options granted when the exercise price of those options is equal to or greater than the market price of the Company's common stock on the date of grant, unless the awards are subsequently modified. The following table illustrates the effect on income attributable to common stock and earnings per share if the Company had applied the fair value recognition provisions of SFAS No. 123, "Accounting for F-14 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Stock-Based Compensation," as amended, to stock-based employee compensation for the Stock Option Plans, the Performance Plan, and the Share Appreciation Plan.
FOR THE YEAR ENDED DECEMBER 31, --------------------------------- 2002 2001 2000 --------- --------- --------- (IN THOUSANDS) Income attributable to Common Stock, as reported..... $543,514 $703,798 $693,068 Add: Stock-based employee compensation expense included in reported net income, net of related tax effects............................................ 751 -- -- Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards (see Note 9), net of related tax effects............................................ (20,494) (22,463) (13,212) -------- -------- -------- Pro forma Income Attributable to Common Stock........ $523,771 $681,335 $679,856 ======== ======== ======== Net Income per Common Share: Basic: As reported..................................... $ 1.83 $ 2.44 $ 2.54 Pro forma....................................... $ 1.76 $ 2.37 $ 2.49 Diluted: As reported..................................... $ 1.80 $ 2.37 $ 2.46 Pro forma....................................... $ 1.74 $ 2.29 $ 2.41
The effects of applying SFAS No. 123, as amended, in this pro forma disclosure should not be interpreted as being indicative of future effects. SFAS No. 123, as amended, does not apply to awards prior to 1995, and the extent and timing of additional future awards cannot be predicted. 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 15). Treasury Stock -- The Company follows the weighted-average-cost method of accounting for treasury stock transactions. Change in Accounting Principle -- In December 2000, the staff of the Securities and Exchange Commission (SEC) announced that commodity inventories should be carried at cost, not market value. As a result, Apache changed its accounting for crude oil inventories in the fourth quarter of 2000, retroactive to the beginning of the year, and recognized a non-cash cumulative-effect charge to earnings effective January 1, 2000 of $8 million, net of income tax, to value crude oil inventory at cost. Reclassifications -- To comply with the consensus reached on Emerging Issues Task Force Issue 00-10, "Accounting for Shipping and Handling Fees and Costs," third party gathering and transportation costs have F-15 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) been reported as an operating cost instead of a reduction of revenues as previously reported. Reclassifications have been made to reflect this change in prior period statements of consolidated operations. 2. NEW ACCOUNTING PRONOUNCEMENTS In 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. This statement requires companies to record the present value of obligations associated with the retirement of tangible long-lived assets in the period in which it is incurred. The liability is capitalized as part of the related long-lived asset's carrying amount. Over time, accretion of the liability is recognized as an operating expense and the capitalized cost is depreciated over the expected useful life of the related asset. The Company's asset retirement obligations relate primarily to the plugging dismantlement, removal, site reclamation and similar activities of its oil and gas properties. Prior to adoption of this statement, such obligations were accrued ratably over the productive lives of the assets through its depreciation, depletion and amortization for oil and gas properties without recording a separate liability for such amounts. Effective January 1, 2003, the Company adopted SFAS No. 143 which will result in an increase to net oil and gas properties of $410 million and additional liabilities related to asset retirement obligations of $369 million. These entries reflect the asset retirement obligation of Apache had the provisions of SFAS No. 143 been applied since inception. This will result in a non-cash cumulative-effect increase to earnings of $27 million ($41 million pretax). The cumulative increase to earnings did not take into consideration potential impacts of adopting SFAS 143 on previous full-cost property impairment tests. SFAS 143 is silent with respect to whether prior period ceiling tests should be reflected in the implementation entry calculation and Management believes that any impairment on the properties should only be reflected for future periods. A ceiling test calculation, however, was performed at the end of each reporting period subsequent to the adoption of this statement and no impairment was necessary. The cumulative increase to earnings did not take into consideration potential impacts of adopting SFAS No. 143 on previous full-cost property impairment tests. Management chose not to re-calculate historical full-cost impairment tests upon adoption even though historical oil and gas property balances would have been higher had we 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 impairment test periods. Had we re-calculated the historical full-cost impairment 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, however, was performed upon adoption and at the end of each reporting period subsequent to adoption of this statement and no impairment was necessary. In November 2002, the FASB issued Interpretation No. 45 "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others." This Interpretation elaborates on the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under certain guarantees that it has issued. It also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. The initial recognition and initial measurement provisions of this Interpretation are applicable on a prospective basis to guarantees issued or modified after December 31, 2002, irrespective of the guarantor's fiscal year-end. The Company adopted this pronouncement upon the FASB's issuance and the implementation had no impact on the consolidated financial statements. In January 2003, the FASB issued Interpretation No. 46, "Consolidation of Variable Interest Entities, an Interpretation of Accounting Research Bulletin No. 51." Interpretation No. 46 requires a company to consolidate a variable interest entity (VIE) if the company has a variable interest (or combination of variable interests) that is exposed to a majority of the entity's expected losses if they occur, receive a majority of the F-16 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) entity's expected residual returns if they occur, or both. In addition, more extensive disclosure requirements apply to the primary and other significant variable interest owners of the VIE. This interpretation applies immediately to VIEs created after January 31, 2003, and to VIEs in which an enterprise obtains an interest after that date. It is also effective for the first fiscal year or interim period beginning after June 15, 2003, to VIEs in which a company holds a variable interest that is acquired before February 1, 2003. The guidance regarding this interpretation is extremely complex and, although we do not believe we have an interest in a VIE, the Company continues to assess the impact, if any, this interpretation will have on the Company's consolidated financial statements. 3. ACQUISITIONS AND DIVESTITURES 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 million barrels of oil equivalent (MMboe), 88 percent of which is natural gas, from a private company. The acquisition includes 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 will actively generate prospects on certain South Louisiana acreage for a total cost of $25 million over a two-year period. (See Note 11.) In 2002, the Company also completed other acquisitions for cash consideration totaling $95 million. These acquisitions added approximately 19.5 MMboe to the Company's proved reserves. In March 2001, Apache completed the acquisition of substantially all of Repsol's oil and gas concession interests in Egypt for approximately $447 million in cash, subject to normal post closing adjustments. The properties included interests in seven Western Desert concessions and had estimated proved reserves of 66 MMboe as of the acquisition date. The Company already held interests in five of the seven concessions. In March 2001, Apache completed the acquisition of subsidiaries of Fletcher for approximately $465 million in cash and 1.9 million (3.8 million shares adjusted for the two-for-one stock split) restricted shares of Apache common stock issued to Shell Overseas Holdings (valued at $52.85 per share ($26.43 per share adjusted for the two-for-one stock split)), subject to normal post closing adjustments. The transaction included properties located primarily in Canada's Western Sedimentary Basin. Estimated proved reserves totaled 120.8 MMboe as of the acquisition date. Apache assumed a liability of $103 million representing the fair value of derivative instruments and fixed-price commodity contracts entered into by Fletcher. The Fletcher and Repsol 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:
FLETCHER REPSOL --------- -------- (IN THOUSANDS) Value of properties acquired, including gathering and transportation facilities................................. $ 571,718 $299,933 Goodwill.................................................... 107,200 90,000 Derivative instruments and fixed-price contracts............ (103,486) -- Common stock issued......................................... (100,325) -- Working capital acquired, net............................... (2,846) 57,000 Notes assumed............................................... (5,356) -- Deferred income tax liability............................... (1,887) -- --------- -------- Cash paid, net of cash acquired............................. $ 465,018 $446,933 ========= ========
F-17 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) In August 2001, Apache completed the acquisition of properties located in Texas, Oklahoma and New Mexico with estimated proved reserves of 9.2 MMboe as of the acquisition date for approximately $53 million in cash and the assumption of certain liabilities, representing the fair value of derivative instruments of $9 million, subject to normal post-closing adjustments. In November 2001, Apache completed the acquisition of all of Novus Bukha Limited's (Novus) oil and gas concession interests in Egypt for approximately $66 million in cash. The acquisition included estimated proved reserves of approximately 11.7 MMboe as of the acquisition date. The properties included interests in three Western Desert concessions, in which Apache previously held an interest. In 2001, the Company also completed other acquisitions for cash consideration totaling $44 million. These acquisitions added approximately 4.9 MMboe to the Company's proved reserves. In January 2000, Apache completed the acquisition of producing properties in Western Oklahoma and the Texas Panhandle, formerly owned by a subsidiary of Repsol, for approximately $119 million, plus assumed liabilities of approximately $30 million. The properties were subject to an existing volumetric production payment, which burdens future production from the acquired properties. The $30 million assumed liability represents the estimated operating costs associated with the volumetric production payment. The acquisition included estimated proved reserves of approximately 28.7 MMboe, which was net of the 8.4 MMboe production payment as of the acquisition date. In June 2000, Apache completed the acquisition of long-lived producing properties in the Permian Basin and South Texas from Collins & Ware, Inc. (Collins & Ware) for approximately $321 million. The acquisition included estimated proved reserves of approximately 83.7 MMboe as of the acquisition date. One-third of the reserves were liquid hydrocarbons. In August 2000, Apache completed the acquisition of a Delaware limited liability company (LLC) owned by subsidiaries of Occidental Petroleum Corporation (Occidental) and related natural gas production for approximately $321 million including a discounted liability of $37 million, as of the acquisition date, representing the present value of future payments of approximately $44 million over four years. The remaining discounted liability at December 31, 2002 was $20 million. The Occidental properties are located in 32 fields on 93 blocks on the Outer Continental Shelf of the Gulf of Mexico. The acquisition included estimated proved reserves of approximately 53.1 MMboe as of the acquisition date. In December 2000, Apache completed the acquisition of Canadian properties from Canadian affiliates of Phillips Petroleum Company (Phillips) for approximately $490 million. The acquisition included estimated proved reserves of approximately 70.0 MMboe as of the acquisition date. The properties comprise approximately 212,000 net developed acres and 275,000 net undeveloped acres, 786 square miles of 3-D seismic and 4,155 miles of 2-D seismic located in the Zama area of Northwest Alberta. The assets also include three sour gas plants with a total capacity of 150 million cubic feet per day (MMcf/d), 13 compressor stations and 150 miles of owned and operated gas gathering lines. In 2000, the Company also completed other acquisitions for cash consideration totaling $104 million. These acquisitions added approximately 18.3 MMboe to the Company's proved reserves. The following unaudited pro forma information shows the effect on the Company's consolidated results of operations as if the Fletcher and Repsol transactions occurred on January 1, 2001, and the Collins & Ware, Occidental and Phillips acquisitions occurred on January 1, 2000. The pro forma information includes only F-18 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) significant acquisitions and numerous assumptions, and is not necessarily indicative of future results of operations:
FOR THE YEAR ENDED DECEMBER 31, 2000 --------------------------------------------------- 2001 2000 ------------------------ ------------------------ AS REPORTED PRO FORMA AS REPORTED PRO FORMA ----------- ---------- ----------- ---------- (UNAUDITED) (IN THOUSANDS, EXCEPT PER COMMON SHARE DATA) Revenues............................. $2,809,391 $2,916,346 $2,301,978 $3,090,248 Net income........................... 723,399 748,976 713,056 908,974 Preferred stock dividends............ 19,601 19,601 19,988 19,988 Income attributable to common stock.............................. 703,798 729,375 693,068 888,986 Net income per common share: Basic.............................. $ 2.44 $ 2.52 $ 2.54 $ 3.08 Diluted............................ 2.37 2.45 2.46 2.98 Average common shares outstanding.... 288,014 288,900 272,530 288,810
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. PENDING ACQUISITIONS On January 13, 2003, Apache announced the acquisition of producing properties in the U.K. North Sea and the Gulf of Mexico, with estimated proved reserves of 233.2 MMboe, from BP p.l.c. (BP), for $1.3 billion, subject to normal closing adjustments, with an effective date of January 1, 2003. Approximately two-thirds of the reserves are in the North Sea's Forties oil field, establishing a new international operating region for the Company. Apache will become field operator with a 97 percent working interest. 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 our senior unsecured debt is lowered by both Moody's and Standard and Poor's from the Company's current ratings of A- and A3, respectively. Additionally, Apache has hedged a portion of Forties production at fixed prices (see Note 4) and will create a defined benefit pension plan for certain employees (see Note 11). The Gulf of Mexico properties are located offshore Texas and Louisiana, where the Company has substantial existing operations. The assets comprise 113 total blocks and 61 fields and 70 percent of the production is operated. Apache will acquire a 100 percent working interest in 19 of the fields. The Gulf of Mexico segment of the transaction closed March 13, 2003 and the North Sea segment is expected to close early in the second quarter. The Company is financing the acquisition with a combination of internally generated funds, previously issued equity and debt. DIVESTITURES In 2002, Apache sold marginal properties containing 1.8 MMboe of proved reserves, for $7 million. Apache used the sales proceeds to reduce bank debt. During 2001, Apache sold marginal properties, primarily in North America, containing 88 MMboe of proved reserves, for $348 million. Apache used the proceeds to reduce bank debt. During 2000, Apache sold proprietary rights to certain Canadian seismic data and various non-strategic oil and gas properties, collecting cash of $26 million. F-19 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 4. DERIVATIVE INSTRUMENTS AND FIXED-PRICE PHYSICAL CONTRACTS Apache uses a variety of strategies to manage its exposure to fluctuations in commodity prices. Primarily, the company enters into cash flow hedges in connection with certain acquisitions. 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 2002 Derivative Activity -- As part of the South Louisiana properties acquired in December 2002, Apache entered into, and designated as a cash flow hedge, natural gas option agreements to establish floor and ceiling prices on anticipated future natural gas production. As of December 31, 2002, the Company had the following natural gas volumes hedged through natural gas options:
