10-K 1 h13064e10vk.txt APACHE CORPORATION - DECEMBER 31, 2003 . . . UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K (MARK ONE) [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 2003, OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM TO
COMMISSION FILE NUMBER 1-4300 APACHE CORPORATION A DELAWARE CORPORATION IRS EMPLOYER NO. 41-0747868 ONE POST OAK CENTRAL 2000 POST OAK BOULEVARD, SUITE 100 HOUSTON, TEXAS 77056-4400 TELEPHONE NUMBER (713) 296-6000 Securities Registered Pursuant to Section 12(b) of the Act:
NAME OF EACH EXCHANGE TITLE OF EACH CLASS ON WHICH REGISTERED ------------------- ------------------- Common Stock, $0.625 par value New York Stock Exchange Chicago Stock Exchange Preferred Stock Purchase Rights New York Stock Exchange Chicago Stock Exchange Apache Finance Canada Corporation New York Stock Exchange 7.75% Notes Due 2029 Irrevocably and Unconditionally Guaranteed by Apache Corporation
Securities Registered Pursuant to Section 12(g) of the Act: Common Stock, $0.625 par value Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ] Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ] Indicate by check whether registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). [X] Aggregate market value of the voting and non-voting common equity held by non-affiliates of registrant as of June 30, 2003...................................................... $10,526,544,439 Number of shares of registrant's common stock outstanding as of February 29, 2004...................................... 325,035,928
DOCUMENTS INCORPORATED BY REFERENCE: Portions of registrant's proxy statement relating to registrant's 2004 annual meeting of stockholders have been incorporated by reference into Part III hereof. TABLE OF CONTENTS DESCRIPTION
ITEM PAGE ---- ---- PART I 1. BUSINESS.................................................... 1 2. PROPERTIES.................................................. 13 3. LEGAL PROCEEDINGS........................................... 13 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS......... 13 PART II 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS......................................... 14 6. SELECTED FINANCIAL DATA..................................... 16 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS................................... 16 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK........................................................ 37 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA................. 39 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.................................... 39 9A. CONTROLS AND PROCEDURES..................................... 39 PART III 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.......... 40 11. EXECUTIVE COMPENSATION...................................... 40 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.................................................. 40 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.............. 40 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES...................... 40 PART IV 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K......................................................... 41
All defined terms under Rule 4-10(a) of Regulation S-X shall have their statutorily prescribed meanings when used in this report. Quantities of natural gas are expressed in this report in terms of thousand cubic feet (Mcf), million cubic feet (MMcf), billion cubic feet (Bcf) or trillion cubic feet (Tcf). Oil is quantified in terms of barrels (bbls); thousands of barrels (Mbbls) and millions of barrels (MMbbls). Natural gas is compared to oil in terms of barrels of oil equivalent (boe) or million barrels of oil equivalent (MMboe). Oil and natural gas liquids are compared with natural gas in terms of million cubic feet equivalent (MMcfe) and billion cubic feet equivalent (Bcfe). One barrel of oil is the energy equivalent of six Mcf of natural gas. Daily oil and gas production is expressed in terms of barrels of oil per day (b/d) and thousands or millions of cubic feet of gas per day (Mcf/d and MMcf/d, respectively) or millions of British thermal units per day (MMBtu/d). Gas sales volumes may be expressed in terms of one million British thermal units (MMBtu), which is approximately equal to one Mcf. With respect to information relating to our working interest in wells or acreage, "net" oil and gas wells or acreage is determined by multiplying gross wells or acreage by our working interest therein. Unless otherwise specified, all references to wells and acres are gross. PART I 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, offshore the United Kingdom in the North Sea and onshore Argentina. Our common stock, par value $0.625 per share, has been listed on the New York Stock Exchange (NYSE) since 1969, on the Chicago Stock Exchange since 1960, and on the NASDAQ National Market (NASDAQ) since January 2004. Through our website, http://www.apachecorp.com, you can access electronic copies of the charters of the committees of our board of directors, other documents related to Apache's corporate governance, and documents Apache files with the Securities and Exchange Commission (SEC), including our annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, 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. 2003 RESULTS Strong crude oil and natural gas prices and our record production during 2003 provided us with record income attributable to common stock of $1.1 billion on total revenues of $4.2 billion, and record cash provided by operating activities of $2.7 billion, a 96 percent increase from 2002. Our 2003 daily production averaged 214.5 Mbbls of oil and natural gas liquids, and 1,217 MMcf of natural gas. Our financial and operational performance enabled us to enhance our financial flexibility by further strengthening our balance sheet and maintain senior unsecured long-term debt ratings of A3 from Moody's, and A- from Standard and Poor's and Fitch rating agencies. We increased our total reserves by 26 percent, compared with the end of 2002, resulting in 1.66 billion boe of estimated proved reserves at year-end, 49 percent of which were natural gas. In 2003, we completed two significant acquisitions in the Gulf of Mexico and entered a new core area with our purchase of the Forties Field in the UK North Sea. In January 2003, we agreed to purchase properties from subsidiaries of BP p.l.c. (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), our largest acquisition so far. The Company closed the Gulf of Mexico portion on March 13, 2003 at an adjusted price of $509 million. This acquisition had estimated proved reserves of 67.1 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 $73 million), production and expenses since January 1, 2003, the effective date of the transaction, and other minor adjustments. The North Sea portion closed on April 2, 2003 for an adjusted purchase price of $630 million. The North Sea acquisition had an estimated 143.7 MMboe of reserves. The acquisition was funded by a combination of proceeds from an equity offering we completed in January 2003, cash from our operations and debt. On July 3, 2003, we completed the acquisition of producing properties on the Outer Continental Shelf of the Gulf of Mexico from Shell Exploration and Production Company for a purchase price of $200 million, subject to post closing adjustments, including adjustments for the exercise of preferential rights. The acquisition included 26 fields covering 50 blocks (approximately 1 209,000 acres) and interests in two onshore gas plants, and we now operate 15 of the fields with 91 percent of the production. We recorded proved reserves of approximately 124.9 Bcf of natural gas and 6.1 million barrels of oil (26.9 MMboe). Prior to the transaction, Morgan Stanley paid Shell $300 million to acquire an overriding royalty interest in a portion of the lower-risk reserves to be produced over the next four years. Throughout this report, per share results and share amounts have been adjusted for the 10 percent common stock dividend paid on January 21, 2002, to our shareholders of record on December 31, 2001, the five percent common stock dividend paid on April 2, 2003, to our shareholders of record on March 12, 2003 and the two-for-one stock split distributed on January 14, 2004 to our shareholders of record on December 31, 2003. The stock dividends and stock split reflect our board of directors' belief that we can reward our shareholders while remaining focused on our primary objective of building Apache to last by achieving profitable growth. OUR GROWTH STRATEGY As Apache enters our 50th year, our mission remains the same as at inception: to grow a significant and profitable company for the benefit of our shareholders. Over the years our strategy for achieving profitable growth has evolved. Over the most recent decade Apache has been an active acquirer of properties, following up with proactive exploitation operations, including workovers, re-completions, and drilling, to increase production, and efforts to reduce costs per unit produced and enhance profitability. Also over the past decade, we added an international component to our strategy, which exposed our shareholders to larger reserve targets and a greater ability to grow production and reserves through drilling. Our expenditures in 2003 were well balanced between acquisitions and drilling, with Apache having a robust year for both. During the year, we invested over $1.6 billion in purchasing 267 MMboe. As for our active drilling program, Apache invested $1.5 billion drilling 1,449 gross wells to add 234.3 MMboe. We plan on another substantial year of drilling activity in 2004, with a preliminary capital budget of approximately $1.8 billion. We do not budget for acquisitions because their timing is unpredictable; however, a significant part of Apache's growth strategy continues to be directed toward the purchase of properties to which we can add value and earn adequate rates of return. Because we maintained our financial flexibility (our yearend ratio of debt-to-capitalization was just over 26 percent), we are in a good position to take advantage of acquisition opportunities that may arise. We take a portfolio approach to the areas in which we drill in an effort to generate consistent, profitable growth. In the U.S., our Gulf of Mexico operations generate substantial production and cash flow and excellent rates of return, however, with steep decline rates, offshore reserves are generally short lived and difficult to replace through drilling alone. Our Central region brings the balance of long-lived reserves and consistent drilling results. In general, the United States is mature, offering smaller reserve targets but presently, excellent prices and high margins. We seek to drill actively in the United States, but not to the extent of pursuing growth at any cost. Our future growth is more likely to be achieved in the U.S. through drilling and acquisition, rather than through drilling activity alone. Apache's Canadian and International operations provide the potential to grow through drilling. Canada, Australia, Egypt and, in the last year, the North Sea, all offer larger reserve targets than those to which we are exposed in the United States. Also, Apache's international operations in Canada, Egypt and Australia typically include large acreage positions with considerable running room when compared to the U.S., where there are more companies competing for acreage and drilling opportunities. In today's industry environment, with high prices and substantial cash flow and earnings, competing for quality opportunities to grow through drilling or acquisition is a challenge. However, Apache has grown production 24 of the last 25 years and reserves for 18 consecutive years in differing industry environments. We are fortunate to have evolved to the point where we believe we have the ability to continue growing over time through drilling, acquisition or both. 2 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, the United Kingdom, China and Argentina. In 2003, we ceased operations in Poland. Our core areas are defined as the United States, Canada, Egypt, Australia, the United Kingdom and Other International. In the U.S., our exploration and production activities are divided into two regions: Gulf Coast and Central. At year-end, approximately 70 percent of our estimated proved reserves were located in North America. Outside North America, our exploration and production activities are focused primarily in Egypt, the North Sea and Australia. Additionally, production began on our interests in China in July 2003, and we have a small production interest in Argentina. The table below sets out a brief comparative summary of certain 2003 data for each area. More detailed information regarding the natural gas, oil, and natural gas liquids (NGLs) production and average prices received in 2003, 2002 and 2001 for our 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.