TOTAL WEIGHTED FAIR VALUE PRODUCTION OPTION VOLUMES AVERAGE ASSET/ PERIOD TYPE (MMBTU) FLOOR/CEILING (LIABILITY) ---------- ------- ---------- ------------- -------------- (IN THOUSANDS) 2003 Collars 13,750,000 $3.50/6.09 $ (859) 2004 Collars 18,300,000 3.25/5.81 (1,921) 2005 Collars 9,050,000 3.25/5.20 (727)
The fair value of derivative assets and liabilities recorded for the Company's hedging activity represents the market value of the natural gas options as of December 31, 2002. The hedging activity had no impact on natural gas revenues during 2002. There was no material ineffectiveness associated with the cash flow hedges during the period the options were outstanding. 2001 Unwind -- Prior to Apache's derivative activity during 2002, the Company had historically entered into derivative positions divided into three general categories: (1) Apache's hedging activity, (2) derivatives assumed in acquisitions (Acquired Contracts), and (3) advances from gas purchasers. Driven by the uncertainty of how the collapse of Enron Corp. could have impacted the derivative markets, Apache closed all of its derivative positions and certain fixed-price physical contracts during October and November 2001, receiving proceeds of approximately $62 million (referred to as the "Unwind"). Upon adoption of SFAS No. 133 on January 1, 2001, or as of the acquisition date in the case of the Acquired Contracts, the fair value of Apache's derivative instruments was:
APACHE HEDGING ACQUIRED ADVANCES FROM GAS ACTIVITY CONTRACTS PURCHASER (JANUARY 1, 2001) (ACQUISITION DATE) (JANUARY 1, 2001) ----------------- ------------------ ----------------- (IN THOUSANDS) Commodity derivatives instruments.... $(116,229) $ (98,557) $ 121,453 Fixed-price physical contracts....... -- (14,085) (121,453) --------- --------- --------- $(116,229) $(112,642) $ -- ========= ========= =========
At the time SFAS 133 was implemented, natural gas prices were approaching record highs. Although Apache was realizing higher prices on its un-hedged production, the fair value of the Company's cash flow hedges was out-of-the-money by approximately $116 million ($71 million, net of income tax). This unrealized loss was reflected as a charge to other comprehensive income. Throughout the year, commodity prices were trending downward. As a result, Apache realized only $40 million of this loss during the year. In connection with the Unwind, the Company closed out the rest of these open positions and received cash proceeds of $8 million. These proceeds will be recognized in earnings as the original hedged production occurs. As of December 31, 2002, $3 million remains to be recognized in 2003. The Company also uses long-term, fixed-price physical contracts to lock in a portion of its natural gas production at a given price. In the Unwind, the Company received approximately $13 million to terminate F-20 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) contracts with certain counterparties. Since the Company has no continuing performance obligations under the contracts, the amount was recognized as a gain in Revenues and Other in 2001. In addition to the cash flow hedges the Company entered into, Apache assumed $113 million of derivative and physical contracts in connection with two acquisitions. Because these derivatives were out-of-the-money when the Company acquired them, the liability was factored into the consideration paid to the sellers (see Note 3). Since commodity prices generally decreased after the acquisitions, Apache was able to settle this liability in the Unwind for only $67 million, including $37 million paid to terminate the remaining open positions. As a result, Apache recognized a gain of $32 million during 2001, and $14 million during 2002. As of December 31, 2002, a loss of $527,000 remains and will be recognized in 2003 and 2004. Effective January 1, 2001, Apache recognized a derivative asset of $121 million reflecting the fair value of gas price swaps entered into in connection with certain advance payments received from gas purchasers in 1998 and 1997. Apache also recognized a derivative liability of $121 million reflecting the fair value of an embedded fixed price physical contract. The net effect of these transactions resulted in Apache delivering natural gas to the advance purchasers at prevailing market prices. Apache terminated the gas price swaps in the Unwind, receiving proceeds of $78 million. These proceeds will be recognized into earnings over the remaining life of the contracts and effectively increase the original contract's fixed prices by approximately 51 percent. Upon termination, Apache designated the remaining contractual volumes of gas that will be delivered to the purchaser as a normal, fixed-price physical contract. See Note 8 for additional information on the advances from gas purchasers. Apache 2003 Derivative Activity -- Subsequent to year end and in conjunction with the BP acquisition, Apache entered into several derivative transactions in order to preserve the Company's financial position in a period of cyclically high gas and oil prices. The Company entered into the following natural gas and crude oil fixed-price swaps:
NATURAL GAS FIXED-PRICE SWAPS (NYMEX) CRUDE OIL FIXED-PRICE SWAPS (NYMEX) --------------------------------------- ---------------------------------------- PRODUCTION TOTAL VOLUMES AVERAGE PRODUCTION TOTAL VOLUMES AVERAGE PERIOD (MMBTU) FIXED PRICE PERIOD (BARRELS) FIXED PRICE ---------- ------------- ----------- ---------- ------------- ----------- 2003 61,675,000 $5.19 2003 16,700,000 $26.59 2004 51,240,000 4.52 2004 1,550,000 26.59
Although the fixed-price swaps are settled at NYMEX, the Company's hedged forecasted sales are based on pricing at different locations. The Company believes the hedging relationships are highly effective; however, Apache entered into separate natural gas basis swap contracts to fix a portion of the sales price differential. Apache designated all of the natural gas and crude oil fixed-price swaps and basis swaps as cash flow hedges of anticipated sales. In addition to the fixed-price swaps, Apache entered into a separate crude oil physical sales contract with BP.
CRUDE OIL FIXED-PRICE PHYSICAL CONTRACTS (BRENT) -------------------------------------------------- PRODUCTION TOTAL VOLUMES AVERAGE PERIOD (MMBTU) FIXED PRICE ---------- ------------- ----------- 2003 8,350,000 $25.32 2004 14,175,000 22.24
5. SHORT-TERM INVESTMENTS In August 2001, Apache purchased $116 million in U.S. Government Agency Notes. The Company subsequently sold $13 million of the notes in 2001. Of the remaining balance, $17 million were designated as "available for sale" securities and were sold for approximately $17 million in January 2002. Approximately F-21 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) $86 million were designated as "held to maturity" and carried at amortized cost. These notes paid interest at rates from 6.25 percent to 6.375 percent and matured on October 15, 2002. 6. DEBT LONG-TERM DEBT
DECEMBER 31, ----------------------- 2002 2001 ---------- ---------- (IN THOUSANDS) Apache: Money market lines of credit.............................. $ 8,900 $ 1,600 Global credit facility -- U.S. ........................... -- 100,000 Commercial paper.......................................... 271,400 530,700 9.25-percent notes due 2002, net of discount.............. -- 99,974 6.25-percent debentures due 2012, net of discount......... 397,307 -- 7-percent notes due 2018, net of discount................. 148,446 148,391 7.625-percent notes due 2019, net of discount............. 149,134 149,109 7.7-percent notes due 2026, net of discount............... 99,660 99,655 7.95-percent notes due 2026, net of discount.............. 178,614 178,595 7.375-percent debentures due 2047, net of discount........ 148,009 148,003 7.625-percent debentures due 2096, net of discount........ 149,175 149,175 ---------- ---------- 1,550,645 1,605,202 ---------- ---------- Subsidiary and other obligations: Money market lines of credit.............................. -- 1,196 Global credit facility -- Canada.......................... -- 30,000 Fletcher notes............................................ 5,356 5,356 Apache Finance Australia 6.5-percent notes due 2007, net of discount............................................ 169,260 169,137 Apache Finance Australia 7-percent notes due 2009, net of discount............................................... 99,535 99,478 Apache Finance Canada 7.75-percent notes due 2029, net of discount............................................... 297,019 296,988 Apache Clearwater notes due 2003.......................... 37,000 37,000 ---------- ---------- 608,170 639,155 ---------- ---------- Total debt.................................................. 2,158,815 2,244,357 Less: current maturities.................................... -- -- ---------- ---------- Long-term debt.............................................. $2,158,815 $2,244,357 ========== ==========
In April 2002, the Company issued $400 million principal amount, $397 million net of discount, of senior unsecured 6.25-percent notes maturing on April 15, 2012. The notes are redeemable, as a whole or in part, at Apache's option, subject to a make-whole premium. The proceeds were used to repay a portion of the Company's outstanding commercial paper and for general corporate purposes. On June 3, 2002, Apache entered into a new $1.5 billion global credit facility to replace its existing global and 364-day credit facilities. The new global credit facility consists of four separate bank facilities: a $750 million 364-day facility in the United States (364-day facility); a $450 million five-year facility in the United States (U.S. five-year facility); a $150 million five-year facility in Australia; and a $150 million five-year facility in Canada. The financial covenants of the global credit facility require the Company to: F-22 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (i) maintain a consolidated tangible net worth, plus the aggregate amount of any non-cash write-downs, of at least $2.3 billion as of December 31, 2002, adjusted for subsequent earnings, (ii) maintain an aggregate book-value for assets of Apache and certain subsidiaries, as defined, on an unconsolidated basis of at least $2 billion as of December 31, 2002, and (iii) maintain a ratio of debt to capitalization of not greater than 60 percent at the end of any fiscal quarter. The Company was in compliance with all financial covenants at December 31, 2002. The five-year facilities are scheduled to mature on June 3, 2007 and the 364-day facility is scheduled to mature on June 1, 2003. The 364-day facility allows the Company the option to convert outstanding revolving loans at maturity into one-year term loans. The Company may request extensions of the maturity dates subject to approval of the lenders. At the Company's option, the interest rate 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. In addition, the U.S. five-year facility allows the Company the option to borrow under competitive auctions. At December 31, 2002, the margin over LIBOR for committed loans was .30 percent on the five-year facilities and .32 percent on the 364-day facility. If the total amount of the loans borrowed under all of the 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 a quarterly facility fee of .10 percent on the total amount of each of the five-year facilities and .08 percent on the total amount of the 364-day facility. The facility fees vary based upon the Company's senior long-term debt rating. The U.S. five-year facility and the 364-day facility are used to support Apache's commercial paper program. The available borrowing capacity under the global credit facility at December 31, 2002 was $1.2 billion. At December 31, 2002, 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 $9 million was outstanding as of December 31, 2002. Such borrowings are 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 available borrowing capacity under the U.S. five-year facility and the 364-day facility. 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, 2002 and 2001 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. five-year facility and the 364-day facility. The weighted average interest rate for commercial paper was 1.85 percent in 2002 and 4.10 percent in 2001. The 9.25-percent notes matured June 1, 2002 and were repaid using commercial paper. These notes were classified as long-term debt at December 31, 2001, in the accompanying consolidated balance sheet as the Company had the ability and intent to refinance such amount on a long-term basis through available borrowing capacity under the global credit facility and 364-day facility. 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 and the Apache Finance Australia 6.5-percent notes due 2007, mentioned below) 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 Corporation (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. In the case of the 6.5-percent F-23 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) notes, Apache Finance Australia may also redeem the notes at its option subject to a make-whole premium (see Note 17). In August 2001, Apache Clearwater, Inc. (Apache Clearwater), a subsidiary of Apache, issued $37 million of senior floating rate notes, which mature August 9, 2003. The notes bear interest at a rate equal to three-month LIBOR plus 1.05 percent and are redeemable at the Company's discretion. The balance is 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 available borrowing capacity under the U.S. five-year facility and the 364-day facility. The $14 million of discounts on the Company's debt at December 31, 2002, is being amortized over the life of the debt issuances as additional interest expense. As of December 31, 2002 and 2001, the Company had approximately $19 million and $14 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. AGGREGATE MATURITIES OF DEBT
(IN THOUSANDS) 2003........................................................ $ -- 2004........................................................ -- 2005........................................................ 830 2006........................................................ 274 2007........................................................ 489,559 Thereafter.................................................. 1,668,152 ---------- $2,158,815 ==========
The Company made cash payments for interest, net of amounts capitalized, of $99 million, $105 million and $93 million for the years ended December 31, 2002, 2001 and 2000, respectively. 7. INCOME TAXES Income before income taxes is composed of the following:
FOR THE YEAR ENDED DECEMBER 31, ---------------------------------- 2002 2001 2000 -------- ---------- ---------- (IN THOUSANDS) United States..................................... $286,840 $ 605,392 $ 654,136 Foreign........................................... 612,130 593,862 549,545 -------- ---------- ---------- Total........................................... $898,970 $1,199,254 $1,203,681 ======== ========== ==========
F-24 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The total provision for income taxes consists of the following:
FOR THE YEAR ENDED DECEMBER 31, --------------------------------- 2002 2001 2000 --------- --------- --------- (IN THOUSANDS) Current taxes: Federal............................................ $ 25,657 $ 19,054 $ 12,000 State.............................................. 1,564 4,995 -- Foreign............................................ 179,748 146,592 120,383 Deferred taxes....................................... 137,672 305,214 350,703 -------- -------- -------- Total.............................................. $344,641 $475,855 $483,086 ======== ======== ========
A reconciliation of the U.S. federal statutory income tax amounts to the effective amounts is shown below:
FOR THE YEAR ENDED DECEMBER 31, --------------------------------- 2002 2001 2000 --------- --------- --------- (IN THOUSANDS) Statutory income tax................................. $314,639 $419,739 $421,288 State income tax, less federal benefit............... 7,171 15,135 9,650 Effect of foreign operations......................... 35,283 38,890 52,354 Realized tax basis in investment..................... (16,321) (1,350) -- All other, net....................................... 3,869 3,441 (206) -------- -------- -------- $344,641 $475,855 $483,086 ======== ======== ========
The net deferred tax liability is comprised of the following:
DECEMBER 31, ----------------------- 2002 2001 ---------- ---------- (IN THOUSANDS) Deferred tax assets: Deferred income........................................... $ (1,120) $ (3,744) Federal net operating loss carryforwards.................. (40,700) (2,462) State net operating loss carryforwards.................... (16,436) (13,469) Statutory depletion carryforwards......................... (5,652) -- Alternative minimum tax credits........................... (13,836) (14,472) Foreign net operating loss carryforwards.................. (9,764) (9,444) Accrued expenses and liabilities.......................... (5,818) (8,088) Other..................................................... (3,539) (3,415) ---------- ---------- Total deferred tax assets.............................. (96,865) (55,094) Valuation allowance....................................... 9,764 -- ---------- ---------- Net deferred tax assets................................ (87,101) (55,094) ---------- ---------- Deferred tax liabilities: Depreciation, depletion and amortization.................. 1,207,710 1,043,687 Other..................................................... -- 3,130 ---------- ---------- Total deferred tax liabilities......................... 1,207,710 1,046,817 ---------- ---------- Net deferred income tax liability........................... $1,120,609 $ 991,723 ========== ==========
F-25 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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, 2002, the undistributed earnings of the foreign subsidiaries amounted to approximately $2.1 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. At December 31, 2002, the Company had federal net operating loss carryforwards of $116 million, state net operating loss carryforwards of $317 million and foreign net operating loss carryforwards of $10 million. The state and federal net operating losses will expire over the next 15 and 20 years, respectively, if they are not otherwise utilized. The foreign net operating loss carryforwards relate to foreign pre-production expenditures which will not be deductible for foreign income tax purposes until production begins, which is expected to be in 2003. Once these expenditures are deducted for foreign income tax purposes, any net operating loss has a five-year carryforward period. A full valuation allowance has been provided on these foreign losses. The Company has alternative minimum tax (AMT) credit carryforwards of $14 million that can be carried forward indefinitely, but which can be used only to reduce regular tax liabilities in excess of AMT liabilities. The Company made cash payments for income and other taxes, net of refunds, of $171 million, $172 million and $123 million for the years ended December 31, 2002, 2001 and 2000, respectively. 8. 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. At December 31, 2002 and 2001, advances of $125 and $140 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 F-26 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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 at termination. 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. 9. CAPITAL STOCK The following shares have been restated to reflect the 10 percent and five percent stock dividends, and two-for-one stock split as discussed in Note 1 of these financial statements. COMMON STOCK OUTSTANDING
2002 2001 2000 ----------- ----------- ----------- Balance, beginning of year.................... 287,916,676 285,596,268 263,331,832 Treasury shares issued (acquired), net........ 121,432 (1,923,564) (1,061,398) Shares issued for: Public offering(1)(4)....................... -- -- 21,252,000 Acquisition of Fletcher subsidiaries(2)..... -- 3,796,550 -- Conversion of Series C Preferred Stock(3)... 13,109,730 -- -- Stock option plans.......................... 1,358,586 484,940 2,073,834 Fractional shares repurchased............... -- (37,518) -- ----------- ----------- ----------- Balance, end of year.......................... 302,506,424 287,916,676 285,596,268 =========== =========== ===========
--------------- (1) In August 2000, Apache completed a public offering of 21.3 million shares of common stock, including 2.8 million shares for the underwriters' over-allotment option, for net proceeds of $434 million. (2) In March 2001, Apache issued to Shell Overseas Holdings 3.8 million restricted shares for net proceeds of $100 million in connection with the Fletcher acquisition. (3) On May 15, 2002, we completed the mandatory conversion of our Series C preferred stock into approximately 13.1 million common shares. (4) 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. F-27 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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, 2002, 2001 and 2000 is presented in the table below:
2002 2001 2000 ------------------------------ ------------------------------ ------------------------------ INCOME SHARES PER SHARE INCOME SHARES PER SHARE INCOME SHARES PER SHARE -------- ------- --------- -------- ------- --------- -------- ------- --------- (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) BASIC: Income attributable to common stock.... $543,514 297,234 $1.83 $703,798 288,014 $2.44 $693,068 272,530 $2.54 ===== ===== ===== EFFECT OF DILUTIVE SECURITIES: Stock options and other.............. -- 2,566 -- 2,122 -- 2,418 Series C Preferred Stock.............. 5,149 4,812 13,952 13,110 14,307 13,146 -------- ------- -------- ------- -------- ------- DILUTED: Income attributable to common stock, including assumed conversions........ $548,663 304,612 $1.80 $717,750 303,246 $2.37 $707,375 288,094 $2.46 ======== ======= ===== ======== ======= ===== ======== ======= =====
Stock Option Plans -- At December 31, 2002, officers and employees had options to purchase shares of the Company's common stock under one or more employee stock option plans adopted in 1990, 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-28 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) A summary of the status of the plans described above as of December 31, 2002, 2001 and 2000, and changes during the years then ended, is presented in the table and narrative below (shares in thousands):
2002 2001 2000 ----------------- ----------------- ------------------ 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........................ 11,544 $17.62 10,354 $15.76 10,956 $14.12 Granted....................... 1,786 27.99 2,402 24.95 2,042 21.50 Exercised..................... (1,544) 14.88 (596) 13.66 (2,220) 12.89 Forfeited..................... (458) 20.21 (616) 18.79 (424) 16.46 ------ ------ ------- Outstanding, end of year(1)... 11,328 19.53 11,544 17.62 10,354 15.76 ====== ====== ======= Exercisable, end of year...... 5,730 17.25 5,156 15.34 3,558 13.48 ====== ====== ======= Available for grant, end of year........................ 1,068 2,558 3,414 ====== ====== ======= Weighted average fair value of options granted during the year(2)..................... $10.14 $10.44 $ 9.03 ====== ====== =======
--------------- (1) Includes 220,608, 285,862 and 329,176 shares as of December 31, 2002, 2001 and 2000, respectively, issuable under stock options assumed by Apache in connection with the 1996 acquisition of The Phoenix Resource Companies, Inc. (2) 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 2002, 2001 and 2000, respectively: (i) risk-free interest rates of 4.87, 4.95 and 6.74 percent; (ii) expected lives of 4.5 years for 2002 and five years for 2001 and 2000 for the Stock Option Plans; (iii) expected volatility of 37.17, 41.39 and 37.42 percent; and (iv) expected dividend yields of .68, .51 and .57 percent. The following table summarizes information about stock options covered by the plans described above that are outstanding at December 31, 2002 (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 ------------------------ ----------- ----------- -------- ----------- -------- $ 7.36 - $14.72................ 2,562 4.55 $12.91 2,284 $12.80 14.78 - 15.59................ 2,596 4.48 15.25 982 15.15 15.75 - 23.10................ 2,280 7.06 20.10 1,392 19.95 23.81 - 28.05................ 3,890 8.77 26.41 1,072 25.13 ------ ----- 11,328 5,730 ====== =====
Share Appreciation Plan -- In October 2000, the Company adopted the Share Appreciation Plan under which grants were made to the Company's officers and substantially all full-time employees. The Share Appreciation Plan provides 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 (the Share Price Goals) and/or a separate production goal (the Production Goal). Generally, shares will be issued in three installments over 24 months after achievement of each goal. When and if the goals are achieved, the Company will recognize compensation F-29 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) expense over the 24-month vesting period equal to the value of the stock on the date the particular goal is achieved. The shares of Apache common stock contingently issuable under the Share Appreciation Plan will be excluded from the computation of income per common share until the stated goals are met. The Share Price Goals were based on achieving a share price of $87, $104, and $156 per share before January 1, 2005 (subject to a meeting of the stock option plan committee of the board of directors in February 2004 to take into consideration an adjustment for the two-for-one stock split). A summary of the number of shares contingently issuable under the Share Price Goals as of December 31, 2002, 2001 and 2000 is presented in the table below (shares in thousands):
SHARES SUBJECT TO CONDITIONAL GRANTS ------------------------ 2002 2001 2000 ------ ------ ------ Outstanding, beginning of year............................. 6,390 5,764 -- Granted.................................................... 436 1,294 5,764 Forfeited.................................................. (592) (668) -- ------ ------ ------ Outstanding, end of year(1)................................ 6,234 6,390 5,764 ====== ====== ====== Exercisable, end of year................................... -- -- -- ====== ====== ====== Weighted average fair value of conditional grants -- Share Price Goals(2)..................................... $ 7.98 $ 9.31 $17.43 ====== ====== ======
--------------- (1) Represents shares issuable upon attainment of the per share price goals (assuming an adjustment by the stock option plan committee to approximately $43.50, $52, and $78 per share) of 1,351,792 shares, 3,381,050 shares and 1,501,398 shares, respectively, in 2002 and 1,386,268 shares, 3,464,788 shares and 1,539,794 shares, respectively, in 2001 and 1,252,020 shares, 3,125,430 shares and 1,388,310 shares, respectively, in 2000. (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 2002, 2001 and 2000, respectively: (i) risk-free interest rate of 2.90, 4.16 and 5.95 percent; (ii) expected volatility of 38.77, 46.27 and 44.69 percent; and (iii) expected dividend yield of .70, .77 and .44 percent. The Production Goal will be attained if and when the Company's average daily production equals or exceeds .6666 barrels of oil equivalent per diluted share (calculated on an annualized basis) during any fiscal quarter ending before January 1, 2005. Such level of production was approximately twice the Company's level of production at the time the Share Appreciation Plan was adopted. Shares issuable in connection with the Production Goal will be a number of shares of the Company's common stock equal to (a) 37.5 percent, 75 percent or 150 percent of a participant's annual base salary (at the time of attainment), as applicable, divided by (b) the average daily per share closing price of the Company's common stock for the fiscal quarter during which the Production Goal is attained. In 2001, the Company modified the Stock Option Plans, 1996 Performance Stock Option Plan and 2000 Share Appreciation Plan to allow for immediate vesting upon a change in control of ownership. This modification did not require recognition of any compensation expense. 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. F-30 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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. During the year, the Company awarded 229,950 restricted shares that are subject to ratable vesting over four years. The value of the stock issued was established by the market price on the date of grant and will be recorded as compensation expense over the vesting terms. During 2002, $538 thousand was charged to expense. 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 140,000 shares have been 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 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. 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 F-31 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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 in the accompanying statement of consolidated operations. 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, -------------------------------- 2002 2001 2000 --------- --------- -------- (IN THOUSANDS) Currency translation adjustments................... $(108,750) $(114,078) $(40,050) Unrealized gain (loss) on available for sale securities....................................... -- 125 (182) Unrealized gain (loss) on derivatives.............. (4,186) 12,136 -- --------- --------- -------- Accumulated other comprehensive loss............... $(112,936) $(101,817) $(40,232) ========= ========= ========
The unrealized gain (loss) on available for sale securities at December 31, 2001 and 2000 is net of income tax expense (benefit) of $67,000 and $(94,000), respectively. The currency translation adjustments are not adjusted for income taxes as they relate to a permanent investment in non-U.S. subsidiaries. A rollforward of the unrealized gain on derivatives is presented in the table below:
GROSS AFTER-TAX ------- --------- (IN THOUSANDS) Unrealized gain on derivatives at December 31, 2001......... $20,559 $12,136 Reclassification of net realized losses into earnings....... (24,193) (14,128) Net change in derivative fair value......................... (3,507) (2,194) ------- ------- Unrealized loss on derivatives at December 31, 2002......... $(7,141) $(4,186) ======= =======
Based on commodity prices as of December 31, 2002, the Company expects to reclassify losses of $5 million ($3 million after tax) to earnings from the balance in accumulated other comprehensive income during the next twelve months. The remaining balance in other comprehensive income is expected to be reclassified to future earnings, contemporaneously with the related sales of natural gas production as applicable to specific hedges. The actual amounts that will be reclassified to earnings over the next year and beyond could vary materially from this estimated amount as a result of changes in market conditions. F-32 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 10. FINANCIAL INSTRUMENTS The following table presents the carrying amounts and estimated fair values of the Company's financial instruments at December 31, 2002 and 2001. See Note 4 for a discussion of the Company's derivative instruments.
2002 2001 --------------------- --------------------- CARRYING CARRYING AMOUNT FAIR VALUE AMOUNT FAIR VALUE -------- ---------- -------- ---------- (IN THOUSANDS) Short-term investments..................... $ -- $ -- $102,950 $103,967 Long-term debt: Apache Money market lines of credit.......... 8,900 8,900 1,600 1,600 Global credit facility -- U.S. ....... -- -- 100,000 100,000 Commercial paper...................... 271,400 271,400 530,700 530,700 6.25-percent debentures............... 397,307 448,880 -- -- 9.25-percent notes.................... -- -- 99,974 102,560 7-percent notes....................... 148,446 179,445 148,391 148,845 7.625-percent notes................... 149,134 180,990 149,109 157,350 7.7-percent notes..................... 99,660 122,890 99,655 105,130 7.95-percent notes.................... 178,614 226,926 178,595 194,454 7.375-percent debentures.............. 148,009 177,090 148,003 152,415 7.625-percent debentures.............. 149,175 179,205 149,175 157,380 Subsidiary and other obligations Money market lines of credit.......... -- -- 1,196 1,196 Global credit facility -- Canada...... -- -- 30,000 30,000 Fletcher notes........................ 5,356 6,065 5,356 5,716 Apache Finance Australia 6.5-percent notes............................... 169,260 193,936 169,137 172,822 Apache Finance Australia 7-percent notes............................... 99,535 116,430 99,478 104,230 Apache Finance Canada 7.75-percent notes............................... 297,019 380,280 296,988 320,880 Apache Clearwater notes............... 37,000 37,000 37,000 37,000
The following methods and assumptions were used to estimate the fair value of the financial instruments summarized in the table above. 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, 2002 and December 31, 2001. Short-Term Investments -- The fair value of the Company's short-term investments are estimates provided to the Company by independent investment banking firms. Long-Term Debt -- The 2002 fair value of the notes and debentures is based upon an estimate provided to the Company by an independent investment banking firm. The fair value of the notes and debentures for 2001 is based on quoted market prices and in the case of the 7.625-percent debentures, an estimate provided by an independent banking firm. The carrying amount of the global credit facility, commercial paper, money market lines of credit and Apache Clearwater notes approximated fair value because the interest rates are variable and reflective of market rates. F-33 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 11. COMMITMENTS AND CONTINGENCIES LITIGATION China -- Texaco China, B.V., initiated an arbitration proceeding against Apache China Corporation LDC in September 2001. Texaco China later added Apache Bohai Corporation LDC to the arbitration. In the arbitration Texaco claims damages arising from Apache Bohai's alleged failure to drill three wells, prior to re-assignment of the interest to Texaco. Apache China and Apache Bohai believe they have not breached their contract obligations to Texaco and that, in any event, Texaco has not suffered any damages. Texaco will fully recover its costs associated with drilling the wells under its cost recovery contract with the Chinese national oil company, and the value of the interest re-assigned by Apache to Texaco far exceeds any damages that could be claimed by Texaco. Therefore, Apache believes that any material recovery by Texaco is remote. The matter is still pending. On February 5, 2003, the Bankruptcy Court for the Western District of Louisiana entered an order confirming Debtor XCL-China Ltd.'s most recently filed plan of arrangement. XCL-China is a participant in certain of our concessions in the Zhao Dong Block in the Bohai Bay of China. We understand that XCL Ltd. will now have one percent or less ownership interest, if any, in XCL-China with any remaining ownership interest being held by the bondholders of XCL Ltd. In connection with the order, Apache China has agreed to waive its approval and preferential purchase rights of the XCL-China interest in the Zhao Dong Block for the event of the confirmation and reorganization of the Debtor only, without waiver of any rights concerning future events. All agreements approved in 2001 by Apache China, XCL-China and the various Chinese parties, which resolved the funding and subsequent repayment of XCL-China's share of development costs, remain in place. Canada -- 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 has since reduced this amount to no more than C$4 billion. Management believes that the counterclaim is without merit, the amount claimed by Predator is frivolous, and the likelihood of success is remote. Cinergy -- Cinergy Marketing & Trading, LLC (Cinergy) purchases most of the Company's United States natural gas production (see Note 13 Transactions with Related Parties and Major Customers.) Disputes have arisen between Cinergy and Apache concerning various matters, including Cinergy's claim to market Apache's Canadian gas production. In response to these disputes, Cinergy commenced an arbitration proceeding in September 2001 seeking, among other things, specific performance to require the Company to sell its Canadian gas production to Cinergy or pay damages. The Company is disputing Cinergy's assertions (including their claim to market our Canadian production), filing a general denial and counterclaim against Cinergy for amounts arising from, among other things, an audit commenced in 2001. Management does not believe the outcome of the arbitration will be material to our financial position or results of operations. The Company continues to market most of its U.S. gas production through Cinergy, although the Company is actively discussing its gas marketing arrangements and a resolution of the disputes with Cinergy. 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 $8 million for contingencies that are probable of occurring and can be reasonably estimated. It is management's opinion that the loss for any 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. 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 F-34 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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 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, 2002, the Company had an undiscounted reserve for environmental remediation of approximately $10 million. Apache is not aware of any environmental claims existing as of December 31, 2002, 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. Exploration Agreement -- In conjunction with the purchase of oil and gas properties in December 2002, Apache entered into a separate exploration joint venture with the seller whereby the seller will actively generate prospects on certain South Louisiana acreage through December 31, 2004. Under the terms of the agreement, Apache will pay up to $25 million for the seller's share of seismic, lease acquisition and drilling and completion cost on covered prospects, with no more than $13 million of carried cost required to be paid on behalf of the seller through December 31, 2003. Apache has the option, but not the obligation, to participate in any individual prospect proposed by the seller. If Apache does not pay a total of $25 million of covered cost through December 31, 2004, it is obligated to pay the difference to the seller within 90 days of the expiration of the agreement. International Lease Concessions -- The Company, through its subsidiaries, has acquired or has been conditionally or unconditionally granted exploration rights in Australia, Egypt, China and Poland. In order to comply with the contracts and agreements granting these rights, the Company, through various wholly-owned subsidiaries, is committed to expend approximately $71 million through 2006. 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) 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 such employee's salary, and which accepts employee contributions and the Company's matching contributions in excess of the above-referenced restrictions on the F-35 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 401(k) savings plan and money purchase retirement plan. Additionally, Apache Energy Limited and Apache Canada Ltd. maintain separate retirement plans, as required under the laws of Australia and Canada, 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 $18 million, $16 million and $9 million for 2002, 2001 and 2000, respectively. The unfunded liability for all plans as of December 31, 2002 and 2001 has been recorded in other accrued expenses. In connection with the pending acquisition of U.K. North Sea assets from BP, Apache will establish a defined benefit pension plan for certain employees acquired in the transaction. BP will contribute amounts to the new plan related to past service for the transferred employees. Operating Lease and Other Commitments -- The Company has leases for buildings, facilities and equipment with varying expiration dates through 2008. Net rental expense was $16 million, $18 million and $16 million for 2002, 2001 and 2000, respectively. As of December 31, 2002, minimum rental commitments under long-term operating leases, net of sublease rentals; and long-term pipeline transportation commitments, ranging from one to 21 years, are as follows:
NET MINIMUM COMMITMENTS ------------------------------------------------- PIPELINE TOTAL LEASES DRILLING RIGS TRANSMISSION -------- ------- ------------- ------------ (IN THOUSANDS) 2003..................................... $107,234 $13,213 $68,234 $ 25,787 2004..................................... 49,735 13,404 14,182 22,149 2005..................................... 33,769 11,969 2,957 18,843 2006..................................... 31,158 11,543 2,957 16,658 2007..................................... 23,096 4,137 2,957 16,002 Thereafter............................... 65,151 319 478 64,354 -------- ------- ------- -------- $310,143 $54,585 $91,765 $163,793 ======== ======= ======= ========
12. 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 (see Note 5). 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 are entitled to receive a weighted average return of 123 basis points above the prevailing LIBOR interest rate. The preferred stock and limited partner interests are repayable from the assets of the subsidiaries. Apache retains credit risks related to collection of proceeds from product sales and intercompany loans. Apache also has 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 are 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 (see Note 6). F-36 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The limited partnership is scheduled to terminate as of August 9, 2021. However, the general partner, an Apache subsidiary, may elect to retire all or part of the limited partner's interest at any time without penalty. In addition, the limited partnership agreement requires that the limited and general partners reset the partners' rate of return over LIBOR every five years beginning in 2006. If the partners fail to mutually agree on new rates of return, the general partner must either dissolve the partnership or purchase the limited partner's interest. Upon dissolution of the partnership, retirement of the limited partner's interest, or purchase of the limited partner's interest by the general partner, the limited partner will receive the unrecouped balance of its initial $361 million capital investment. If Apache's senior unsecured long-term debt ratings from Standard & Poor's and Moody's fall to BBB- or lower and Baa3 or lower, respectively, or if either rating is withdrawn, our subsidiaries that issued the preferred stock and limited partnership interests may need to obtain additional cash or cash equivalents or redeem part of the preferred interests to remain in compliance with certain covenants. Also, if Apache's rating falls to BB or lower or Ba2 or lower, the limited partner has the right to cause the dissolution of the partnership, though Apache can avoid this by exercising its right to retire the limited partnership interests without penalty. The preferred stock certificates require that the Apache subsidiaries and their preferred shareholders reset the preferred stock dividend rate every five years beginning in 2006. If they fail to mutually agree on a new rate, the Apache subsidiaries must either register the stock for public sale, or redeem all of the outstanding preferred stock. The Apache subsidiaries may elect to redeem all or part of the preferred stock at any time without penalty. The assets and liabilities of the subsidiaries are 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 are reflected as preferred interests of subsidiaries in the statement of consolidated operations. 13. TRANSACTIONS WITH RELATED PARTIES AND MAJOR CUSTOMERS Cinergy Corp. -- In June 1998, Apache contracted with Cinergy Corp. to market substantially all the Company's natural gas production from the United States 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 sold its 57 percent interest in ProEnergy for 771,258 shares of Cinergy Corp. common stock, 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. Pursuant to the gas purchase agreement, ProEnergy, renamed Cinergy Marketing and Trading LLC (Cinergy), will continue 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 is generally obligated to deliver most of its United States gas production to Cinergy and, under certain circumstances, reimburse Cinergy if certain gas throughput thresholds are not met. All throughput thresholds have been met. The prices received for its gas production under this agreement approximate market prices. Apache and Cinergy are parties to arbitration (see Note 11 Commitments and Contingencies). Apache continues to market most of its U.S. gas production through Cinergy, although the Company is actively discussing with Cinergy its gas marketing arrangements and a resolution of its disputes. Related Parties -- 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 F-37 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Apache's board of directors through December 19, 2003, is president, chief executive officer and the sole stockholder of Maralo. In the ordinary course of business, Cimarex Energy, Co. ("Cimarex"), formerly Key Production Company, Inc., paid to Apache during 2002 approximately $2 million 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 $4 million 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 during 2002 approximately $217,000 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 $785,000 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 and chief executive officer of Cimarex. In the ordinary course of business, Matador Petroleum Corporation ("Matador") paid to Apache during 2002 approximately $708,000 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 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 2002 approximately $2 million 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 $621,000 directly by Matador for its proportionate share of revenues from wells in which Apache marketed its revenues with Matador as operator. Eugene C. Fiedorek, a member of Apache's board of directors, is a member of the board of directors of Matador. 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. All transactions with related parties were consummated at fair value. Major Customers -- In 2002, purchases by Cinergy and EGPC accounted for 19 percent and 22 percent of the Company's oil and gas production revenues, respectively. In 2001, purchases by Cinergy and EGPC accounted for 35 percent and 17 percent of the Company's oil and gas production revenues, respectively. In 2000, purchases by Cinergy and EGPC accounted for 26 percent and 16 percent of the Company's oil and gas production revenues, respectively. No other purchaser has accounted for more than 10 percent of revenues for 2002, 2001 or 2000. 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. Sales of natural gas by Apache to Cinergy are similarly uncollateralized. Apache sells all of its Egyptian crude oil and natural gas to the EGPC for U.S. dollars. Deteriorating economic conditions during 2001 and 2002 in Egypt have lessened the availability of U.S. dollars, resulting in a one to two month delay in receipts from EGPC. Continuation of the hard currency shortage in Egypt could lead to further delays, deferrals of payment or non-payment in the future. F-38 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 14. BUSINESS SEGMENT INFORMATION Apache has five 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. 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 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............. 239,837 114,299 69,160 37,107 1,721 462,124 Gathering and transportation costs........................... 17,311 21,256 -- -- -- 38,567 Severance and other taxes......... 34,792 5,489 -- 22,807 -- 63,088 ---------- ---------- ---------- -------- -------- ---------- Operating Income (Loss)............. $ 422,261 $ 234,092 $ 327,291 $166,132 $(17,286) 1,132,490 ========== ========== ========== ======== ======== Other Income (Expense): Other revenues.................... 125 Administrative, selling and other........................... (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-39 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
OTHER UNITED STATES CANADA EGYPT AUSTRALIA INTERNATIONAL TOTAL ------------- ---------- ---------- --------- ------------- ---------- (IN THOUSANDS) 2001 Oil and Gas Production Revenues..... $1,474,628 $ 628,967 $ 460,910 $257,407 $ 1,047 $2,822,959 Operating Expenses: Depreciation, depletion and amortization.................... 423,727 178,770 135,225 82,686 423 820,831 International impairments......... -- -- -- -- 65,000 65,000 Lease operating costs............. 227,418 95,833 49,449 31,728 386 404,814 Gathering and transportation costs........................... 15,790 18,794 -- -- -- 34,584 Severance and other taxes......... 49,555 8,483 -- 11,789 -- 69,827 ---------- ---------- ---------- -------- -------- ---------- Operating Income (Loss)............. $ 758,138 $ 327,087 $ 276,236 $131,204 $(64,762) 1,427,903 ========== ========== ========== ======== ======== Other Income (Expense): Other revenues (losses)........... (13,568) Administrative, selling and other........................... (88,710) Financing costs, net.............. (118,762) Preferred interests of subsidiaries.................... (7,609) ---------- Income Before Income Taxes.......... $1,199,254 ========== Net Property and Equipment.......... $3,855,674 $1,984,147 $1,238,234 $814,423 $120,594 $8,013,072 ========== ========== ========== ======== ======== ========== Total Assets........................ $4,172,551 $2,163,615 $1,564,474 $882,141 $150,875 $8,933,656 ========== ========== ========== ======== ======== ========== Additions to Net Property and Equipment......................... $ 834,581 $1,015,184 $ 515,551 $113,171 $ 34,048 $2,512,535 ========== ========== ========== ======== ======== ========== 2000 Oil and Gas Production Revenues..... $1,386,642 $ 337,876 $ 360,772 $223,543 $ -- $2,308,833 Operating Expenses: Depreciation, depletion and amortization.................... 356,998 79,892 84,425 62,183 48 583,546 Lease operating costs............. 167,986 32,945 28,328 24,450 -- 253,709 Gathering and transportation costs........................... 11,701 7,915 -- -- -- 19,616 Severance and other taxes......... 48,015 5,072 -- 6,086 -- 59,173 ---------- ---------- ---------- -------- -------- ---------- Operating Income (Loss)............. $ 801,942 $ 212,052 $ 248,019 $130,824 $ (48) 1,392,789 ========== ========== ========== ======== ======== Other Income (Expense): Other revenues (losses)........... (6,855) Administrative, selling and other........................... (75,615) Financing costs, net.............. (106,638) ---------- Income Before Income Taxes.......... $1,203,681 ========== Net Property and Equipment.......... $3,643,439 $1,378,639 $ 854,531 $783,884 $151,969 $6,812,462 ========== ========== ========== ======== ======== ========== Total Assets........................ $4,022,749 $1,463,306 $ 965,733 $856,575 $173,587 $7,481,950 ========== ========== ========== ======== ======== ========== Additions to Net Property and Equipment......................... $1,461,479 $ 649,804 $ 93,083 $117,248 $ 20,865 $2,342,479 ========== ========== ========== ======== ======== ==========
F-40 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 15. 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.