12/31/03 PERCENTAGE 2003 2003 ESTIMATED OF TOTAL 2003 GROSS NEW 2003 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............... 48.9 $1,470.0 350 21.1% 85 67 Central.................. 19.7 553.5 378 22.8 208 200 ----- -------- ----- ----- ----- ----- Total U.S. ............ 68.6 2,023.5 728 43.9 293 267 ----- -------- ----- ----- ----- ----- Canada................... 29.1 823.3 436 26.3 984 913 ----- -------- ----- ----- ----- ----- Total North America.... 97.7 2,846.8 1,164 70.2 1,277 1,180 ----- -------- ----- ----- ----- ----- Egypt.................... 24.3 652.9 165 10.0 107 94 Australia................ 17.9 392.0 167 10.0 37 19 United Kingdom........... 10.8 273.0 148 9.0 -- -- China.................... 1.0 26.8 11 .7 25 25 Argentina................ .6 7.4 2 .1 3 1 ----- -------- ----- ----- ----- ----- Total International.... 54.6 1,352.1 493 29.8 172 139 ----- -------- ----- ----- ----- ----- Total.................. 152.3 $4,198.9 1,657 100.0% 1,449 1,319 ===== ======== ===== ===== ===== =====
The following discussions include references to our plans for 2004. These only represent initial estimates and will be reviewed and revised throughout the year in light of changing industry conditions. United States An increase in our capital spending over 2002's level led to a busy drilling year in which we completed 267 out of 293 total wells and replaced 79 percent of our domestic production through extensions, discoveries and other additions. 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 2003, the Gulf Coast region was once again our leading 3 region for production volumes and revenues. This region performed 354 workover and recompletion operations during 2003 and completed 67 out of 85 total wells drilled, replacing 51 percent of the regions production from extensions, discoveries and other additions. As of year-end 2003, Gulf Coast accounted for 21 percent of our estimated proved reserves. In 2004, we currently plan on spending approximately $400 million to drill an estimated 100 wells and to continue exploitation. We will continue our production enhancement program and exploitation of properties acquired from BP and Shell in 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 2003, the Central region accounted for approximately 23 percent of our estimated proved reserves, the second largest in the Company. During 2003, we participated in 208 wells, 200 of which were completed as productive wells, replacing 150 percent of the region's production from extensions, discoveries and other additions. Apache performed 357 workovers and recompletions in the region during the year. In 2004, we currently plan to spend approximately $150 million drilling an estimated 200 wells and continuing our production enhancement programs. Marketing -- The Company began marketing its domestic natural gas production in July 2003. Our objective is to enhance the value of our natural gas sales by diversifying our customer base and optimizing transportation arrangements. The flexibility to transport our gas from the wellhead has provided us access to new markets as our customers now include Local Distribution Companies (LDCs), utilities, endusers, integrated majors and marketers. We manage our credit risk by only selling to creditworthy customers and monitoring our credit exposure daily. Prior to July 2003, Apache sold most of its U.S. natural gas production to Cinergy Marketing and Trading, LLC (Cinergy), under a long-term gas purchase agreement. The prices received for our gas production under this agreement were based on published indexes. (See Note 11 under Item 15 of this Form 10-K). Several years ago, we locked in a portion of our domestic future natural gas production at a fixed price using long-term fixed price physical contracts. These contracts, which represented approximately 9 percent of our 2003 domestic natural gas production, will expire in 2007 and 2008. The contracts provide protection to the Company in the event of decreasing natural gas prices. Most of our gas is being sold monthly at market prices. However, to meet the needs of our customers, we may sell some of our gas under long-term contracts at prices that fluctuate with market conditions. We market our own U.S. crude oil to integrated majors, marketers and refiners. Contracts are generally 30 days and renew automatically until canceled. These oil contracts provide for sales 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 26 percent of our estimated proved reserves, the largest in the Company. We hold over 4.7 million net acres in Canada, the largest of the North American regions. 2003 -- Canada was our most active region for drilling in 2003, with Apache participating in 984 gross wells, approximately half of which were shallow development wells, 913 of which were completed as producers. We also conducted 889 workover and recompletion projects. We replaced 275 percent of our Canadian production through extensions, discoveries and other additions. 2004 -- We currently plan to spend approximately $450 million drilling an estimated 1,100 wells, continuing the exploration program, exploiting acquired properties and developing our gas processing infrastructure. Marketing -- Our Canadian natural gas sales include sales to Local Distribution Companies (LDCs), utilities, endusers, integrated majors, supply aggregators and marketers in the United States and Canada. With the expansion of pipeline transport capacity out of Canada in recent years, Canadian prices have become more 4 closely correlated with United States prices. To diversify our market exposure and optimize pricing differences in the U.S. and Canada, we transport natural gas via our firm transportation contracts to California, the Chicago area, and eastern Canada. We currently have longer term commitments to sell gas into the United States in the Pacific Northwest, the upper Midwest and the northeastern U.S. market regions (See Note 11 under Item 15 of this Form 10-K). The volumes are relatively small and none of the terms extend beyond 2008. We also have long-term commitments to supply production to a market in eastern Canada. Again, the volumes are relatively small and the term is through 2011. The prices we receive under these contracts fluctuate monthly with market indices. The remainder of our natural gas production is sold monthly at market prices. Our Canadian crude oil is primarily sold to refiners, integrated majors and marketers. Our condensate is primarily sold to heavy oil producers for blending purposes. All NGLs are sold to midstream companies. We sell our crude and NGLs on Canadian Postings which are market reflective prices that depend on worldwide crude prices and are adjusted for transportation and crude quality. In order to reach more purchasers and diversify our market we transport crude on 12 pipelines to the major trading hubs within Alberta, Saskatchewan and Manitoba. Egypt 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, 2003, we held over 6.6 million net acres encompassing 12 concessions. Apache is the largest producer of liquid hydrocarbons and the second largest producer of natural gas in the Western Desert. 2003 -- Egypt accounted for 16 percent of Apache's production revenues on 16 percent of total production for the year and accounted for 10 percent of total proved reserves at December 31, 2003. Apache had an active drilling program in Egypt, completing 94 of 107 gross wells, for a success rate of 88 percent. 2004 -- We currently plan to spend approximately $300 million to drill more than 100 wells and continue exploitation. Our plans seek to maintain momentum and preserve our flexibility to respond to market conditions with a balanced mix of exploratory and development drilling. Marketing -- In 1996, we and our partners in the Khalda Block entered into a 25-year 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 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 our Qarun development lease. However, we have entered into new gas sales contracts containing Industry Pricing at our Matruh, Ras Kanayes, Ras El Hekma, and Akik development leases. We also entered into a Memorandum of Understanding (MOU) for a Gas Sales Agreement, Field Development Plan and Deepwater Development Lease for a minimum of 2.7 Tcf of natural gas over 25 years from our deepwater interests in the West Mediterranean Concession. Reserve recognition and proper scaling of the significant future development infrastructure are pending negotiation and completion of the final sales agreement with EGPC and resolution in delays of certain payments by EGPC. 5 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 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 presently sold to EGPC on a spot basis at a "Western Desert" price (indexed to Brent Crude Oil). Australia Our exploration activity in Australia is focused in the offshore Carnarvon and Perth Basins where Apache holds 4.4 million net acres in 26 Exploration Permits, 10 Production Licenses, and four Retention Leases. Production operations are concentrated in the Carnarvon Basin within 10 Production Licenses, nine of which are operated by Apache. 2003 -- We produced 17.9 million barrels of oil equivalent in Australia (12 percent of our total) generating $392 million of production revenues. During the year we participated in drilling 37 wells; 24 exploration and 13 development wells. Ten of the exploration wells and nine of the development wells were successful for an overall 51 percent success rate. Additionally, there were 11 workover and recompletion projects performed during the year. Apache added 33.0 million barrels of oil equivalent to our Australian reserve base through exploration and development activities and another 6.7 million barrels of oil equivalent by way of acquisitions, as we increased our interest in the John Brookes gas field from 20 percent to 55 percent and assumed operatorship. The 39.7 million barrels of oil equivalent reserve add equates to a 222 percent replacement of production, 184 percent of which came through drilling operations. Our Australian region had a successful exploration year with five discoveries, the most significant being Ravensworth, Crosby, and Thomas Bright. We also had a very substantial appraisal program with 10 successes. On the development side, the Double Island oil field commenced production in February 2003, 12 months from discovery, at an average net rate of 6,165 barrels of oil per day and has thus far produced 1.7 million barrels of oil equivalent net to Apache's 68.5 percent interest. The East Spar-6 development well was placed on production in mid November at an average rate of 33 million cubic feet of gas per day and 1,733 barrels of condensate per day net to Apache's 55 percent interest. Fabrication of the platform for the Linda gas development has been completed with installation scheduled for February 2004 and first gas expected in April 2004. Apache owns a 68.5 percent interest in the Linda gas field. 2004 -- First production from the Linda gas development is scheduled for April 2004 at an average projected rate of 19 million cubic feet of gas and 900 barrels of condensate per day net to Apache's 68.5 percent interest. The John Brookes gas development is underway with first production anticipated in the second quarter of 2005. For 2004, we have budgeted expenditures of over $200 million for an estimated 25 exploration wells, nine appraisal wells, eight development wells, and various production development and enhancement capital projects. Marketing -- In Australia, we executed two new gas sales contracts and extended four existing gas sales contracts during 2003, bringing our total to 22 active contracts. In aggregate, we committed a further 115 billion cubic feet of gas (gross) for delivery. Under the largest new contract, we will supply more than 88 billion cubic feet of gas over an 11-year period which commenced in July 2003. Additionally, we were awarded two conditional gas contracts with a combined commitment of 114 billion cubic feet of gas (gross). The larger contract would have us deliver 102 billion cubic feet of gas over a 14-year period beginning in September 2004. Our total Australian net delivery rates are expected to average approximately 115 million cubic feet of gas per day in 2004. Generally, natural gas is sold in Western Australia 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. We continue to export all of our crude oil production to domestic and international buyers at prices which fluctuate with world market conditions. 6 United Kingdom With the closing of our purchase of the Forties Field in April 2003, we established a new core area in the North Sea. The Forties Field was first discovered in 1970, and has been one of the most productive fields in the UK North Sea. At the time of closing, Apache booked 143.7 MMboe of reserves, and produced an average of approximately 41 Mbbls/d of oil and 1,400 Mcf/d of natural gas through year-end. Apache acquired operatorship of the field with a 96 percent interest, which includes five platforms. Our North Sea interests had production of 10.8 MMboe in 2003, provided us with $273 million of production revenue, and accounted for nine percent of our year end proved reserves. We plan a significant capital program for the North Sea during 2004, with a projected drilling budget of approximately $300 million for 20 wells and various production, development and enhancement capital projects. Marketing -- Concurrent with the acquisition of the UK North Sea properties, the Company entered into a separate crude oil physical sales contract with BP. The contract provides for BP to market all of the Company's equity crude oil through December 31, 2004. A portion of the crude oil (25,000 b/d through January 31, 2004 and 40,000 bopd for the remainder of the term) is sold at fixed prices. The balance of the crude oil is sold at prevailing market prices. We are reviewing potential marketing arrangements upon expiration of our term sales contract with BP. The possible marketing strategies include expanding the current customer base and selling a portfolio mix of spot and term arrangements into the export market. Other International We have exploration and production interests offshore China and in Argentina. During 2003, we ceased operations in Poland. In August, first production came on stream from our interests in the Zhao Dong block in Bohai Bay, China, at the rate of 6,000 barrels of oil per day from three wells. Production is projected to reach its peak level of approximately 22,000 barrels per day in the first half of 2004. In 2003, our Chinese interests produced $26.8 million of production revenue on over 1 MMboe of production. We are the operator, with a 24.5 percent interest, of the Zhao Dong Block. Since production began, we have exported our portion of the production to international companies at prices that change with market conditions. We currently plan to spend an estimated $20 million of drilling capital this year. 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. During 2003, we ceased operations in Poland, and we wrote off $16 million ($10 million net of tax), of which $13 million was recorded as an impairment of the remaining unproved property costs. In 2001, we acquired exploration and production assets of Fletcher Challenge and Anadarko Petroleum in Argentina. After these transactions, we hold interests in a number of blocks in Argentina's Neuquen basin. We are the operator, with a 100 percent interest, in two blocks and hold smaller interests in another four blocks. For the year, these interests represent under one percent of our proved reserves and generated small amounts of production and revenue. Our total net acreage in Argentina is 375,769 acres, with 328,049 developed and 47,720 undeveloped at year-end 2003. In 2004, we plan to spend approximately $4 million drilling six wells in Argentina. DRILLING STATISTICS Worldwide, in 2003, we participated in drilling 1,449 gross wells, with 1,319 (91 percent) completed as producers. Canada was our most active region, drilling 984 gross new, mostly development wells, with a success rate of 92.8 percent. We also performed over 2,000 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 drilling activities focus more on exploration drilling and our Canadian region on a mix of exploration and exploitation. In addition to our completed wells, at year-end several wells had not yet reached completion: 17 in the U.S. (9 net); 17 in Canada (15.5 net); 11 in Egypt (10.5 net); one in Australia (0.6 net); and one in Argentina (0.3 net). 7 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 ---------- ---- ----- ---------- ---- ----- ---------- ----- ------- 2003 United States............. 2.2 -- 2.2 133.6 18.3 151.9 135.8 18.3 154.1 Canada.................... 57.3 25.3 82.6 742.8 34.8 777.6 800.1 60.1 860.2 Egypt..................... 15.5 5.2 20.7 76.2 6.0 82.2 91.7 11.2 102.9 Australia................. 8.4 10.8 19.2 2.3 -- 2.3 10.7 10.8 21.5 United Kingdom............ -- -- -- -- -- -- -- -- -- China..................... -- -- -- 6.1 -- 6.1 6.1 -- 6.1 Other International....... -- .6 .6 .3 -- .3 .3 .6 .9 ---- ---- ----- ----- ---- ------- ------- ----- ------- Total.............. 83.4 41.9 125.3 961.3 59.1 1,020.4 1,044.7 101.0 1,145.7 ==== ==== ===== ===== ==== ======= ======= ===== ======= 2002 United States............. 3.0 3.5 6.5 92.8 17.1 109.9 95.8 20.6 116.4 Canada.................... 25.9 10.1 36.0 714.2 20.4 734.6 740.1 30.5 770.6 Egypt..................... 7.7 7.0 14.7 32.3 6.0 38.3 40.0 13.0 53.0 Australia................. 6.3 7.6 13.9 1.3 -- 1.3 7.6 7.6 15.2 Other International....... -- -- -- -- -- -- -- -- -- ---- ---- ----- ----- ---- ------- ------- ----- ------- Total.............. 42.9 28.2 71.1 840.6 43.5 884.1 883.5 71.7 955.2 ==== ==== ===== ===== ==== ======= ======= ===== ======= 2001 United States............. 5.9 4.4 10.3 202.9 32.0 234.9 208.8 36.4 245.2 Canada.................... .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 .3 -- .3 .3 3.4 3.7 ---- ---- ----- ----- ---- ------- ------- ----- ------- Total.............. 12.5 24.5 37.0 581.6 59.3 640.9 594.1 83.8 677.9 ==== ==== ===== ===== ==== ======= ======= ===== =======