OTHER UNITED STATES CANADA EGYPT AUSTRALIA 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............. 239,837 114,299 69,160 37,107 1,721 462,124 Gathering and transportation costs... 17,311 21,256 -- -- -- 38,567 Production taxes(2).................. 33,336 -- -- 18,659 -- 51,995 Income tax........................... 165,390 104,869 157,100 58,167 (6,536) 478,990 ---------- -------- -------- -------- -------- ---------- 825,738 421,511 389,908 221,127 17,240 1,875,524 ---------- -------- -------- -------- -------- ---------- Results of operations.................. $ 275,650 $136,209 $170,191 $112,912 $(10,738) $ 684,224 ========== ======== ======== ======== ======== ========== Amortization rate per boe.............. $ 7.06 $ 5.71 $ 6.10 $ 5.36 $ 3.68 $ 6.29 ========== ======== ======== ======== ======== ========== 2001 Oil and gas production revenues........ $1,474,628 $628,967 $460,910 $257,407 $ 1,047 $2,822,959 ---------- -------- -------- -------- -------- ---------- Operating costs: Depreciation, depletion and amortization(1).................... 409,096 177,159 135,086 81,930 388 803,659 International impairments............ -- -- -- -- 65,000 65,000 Lease operating expenses............. 227,418 95,833 49,449 31,728 386 404,814 Gathering and transportation costs... 15,790 18,794 -- -- -- 34,584 Production taxes(2).................. 47,462 -- -- 11,789 -- 59,251 Income tax........................... 290,573 150,450 132,660 44,866 (24,279) 594,270 ---------- -------- -------- -------- -------- ---------- 990,339 442,236 317,195 170,313 41,495 1,961,578 ---------- -------- -------- -------- -------- ---------- Results of operations.................. $ 484,289 $186,731 $143,715 $ 87,094 $(40,448) $ 861,381 ========== ======== ======== ======== ======== ========== Amortization rate per boe.............. $ 6.64 $ 5.80 $ 5.66 $ 4.70 $ 4.72 $ 6.05 ========== ======== ======== ======== ======== ==========
F-41 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
OTHER UNITED STATES CANADA EGYPT AUSTRALIA INTERNATIONAL TOTAL ------------- -------- -------- --------- ------------- ---------- (IN THOUSANDS) 2000 Oil and gas production revenues........ $1,386,642 $337,876 $360,772 $223,543 $ -- $2,308,833 ---------- -------- -------- -------- -------- ---------- Operating costs: Depreciation, depletion and amortization(1).................... 345,624 76,286 84,302 61,358 -- 567,570 Lease operating expenses............. 167,985 32,945 28,328 24,451 -- 253,709 Gathering and transportation costs... 11,701 7,915 -- -- -- 19,616 Production taxes(2).................. 46,509 -- -- 6,086 -- 52,595 Income tax........................... 305,559 98,489 119,108 44,760 -- 567,916 ---------- -------- -------- -------- -------- ---------- 877,378 215,635 231,738 136,655 -- 1,461,406 ---------- -------- -------- -------- -------- ---------- Results of operations.................. $ 509,264 $122,241 $129,034 $ 86,888 $ -- $ 847,427 ========== ======== ======== ======== ======== ========== Amortization rate per boe.............. $ 6.16 $ 5.53 $ 5.46 $ 4.42 $ -- $ 5.75 ========== ======== ======== ======== ======== ==========
--------------- (1) This amount reflects DD&A of capitalized costs of oil and gas proved properties only and, therefore, does not agree with DD&A reflected on Note 14, Business Segment Information. (2) This amount reflects amounts directly related to oil and gas producing properties and, therefore, does not agree with severance and other taxes reflected on Note 14, Business Segment Information. Costs Not Being Amortized -- The following table sets forth a summary of oil and gas property costs not being amortized at December 31, 2002, 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.
1999 TOTAL 2002 2001 2000 AND PRIOR -------- -------- -------- ------- --------- (IN THOUSANDS) Property acquisition costs....... $393,426 $150,855 $ 38,658 $70,622 $133,291 Exploration and development...... 214,519 119,901 48,764 21,000 24,854 Capitalized interest............. 48,327 19,130 14,427 3,041 11,729 -------- -------- -------- ------- -------- Total.......................... $656,272 $289,886 $101,849 $94,663 $169,874 ======== ======== ======== ======= ========
F-42 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Capitalized Costs Incurred -- The following table sets forth the capitalized costs incurred in oil and gas producing activities:
OTHER UNITED STATES CANADA EGYPT AUSTRALIA INTERNATIONAL TOTAL ------------- -------- -------- --------- ------------- ---------- (IN THOUSANDS) 2002 Acquisitions(1)................. $ 267,537 $ 84,170 $ -- $ -- $ -- $ 351,707 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 Property sales.................. 873 84 (8,000) -- -- (7,043) ---------- -------- -------- ------- ------- ---------- $ 584,221 $356,837 $172,035 $94,037 $38,409 $1,245,539 ========== ======== ======== ======= ======= ========== 2001 Acquisitions (1)................ $ 65,395 $561,700 $240,255 $ -- $12,936 $ 880,286 Purchase of non-producing leases........................ 14,004 27,941 -- -- -- 41,945 Exploration..................... 47,688 64,172 39,806 38,727 12,536 202,929 Development..................... 637,488 318,232 87,798 46,441 8,302 1,098,261 Capitalized interest............ 24,500 13,920 11,293 7,036 -- 56,749 Property sales.................. (200,445) (147,851) -- -- -- (348,296) ---------- -------- -------- ------- ------- ---------- $ 588,630 $838,114 $379,152 $92,204 $33,774 $1,931,874 ========== ======== ======== ======= ======= ========== 2000 Acquisitions (1)................ $ 922,523 $401,904 $ -- $ -- $ -- $1,324,427 Purchase of non-producing leases........................ 10,712 11,548 -- -- -- 22,260 Exploration..................... 26,045 16,331 51,819 40,917 18,077 153,189 Development..................... 459,046 107,748 33,130 32,918 -- 632,842 Capitalized interest............ 27,185 10,063 12,194 9,908 2,650 62,000 Property sales.................. (10,853) (15,418) -- -- -- (26,271) ---------- -------- -------- ------- ------- ---------- $1,434,658 $532,176 $ 97,143 $83,743 $20,727 $2,168,447 ========== ======== ======== ======= ======= ==========
--------------- (1) Acquisitions include unproved costs of $70 million, $77 million and $125 million for transactions completed in 2002, 2001 and 2000, respectively. F-43 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 INTERNATIONAL TOTAL ------------- ---------- ---------- ---------- ------------- ----------- (IN THOUSANDS) 2002 Proved properties........ $7,906,966 $2,478,623 $1,232,119 $ 970,386 $239,365 $12,827,459 Unproved properties...... 203,366 204,059 174,925 39,962 33,960 656,272 ---------- ---------- ---------- ---------- -------- ----------- 8,110,332 2,682,682 1,407,044 1,010,348 273,325 13,483,731 Accumulated DD&A......... (4,121,751) (637,546) (502,658) (357,271) (137,668) (5,756,894) ---------- ---------- ---------- ---------- -------- ----------- $3,988,581 $2,045,136 $ 904,386 $ 653,077 $135,657 $ 7,726,837 ========== ========== ========== ========== ======== =========== 2001 Proved properties........ $7,314,153 $2,103,263 $1,037,431 $ 816,620 $119,225 $11,390,692 Unproved properties...... 211,958 215,003 197,578 99,691 115,691 839,921 ---------- ---------- ---------- ---------- -------- ----------- 7,526,111 2,318,266 1,235,009 916,311 234,916 12,230,613 Accumulated DD&A......... (3,751,887) (466,703) (359,792) (259,373) (115,613) (4,953,368) ---------- ---------- ---------- ---------- -------- ----------- $3,774,224 $1,851,563 $ 875,217 $ 656,938 $119,303 $ 7,277,245 ========== ========== ========== ========== ======== ===========
F-44 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's estimates of proved reserve quantities of its U.S., Canadian and international properties are subject to review by Ryder Scott Company, L.P. Petroleum Consultants, independent petroleum engineers. During 2002, 2001 and 2000, their review covered 68 percent, 61 percent and 72 percent of the 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 represents estimates only and should not be construed as being exact.