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, 2003, is set forth below:
GAS OIL TOTAL -------------- -------------- ---------------- GROSS NET GROSS NET GROSS NET ----- ----- ----- ----- ------ ------ Gulf Coast...................................... 995 654 1,164 797 2,159 1,451 Central......................................... 2,545 1,280 3,261 2,055 5,806 3,335 Canada.......................................... 5,122 4,433 2,288 960 7,410 5,393 Egypt........................................... 25 24 239 226 264 250 Australia....................................... 8 5 41 22 49 27 United Kingdom.................................. -- -- 48 47 48 47 China........................................... -- -- 11 3 11 3 Argentina....................................... 17 5 36 23 53 28 ----- ----- ----- ----- ------ ------ Total.................................... 8,712 6,401 7,088 4,133 15,800 10,534 ===== ===== ===== ===== ====== ======
8 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.................................. 1,156,022 695,682 2,603,016 1,610,265 Canada......................................... 3,741,303 2,724,595 2,831,527 1,981,522 Egypt.......................................... 9,084,916 5,636,139 1,128,037 1,012,089 United Kingdom................................. 87,498 72,220 29,924 29,068 Australia...................................... 8,231,350 4,152,950 467,770 274,470 China.......................................... 5,314 2,657 5,911 1,448 Poland......................................... 473,469 355,252 -- -- Argentina...................................... 174,402 47,720 534,686 328,049 ---------- ---------- --------- --------- Total Company............................. 22,954,274 13,687,215 7,600,871 5,236,911 ========== ========== ========= =========
PRODUCTION AND PRICING DATA The following table describes, for each of the last three fiscal years, oil, 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) ----------------------- ------- ------- ------- ------------ --------- --------- --------- 2003 United States.......... 25,332 2,766 242,782 5.14 27.48 21.70 5.22 Canada................. 9,205 571 116,263 5.41 29.06 19.25 4.69 Egypt.................. 17,356 -- 41,447 3.40 27.64 -- 4.18 Australia.............. 11,165 -- 40,537 4.05 29.87 -- 1.44 United Kingdom......... 10,680 -- 626 11.94 25.40 -- 2.77 China.................. 1,019 -- -- 5.18 26.33 -- -- Argentina.............. 211 -- 2,607 5.76 29.23 -- .47 ------ ----- ------- ----- ----- ----- ---- Total............. 74,968 3,337 444,262 5.27 27.76 21.28 4.61 ====== ===== ======= ===== ===== ===== ==== 2002 United States.......... 19,348 2,442 183,708 5.21 25.31 15.29 3.15 Canada................. 9,205 641 120,210 3.83 23.46 12.41 2.74 Egypt.................. 15,977 -- 44,769 2.95 24.65 -- 3.71 Australia.............. 11,082 -- 42,998 3.06 25.17 -- 1.28 Other International.... 225 -- 2,656 2.58 23.90 -- 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 ====== ===== ======= ===== ===== ===== ====
ESTIMATED PROVED RESERVES AND FUTURE NET CASH FLOWS As of December 31, 2003, Apache had total estimated proved reserves of 843.9 million barrels of crude oil, condensate and NGLs and 4.9 Tcf of natural gas. Combined, these total estimated proved reserves are 9 equivalent to 1.66 billion barrels of oil or 9.9 Tcf of gas. The company's reserves have grown for the 18th consecutive year. Estimated proved developed reserves comprise 71.5 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, 2003, 2002 and 2001, 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 2003 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. 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 2003, 2002 and 2001, their review covered 78, 68, and 61 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 Statement of Financial Accounting Standards (SFAS) No. 69, "Disclosures about Oil and Gas producing Activities." Disclosure of this value and related reserves has been prepared in accordance with SEC Regulation S-X Rule 4-10 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. 10 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, 2003, 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. 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. In October 2003, Apache was issued a Findings of Violation and Order for Compliance (an "Administrative Order") by the United States Environmental Protection Agency (EPA), which cited certain paperwork administrative errors and effluent violations reported by Apache during the period May 1, 1998 to June 30, 2003, as part of our offshore discharge permit monitoring. In discussions with the EPA, Apache has agreed to pay a monetary penalty of $20,650 and undertake a Supplemental Environmental Project with an estimated cost of $94,500. As of December 31, 2003, 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 upstream companies in the industry. We do not believe that compliance with federal, state, local or foreign country provisions regulating the discharge of materials into the environment, or otherwise relating to the protection of the environment, will have a material adverse effect upon the capital expenditures, earnings or competitive position of Apache or its subsidiaries; however, there is no assurance that changes in or additions to laws or regulations regarding the protection of the environment will not have such an impact. 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 low finding and production costs 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 11 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 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. Ernst & Young also served as our independent public accountants in 2003. However, included in this annual report on Form 10-K, are financial data and other information for 2001 that were audited by Arthur Andersen. Investors in our securities may encounter difficulties in obtaining, or be unable to obtain, from Arthur Andersen with respect to its audits of our financial statements, relief that may be available to investors under the federal securities laws against auditing firms. 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 12 would customarily be performed by potential investors in our securities, which process included 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, 2003, we had 2,353 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 2003, we maintained regional exploration and/or production offices in Tulsa, Oklahoma; Houston, Texas; Calgary, Alberta; Cairo, Egypt; Perth, Western Australia; Aberdeen, Scotland; Beijing, China; and Buenos Aires, Argentina. Apache leases all of its primary office space. The current lease on our principal executive offices runs through December 31, 2013. For information regarding the Company's obligations under its office leases, see the information appearing in the table in Item 7 -- Management's Discussion and Analysis of Financial Condition and Results of Operations, "Liquidity" and 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 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 A special meeting of the Company's stockholders was held in Houston, Texas, at 10:00 a.m. local time, on Thursday, December 18, 2003. Proxies for the meeting were solicited pursuant to Regulation 14 under the Securities Act of 1934, as amended. There was no solicitation in opposition to the proposal to amend the Company's Restated Certificate of Incorporation to increase the number of authorized shares of Apache's common stock from 215,000,000 shares to 430,000,000 shares, and the amendment was approved. 13 Out of a total of 162,037,849 shares of the Company's common stock outstanding and entitled to vote as of October 29, 2003, the record date for the special meeting, October 29, 2003, 142,137,696 shares, or 87.7 percent, were present at the meeting in person or by proxy. The vote tabulation for amendment of Apache's Restated Certificate of Incorporation was as follows:
FOR AGAINST WITHHELD ----------- --------- -------- 140,150,724 1,173,351 813,621
The shares referenced above have not been adjusted for the two-for-one stock split, record date December 31, 2003, distributed January 14, 2004. PART II ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS During 2003 Apache common stock, par value $0.625 per share, was traded on the New York Stock Exchange, the Chicago Stock Exchange under the symbol APA. The table below provides certain information regarding our common stock for 2003 and 2002. 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 five percent stock dividend, all of which are described below. Per share prices and dividends shown below have been rounded to the indicated decimal place.
2003 2002 ------------------------------------- ------------------------------------- PRICE RANGE DIVIDENDS PER SHARE PRICE RANGE DIVIDENDS PER SHARE --------------- ------------------- --------------- ------------------- HIGH LOW DECLARED PAID HIGH LOW DECLARED PAID ------ ------ --------- ------- ------ ------ --------- ------- First Quarter........... $32.15 $26.26 $.0475 $.0475 $27.71 $21.12 $.0475 $.0475 Second Quarter.......... 34.60 28.13 .0500 .0500 28.61 25.03 .0475 .0475 Third Quarter........... 35.04 30.41 .0600 .0500 28.57 21.46 .0475 .0475 Fourth Quarter.......... 41.68 34.05 .0600 .0600 28.88 23.53 .0475 .0475
The closing price per share of our common stock, as reported on the New York Stock Exchange Composite Transactions Reporting System for February 27, 2004 , was $41.17. At February 29, 2004, there were 325,035,928 shares of our common stock outstanding held by approximately 8,000 shareholders of record and approximately 157,000 beneficial owners. We have paid cash dividends on our common stock for 39 consecutive years through December 31, 2003. 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 2.310 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 14 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. 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 26,916,872 shares (adjusted for the 2002 five percent stock dividend and the 2003 stock split) of our common stock on January 21, 2002 to the holders of the 130,888,270 shares (adjusted for the five percent stock dividend and the 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 issued approximately 15,736,496 shares of (adjusted for the 2003 stock split) our common stock on April 2, 2003 to the holders of the 307,819,628 of common stock outstanding (adjusted for the 2003 stock split) on March 12, 2003. No fractional shares were issued in connection with the stock dividend and we made cash payments totaling approximately $1,437,000 in lieu of fractional shares. On January 22, 2003, in conjunction with the pending BP acquisition, the Company completed the public offering of 19.8 million shares (adjusted for the stock split) of Apache common stock, including 2.6 million shares (adjusted for the stock split) for the underwriters' over-allotment option, at $29.05 per share. Net proceeds after placement fees totaled approximately $554 million. The proceeds were used to repay indebtedness under our commercial paper program and money market lines of credit and to invest in short-term treasury-only money market funds and treasury notes to hold funds for the $1.3 billion BP acquisition. On September 11, 2003, our board of directors declared a two-for-one common stock split which was distributed on January 14, 2004 to holders of record on December 31, 2003. In connection with the stock split, the company issued 166,254,667 shares. 15 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, 2003, which information has been derived from the Company's audited financial statements. Our financial statements for the years 1999 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 issues related to Arthur Andersen in Item 1 of this Form 10-K "Risk Factors Related to our Business and Operations." 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, --------------------------------------------------------------- 2003 2002 2001 2000 1999 ----------- ---------- ---------- ---------- ---------- (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) INCOME STATEMENT DATA Total revenues and other........ $ 4,190,299 $2,559,873 $2,809,391 $2,301,978 $1,161,697 Income attributable to common stock......................... 1,116,205 543,514 703,798 693,068 186,406 Net income per common share: Basic......................... 3.46 1.83 2.44 2.54 .75 Diluted....................... 3.43 1.80 2.37 2.46 .74 Cash dividends declared per common share.................. .22 .19 .17 .09 .12 BALANCE SHEET DATA Total assets.................... 12,416,126 9,459,851 8,933,656 7,481,950 5,502,543 Long-term debt.................. 2,326,966 2,158,815 2,244,357 2,193,258 1,879,650 Preferred interests of subsidiaries.................. -- 436,626 440,683 -- -- Shareholders' equity............ 6,532,798 4,924,280 4,418,483 3,754,640 2,669,427 Common shares outstanding....... 324,497 302,506 287,917 285,596 263,332
For a discussion of significant acquisitions, see Note 3 to the Company's consolidated financial statements in Item 15 of this Form 10-K. ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS OVERVIEW Apache Corporation is an independent energy company whose principle business includes exploration, development and production of crude oil, natural gas and natural gas liquids. During 2003 the Company added an additional international core area with the acquisition of the U.K. North Sea Forties Field from BP p.l.c. (BP). The Company's other core geographic areas include operations in the United States, Canada, Australia and Egypt. Smaller, non-core operations are conducted in China and Argentina. Apache adheres to a portfolio approach to provide diversity in terms of hydrocarbon mix (crude oil and natural gas), geologic risk and geographic location. Our growth strategy focuses on economic growth through drilling, through acquisitions, or through a combination of both, depending on what the environment gives us. As we pursue growth, we continually monitor the capital resources available to us to meet our future financial obligations and liquidity needs. These obligations and needs must be met with cash on hand, cash generated from our operations, unused committed borrowing capacity under our global credit facility and the capital markets. The interest cost of debt and access to the equity markets are greatly influenced by a company's ability to maintain a strong balance sheet and generate ongoing operating cash flow. For these reasons, we strive to maintain a manageable debt load that is properly balanced with equity, and our single-A credit ratings. We are also cognizant of the costs to add reserves through drilling and acquisitions as well as the costs necessary to produce such reserves. Consequently, we must stay abreast of industry drilling costs and the price 16 at which properties are available for purchase, when choosing where to allocate our available funds. We monitor operating costs, on both an absolute dollar and per unit of production basis, relative to our historical norms and relative to our industry sector, factoring in the impact from property acquisitions and changes in industry conditions. Given the inherent volatility and unpredictability of commodity prices, and changing industry conditions, we frequently revise our forecasts and adjust our budgets accordingly. Commodity prices throughout 2003 were relatively high and remained consistently strong throughout the year. This price consistency allowed us to maintain a fairly constant level of capital expenditures for exploration and development drilling throughout the year. Our 2003 drilling and acquisition capital expenditures (discussed below) were balanced, as we grew both production and reserves to record levels, while maintaining a balance in terms of hydrocarbon mix. We had exceptional profitability growth in 2003, achieving several operational and financial milestones noted below: - Our 2003 oil and gas production revenues reached a record $4.2 billion, 64 percent higher than in 2002. - We generated record earnings of $1.1 billion, more than twice our prior-year level. More importantly, on a diluted share basis