CRUDE OIL, CONDENSATE AND NATURAL GAS LIQUIDS NATURAL GAS ---------------------------------------------------------- ------------------------------- (THOUSANDS OF BARRELS) (MILLIONS OF CUBIC FEET) UNITED OTHER UNITED STATES CANADA EGYPT AUSTRALIA INT'L TOTAL STATES CANADA EGYPT ------- ------- ------- --------- ------ ------- --------- --------- ------- PROVED DEVELOPED RESERVES: December 31, 1999............. 186,962 50,401 30,719 33,887 -- 301,969 1,004,844 397,704 106,830 December 31, 2000............. 232,361 66,484 26,028 29,124 -- 353,997 1,579,865 660,334 93,205 December 31, 2001............. 230,017 76,250 59,188 45,628 699 411,782 1,407,561 1,148,516 338,707 December 31, 2002............. 240,880 89,554 51,162 31,746 1,033 414,375 1,444,677 1,255,068 246,529 TOTAL PROVED RESERVES: Balance December 31,1999........ 238,657 83,043 39,076 54,466 -- 415,242 1,214,887 407,053 156,049 Extensions, discoveries and other additions............. 36,681 6,589 9,168 6,074 -- 58,512 154,489 94,792 32,967 Purchases of minerals in-place.................... 60,519 29,514 -- -- -- 90,033 736,079 246,360 -- Revisions of previous estimates................... 2,655 159 1,012 429 -- 4,255 32,414 (8,397) 2,966 Production.................... (22,894) (5,828) (10,155) (5,691) -- (44,568) (199,362) (47,758) (17,371) Sales of properties........... (914) (87) -- -- -- (1,001) (10,454) (333) -- ------- ------- ------- ------- ------ ------- --------- --------- ------- Balance December 31, 2000....... 314,704 113,390 39,101 55,278 -- 522,473 1,928,053 691,717 174,611 Extensions, discoveries and other additions............. 54,533 21,121 17,121 12,320 -- 105,095 166,307 281,037 52,938 Purchases of minerals in-place.................... 6,728 35,298 36,465 -- 1,099 79,590 34,827 512,927 247,302 Revisions of previous estimates................... (7,943) 814 2,621 -- -- (4,508) (61,522) 8,391 13,392 Production.................... (24,157) (9,916) (14,322) (8,595) (42) (57,032) (224,600) (108,925) (35,010) Sales of properties........... (22,428) (23,802) -- -- -- (46,230) (167,271) (83,265) -- ------- ------- ------- ------- ------ ------- --------- --------- ------- Balance December 31, 2001....... 321,437 136,905 80,986 59,003 1,057 599,388 1,675,794 1,301,882 453,233 Extensions, discoveries and other additions............. 20,082 31,366 18,227 4,221 11,793 85,689 102,050 70,066 6,123 Purchases of minerals in-place.................... 7,109 5,055 -- -- -- 12,164 154,459 66,113 -- Revisions of previous estimates................... 6,630 159 (8,140) 106 40 (1,205) 37,944 20,900 (37,480) Production.................... (21,790) (9,846) (15,977) (11,082) (225) (58,920) (183,708) (120,210) (44,769) Sales of properties........... (46) -- (305) -- -- (351) (2,446) -- (6,440) ------- ------- ------- ------- ------ ------- --------- --------- ------- Balance December 31, 2002....... 333,422 163,639 74,791 52,248 12,665 636,765 1,784,093 1,338,751 370,667 ======= ======= ======= ======= ====== ======= ========= ========= ======= NATURAL GAS TOTAL ------------------------------ ----------- (MILLIONS OF CUBIC FEET) (THOUSAND OTHER BARRELS OF AUSTRALIA INT'L TOTAL OIL --------- ------ --------- EQUIVALENT) PROVED DEVELOPED RESERVES: December 31, 1999............. 364,369 -- 1,873,747 614,260 December 31, 2000............. 331,390 -- 2,664,794 798,129 December 31, 2001............. 307,509 1,524 3,203,817 945,751 December 31, 2002............. 256,790 3,469 3,206,533 948,797 TOTAL PROVED RESERVES: Balance December 31,1999........ 573,589 -- 2,351,578 807,172 Extensions, discoveries and other additions............. 55,195 -- 337,443 114,752 Purchases of minerals in-place.................... -- -- 982,439 253,773 Revisions of previous estimates................... (6) -- 26,977 8,751 Production.................... (39,489) -- (303,980) (95,231) Sales of properties........... -- -- (10,787) (2,799) ------- ------ --------- --------- Balance December 31, 2000....... 589,289 -- 3,383,670 1,086,418 Extensions, discoveries and other additions............. 25,084 -- 525,366 192,656 Purchases of minerals in-place.................... -- 2,969 798,025 212,594 Revisions of previous estimates................... -- -- (39,739) (11,131) Production.................... (42,684) (236) (411,455) (125,608) Sales of properties........... -- -- (250,536) (87,986) ------- ------ --------- --------- Balance December 31, 2001....... 571,689 2,733 4,005,331 1,266,943 Extensions, discoveries and other additions............. 28,943 3,355 210,537 120,779 Purchases of minerals in-place.................... -- -- 220,572 48,926 Revisions of previous estimates................... 22 37 21,423 2,366 Production.................... (42,998) (2,656) (394,341) (124,644) Sales of properties........... -- -- (8,886) (1,832) ------- ------ --------- --------- Balance December 31, 2002....... 557,656 3,469 4,054,636 1,312,538 ======= ====== ========= =========
As of December 31, 2002, 2001 and 2000, on a barrel of equivalent basis 28, 25 and 27 percent of our worldwide reserves, respectively, were classified as proved undeveloped. Approximately 19.2 percent of our 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 due to 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 our standardized measure Note 15. F-45 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.
OTHER UNITED STATES CANADA(1) EGYPT AUSTRALIA 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 =========== =========== ========== ========== ======== ============ 2001 Cash inflows.................... $10,424,737 $ 5,468,028 $2,831,285 $1,838,437 $ 22,381 $ 20,584,868 Production costs................ (3,457,430) (1,538,797) (564,714) (383,171) (13,789) (5,957,901) Development costs............... (613,594) (333,043) (306,543) (188,017) (3,532) (1,444,729) Income tax expense.............. (1,417,677) (851,971) (683,856) (345,392) -- (3,298,896) ----------- ----------- ---------- ---------- -------- ------------ Net cash flows.................. 4,936,036 2,744,217 1,276,172 921,857 5,060 9,883,342 10 percent discount rate........ (2,286,959) (1,337,536) (427,744) (286,696) (946) (4,339,881) ----------- ----------- ---------- ---------- -------- ------------ Discounted future net cash flows(2)...................... $ 2,649,077 $ 1,406,681 $ 848,428 $ 635,161 $ 4,114 $ 5,543,461 =========== =========== ========== ========== ======== ============ 2000 Cash inflows.................... $26,652,689 $ 8,865,939 $1,430,178 $2,133,073 $ -- $ 39,081,879 Production costs................ (4,909,091) (996,123) (214,686) (453,153) -- (6,573,053) Development costs............... (640,218) (347,708) (84,025) (197,998) -- (1,269,949) Income tax expense.............. (7,132,257) (2,194,511) (375,112) (385,953) -- (10,087,833) ----------- ----------- ---------- ---------- -------- ------------ Net cash flows.................. 13,971,123 5,327,597 756,355 1,095,969 -- 21,151,044 10 percent discount rate........ (6,148,566) (2,478,102) (238,985) (337,741) -- (9,203,394) ----------- ----------- ---------- ---------- -------- ------------ Discounted future net cash flows(2)...................... $ 7,822,557 $ 2,849,495 $ 517,370 $ 758,228 $ -- $ 11,947,650 =========== =========== ========== ========== ======== ============
--------------- (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 $13.2 billion, $7.4 billion and $17.7 billion as of December 31, 2002, 2001 and 2000, respectively. F-46 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, ---------------------------------------- 2002 2001 2000 ----------- ------------ ----------- (IN THOUSANDS) Sales, net of production costs............... $(1,994,631) $ (2,327,679) $(2,064,471) Net change in prices and production costs.... 4,767,785 (10,125,666) 4,693,840 Discoveries and improved recovery, net of related costs.............................. 1,885,266 1,760,299 2,703,195 Change in future development costs........... 222,160 182,816 67,442 Revision of quantities....................... (15,400) (79,138) 135,669 Purchases of minerals in-place............... 603,608 1,332,244 5,796,278 Accretion of discount........................ 737,112 1,772,520 606,801 Change in income taxes....................... (2,200,925) 3,949,890 (4,284,904) Sales of properties.......................... (14,502) (1,306,042) (25,585) Change in production rates and other......... (382,314) (1,563,433) (255,976) ----------- ------------ ----------- $ 3,608,159 $ (6,404,189) $ 7,372,289 =========== ============ ===========
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. Price fluctuations are largely attributable to supply and demand perceptions for natural gas and volatility in oil prices. Under the full-cost accounting rules of the SEC, 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-47 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 16. SUPPLEMENTAL QUARTERLY FINANCIAL DATA (UNAUDITED)
FIRST SECOND THIRD FOURTH TOTAL -------- -------- -------- -------- ---------- (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) 2002 Revenues............................... $527,996 $656,315 $645,189 $730,373 $2,559,873 Expenses, net.......................... 447,324 510,005 498,661 549,554 2,005,544 -------- -------- -------- -------- ---------- Net income............................. $ 80,672 $146,310 $146,528 $180,819 $ 554,329 ======== ======== ======== ======== ========== Income attributable to common stock.... $ 75,764 $143,229 $145,122 $179,399 $ 543,514 ======== ======== ======== ======== ========== Net income per common share (1)(2): Basic................................ $ .26 $ .48 $ .48 $ .59 $ 1.83 ======== ======== ======== ======== ========== Diluted.............................. $ .26 $ .48 $ .48 $ .59 $ 1.80 ======== ======== ======== ======== ========== 2001 Revenues............................... $803,515 $808,681 $659,917 $537,278 $2,809,391 Expenses, net.......................... 521,314 602,936 503,084 458,658 2,085,992 -------- -------- -------- -------- ---------- Net income............................. $282,201 $205,745 $156,833 $ 78,620 $ 723,399 ======== ======== ======== ======== ========== Income attributable to common stock.... $277,293 $200,868 $151,925 $ 73,712 $ 703,798 ======== ======== ======== ======== ========== Net income per common share (1)(2): Basic................................ $ .97 $ .69 $ .53 $ .26 $ 2.44 ======== ======== ======== ======== ========== Diluted.............................. $ .93 $ .67 $ .51 $ .25 $ 2.37 ======== ======== ======== ======== ==========
--------------- (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. In addition, certain potentially dilutive securities were not included in certain of the quarterly computations of diluted net income per common share because to do so would have been antidilutive. (2) Earnings per share have been restated to reflect the 10 percent stock dividend declared September 13, 2001, paid January 21, 2002 to shareholders of record on December 31, 2001, 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, distributed January 14, 2004 to shareholders of record on December 31, 2003. 17. 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 SEC. Since these subsidiaries had no independent operations and qualified as "finance subsidiaries", they were exempted from these requirements. F-48 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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-49 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 -- -- -- 424,558 Gathering and transportation costs.......................... 15,896 -- -- -- 22,671 Severance and other taxes........ 34,015 -- -- 270 28,803 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) 462,124 Gathering and transportation costs.......................... -- 38,567 Severance and other taxes........ -- 63,088 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-50 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS FOR THE YEAR ENDED DECEMBER 31, 2001
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....................... $1,388,017 $ -- $ -- $ -- $1,897,305 Equity in net income of affiliates..................... 202,137 16,227 26,170 88,243 (31,085) Other............................ (3,064) -- 3,053 -- (13,557) ---------- ------- ------- -------- ---------- 1,587,090 16,227 29,223 88,243 1,852,663 ---------- ------- ------- -------- ---------- OPERATING EXPENSES: Depreciation, depletion and amortization................... 170,854 -- -- -- 649,977 International impairments........ -- -- -- -- 65,000 Lease operating costs............ 214,075 -- -- -- 653,102 Gathering and transportation costs.......................... 15,337 -- -- -- 19,247 Severance and other taxes........ 49,201 -- -- 36 20,590 Administrative, selling and other.......................... 78,440 -- -- -- 10,270 Financing costs, net............. 71,150 -- 18,119 37,450 (7,957) ---------- ------- ------- -------- ---------- 599,057 -- 18,119 37,486 1,410,229 ---------- ------- ------- -------- ---------- PREFERRED INTERESTS OF SUBSIDIARIES..................... -- -- -- -- 7,609 ---------- ------- ------- -------- ---------- INCOME (LOSS) BEFORE INCOME TAXES............................ 988,033 16,227 11,104 50,757 434,825 Provision (benefit) for income taxes.......................... 264,634 -- (5,123) (16,344) 232,688 ---------- ------- ------- -------- ---------- NET INCOME......................... 723,399 16,227 16,227 67,101 202,137 Preferred stock dividends........ 19,601 -- -- -- -- ---------- ------- ------- -------- ---------- INCOME ATTRIBUTABLE TO COMMON STOCK............................ $ 703,798 $16,227 $16,227 $ 67,101 $ 202,137 ========== ======= ======= ======== ========== RECLASSIFICATIONS & ELIMINATIONS CONSOLIDATED ----------------- ------------ (IN THOUSANDS) REVENUES AND OTHER: Oil and gas production revenues....................... $(462,363) $2,822,959 Equity in net income of affiliates..................... (301,692) -- Other............................ -- (13,568) --------- ---------- (764,055) 2,809,391 --------- ---------- OPERATING EXPENSES: Depreciation, depletion and amortization................... -- 820,831 International impairments........ -- 65,000 Lease operating costs............ (462,363) 404,814 Gathering and transportation costs.......................... -- 34,584 Severance and other taxes........ -- 69,827 Administrative, selling and other.......................... -- 88,710 Financing costs, net............. -- 118,762 --------- ---------- (462,363) 1,602,528 --------- ---------- PREFERRED INTERESTS OF SUBSIDIARIES..................... -- 7,609 --------- ---------- INCOME (LOSS) BEFORE INCOME TAXES............................ (301,692) 1,199,254 Provision (benefit) for income taxes.......................... -- 475,855 --------- ---------- NET INCOME......................... (301,692) 723,399 Preferred stock dividends........ -- 19,601 --------- ---------- INCOME ATTRIBUTABLE TO COMMON STOCK............................ $(301,692) $ 703,798 ========= ==========
F-51 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS FOR THE YEAR ENDED DECEMBER 31, 2000