earnings rose 91 percent to a record $3.43 per share. - Cash from operating activities increased 96 percent from the prior year to a record $2.7 billion. - Production averaged a record 417,400 barrels of oil equivalent per day (boe/d), the 24th increase in the last 25 years. - In mid-July 2003, production was initiated on the Zhao Dong block in Bohai Bay, offshore China. - We began actively marketing our U.S. natural gas effective with July 2003 production. With our 2nd quarter North American daily natural gas production exceeding one billion cubic feet (Bcf), we felt it was prudent to bring this responsibility back in-house. - On December 16, 2003 we announced the signing of a Memorandum of Understanding (MOU) with the Egyptian General Petroleum Corporation (EGPC) for a Gas Sales Agreement, Field Development Plan and Deepwater Development Lease for a minimum of 2.7 trillion cubic feet (Tcf) of natural gas over 25 years from the deepwater portion of our Egyptian West Mediterranean Concession. Production is scheduled to commence in 2007, contingent upon completion of significant development infrastructure and resolution of delays in certain payments for production by EGPC. - We ended the year with record proved reserves of 1.66 billion barrels of oil equivalent (boe), marking the 18th consecutive year of reserve growth. Nearly half of our proved reserve additions were added through exploration and development activities. We began our 49th year in a strong financial position and on January 13, 2003, we announced the BP acquisition, our single-largest acquisition to date, establishing a new international core area and augmenting our Gulf of Mexico portfolio. The BP acquisition fit our balanced-portfolio business model and provides the potential for internal growth similar to what we have experienced in other areas. It also extends our relationship with one of the world's largest integrated major companies. In July 2003, we consummated a deal with Shell Exploration and Production Company (Shell) adding additional oil and gas fields on the outer Continental Shelf of the Gulf of Mexico. Our total acquisition costs for 2003 were approximately $1.6 billion, compared to $355 million in the prior year. These acquisitions are discussed in more detail below. Our worldwide capital expenditures for exploration and development were approximately $1.5 billion, 73 percent higher than 2002 and approximately 18 percent higher than our initial plan. Our strong cash flow enabled us to allocate additional funds to exploration and development during 2003. We spent approximately 69 percent of our exploration and development capital in North America, which is consistent with reserve and production contributions. We had numerous drilling successes throughout the year, particularly in Egypt and Australia: - Our most significant exploration success in Egypt, announced in July 2003, was the Qasr-1X well located on the Khalda Concession. In November, we announced completion of the Qasr-2X confirming the Qasr-1X discovery. We believe the Qasr discovery has the potential to be the most 17 significant discovery in Apache's 49-years. Production was initiated on a restricted basis in the fourth quarter of 2003, with full production expected in 2005, pending completion of additional development wells, appraisal wells and construction of pipeline facilities. - In July 2003, we announced that our Ravensworth-1 well discovered oil in the Exmouth Sub-Basin offshore Western Australia, creating a new oil-play area for Apache in an oil-prone area and adding a new dimension to our exploration program offshore Western Australia. Early in October 2003, we announced our second discovery in the Exmouth Sub-Basin, the Crosby-1, providing additional confidence that we have established a new oil-play area. Appraisal wells along with additional exploration drilling will occur in 2004. Following a very active year of drilling and acquisitions, our year-end 2003 reserves remained balanced at 51 percent oil and 49 percent natural gas, compared with 49 percent oil and 51 percent natural gas at year-end 2002. The increase in oil reserves is primarily attributable to the properties acquired in the North Sea. During 2003, the U.S. contributed 45 percent of equivalent production, up from 42 percent in 2002, reflecting the impact of the Gulf of Mexico assets acquired from BP and Shell. Apache ended the year in a strong financial position, maintaining single-A credit ratings on unsecured long-term debt issued by Moody's, Standard and Poor's and Fitch rating agencies. Also, we reduced debt to 26 percent of capitalization despite over $3 billion in capital expenditures. To manage our financial flexibility, we consummated several debt and equity transactions during 2003: - On January 22, 2003, in conjunction with the pending BP transaction, we completed a public offering of 19.8 million shares of common stock, adjusted for the two-for-one stock split, raising $554 million. - During the second quarter, the Company issued $350 million of 12-year, senior unsecured notes at a 4.375-percent coupon rate. Proceeds were used to reduce bank debt and outstanding commercial paper, and for general corporate purposes. - To take advantage of historically low interest rates on commercial paper and better position ourselves to pay down short-term debt, if we so elect, on September 26, 2003, Apache repurchased and retired preferred interests issued by three of its subsidiaries for approximately $443 million, plus an additional $1 million for accrued dividends and distributions. - The Company also filed a shelf registration with the Securities and Exchange Commission that allows Apache to sell up to $1.5 billion in stock and debt securities. On September 12, 2003 the Company announced that its Board of Directors, in recognition of the Company's outstanding growth and progress, voted to increase the quarterly cash dividend on its common stock 20 percent to 6 cents per share from 5 cents per share, effective with the November 2003 payment, and to split the stock two-for-one. While 2003 was an outstanding year, the current outlook for 2004 is also encouraging. Recent drilling successes and acquisitions should generate substantial production. Also, the current NYMEX futures markets indicate oil and natural gas prices above historical averages in 2004. Lastly, we are well positioned to access capital should appropriate acquisition opportunities present themselves. A more detailed discussion of operations follows our Critical Accounting Policies. 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 18 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, costs such as geological and geophysical (G&G), exploratory dry holes and delay rentals, are expensed as incurred where under the full-cost method these types of charges would be capitalized to their respective full-cost pool. In the measurement of impairment of oil and gas properties, the successful-efforts method of accounting follows the guidance provided in Statement of Financial Accounting Standards (SFAS) No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," where the first measurement for impairment is to compare the net book value of the related asset to its undiscounted future cash flows using commodity prices consistent with management expectations. Under the full-cost method the net book value (full-cost pool) is compared to the future net cash flows discounted at 10 percent using commodity prices in effect on the last day of the reporting period. 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 benefits of successful wells to more than offset the costs of any unsuccessful ones. In addition, gains or losses on the sale or other disposition of oil and gas properties are not recognized unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a country. As a result, we believe that the full-cost method of accounting better reflects the true economics of exploring for and developing oil and gas reserves. Our financial position and results of operations would have been significantly different had we used the successful-efforts method of accounting for our oil and gas investments. Typically, the application of the full-cost method of accounting for oil and gas property generally results in higher capitalized costs and higher depletion, depreciation and amortization (DD&A) rates compared to similar companies applying the successful efforts methods of accounting. The Company has taken note of a July 2003 inquiry to the Financial Accounting Standards Board (FASB) 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 19 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 $78 million and $259 million as of December 31, 2002 and December 31, 2003, 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 $332 million and $1.4 billion as of December 31, 2002 and December 31, 2003, respectively. Intangible developed mineral interest amounts are presented net of accumulated 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. 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 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 2003, 2002 and 2001, their review covered 78, 68 and 61 percent of the reserve value, respectively. 20 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. However, during 2001 and 2002, we experienced a gradual decline in the timeliness of receipts from EGPC for our oil and gas sales. Deteriorating economic conditions during 2001 and 2002 in Egypt lessened the availability of U.S. dollars, resulting in an additional one to two month delay in receipts from EGPC. While hard currency shortages in Egypt could lead to further delays, we did not experience any further delays in 2003. Please refer to the Future Trends section in this Item 7 for additional discussion concerning our Egyptian receivables. 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. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations. Prior to 2003, under the full-cost method of accounting, as described in the preceding critical accounting policy sections, the estimated undiscounted costs of the abandonment obligations, net of the value of salvage, were included as a component of our depletion base and expensed over the production life of the oil and gas properties. In 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations." Apache adopted this statement effective January 1, 2003, as discussed in Note 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. 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. 21 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 accretion expense, which reflects increases in the discounted asset retirement obligation over time. Also, the Company had to determine how to incorporate the asset retirement obligations into the quarterly calculation of its full-cost ceiling tests (see Note 1 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 comparatively 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. Derivatives Apache uses commodity derivative contracts on a limited basis to manage its exposure to oil and gas price volatility and accounts for the contracts in accordance with SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS 133). The estimated fair values of Apache's derivative contracts within the scope of this statement are carried on the Company's consolidated balance sheet. For contracts designated and qualifying as cash flow hedges, realized gains and losses are generally recognized in oil and gas production revenues when the forecasted transaction occurs. SFAS 133 requires that gains and losses from the change in fair value of derivative instruments that do not qualify for hedge accounting be "marked-to-market" and reported in current period income, rather than in the period in which the hedged transaction is settled. The Company does not currently enter into derivative or other financial instruments for trading purposes. The estimate of fair value of Apache's derivative contracts requires substantial judgment; however, the Company's derivative contracts are generally exchange traded or valued by reference to commodities that are traded in highly liquid markets. As such, the ultimate fair value is determined by references to readily available public data. Option valuations are verified against independent third-party quotations. (see Commodity Risk under Item 7a of this Form 10-K for commodity price sensitivity information). RESULTS OF OPERATIONS This section includes a discussion of our 2003 and 2002 results of operations. Apache has six reportable segments, which are the United States, Canada, Australia, Egypt, the North Sea and Other International. 22 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 2003, we spent $1.6 billion on oil and gas acquisitions, adding 267 MMboe to our reserve base. The preponderance of our 2003 acquisition activity was focused in the North Sea and Gulf of Mexico. The North Sea assets further diversified our reserves and production, while the Gulf of Mexico properties provide opportunities in an area that historically enjoys the highest netback natural gas pricing in North America. Seventy-two percent of our acquisition capital was spent to acquire North Sea and Gulf of Mexico properties from BP. Another 13 percent was spent to acquire additional Gulf of Mexico properties from Shell. The balance of our activity involved smaller acquisitions in Australia and North America. The North Sea acquisition establishes a new international operating region for Apache, providing the potential for future internal growth. The Gulf of Mexico properties acquired from BP and Shell lay down well with our existing Gulf of Mexico properties and provide promising prospects for future exploration, exploitation and development activities. As we have in the past, we expect to identify and take advantage of efficiencies in field operations and economics of scale, while concurrently accelerating production and adding reserves. In association with the BP acquisition, Apache agreed to sell all of the production from the North Sea properties to BP for a two year period at a combination of fixed and market sensitive prices pursuant to a contract entered into in connection with the North Sea purchase agreement. To protect the acquisition economics on the Gulf of Mexico properties acquired from BP we hedged prices on a substantial portion of the oil production for a 12-month period ending January 31, 2004, and a substantial portion of the gas production for the first two years (see Note 4 under Item 15 of this Form 10-K). Prior to the Shell transaction, Morgan Stanley Capital Group, Inc. (Morgan Stanley) paid Shell $300 million to acquire an overriding royalty interest in a portion of the reserves to be produced over the next four years. Shell's sale of an overriding royalty interest to Morgan Stanley is commonly known in the industry as a volumetric production payment (VPP). Under the terms of the VPP, Morgan Stanley is to receive a fixed volume of oil and gas production over the four-year term. The VPP reserves and production will not be recorded by Apache. In addition, a $60 million liability for the future cost to produce and deliver volumes subject to the VPP has been recorded by the Company because the overriding royalties are not burdened by production costs. This liability will be amortized as the volumes are produced and delivered to Morgan Stanley. In 2002, we elected to exercise patience on the acquisition front, in anticipation of lower acquisition prices. 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 we expended during 2001, which added 213 MMboe of proved reserves. In addition, the acquisitions added $3 million and $146 million of production, processing and transportation facilities in 2002 and 2001, respectively, and $197 million of goodwill in 2001. 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. 23 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 2003 year-end international reserves as a percentage of total reserves climbed to 30 percent from 22 percent at year-end 2002, while our international average daily production remained constant at 36 percent of our total production in both 2003 and 2002. Our hydrocarbon product mix on a boe basis in 2003 remained relatively constant at 49 percent natural gas and 51 percent oil, compared to 51 percent natural gas and 49 percent oil in 2002. While the U.S., a highly stable environment, remains our largest producing core area, Apache will continue to evaluate acquisition opportunities in existing core areas and in new areas should they arise. 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 in 2001 of $10 million with additional gains and losses to be recognized over the original life of the hedge. A net gain of $24 million was recognized in 2002 and a $4 million net loss was recognized in 2003. 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 $.02 per Mcf during 2003, $.04 per Mcf during 2002 and $.09 per Mcf during 2001. They increased our average crude oil price by $.03 per bbl during 2003, $.15 per bbl during 2002, and reduced our average crude oil price by $.42 per bbl during 2001. There is no material affect in future periods related to closed derivative positions. We routinely evaluate our property portfolio and divest those that are marginal or no longer fit into our strategic growth program. We divested $59 million, $7 million and $348 million of properties during 2003, 2002 and 2001, 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 other economic factors could impact demand. Oil and Natural Gas Prices While the market price received for crude oil and natural gas varies among geographic areas, crude oil trades in a world-wide market, whereas natural gas, which has a limited global transportation system, is subject to local supply and demand conditions. Consequently, price movements for all types and grades of crude oil generally move in the same direction, while natural gas price movements generally follow local market conditions. 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 FOR THE YEAR ENDED DECEMBER 31, DECEMBER 31, ------------------------ ------------------------ 2003 2002 2001 2003 2002 2001 ---- ---- ---- ---- ---- ---- United States....................................... 33% 35% 40% 62% 51% 61% Canada.............................................. 13% 16% 17% 27% 29% 27% --- --- --- --- --- --- North America....................................... 46% 51% 57% 89% 80% 88% Egypt............................................... 23% 29% 27% 8% 15% 8% Australia........................................... 16% 20% 16% 3% 5% 4% North Sea........................................... 13% -- -- -- -- -- Other International................................. 2% -- -- -- -- -- --- --- --- --- --- --- Total........................................ 100% 100% 100% 100% 100% 100% === === === === === ===