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....................... $1,409,724 $ -- $ -- $ -- $1,281,209 Equity in net income of affiliates..................... 290,644 -- -- 21,417 (10,884) Other............................ (4,323) -- -- -- (3,394) ---------- ----- ----- ------- ---------- 1,696,045 -- -- 21,417 1,266,931 ---------- ----- ----- ------- ---------- OPERATING EXPENSES: Depreciation, depletion and amortization................... 356,998 -- -- -- 226,548 Lease operating costs............ 168,336 -- -- -- 467,473 Gathering and transportation costs.......................... 11,701 -- -- -- 7,915 Severance and other taxes........ 48,014 -- -- -- 11,159 Administrative, selling and other.......................... 63,418 -- -- -- 12,197 Financing costs, net............. 80,066 -- -- 19,297 7,275 ---------- ----- ----- ------- ---------- 728,533 -- -- 19,297 732,567 ---------- ----- ----- ------- ---------- INCOME (LOSS) BEFORE INCOME TAXES............................ 967,512 -- -- 2,120 534,364 Provision (benefit) for income taxes.......................... 246,917 -- -- (8,413) 244,582 ---------- ----- ----- ------- ---------- INCOME (LOSS) BEFORE CHANGE IN ACCOUNTING PRINCIPLE............. 720,595 -- -- 10,533 289,782 Cumulative effect of change in accounting principle, net of income tax..................... (7,539) -- -- -- (4,831) ---------- ----- ----- ------- ---------- NET INCOME......................... 713,056 -- -- 10,533 284,951 Preferred stock dividends........ 19,988 -- -- -- -- ---------- ----- ----- ------- ---------- INCOME ATTRIBUTABLE TO COMMON STOCK............................ $ 693,068 $ -- $ -- $10,533 $ 284,951 ========== ===== ===== ======= ========== RECLASSIFICATIONS & ELIMINATIONS CONSOLIDATED ----------------- ------------ (IN THOUSANDS) REVENUES AND OTHER: Oil and gas production revenues....................... $(382,100) $2,308,833 Equity in net income of affiliates..................... (300,315) 862 Other............................ -- (7,717) --------- ---------- (682,415) 2,301,978 --------- ---------- OPERATING EXPENSES: Depreciation, depletion and amortization................... -- 583,546 Lease operating costs............ (382,100) 253,709 Gathering and transportation costs.......................... -- 19,616 Severance and other taxes........ -- 59,173 Administrative, selling and other.......................... -- 75,615 Financing costs, net............. -- 106,638 --------- ---------- (382,100) 1,098,297 --------- ---------- INCOME (LOSS) BEFORE INCOME TAXES............................ (300,315) 1,203,681 Provision (benefit) for income taxes.......................... -- 483,086 --------- ---------- INCOME (LOSS) BEFORE CHANGE IN ACCOUNTING PRINCIPLE............. (300,315) 720,595 Cumulative effect of change in accounting principle, net of income tax..................... 4,831 (7,539) --------- ---------- NET INCOME......................... (295,484) 713,056 Preferred stock dividends........ -- 19,988 --------- ---------- INCOME ATTRIBUTABLE TO COMMON STOCK............................ $(295,484) $ 693,068 ========= ==========
F-52 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 APACHE SUBSIDIARIES OF APACHE APACHE FINANCE APACHE APACHE CORPORATION NORTH AMERICA AUSTRALIA FINANCE CANADA CORPORATION ----------- ------------- --------- -------------- --------------- (IN THOUSANDS) CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES...... $ 39,727 $ -- $(18,687) $(43,819) $ 1,403,497 ----------- -------- -------- -------- ----------- 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) -- -- (843,894) Other, net......................................... (15,105) -- -- -- (22,415) ----------- -------- -------- -------- ----------- NET CASH USED IN INVESTING ACTIVITIES................ (703,442) (18,050) -- -- (1,544,940) ----------- -------- -------- -------- ----------- CASH FLOWS FROM FINANCING ACTIVITIES: Long-term borrowings............................... 2,063,264 -- 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............ 657,556 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.... 1,030,425 -- Other, net......................................... -- (37,520) ----------- ----------- NET CASH USED IN INVESTING ACTIVITIES................ 1,030,425 (1,236,007) ----------- ----------- CASH FLOWS FROM FINANCING ACTIVITIES: Long-term borrowings............................... (824,316) 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............ (1,030,425) (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-53 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS FOR THE YEAR ENDED DECEMBER 31, 2001
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............. $1,149,273 $ -- $(1,575) $ (29) $ 757,331 ---------- ------- ------- --------- ----------- CASH FLOWS FROM INVESTING ACTIVITIES: Additions to property and equipment...................... (708,139) -- -- -- (820,845) Acquisitions..................... (11,000) -- -- -- (911,951) Proceeds from sales of oil and gas properties................. 200,445 -- -- -- 147,851 Purchase of U.S. Government Agency Notes................... -- -- -- -- (103,863) Investment in and advances to subsidiaries, net.............. (1,055,334) (5,568) (5,568) (250,849) (652,967) Other, net....................... (17,564) -- -- -- (59,271) ---------- ------- ------- --------- ----------- NET CASH USED IN INVESTING ACTIVITIES....................... (1,591,592) (5,568) (5,568) (250,849) (2,401,046) ---------- ------- ------- --------- ----------- CASH FLOWS FROM FINANCING ACTIVITIES: Long-term borrowings............. 2,783,409 -- 1,577 250,878 1,151,428 Payments on long-term debt....... (2,251,000) -- -- -- (482,641) Dividends paid................... (54,492) -- -- -- -- Common stock activity............ 10,205 5,568 5,568 -- 531,598 Treasury stock activity, net..... (42,959) -- -- -- -- Cost of debt and equity transactions................... (1,718) -- -- -- -- Proceeds from preferred interests of subsidiaries................ -- -- -- -- 440,654 ---------- ------- ------- --------- ----------- NET CASH PROVIDED BY FINANCING ACTIVITIES....................... 443,445 5,568 7,145 250,878 1,641,039 ---------- ------- ------- --------- ----------- NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS................. 1,126 -- 2 -- (2,676) CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR................ 5,257 -- -- -- 31,916 ---------- ------- ------- --------- ----------- CASH AND CASH EQUIVALENTS AT END OF YEAR............................. $ 6,383 $ -- $ 2 $ -- $ 29,240 ========== ======= ======= ========= =========== RECLASSIFICATIONS & ELIMINATIONS CONSOLIDATED ----------------- ------------ (IN THOUSANDS) CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES............. $ -- $ 1,905,000 ----------- ----------- CASH FLOWS FROM INVESTING ACTIVITIES: Additions to property and equipment...................... -- (1,528,984) Acquisitions..................... -- (922,951) Proceeds from sales of oil and gas properties................. -- 348,296 Purchase of U.S. Government Agency Notes................... -- (103,863) Investment in and advances to subsidiaries, net.............. 1,970,286 -- Other, net....................... -- (76,835) ----------- ----------- NET CASH USED IN INVESTING ACTIVITIES....................... 1,970,286 (2,284,337) ----------- ----------- CASH FLOWS FROM FINANCING ACTIVITIES: Long-term borrowings............. (1,427,552) 2,759,740 Payments on long-term debt....... -- (2,733,641) Dividends paid................... -- (54,492) Common stock activity............ (542,734) 10,205 Treasury stock activity, net..... -- (42,959) Cost of debt and equity transactions................... -- (1,718) Proceeds from preferred interests of subsidiaries................ -- 440,654 ----------- ----------- NET CASH PROVIDED BY FINANCING ACTIVITIES....................... (1,970,286) 377,789 ----------- ----------- NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS................. -- (1,548) CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR................ -- 37,173 ----------- ----------- CASH AND CASH EQUIVALENTS AT END OF YEAR............................. $ -- $ 35,625 =========== ===========
F-54 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS FOR THE YEAR ENDED DECEMBER 31, 2000
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....................... $ 899,872 $ -- $ 250 $ 1,721 $ 615,525 ---------- ------ ----- -------- --------- CASH FLOWS FROM INVESTING ACTIVITIES: Additions to property and equipment...................... (579,856) -- -- -- (375,720) Acquisitions..................... (760,566) -- -- -- (490,250) Proceeds from sales of oil and gas properties................. 10,853 -- -- -- 15,418 Investment in and advances to subsidiaries, net.............. (472,778) -- (406) (27,084) (25,337) Other, net....................... (15,380) -- -- -- (21,495) ---------- ------ ----- -------- --------- NET CASH USED IN INVESTING ACTIVITIES....................... (1,817,727) -- (406) (27,084) (897,384) ---------- ------ ----- -------- --------- CASH FLOWS FROM FINANCING ACTIVITIES: Long-term borrowings............. 892,315 -- 156 202 712,347 Payments on long-term debt....... (361,925) -- -- -- (431,606) Dividends paid................... (52,945) -- -- -- -- Issuance (repurchase) of preferred stock................ (2,613) -- -- -- -- Common stock activity............ 465,306 -- -- 25,161 21,405 Treasury stock activity, net..... (17,730) -- -- -- -- Cost of debt and equity transactions................... (838) -- -- -- -- ---------- ------ ----- -------- --------- NET CASH PROVIDED BY FINANCING ACTIVITIES....................... 921,570 -- 156 25,363 302,146 ---------- ------ ----- -------- --------- NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS................. 3,715 -- -- -- 20,287 CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR................ 1,542 -- -- -- 11,629 ---------- ------ ----- -------- --------- CASH AND CASH EQUIVALENTS AT END OF YEAR............................. $ 5,257 $ -- $ -- $ -- $ 31,916 ========== ====== ===== ======== ========= RECLASSIFICATIONS & ELIMINATIONS CONSOLIDATED ----------------- ------------ (IN THOUSANDS) CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES....................... $ -- $ 1,517,368 --------- ----------- CASH FLOWS FROM INVESTING ACTIVITIES: Additions to property and equipment...................... -- (955,576) Acquisitions..................... -- (1,250,816) Proceeds from sales of oil and gas properties................. -- 26,271 Investment in and advances to subsidiaries, net.............. 525,605 -- Other, net....................... -- (36,875) --------- ----------- NET CASH USED IN INVESTING ACTIVITIES....................... 525,605 (2,216,996) --------- ----------- CASH FLOWS FROM FINANCING ACTIVITIES: Long-term borrowings............. (479,039) 1,125,981 Payments on long-term debt....... -- (793,531) Dividends paid................... -- (52,945) Issuance (repurchase) of preferred stock................ -- (2,613) Common stock activity............ (46,566) 465,306 Treasury stock activity, net..... -- (17,730) Cost of debt and equity transactions................... -- (838) --------- ----------- NET CASH PROVIDED BY FINANCING ACTIVITIES....................... (525,605) 723,630 --------- ----------- NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS................. -- 24,002 CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR................ -- 13,171 --------- ----------- CASH AND CASH EQUIVALENTS AT END OF YEAR............................. $ -- $ 37,173 ========= ===========
F-55 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) CONDENSED CONSOLIDATING BALANCE SHEET 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) ASSETS CURRENT ASSETS: Cash and cash equivalents........ $ 224 $ -- $ 2 $ 127 $ 51,533 Receivables, net of allowance.... 121,410 -- -- -- 406,277 Inventories...................... 15,509 -- -- -- 93,695 Advances to oil and gas ventures and others..................... 19,468 -- -- -- 58,536 Short-term investments........... -- -- -- -- -- ---------- -------- -------- --------- ---------- 156,611 -- 2 127 610,041 ---------- -------- -------- --------- ---------- PROPERTY AND EQUIPMENT, NET........ 3,403,716 -- -- -- 5,061,869 ---------- -------- -------- --------- ---------- OTHER ASSETS: Intercompany receivable, net..... 1,146,086 -- (662) (253,851) (891,573) Goodwill, net.................... -- -- -- -- 189,252 Equity in affiliates............. 2,994,954 142,422 402,596 958,382 (808,503) Deferred charges and other....... 31,804 -- -- 2,472 3,957 ---------- -------- -------- --------- ---------- $7,733,171 $142,422 $401,936 $ 707,130 $4,165,043 ========== ======== ======== ========= ========== LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES: Accounts payable................. $ 124,152 $ -- $ -- $ -- $ 90,136 Other accrued expenses........... 134,191 -- 2,229 1,263 180,264 ---------- -------- -------- --------- ---------- 258,343 -- 2,229 1,263 270,400 ---------- -------- -------- --------- ---------- LONG-TERM DEBT..................... 1,550,645 -- 268,795 297,019 42,356 ---------- -------- -------- --------- ---------- DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES: Income taxes................... 736,661 -- (11,510) (1,205) 396,663 Advances from gas purchasers... 125,453 -- -- -- -- Oil and gas derivative instruments.................. 3,507 -- -- -- -- Other.......................... 134,282 -- -- -- 24,044 ---------- -------- -------- --------- ---------- 999,903 -- (11,510) (1,205) 420,707 ---------- -------- -------- --------- ---------- PREFERRED INTERESTS OF SUBSIDIARIES..................... -- -- -- -- 436,626 ---------- -------- -------- --------- ---------- COMMITMENTS AND CONTINGENCIES SHAREHOLDERS' EQUITY............... 4,924,280 142,422 142,422 410,053 2,994,954 ---------- -------- -------- --------- ---------- $7,733,171 $142,422 $401,936 $ 707,130 $4,165,043 ========== ======== ======== ========= ========== RECLASSIFICATIONS & ELIMINATIONS CONSOLIDATED ----------------- ------------ (IN THOUSANDS) ASSETS CURRENT ASSETS: Cash and cash equivalents........ $ -- $ 51,886 Receivables, net of allowance.... -- 527,687 Inventories...................... -- 109,204 Advances to oil and gas ventures and others..................... -- 78,004 Short-term investments........... -- -- ----------- ---------- -- 766,781 ----------- ---------- PROPERTY AND EQUIPMENT, NET........ -- 8,465,585 ----------- ---------- OTHER ASSETS: Intercompany receivable, net..... -- -- Goodwill, net.................... -- 189,252 Equity in affiliates............. (3,689,851) -- Deferred charges and other....... -- 38,233 ----------- ---------- $(3,689,851) $9,459,851 =========== ========== LIABILITIES AND SHAREHOLDERS' EQUIT CURRENT LIABILITIES: Accounts payable................. $ -- $ 214,288 Other accrued expenses........... -- 317,947 ----------- ---------- -- 532,235 ----------- ---------- LONG-TERM DEBT..................... -- 2,158,815 ----------- ---------- DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES: Income taxes................... -- 1,120,609 Advances from gas purchasers... -- 125,453 Oil and gas derivative instruments.................. -- 3,507 Other.......................... -- 158,326 ----------- ---------- -- 1,407,895 ----------- ---------- PREFERRED INTERESTS OF SUBSIDIARIES..................... -- 436,626 ----------- ---------- COMMITMENTS AND CONTINGENCIES SHAREHOLDERS' EQUITY............... (3,689,851) 4,924,280 ----------- ---------- $(3,689,851) $9,459,851 =========== ==========