Crude Oil Contribution In 2003 oil revenues from areas outside the U.S. rose to approximately 67 percent of consolidated oil revenues, up from 65 percent in 2002. The increase is directly related to the acquisition of the North Sea properties and, to a much lesser extent, initial production from China. The percentage contribution from all other areas fell, reflecting the impact from the North Sea revenues and China revenues. 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 29 percent and 20 percent of total oil revenues, respectively. Canada contributed 16 percent of oil revenue, down from 17 percent in 2001. Natural Gas Contribution The preponderance of consolidated natural gas revenues comes from our North American operations. In 2003, 89 percent of Apache's natural gas revenues came from North America, 62 percent from the U.S. and 27 percent from Canada. The U.S. contribution rose 11 percent from 2002, primarily because of the properties acquired from BP and Shell in 2003, and properties acquired in South Louisiana in December 2002. Our U.S. Gulf Coast region, which contributed 71 percent of Apache's U.S. 2003 production, is characterized by reservoirs which demonstrate high initial production rates followed by steep declines when compared to most other U.S. producing areas. Higher U.S. natural gas prices also contributed, but to a much lesser extent. Canada's contribution was down two percent from 2002 primarily because of the production growth in the U.S. Egypt's contribution to total gas revenues declined to eight percent from 15 percent in 2002. Egypt's total natural gas revenues were relatively flat year-over-year, as additional revenues generated from higher natural gas prices were offset by lower production-generated revenues. Australia's contribution to 2003 natural gas revenues declined to three percent from five percent in 2002. 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. 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, ------------------------------------ 2003 2002 2001 ---------- ---------- ---------- Revenues (in thousands): Natural gas............................................ $2,046,625 $1,130,692 $1,521,959 Oil.................................................... 2,081,283 1,383,749 1,246,384 Natural gas liquids.................................... 71,012 45,307 54,616 ---------- ---------- ---------- Total............................................... $4,198,920 $2,559,748 $2,822,959 ========== ========== ========== Natural Gas Volume -- Mcf per day: United States.......................................... 665,156 503,310 615,341 Canada................................................. 318,528 329,344 298,424 Egypt.................................................. 113,554 122,655 95,918 Australia.............................................. 111,061 117,802 116,943 North Sea.............................................. 1,714 -- -- Argentina.............................................. 7,144 7,276 648 ---------- ---------- ---------- Total............................................... 1,217,157 1,080,387 1,127,274 ========== ========== ========== Average Natural Gas Price -- Per Mcf: United States.......................................... $ 5.22 $ 3.15 $ 4.15 Canada................................................. 4.69 2.74 3.81 Egypt.................................................. 4.18 3.71 3.51 Australia.............................................. 1.44 1.28 1.22 North Sea.............................................. 2.77 -- -- Argentina.............................................. .47 .42 1.20 Total............................................... 4.61 2.87 3.70 Oil Volume -- Barrels per day: United States.......................................... 69,404 53,009 58,501 Canada................................................. 25,220 25,220 25,895 Egypt.................................................. 47,551 43,772 39,238 Australia.............................................. 30,589 30,361 23,548 North Sea.............................................. 29,260 -- -- China.................................................. 2,791 -- -- Argentina.............................................. 579 617 117 ---------- ---------- ---------- Total............................................... 205,394 152,979 147,299 ========== ========== ========== Average Oil Price -- Per barrel: United States.......................................... $ 27.48 $ 25.31 $ 24.39 Canada................................................. 29.06 23.46 19.22 Egypt.................................................. 27.64 24.65 23.59 Australia.............................................. 29.87 25.17 23.89 North Sea.............................................. 25.40 -- -- China.................................................. 26.33 -- -- Argentina.............................................. 29.23 23.90 17.90 Total............................................... 27.76 24.78 23.18 NGL Volume -- Barrels per day: United States.......................................... 7,578 6,691 7,679 Canada................................................. 1,565 1,756 1,272 ---------- ---------- ---------- Total............................................... 9,143 8,447 8,951 ========== ========== ========== Average NGL Price -- Per barrel: United States.......................................... $ 21.70 $ 15.29 $ 16.60 Canada................................................. 19.25 12.41 17.45 Total............................................... 21.28 14.69 16.72
26 Natural Gas Revenues Our 2003 consolidated natural gas revenues climbed $916 million with a $1.74 per Mcf increase in our average natural gas price realizations generating an additional $686 million of revenues. Higher production added the remaining $230 million. Virtually all of the additional revenues attributable to price came from the U.S. and Canada. The additional revenues attributable to production were concentrated in the U.S., where natural gas production increased 32 percent, reflecting the impact from the 2003 BP and Shell acquisitions and the December 2002 acquisition of the South Louisiana properties. Partially offsetting the additional U.S. production revenues were lower production in Egypt, Australia and Canada, down seven percent, six percent and three percent, respectively. Egypt's lower production related to gas production curtailment imposed by EGPC and scheduled plant shutdowns, while Australia saw lower customer demand. 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 percent of Apache's U.S. 2002 production, is characterized by reservoirs which demonstrate high initial rates followed by steep declines when compared to other US producing regions. Natural decline 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. 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 a measure of protection to the Company in the event of decreasing natural gas prices and represented approximately nine and 11 percent of our 2003 and 2002 domestic natural gas production, respectively. In 2003, these contracts reduced our average realized price $.08 per Mcf. In 2002, these contracts added $.01 per Mcf. Additionally, substantially all of our natural gas production sold in Australia is subject to long-term fixed-price contracts that are periodically adjusted for changes in Australia's consumer price index. Our realized prices are also impacted by a change in the value of the Australian dollar relative to the U.S. dollar. In 2003, we saw an increase in our realized prices primarily because of the stronger Australian dollar. Crude Oil Revenues Our 2003 consolidated oil revenues increased $698 million with a 34 percent increase in oil production generating an additional $531 million of revenues. Crude oil prices improved in all areas, pushing our worldwide weighted-average crude oil price up $2.98 per barrel, adding the remaining $167 million. Revenues from properties acquired in the North Sea accounted for over half of the increase in oil revenues attributable to production. A portion of the revenue from the North Sea is tied to a separate crude oil physical sales contract entered into in conjunction with the acquisition. See Note 4 of Item 15 of this Form 10-K for a discussion of the terms of this contract. Production in the U.S. increased 31 percent, primarily from the Gulf of Mexico BP properties and to a lesser extent from properties acquired from Shell and in South Louisiana in December 2002. Initial production from China and a nine percent increase in production from Egypt also contributed to the revenue gains. 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 in 2001 and subsequent drilling. U.S. production declined nine percent related to natural decline, 27 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. Operating Expenses The tables below present a comparison of our expenses on an absolute dollar basis and an equivalent unit of production (boe) basis. Our discussion may reference either expenses on a boe basis or expenses on an absolute dollar basis, or both, depending on their relevance. During 2003, we saw tremendous growth in production and reserves accompanied by a corresponding rise in operating costs.
YEAR ENDED DECEMBER 31, YEAR ENDED DECEMBER 31, ------------------------ ------------------------ 2003 2002 2001 2003 2002 2001 ------ ------ ------ ------ ------ ------ (IN MILLIONS) (PER BOE) Depreciation, depletion and amortization: Oil and gas property and equipment...... $1,003 $ 784 $ 760 $ 6.59 $ 6.29 $ 6.05 Other assets............................ 70 60 61 .46 .48 .48 Asset retirement obligation accretion..... 38 -- -- .25 -- -- International impairments................. 13 20 65 .08 .16 .52 Lease operating costs..................... 700 458 400 4.59 3.67 3.18 Gathering and transportation costs........ 60 38 35 .40 .31 .28 Severance and other taxes................. 122 67 75 .80 .54 .59 General and administrative expenses....... 138 105 89 .91 .84 .71 Financing costs, net...................... 115 113 118 .75 .91 .95 ------ ------ ------ ------ ------ ------ Total................................ $2,259 $1,645 $1,603 $14.83 $13.20 $12.76 ====== ====== ====== ====== ====== ======
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. 2003 full-cost DD&A expense of $1 billion is comprised of the U.S., $489 million; Canada, $158 million; Egypt, $161 million; Australia, $110 million; the North Sea, $72 million; and China, $12 million. Full-cost DD&A expense increased $220 million compared to 2002. The majority of the increase in absolute costs was in the U.S., up $119 million; and the North Sea, $72 million; related to increases in production driven by our recent acquisitions. First production in China added $12 million. The remaining increase is concentrated in Egypt and Australia. On a boe basis, our average full-cost DD&A rate in 2003 increased $.30 to $6.59 from $6.29 in 2002. The bulk of the increase occurred in Australia, Egypt and the U.S. contributing $.12, $.09 and $.06, respectively. The increases in Australia and Egypt reflect the impact of higher finding and development costs, while the increase in the U.S. reflects the impact of higher finding and development costs and higher acquisition costs. China and the North Sea each added $.03, while Canada's rate lowered the consolidated rate $.03. 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. Depreciation of other assets increased $10 million, in 2003 in line with our overall growth. 28 Impairments We assess all of our unproved properties for possible impairment on a quarterly basis based on geological trend analysis, dry holes or relinquishment of acreage. When an impairment occurs, costs associated with these properties are generally transferred to our proved property base where they become subject to amortization. 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). In 2003, we impaired the remaining $13 million ($8 million after-tax) of unproved property costs in Poland. Goodwill is subject to a periodic fair-value-based impairment assessment beginning in 2002. Goodwill totals $189 million at December 31, 2003 and no impairment was recorded in 2003 or 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 priced environments. Repair and maintenance costs are higher on offshore properties and in areas with plants and facilities. During 2003, the Company saw a substantial increase in its LOE costs on both an absolute dollar basis and boe basis. The majority of the increase on an absolute dollar basis was expected, given the BP and Shell acquisitions and the acquisition of the South Louisiana properties. On a boe basis, 2003 LOE increased $.92 to $4.59, with all of the increase occurring outside the U.S. The North Sea properties, which are located offshore and produce oil, added approximately $109 million of costs, increasing our consolidated rate $.46 per boe. Canada's LOE costs increased $44 million, adding $.30 to our consolidated boe rate. The impact from a weaker U.S. dollar, a full year of LOE on properties acquired in the second half of 2002, costs associated with new fields, and higher power and fuel rates drove the increase in Canadian costs. Egypt's operating costs increased $13 million, adding $.09 to the overall rate. The majority of the increase in Egypt was attributable to higher workover activity. Australia's LOE increased $7 million because of an increase in repair and maintenance and higher oil production. Australia added $.10 to the overall boe rate. The LOE rate in the U.S. declined as the impact from the additional costs associated with the acquisitions discussed above were more than offset by the incremental production. The U.S. reduced the overall rate by $.05 per boe. During 2002, LOE was $3.67 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. 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 29 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. Apache generally sells oil and natural gas under two types of transactions, both of which include a transportation charge. One is a netback arrangement, under which Apache sells oil or natural gas at the wellhead and collects a price, net of transportation incurred by the purchaser. Under the other arrangement, Apache sells oil or natural gas at a specific delivery point, pays transportation to a carrier and receives from the purchaser a price with no transportation deduction. In both the U.S. and Canada, Apache sells oil and natural gas under both types of arrangements. In the North Sea, Apache pays transportation to a carrier and receives a purchase price with no transportation deduction. In Egypt and Australia, oil and natural gas are sold under the netback arrangement. Gathering and transportation costs disclosed here only include transportation paid by Apache to a carrier. These costs are primarily related to the transportation of natural gas in our North American operations. In 2003, these costs totaled $28 million in Canada and $21 million in the U.S., up from $21 million and $17 million in 2002, respectively. The increase in Canada primarily involved higher third-party transportation charges for gas transported from several fields and increased production volumes from 2002 acquisitions. Canada also incurred transportation charges for crude oil as we began taking our oil "in-kind" and marketing it ourselves instead of selling it at the lease. The increase in the U.S. is related to the higher production from the Gulf of Mexico acquisitions. In the North Sea, these costs are related to the transportation of crude oil and totaled $11 million in 2003. Overall, transportation costs in 2002 were relatively flat to 2001. 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 2003 and 2002, these severance taxes, which are generally based on a percentage of oil and gas production revenues, represented over 60 percent of the total severance and other taxes expense incurred. The other tax component is primarily made up of the Australian Petroleum Resources Rent Tax (PRRT), to which Apache first became subject in 2002, the Petroleum Revenue Tax (PRT) on the North Sea properties and the Canadian Large Corporation Tax, Saskatchewan Capital Tax, Saskatchewan Resource Surtax and Freehold Mineral Tax. Oil and gas production revenues generated from Egypt, Canada and the North Sea are not subject to severance taxes. In 2003, severance and other taxes totaled $122 million ($53 million in the U.S., $28 million in Australia, $20 million in the North Sea, $20 million in Canada and $1 million in Argentina). Severance and other taxes increased 81 percent or $54 million. Twenty million dollars of the increase is associated with North Sea's PRT expense. Canadian taxes increased $10 million as a result of exchange rate increases and higher prices in 2003, and a $2 million refund in 2002. U.S. and Australia severance taxes increased $17 million and $7 million, respectively, in line with higher production revenues. In 2002, severance and other taxes totaled $67 million, comprised of U.S., $35 million, Australia, $23 million and Canada, $9 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. General and Administrative Expenses General and administrative expenses (G&A) of $.91 per boe for 2003 increased $.07 per boe over 2002. Absolute costs increased $34 million, or 32 percent. Over $11 million, or 34 percent, is associated with expensing compensation, including Stock Appreciation Rights (SARs), stock options, restricted stock and 30 incremental incentive compensation, in light of our record year. The increased stock compensation expense stems from Apache's decision to expense stock related compensation plans (see Note 9 in Item 15 of this Form 10-K). Approximately $9 million, or 28 percent, of the increase is related to our new North Sea operations. The balance of the increase was related to the Company's decision to increase its charitable contributions, expansion of the Company's new gas marketing group and transition costs incurred on acquisitions. Overall, general and administrative expenses trended higher in 2002, rising $.13 to $.84 per boe. On an absolute cost basis, 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. Financing Costs, Net The major components of net financing costs are interest expense and capitalized interest. Net financing costs increased $2 million compared to 2002 with a $13 million increase in expense largely offset by an increase in capitalized interest. Five million dollars of the increase is interest expense related to the write-off of unamortized fees triggered by the retirement of preferred interests of subsidiaries discussed below. The remaining $8 million of higher interest expense was attributable to a higher average debt balance in 2003 compared to 2002. Capitalized interest increased $12 million driven by a higher unproved property balance associated with acquisitions and an active drilling program. If net financing costs included distributions from Preferred Interests of Subsidiaries, net financing costs would have decreased by approximately $5 million. Net financing costs decreased by five percent in 2002. Lower average debt outstanding during 2002 resulted in a decrease in interest expense of $23 million compared to 2001. A reduction in capitalized interest of $16 million, associated with lower unproved property balances, partially offset this decrease. Our weighted-average cost of borrowing on December 31, 2003 was 6.4 percent compared to 6.3 percent on December 31, 2002. The rate is higher at year-end 2003 as a lower percentage of our debt is at floating rates, which carry a lower rate than fixed-rate debt. Provision for Income Taxes 2003 income tax expense of $827 million was $482 million or 140 percent higher than the 2002. The higher taxes were primarily associated with higher income in 2003 and, to a lesser extent, a higher effective tax rate. Our effective tax rate increased primarily because of $172 million of additional deferred tax expenses resulting from currency fluctuations. For a discussion of Apache's sensitivity to foreign currency fluctuations, please refer to "Foreign Currency Risk" under Item 7A of this Form 10-K. The impact caused by currency fluctuations was partially offset by a $71 million reduction in deferred tax expense related to a reduction in Canadian federal statutory income tax rates. Our effective tax rate for 2003 was 43.02 percent compared to 38.34 percent for the prior year. Our 2002 effective tax rate was slightly lower than 2001. 31 OIL AND GAS CAPITAL EXPENDITURES
YEAR ENDED DECEMBER 31, ------------------------------------ 2003 2002 2001 ---------- -------- ---------- (IN THOUSANDS) Exploration and Development: United States............................................ $ 439,541 $302,611 $ 699,180 Canada................................................... 579,495 258,191 410,345 Egypt.................................................... 242,652 171,160 127,603 Australia................................................ 128,261 89,813 85,169 North Sea................................................ 60,204 -- -- Other International...................................... 35,098 38,409 20,838 ---------- -------- ---------- $1,485,251 $860,184 $1,343,135 ========== ======== ========== Capitalized Interest....................................... $ 52,891 $ 40,691 $ 56,749 ========== ======== ========== Gas Gathering Transmission and Processing Facilities....... $ 38,533 $ 32,155 $ 28,759 ========== ======== ========== Acquisitions: Oil and gas properties................................... $1,568,106 $351,707 $ 880,286 Gas gathering, transmission and processing facilities.... 5,484 2,875 146,295 Goodwill................................................. -- -- 197,200 ---------- -------- ---------- $1,573,590 $354,582 $1,223,781 ========== ======== ==========
In 2003, Apache added 503.2 MMboe of proved reserves through acquisitions, drilling and revisions, replacing 330 percent of production. 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 2004 is approximately $1.8 billion (excluding acquisitions), including $1 billion for North America. Preliminary North American capital expenditures include $400 million in the Gulf Coast region, $100 million in the Central region and $500 million in Canada. The Company has estimated its international capital expenditures in 2004 at $800 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 $6 million in dividends during 2003 on its Series B Preferred Stock issued in August 1998. Dividends on the Series C Preferred Stock were paid through May 15, 2002, when the shares automatically converted to common stock (see Note 9, under Item 15 of this Form 10-K). Common dividends paid during 2003 rose 19 percent to $67 million, reflecting the increase in common shares outstanding and the higher common stock dividend rate. The Company has paid cash dividends on its common stock for 39 consecutive years through 2003. Future dividend payments will depend on the Company's level of earnings, financial requirements and other relevant factors. The Company has increased its quarterly cash dividend 20 percent, to six cents per share from five cents per share, effective with the November 2003 dividend payment. 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 32 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 2003 totaled $2.7 billion, an increase of 96 percent from 2002 driven by higher oil and gas production revenues partially offset by higher operating expenses. Oil production revenues increased with a 34 percent increase in production and a 12 percent increase in prices. Gas production revenues increased with a 13 percent production increase and a 61 percent price increase. Net cash provided by operating activities during 2002 decreased 28 percent to $1.4 billion from $1.9 billion in 2001. The decrease was 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. Debt At December 31, 2003, Apache had outstanding debt of $135 million under its commercial paper program and uncommitted lines of credit and a total of $2.2 billion of other debt. This other debt included notes and debentures maturing in the years 2005 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 2004 are projected to be $160 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 currently scheduled to mature on May 28, 2004. 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, 2003 and 2002 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 1.19 percent in 2003 and 1.85 percent in 2002. 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 paid a weighted-average return to the investors of 123 basis points above the prevailing LIBOR interest rate. These subsidiaries were consolidated in the accompanying financial 33 statements with the $437 million at December 31, 2002 reflected as preferred interests of subsidiaries on the balance sheet. On September 26, 2003, Apache repurchased and retired the preferred interests issued by three of its subsidiaries for approximately $443 million, plus an additional $1 million for accrued dividends and distributions. The transactions involved the purchase of preferred stock issued by two of the Company's subsidiaries for approximately $82 million and the retirement of a limited partnership interest in a partnership controlled by a subsidiary of the Company for approximately $361 million. Apache funded the transactions with available cash on hand and by issuing commercial paper under its existing commercial paper facility. Stock Transactions On September 13, 2001, our 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, we 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 May 15, 2002, we completed the mandatory conversion of our Series C Preferred Stock into approximately 13.1 million common shares. On December 18, 2002, our Board of Directors declared a five percent stock dividend payable on April 2, 2003 to shareholders of record on March 12, 2003. As a result, in December 2002, we reclassified approximately $396 million from retained earnings to common stock and paid-in capital, which represents the fair market value at the date of declaration of the shares distributed. In 2003, at the date of the distribution, an additional $26 million was reclassified from retained earnings to common stock and paid-in capital. No fractional shares were issued and cash payments were made in lieu of fractional shares. On January 22, 2003, we completed a public offering of approximately 19.8 million shares of common stock, including 2.6 million shares for the underwriters' over-allotment option, for net proceeds of $554 million. On December 18, 2003, we announced that holders of our common stock approved an increase in the number of authorized common shares to 430 million from 215 million in order to complete a previously announced two-for-one stock split. The record date for the stock split was December 31, 2003 and the additional shares were distributed on January 14, 2004. LIQUIDITY During 2003, 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. 34 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, 2003, available borrowing capacity under our global credit facility was $1.4 billion. We had $34 million in cash and cash equivalents on hand at December 31, 2003, a decrease from $52 million at the prior year-end. In addition, the ratio of current assets to current liabilities decreased from 1.44 at the end of last year to 1.10 at December 31, 2003. 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, 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, 2003. 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 2004 2005 2006 2007 2008 THEREAFTER ----------------------- --------- ---------- -------- ------- ------- -------- ------- ---------- (IN THOUSANDS) Long-term debt................ Note 6 $2,326,966 $ -- $ 830 $ 274 $307,590 $ 353 $2,017,919 Operating leases and other commitments................. Note 11 303,750 108,285 40,875 33,468 29,303 25,779 66,040 International lease commitments................. Note 11 51,753 18,667 7,659 10,942 14,485 -- -- Exploration agreement......... Note 11 19,651 19,651 -- -- -- -- -- Operating costs associated with a pre-existing volumetric production payment of acquired properties.................. Note 3 64,602 21,159 18,740 15,551 9,152 -- -- --------------------------------------------------------------------------- Total Contractual Obligations(a)(b)....... $2,766,722 $167,762 $68,104 $60,235 $360,530 $26,132 $2,083,959 ===========================================================================
(a) This table does not include the liability for dismantlement, abandonment and restoration costs of oil and gas properties. Effective with adoption of SFAS No. 143, "Accounting for Asset Retirement Obligations" on January 1, 2003, the Company recorded a separate liability for the fair value of this asset retirement obligation. See Note 2, under Item 15 of this Form 10-K for further discussion. (b) This table does not include the Company's pension or postretirement benefit obligations. See Note 11 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 legal 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 payment of these costs, Apache agreed to deliver a letter of credit to BP if the rating of our senior unsecured debt is lowered by both Moody's and 35 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 175 million British pounds ($306 million U.S. at December 31, 2003). 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. The outstanding position of the term oil physical sales contract with BP is described in greater detail in Note 4 under Item 15 of this Form 10-K. The Company's future liquidity could be impacted by a significant downgrade of its credit ratings by Standard and Poor's and Moody's; however, we do not believe that such a sharp downgrade is reasonably likely. The Company's global credit facility does not require the Company to maintain a minimum credit rating. The negative covenants associated with our debt are outlined in greater detail within the debt section of our discussion on Capital Resources above. 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 for any other purpose. Any future transactions involving off-balance sheet arrangements would 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 2004 worldwide capital expenditures for exploratory and development drilling to approximately $1.8 billion from $1.5 billion in 2003. We will continue to monitor commodity prices and adjust our capital expenditures accordingly. We will also continue to evaluate and pursue acquisition opportunities. Exploiting Existing Asset Base Apache seeks to maximize the value of our existing asset base by increasing production and reserves while containing 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. Our 2003 acquisitions from BP and Shell added to our 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. We evaluate potential purchases on an ongoing basis, but we are very selective. Practically all of our 2003 acquisition activity was completed by early July. We remained in the market during the second half of 2003, but we did 36 not identify any assets that fit our balanced-portfolio business model. We believe attractive assets will be available, as larger energy companies look to shed non-core assets. 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 have "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. Egyptian Receivables Deteriorating economic conditions during 2001 and 2002 in Egypt lessened the availability of U.S. dollars, resulting in an additional one to two month delay in receipts from EGPC. While hard currency shortages in Egypt could lead to further delays, we did not experience any further delays in 2003. It is currently our intention to resolve the delays in EGPC's payments prior to incurring the substantial capital expenditures required to develop our deepwater interests in the West Mediterranean Concession or signing the gas sales agreement provided for by the MOU for a minimum of 2.7 Tcf of natural gas over 25 years from such concession. 