F-56 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) CONDENSED CONSOLIDATING BALANCE SHEET FOR THE YEAR ENDED DECEMBER 31, 2001
ALL OTHER APACHE SUBSIDIARIES APACHE APACHE FINANCE APACHE OF APACHE CORPORATION NORTH AMERICA AUSTRALIA FINANCE CANADA CORPORATION ----------- ------------- --------- -------------- ------------ (IN THOUSANDS) ASSETS CURRENT ASSETS: Cash and cash equivalents........ $ 6,383 $ -- $ 2 $ -- $ 29,240 Receivables, net of allowance.... 94,881 -- -- -- 309,912 Inventories...................... 17,024 -- -- -- 85,512 Advances to oil and gas ventures and others..................... 24,644 -- -- -- 27,201 Short-term investments........... -- -- -- -- 102,950 ---------- -------- -------- ---------- ----------- 142,932 -- 2 -- 554,815 ---------- -------- -------- ---------- ----------- PROPERTY AND EQUIPMENT, NET........ 3,098,485 -- -- -- 4,914,587 ---------- -------- -------- ---------- ----------- OTHER ASSETS: Intercompany receivable, net..... 1,426,455 -- (25) (251,025) (1,175,405) Goodwill, net.................... -- -- -- -- 188,812 Equity in affiliates............. 2,566,969 103,577 369,691 1,082,328 (812,827) Deferred charges and other....... 27,688 -- -- 2,564 3,771 ---------- -------- -------- ---------- ----------- $7,262,529 $103,577 $369,668 $ 833,867 $ 3,673,753 ========== ======== ======== ========== =========== LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES: Accounts payable................. $ 75,164 $ -- $ -- $ -- $ 104,614 Other accrued expenses........... 165,858 -- 2,599 1,246 172,977 ---------- -------- -------- ---------- ----------- 241,022 -- 2,599 1,246 277,591 ---------- -------- -------- ---------- ----------- LONG-TERM DEBT..................... 1,605,201 -- 268,615 296,988 73,553 ---------- -------- -------- ---------- ----------- DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES: Income taxes................... 696,441 -- (5,123) 18 300,387 Advances from gas purchasers... 140,027 -- -- -- -- Other.......................... 161,355 -- -- -- 14,570 ---------- -------- -------- ---------- ----------- 997,823 -- (5,123) 18 314,957 ---------- -------- -------- ---------- ----------- PREFERRED INTERESTS OF SUBSIDIARIES..................... -- -- -- -- 440,683 ---------- -------- -------- ---------- ----------- COMMITMENTS AND CONTINGENCIES SHAREHOLDERS' EQUITY............... 4,418,483 103,577 103,577 535,615 2,566,969 ---------- -------- -------- ---------- ----------- $7,262,529 $103,577 $369,668 $ 833,867 $ 3,673,753 ========== ======== ======== ========== =========== RECLASSIFICATIONS & ELIMINATIONS CONSOLIDATED ----------------- ------------ (IN THOUSANDS) ASSETS CURRENT ASSETS: Cash and cash equivalents........ $ -- $ 35,625 Receivables, net of allowance.... -- 404,793 Inventories...................... -- 102,536 Advances to oil and gas ventures and others..................... -- 51,845 Short-term investments........... -- 102,950 ----------- ---------- -- 697,749 ----------- ---------- PROPERTY AND EQUIPMENT, NET........ -- 8,013,072 ----------- ---------- OTHER ASSETS: Intercompany receivable, net..... -- -- Goodwill, net.................... -- 188,812 Equity in affiliates............. (3,309,738) -- Deferred charges and other....... -- 34,023 ----------- ---------- $(3,309,738) $8,933,656 =========== ========== LIABILITIES AND SHAREHOLDERS' EQUIT CURRENT LIABILITIES: Accounts payable................. $ -- $ 179,778 Other accrued expenses........... -- 342,680 ----------- ---------- -- 522,458 ----------- ---------- LONG-TERM DEBT..................... -- 2,244,357 ----------- ---------- DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES: Income taxes................... -- 991,723 Advances from gas purchasers... -- 140,027 Other.......................... -- 175,925 ----------- ---------- -- 1,307,675 ----------- ---------- PREFERRED INTERESTS OF SUBSIDIARIES..................... -- 440,683 ----------- ---------- COMMITMENTS AND CONTINGENCIES SHAREHOLDERS' EQUITY............... (3,309,738) 4,418,483 ----------- ---------- $(3,309,738) $8,933,656 =========== ==========
F-57 BOARD OF DIRECTORS FREDERICK M. BOHEN(3)(5) Acting 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) President and Chief Executive Officer, Caremark Rx, 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. (formerly Key Production Company, Inc.) 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 -- Eurasia and New Ventures RODNEY J. EICHLER Executive Vice President ROGER B. PLANK Executive Vice President and Chief Financial Officer FLOYD R. PRICE Executive Vice President and President, Apache Canada Ltd. LISA A. STEWART Executive Vice President Business Development and E&P Services JON A. JEPPESEN Senior Vice President JEFFREY M. BENDER Vice President -- Human Resources MICHAEL J. BENSON Vice President -- Security THOMAS P. CHAMBERS Vice President -- Corporate Planning MATTHEW W. DUNDREA Vice President and Treasurer ROBERT J. DYE Vice President -- Investor Relations ERIC L. HARRY Vice President and Associate General Counsel P. ANTHONY LANNIE Vice President and 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 JON W. SAUER Vice President -- Tax CHERI L. PEPER Corporate Secretary --------------- (1) Executive Committee (2) Audit Committee (3) Management, Development & Compensation Committee (4) Nominating Committee (5) Stock Option Plan Committee SHAREHOLDER INFORMATION STOCK DATA
DIVIDENDS PRICE RANGE* PER SHARE** --------------- ----------------- HIGH LOW DECLARED PAID ------ ------ -------- ------ 2002 First Quarter..................................... $27.72 $21.13 $.0475 $.0475 Second Quarter.................................... 28.62 25.04 .0475 .0475 Third Quarter..................................... 28.57 21.46 .0475 .0475 Fourth Quarter.................................... 28.88 23.55 .0475 .0475 2001 First Quarter..................................... $31.55 $23.47 $ -- $ -- Second Quarter.................................... 28.92 20.80 -- -- Third Quarter..................................... 23.55 16.56 .121 -- Fourth Quarter.................................... 23.87 17.57 .0475 .121
--------------- * Per share prices have been adjusted to reflect the effects of the ten percent stock dividend in 2001, the five percent stock dividend in 2002 and the two-for-one stock split in 2003. ** The amounts in the chart have been adjusted to reflect the ten percent stock dividend in 2001, the five percent stock dividend in 2002 and the two-for-one stock split in 2003. The Company has paid cash dividends on its common stock for 36 consecutive years through December 31, 2002. During 2000, the Company changed the dividend payment schedule on its common stock from a quarterly basis to an annual basis; however, during 2001, the Company implemented a return to a quarterly dividend payment schedule beginning in 2002. 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 (symbol APA). At December 31, 2002, the Company's shares of common stock outstanding were held by approximately 8,000 shareholders of record and 104,000 beneficial owners. Also listed on the New York Stock Exchange are: - the Company's 9.25% notes, due 2002 (symbol APA 02) - 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 Minnesota, 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. 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 $5,000 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 Minnesota, N.A. ANNUAL MEETING Apache will hold its annual meeting of shareholders on Thursday, May 1, 2003, at 10 a.m. in the Ballroom, Doubletree Hotel at 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 EXHIBIT INDEX
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, 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, filed January 13, 2003, SEC File No. 1-4300). 3.1 -- Restated Certificate of Incorporation of Registrant, dated December 16, 1999, as filed with the Secretary of State of Delaware on December 17, 1999 (incorporated by reference to Exhibit 99.1 to Registrant's Current Report on Form 8-K, filed February 7, 2000, SEC File No. 1-4300). 3.2 -- Bylaws of Registrant, as amended May 2, 2002 (incorporated by reference to Exhibit 3.1 to Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, 2002, 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 Annual Report on Form 10-K for year ended December 31, 1995, 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, filed August 25, 1998, to Registrant's Current Report on Form 8-K, filed August 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, filed May 12, 1999, to Registrant's Current Report on Form 8-K, 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 -- Credit Agreement, dated June 12, 1997, among Registrant, the lenders named therein, Morgan Guaranty Trust Company, as Global Documentation Agent and U.S. Syndication Agent, The First National Bank of Chicago, as U.S. Documentation Agent, NationsBank of Texas, N.A., as Co-Agent, Union Bank of Switzerland, Houston Agency, as Co-Agent, and The Chase Manhattan Bank, as Global Administrative Agent (incorporated by reference to Exhibit 10.1 to Registrant's Current Report on Form 8-K, filed June 25, 1997, SEC File No. 1-4300). 10.2 -- 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). 10.3 -- 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).
EXHIBIT NO. DESCRIPTION ------- ----------- 10.4 -- Credit Agreement, dated June 12, 1997, among Apache Canada Ltd., a wholly-owned subsidiary of the Registrant, the Lenders named therein, Morgan Guaranty Trust Company, as Global Documentation Agent, Royal Bank of Canada, as Canadian Documentation Agent, The Chase Manhattan Bank of Canada, as Canadian Syndication Agent, Bank of Montreal, as Canadian Administrative Agent, and The Chase Manhattan Bank, as Global Administrative Agent (incorporated by reference to Exhibit 10.2 to Registrant's Current Report on Form 8-K, filed June 25, 1997, 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 -- Credit Agreement, dated June 12, 1997, among Apache Energy Limited and Apache Oil Australia Pty Limited, wholly-owned subsidiaries of the Registrant, the Lenders named therein, Morgan Guaranty Trust Company, as Global Documentation Agent, Bank of America National Trust and Savings Association, Sydney Branch, as Australian Documentation Agent, The Chase Manhattan Bank, as Australian Syndication Agent, Citisecurities Limited, as Australian Admin- istrative Agent, and The Chase Manhattan Bank, as Global Administrative Agent (incorporated by reference to Exhibit 10.3 to Registrant's Current Report on Form 8-K, filed June 25, 1997, SEC File No. 1-4300). 10.7 -- 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, NA, 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). 10.8 -- 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). 10.9 -- 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). 10.10 -- 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). 10.11 -- 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 ------- ----------- 10.12 -- 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). 10.13 -- 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). 10.14 -- 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). +10.15 -- 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). +10.16 -- 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). +10.17 -- 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). +**10.18 -- Amendment to Apache Corporation 401(k) Savings Plan, dated January 27, 2003, effective as January 1, 2003. +10.19 -- 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). +**10.20 -- Amendment to Apache Corporation Money Purchase Retirement Plan, dated January 27, 2003, effective as of January 1, 2003. +10.21 -- Non-Qualified Retirement/Savings Plan of Apache Corporation, restated as of January 1, 1997, and amendments effective as of 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). +10.22 -- Amendment to Non-Qualified Retirement/Savings Plan of Apache Corporation, dated February 22, 2000, effective as of 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 Post-Effective Amendment No. 1 to Registrant's Registration Statement on Form S-8, Registration No. 333-31092, filed August 18, 2000). +10.23 -- Amendment to Non-Qualified Retirement/Savings Plan of Apache Corporation, dated August 3, 2001, effective as of 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). +10.24 -- 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, as amended by Form 10-Q/A, for the quarter ended September 30, 2001, SEC File No. 1-4300).
EXHIBIT NO. DESCRIPTION ------- ----------- +**10.26 -- Apache Corporation 2000 Share Appreciation Plan, as amended and restated February 5, 2003, effective as of March 12, 2003. +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 -- 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). +10.31 -- 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). +10.32 -- Apache Corporation Deferred Delivery Plan, as amended and restated December 18, 2002, effective as of May 2, 2002 (incorporated by reference o 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). +10.33 -- Apache Corporation Executive Restricted Stock Plan, as amended and restated December 18, 2002, effective as of 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). +10.34 -- Apache Corporation Non-Employee Directors' Compensation Plan, as amended and restated December 17, 1998 (incorporated by reference to Exhibit 10.26 to Registrant's Annual Report on Form 10-K for year ended December 31, 1998, SEC File No. 1-4300). +10.35 -- 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). +10.36 -- Apache Corporation Equity Compensation Plan for Non-Employee Directors, as amended and restated May 3, 2001 (incorporated by reference to Exhibit 10.09 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 -- 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). +10.38 -- 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). +10.39 -- 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). +10.40 -- 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). +10.41 -- 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 by Form 10-Q, as amended on Form 10-Q/A, for the quarter ended June 30, 2001, SEC File No. 1-4300).
EXHIBIT NO. DESCRIPTION ------- ----------- 10.42 -- 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, filed June 23, 1998, SEC File No. 1-4300). 10.43 -- Deed of Guaranty and Indemnity, dated January 11, 2003, made by Registrant in favor of BP Exploration Operating Company Limited (incorporated by reference to Exhibit 10.1 to Regis- trant's Current Report on Form 8-K, 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 **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. **Previously filed. + 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.