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 $25.53 per barrel to a high of $31.66 per barrel during 2003. Average gas price realizations ranged from a monthly low of $4.11 per Mcf to a monthly high of $6.66 per Mcf during the same period. Based on the Company's 2003 worldwide oil production levels, a $1.00 per barrel change in the weighted-average realized price of oil would increase or decrease revenues by $75 million. Based on the Company's 2003 worldwide gas production levels, a $.10 per Mcf change in the weighted-average realized price of gas would increase or decrease revenues by $44 million. If oil and gas prices decline significantly, even if only for a short period of time, it is possible that non-cash write-downs of our oil and gas properties could occur under the full-cost accounting method allowed by the Securities Exchange Commission (SEC). Under these rules, we review the carrying value of our proved oil and gas properties each quarter on a country-by-country basis to ensure that capitalized costs of proved oil and gas properties, net of accumulated depreciation, depletion and amortization, and deferred income taxes, do not exceed the "ceiling." This ceiling is the present value of estimated future net cash flows from proved oil and gas reserves, discounted at 10 percent, plus the lower of cost or fair value of unproved properties included in the costs being amortized, net of related tax effects. If capitalized costs exceed this limit, the excess is charged to additional DD&A expense. The calculation of estimated future net cash flows is based on the prices for crude oil and natural gas in effect on the last day of each fiscal quarter except for volumes sold under long-term contracts. Write-downs required by these rules do not impact cash flow from operating activities; however, as discussed above, sustained low prices would have a material adverse effect on future cash flows. We periodically enter into hedging activities on a portion of our projected oil and natural gas production through a variety of financial and physical arrangements intended to support oil and natural gas prices at targeted levels and to manage our overall exposure to oil and gas price fluctuations. Apache may use futures 37 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 with the acquisition from BP in 2003. These positions were entered into to preserve our strong financial position in a period of cyclically high gas and oil prices and were designated as cash flow hedges of anticipated production. On December 31, 2003, the Company had open natural gas derivative positions with a fair value of $(60) million. A 10 percent increase in natural gas prices would change the fair value by $(32) million. A 10 percent decrease in prices would change the fair value by $31 million. The Company also had open oil price swap positions with a fair value of $(9) million. A 10 percent change in oil prices would change the fair value by plus or minus $5 million. These fair value changes assume volatility based on prevailing market parameters at December 31, 2003. See Note 4 under Item 15 of this Form 10-K for notional volumes associated with the Company's derivative contracts. INTEREST RATE RISK Approximately 94 percent of the Company's yearend 2003 debt is term debt with fixed interest rates, minimizing the Company's exposure to fluctuations in short-term interest rates. At December 31, 2003, the Company had $135 million of floating-rate debt which is subject to fluctuations in short-term interest rates. A 10 percent change in the floating interest rate (approximately 11 basis points) on these year-end balances, would change annual interest expense $148,000. The Company did not have any open derivative contracts relating to interest rates at December 31, 2003 or 2002. FOREIGN CURRENCY RISK The Company's cash flow stream relating to certain international operations is based on the U.S. dollar equivalent of cash flows measured in foreign currencies. In Australia, gas production is sold under fixed-price Australian dollar contracts and over half the costs incurred are paid in Australian dollars. The North Sea production is sold under U.S. dollar contracts, however, the majority of costs incurred are paid in British pounds. Revenue and disbursement transactions denominated in Australian dollars and British pounds are converted to U.S. dollar equivalents based on the exchange rate as of the transaction date. Prior to October 1, 2002, reported cash flow from Canadian operations was measured in Canadian dollars and converted to the U.S. dollar equivalent based on the average of the Canadian and U.S. dollar exchange rates for the period reported. The majority of Apache's debt in Canada is denominated in U.S. dollars and, as such, was adjusted for differences in exchange rates at each period end and recorded as Revenues and Other. In light of the continuing transformation of the U.S. and Canadian energy markets into a single energy market, we adopted the U.S. dollar as our functional currency in Canada, effective October 1, 2002. A 10 percent strengthening of the Australian and Canadian dollars and the British pound as of December 31, 2003 will result in a foreign currency net loss of approximately $66 million. This is primarily driven from foreign currency effects on the Companies deferred tax liability positions in its international operations. The Company did not have any open derivative contracts relating to foreign currencies at December 31, 2003 or 2002. 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. 38 There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and in projecting future rates of production and the timing of development expenditures. The total amount or timing of actual future production may vary significantly from reserve and production estimates. The drilling of exploratory wells can involve significant risks, including those related to timing, success rates and cost overruns. Lease and rig availability, complex geology and other factors can affect these risks. Although Apache makes use of futures contracts, swaps, options and fixed-price physical contracts to mitigate risk, fluctuations in oil and gas prices, or a prolonged continuation of low prices, may substantially adversely affect the Company's financial position, results of operations and cash flows. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA The financial statements and supplementary financial information required to be filed under this item are presented on pages F-1 through F-61 of this Form 10-K, and are incorporated herein by reference. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE The financial statements for the fiscal years ended December 31, 2003 and 2002, included in this report, have been audited by Ernst & Young LLP, independent public auditors, as stated in their audit report appearing herein. The financial statements for the fiscal year ended December 31, 2001, 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 the fiscal year ended December 31, 2001, 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 year ended December 31, 2001 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. ITEM 9A. CONTROLS AND PROCEDURES G. Steven Farris, the Company's President, Chief Executive Officer and Chief Operating Officer, and Roger B. Plank, the Company's Executive Vice President and Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures as of December 31, 2003, the end of the period covered by this report. Based on that evaluation and as of the date of that evaluation, these officers concluded that the Company's disclosure controls were effective, providing effective means to insure that information we are required to disclose under applicable laws and regulations is recorded, processed, summarized and reported in a timely manner. We also made no significant changes in internal controls over financial reporting during the quarter ending December 31, 2003 that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting. We periodically review the design and effectiveness of our disclosure controls, including compliance with various laws and regulations that apply to our operations both inside and outside the United States. We make modifications to improve the design and effectiveness of our disclosure controls, and may take other corrective action, if our reviews identify deficiencies or weaknesses in our controls. 39 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 2004 annual meeting of stockholders (the Proxy Statement) is incorporated herein by reference. Code of Business Conduct Pursuant to Rule 303A.10 of the NYSE and Rule 4350(n) of the NASDAQ, we are required to adopt a code of business conduct and ethics for our directors, officers and employees. In February 2004, the Board of Directors adopted the Code of Business Conduct (Code of Conduct), which also meets the requirements of a code of ethics under Item 406 of Regulation S-K. You can access the Company's Code of Conduct on the Investor Relations page of the Company's website at www.apachecorp.com. Any stockholder who so requests may obtain a printed copy of the Code of Conduct by submitting a request to the Company's corporate secretary. Changes in and waivers to the Code of Conduct for the Company's directors, chief executive officer and certain senior financial officers will be posted on the Company's website within five business days and maintained for at least 12 months. ITEM 11. EXECUTIVE COMPENSATION The information set forth under the captions "Summary Compensation Table", "Option/SAR Exercises and Year-End Value Table", "Employment Contracts and Termination of Employment and Change-in-Control Arrangements" and "Director Compensation" in the Proxy Statement is incorporated herein by reference. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The information set forth under the captions "Securities Ownership and Principal Holders" and "Equity Compensation Plan Information" in the Proxy Statement is incorporated herein by reference. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS The information set forth under the caption "Certain Business Relationships and Transactions" in the Proxy Statement is incorporated herein by reference. ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES The information set forth under the caption "Independent Public Auditors" in the Proxy Statement is incorporated herein by reference. 40 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 Report of independent public accountants.................... F-3 Statement of consolidated operations for each of the three years in the period ended December 31, 2003............... F-4 Statement of consolidated cash flows for each of the three years in the period ended December 31, 2003............... F-5 Consolidated balance sheet as of December 31, 2003 and 2002...................................................... F-6 Statement of consolidated shareholders' equity for each of the three years in the period ended December 31, 2003..... F-7 Notes to consolidated financial statements.................. F-8
2. Financial Statement Schedules Financial statement schedules have been omitted because they are either not required, not applicable or the information required to be presented is included in the Company's financial statements and related notes. 3. Exhibits
EXHIBIT NO. DESCRIPTION ------- ----------- 2.1 -- Agreement and Plan of Merger among Registrant, YPY Acquisitions, Inc. and The Phoenix Resource Companies, Inc., dated March 27, 1996 (incorporated by reference to Exhibit 2.1 to Registrant's Registration Statement on Form S-4, Registration No. 333-02305, filed April 5, 1996). 2.2 -- Purchase and Sale Agreement by and between BP Exploration & Production Inc., as seller, and Registrant, as buyer, dated January 11, 2003 (incorporated by reference to Exhibit 2.1 to Registrant's Current Report on Form 8-K, dated and filed January 13, 2003, SEC File No. 1-4300). 2.3 -- Sale and Purchase Agreement by and between BP Exploration Operating Company Limited, as seller, and Apache North Sea Limited, as buyer, dated January 11, 2003 (incorporated by reference to Exhibit 2.2 to Registrant's Current Report on Form 8-K, dated and filed January 13, 2003, SEC File No. 1-4300). *3.1 -- Restated Certificate of Incorporation of Registrant, dated February 11, 2004, as filed with the Secretary of State of Delaware on February 12, 2004. *3.2 -- Bylaws of Registrant, as amended February 5, 2004. 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 to Registrant's Current Report on Form 8-K, dated and filed April 18, 1998, SEC File No. 1-4300).
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EXHIBIT NO. DESCRIPTION ------- ----------- 4.3 -- Form of Certificate for Registrant's Automatically Convertible Equity Securities, Conversion Preferred Stock, Series C (incorporated by reference to Exhibit 99.8 to Amendment No. 1 on Form 8-K/A to Registrant's Current Report on Form 8-K, dated and filed April 29, 1999, SEC File No. 1-4300). 4.4 -- Rights Agreement, dated January 31, 1996, between Registrant and Norwest Bank Minnesota, N.A., rights agent, relating to the declaration of a rights dividend to Registrant's common shareholders of record on January 31, 1996 (incorporated by reference to Exhibit (a) to Registrant's Registration Statement on Form 8-A, dated January 24, 1996, SEC File No. 1-4300). 10.1 -- 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, dated June 13, 1997, 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). 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, dated June 13, 1997, 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).
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EXHIBIT NO. DESCRIPTION ------- ----------- 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 Administrative 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, dated June 13, 1997, 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). 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).
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EXHIBIT NO. DESCRIPTION ------- ----------- 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 January 1, 2003 (incorporated by reference to Exhibit 10.18 to Registrant's Annual Report on Form 10-K, as amended by Form 10-K/A, for year ended December 31, 2002, SEC File No. 1-4300). +10.19 -- 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 January 1, 2003 (incorporated by reference to Exhibit 10.20 to Registrant's Annual Report on Form 10-K for year ended December 31, 2002, SEC File No. 1-4300). +10.21 -- Non-Qualified Retirement/Savings Plan of Apache Corporation, restated January 1, 1997, and amendments effective January 1, 1997, January 1, 1998 and January 1, 1999 (incorporated by reference to Exhibit 10.17 to Registrant's Annual Report on Form 10-K for year ended December 31, 1998, SEC File No. 1-4300). +10.22 -- Amendment to Non-Qualified Retirement/Savings Plan of Apache Corporation, dated February 22, 2000, effective January 1, 1999 (incorporated by reference to Exhibit 4.7 to Registrant's Registration Statement on Form S-8, Registration No. 333-31092, filed February 25, 2000); and Amendment dated July 27, 2000 (incorporated by reference to Exhibit 4.8 to Amendment No. 1 to Registrant's Registration Statement on Form S-8, Registration No. 333-31092, filed August 18, 2000). +10.23 -- Amendment to Non-Qualified Retirement/Savings Plan of Apache Corporation, dated August 3, 2001, effective September 1, 2000 and July 1, 2001 (incorporated by reference to Exhibit 10.13 to Registrant's Quarterly Report on Form 10-Q, as amended by Form 10-Q/A, for the quarter ended June 30, 2001, SEC File No. 1-4300). +*10.24 -- Amendment to Non-Qualified Retirement/Savings Plan of Apache Corporation, dated December 18, 2003, effective January 1, 2004. +10.25 -- 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). +10.26 -- Apache Corporation 1995 Stock Option Plan, as amended and restated September 13, 2001 (incorporated by reference to Exhibit 10.02 to Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2001, as amended by Form 10-Q/A, SEC File No. 1-4300). +*10.27 -- Apache Corporation 2000 Share Appreciation Plan, as amended and restated February 5, 2004.
44
EXHIBIT NO. DESCRIPTION ------- ----------- +10.28 -- 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). +10.29 -- 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). +10.30 -- 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). +*10.31 -- Apache Corporation 2003 Stock Appreciation Rights Plan, dated and effective May 1, 2003. +10.32 -- 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). +10.33 -- 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). +10.34 -- Apache Corporation Deferred Delivery Plan, as amended and restated December 18, 2002, effective May 2, 2002 (incorporated by reference to Exhibit 4.5 to Post-Effective Amendment No. 2 to Registrant's Registration Statement on Form S-8, Registration No. 333-31092, filed March 11, 2003). +10.35 -- Apache Corporation Executive Restricted Stock Plan, as amended and restated December 18, 2002, effective May 2, 2002 (incorporated by reference to Exhibit 4.5 to Post Effective Amendment No. 1 to Registrant's Registration Statement on Form S-8, Registration No. 333-97403, filed December 30, 2002). +10.36 -- Apache Corporation Non-Employee Directors' Compensation Plan, as amended and restated May 1, 2003, effective July 1, 2003 (incorporated by reference to Exhibit 10.1 to Registrant's Quarterly Report on Form 10-Q, as amended by Form 10-Q/A, for the quarter ended June 30, 2003, SEC File No. 1-4300). +10.37 -- 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). +*10.38 -- Apache Corporation Equity Compensation Plan for Non-Employee Directors, as amended and restated February 5, 2004. +10.39 -- 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). +10.40 -- 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). +10.41 -- 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). +10.42 -- 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).
45
EXHIBIT NO. DESCRIPTION ------- ----------- +10.43 -- 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). 10.44 -- Amended and Restated Gas Purchase Agreement, effective July 1, 1998, by and among Registrant and MW Petroleum Corporation, as seller, and Producers Energy Marketing, LLC, as buyer (incorporated by reference to Exhibit 10.1 to Registrant's Current Report on Form 8-K, dated June 18, 1998, filed June 23, 1998, SEC File No. 1-4300). 10.45 -- Deed of Guaranty and Indemnity, dated January 11, 2003, made by Registrant in favor of BP Exploration Operating Company Limited (incorporated by reference to Registrant's Current Report on Form 8-K, dated and filed January 13, 2003, SEC File No. 1-4300). *12.1 -- Statement of Computation of Ratios of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividends *14.1 -- Code of Business Conduct *21.1 -- Subsidiaries of Registrant *23.1 -- Consent of Ernst & Young LLP *23.2 -- Consent of Ryder Scott Company L.P., Petroleum Consultants *24.1 -- Power of Attorney (included as a part of the signature pages to this report) *31.1 -- Certification of Chief Executive Officer *31.2 -- Certification of Chief Financial Officer *32.1 -- Certification of Chief Executive Officer and Chief Financial Officer
--------------- * Filed herewith. + Management contracts or compensatory plans or arrangements required to be filed herewith pursuant to Item 15 hereof. NOTE: Debt instruments of the Registrant defining the rights of long-term debt holders in principal amounts not exceeding 10 percent of the Registrant's consolidated assets have been omitted and will be provided to the Commission upon request. (b) Reports filed on Form 8-K The following current reports on Form 8-K were filed by the Company during the fiscal quarter ended December 31, 2003: Item 5 -- Other Events -- dated December 18, 2003, filed December 22, 2003 On December 18, 2003, Apache announced that (i) the holders of its common stock approved a proposal to increase the number of authorized common shares to 430 million from 215 million in order to complete the previously announced two-for-one stock split and (ii) the record date for the stock split was December 31, 2003, with the additional shares distributed January 14, 2004. 46 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. APACHE CORPORATION /s/ G. STEVEN FARRIS -------------------------------------- G. Steven Farris President, Chief Executive Officer and Chief Operating Officer Dated: March 11, 2004 POWER OF ATTORNEY The officers and directors of Apache Corporation, whose signatures appear below, hereby constitute and appoint G. Steven Farris, Roger B. Plank, P. Anthony Lannie and Eric L. Harry each of them (with full power to each of them to act alone), the true and lawful attorney-in-fact to sign and execute, on behalf of the undersigned, any amendment(s) to this report and each of the undersigned does hereby ratify and confirm all that said attorneys shall do or cause to be done by virtue thereof. Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
NAME TITLE DATE ---- ----- ---- /s/ G. STEVEN FARRIS Director, President, Chief March 11, 2004 ------------------------------------------------------ Executive Officer and Chief G. Steven Farris Operating Officer (Principal Executive Officer) /s/ ROGER B. PLANK Executive Vice President and March 11, 2004 ------------------------------------------------------ Chief Financial Officer Roger B. Plank (Principal Financial Officer) /s/ THOMAS L. MITCHELL Vice President and Controller March 11, 2004 ------------------------------------------------------ (Principal Accounting Thomas L. Mitchell Officer) /s/ RAYMOND PLANK Chairman of the Board March 11, 2004 ------------------------------------------------------ Raymond Plank /s/ FREDERICK M. BOHEN Director March 11, 2004 ------------------------------------------------------ Frederick M. Bohen /s/ RANDOLPH M. FERLIC Director March 11, 2004 ------------------------------------------------------ Randolph M. Ferlic /s/ EUGENE C. FIEDOREK Director March 11, 2004 ------------------------------------------------------ Eugene C. Fiedorek /s/ A. D. FRAZIER, JR. Director March 11, 2004 ------------------------------------------------------ A. D. Frazier, Jr.
NAME TITLE DATE ---- ----- ---- /s/ PATRICIA ALBJERG GRAHAM Director March 11, 2004 ------------------------------------------------------ Patricia Albjerg Graham /s/ JOHN A. KOCUR Director March 11, 2004 ------------------------------------------------------ John A. Kocur /s/ GEORGE D. LAWRENCE Director March 11, 2004 ------------------------------------------------------ George D. Lawrence /s/ F. H. MERELLI Director March 11, 2004 ------------------------------------------------------ F. H. Merelli /s/ RODMAN D. PATTON Director March 11, 2004 ------------------------------------------------------ Rodman D. Patton /s/ CHARLES J. PITMAN Director March 11, 2004 ------------------------------------------------------ Charles J. Pitman /s/ JAY A. PRECOURT Director March 11, 2004 ------------------------------------------------------ Jay A. Precourt
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 2003 and 2002 and Arthur Andersen LLP for 2001. 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. G. Steven Farris President, Chief Executive Officer and Chief Operating Officer Roger B. Plank Executive Vice President and Chief Financial Officer Thomas L. Mitchell Vice President and Controller (Chief Accounting Officer) Houston, Texas March 11, 2004 F-1 REPORT OF INDEPENDENT AUDITORS To the Shareholders of Apache Corporation: We have audited the accompanying consolidated balance sheets of Apache Corporation (a Delaware corporation) and subsidiaries as of December 31, 2003 and 2002 and the related consolidated statements of operations, shareholders' equity, and cash flows for each of the two years in the period ended December 31, 2003. 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. The financial statements of Apache Corporation as of December 31, 2001, and for the year 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 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, 2003 and 2002 and the consolidated results of their operations and their cash flows for each of the two years in the period ended December 31, 2003, 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 the year 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 consolidated statement of operations. As described in Note 1, the Company's Board of Directors approved a five percent stock dividend and a two-for-one stock split, and all references to number of shares and per share information in the financial statements have been adjusted to reflect the stock dividend and stock split on a retroactive basis. We audited the adjustments that were applied to restate the number of shares and per share information reflected in the 2001 financial statements. Our procedures included (a) agreeing the authorization for the five percent stock dividend and the two-for-one stock split 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 financial statements of Apache Corporation other than with respect to such adjustments; accordingly, we do not express an opinion or any other form of assurance on the 2001 financial statements taken as a whole. As discussed in Notes 1 and 2 to the consolidated financial statements, effective January 1, 2003, the Company change its method of accounting for Asset Retirement Obligations and stock-based compensation. ERNST & YOUNG LLP Houston, Texas March 11, 2004 F-2 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-3 APACHE CORPORATION AND SUBSIDIARIES STATEMENT OF CONSOLIDATED OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, -------------------------------------------- 2003 2002 2001 ---------- ---------- ---------- (IN THOUSANDS, EXCEPT PER COMMON SHARE DATA) REVENUES AND OTHER: Oil and gas production revenues................. $4,198,920 $2,559,748 $2,822,959 Other........................................... (8,621) 125 (13,568) ---------- ---------- ---------- 4,190,299 2,559,873 2,809,391 ---------- ---------- ---------- OPERATING EXPENSES: Depreciation, depletion and amortization........ 1,073,286 843,879 820,831 Asset retirement obligation accretion........... 37,763 -- -- International impairments....................... 12,813 19,600 65,000 Lease operating costs........................... 699,663 457,903 399,919 Gathering and transportation costs.............. 60,460 38,567 34,584 Severance and other taxes....................... 121,793 67,309 74,722 General and administrative...................... 138,524 104,588 88,710 Financing costs: Interest expense............................. 169,090 155,667 178,915 Amortization of deferred loan costs.......... 2,163 1,859 2,460 Capitalized interest......................... (52,891) (40,691) (56,749) Interest income.............................. (3,290) (4,002) (5,864) ---------- ---------- ---------- 2,259,374 1,644,679 1,602,528 ---------- ---------- ---------- PREFERRED INTERESTS OF SUBSIDIARIES............... 8,668 16,224 7,609 ---------- ---------- ---------- INCOME BEFORE INCOME TAXES........................ 1,922,257 898,970 1,199,254 Provision for income taxes...................... 827,004 344,641 475,855 ---------- ---------- ---------- INCOME BEFORE CHANGE IN ACCOUNTING PRINCIPLE...... 1,095,253 554,329 723,399 Cumulative effect of change in accounting principle, net of income tax................. 26,632 -- -- ---------- ---------- ---------- NET INCOME........................................ 1,121,885 554,329 723,399 Preferred stock dividends....................... 5,680 10,815 19,601 ---------- ---------- ---------- INCOME ATTRIBUTABLE TO COMMON STOCK............... $1,116,205 $ 543,514 $ 703,798 ========== ========== ========== BASIC NET INCOME PER COMMON SHARE: Before change in accounting principle........... $ 3.38 $ 1.83 $ 2.44 Cumulative effect of change in accounting principle.................................... .08 -- -- ---------- ---------- ---------- $ 3.46 $ 1.83 $ 2.44 ========== ========== ========== DILUTED NET INCOME PER COMMON SHARE: Before change in accounting principle........... $ 3.35 $ 1.80 $ 2.37 Cumulative effect of change in accounting principle.................................... .08 -- -- ---------- ---------- ---------- $ 3.43 $ 1.80 $ 2.37 ========== ========== ==========
The accompanying notes to consolidated financial statements are an integral part of this statement. F-4 APACHE CORPORATION AND SUBSIDIARIES STATEMENT OF CONSOLIDATED CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31, --------------------------------------- 2003 2002 2001 ----------- ----------- ----------- (IN THOUSANDS) CASH FLOWS FROM OPERATING ACTIVITIES: Net income................................................ $ 1,121,885 $ 554,329 $ 723,399 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion and amortization................ 1,073,286 843,879 820,831 Asset retirement obligation accretion................... 37,763 -- -- Provision for deferred income taxes..................... 546,357 137,672 305,214 Amortization of deferred loan costs..................... 2,163 1,859 2,460 International impairments............................... 12,813 19,600 65,000 Cumulative effect of change in accounting principle, net of income tax......................................... (26,632) -- -- Other................................................... 32,923 9,531 10,469 Changes in operating assets and liabilities, net of effects of acquisitions: (Increase) decrease in receivables...................... (94,295) (122,830) 199,160 (Increase) decrease in inventories...................... (4,216) 717 (3,005) (Increase) decrease in drilling advances and other...... (19,881) (26,116) (14,474) (Increase) decrease in deferred charges and other....... (29,520) 496 (922) Increase (decrease) in accounts payable................. 68,176 32,219 (143,969) Increase (decrease) in accrued expenses................. 11,227 (16,595) 10,065 Increase (decrease) in advances from gas purchasers..... (16,246) (14,574) (13,079) Increase (decrease) in deferred credits and noncurrent liabilities........................................... (9,903) (39,469) (56,149) ----------- ----------- ----------- NET CASH PROVIDED BY OPERATING ACTIVITIES.......... 2,705,900 1,380,718 1,905,000 ----------- ----------- ----------- CASH FLOWS FROM INVESTING ACTIVITIES: Additions to property and equipment....................... (1,594,936) (1,037,368) (1,528,984) Acquisition of BP properties.............................. (1,140,156) -- -- Acquisition of Shell properties........................... (203,033) -- -- 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) Acquisition of Occidental properties...................... (22,000) (11,000) (11,000) Proceeds from sales of oil and gas properties............. 58,944 7,043 348,296 Proceeds from (purchase of) short-term investments, net... -- 101,723 (103,863) Other..................................................... (57,576) (37,520) (76,835) ----------- ----------- ----------- NET CASH USED IN INVESTING ACTIVITIES.............. (2,958,757) (1,236,007) (2,284,337) ----------- ----------- ----------- CASH FLOWS FROM FINANCING ACTIVITIES: Long-term borrowings...................................... 1,780,870 1,467,929 2,759,740 Payments on long-term debt................................ (1,613,362) (1,553,471) (2,733,641) Dividends paid............................................ (72,832) (68,879) (54,492) Common stock activity..................................... 582,865 30,708 10,205 Treasury stock activity, net.............................. 5,350 1,991 (42,959) Cost of debt and equity transactions...................... (5,417) (6,728) (1,718) (Repurchase of) proceeds from preferred interests of subsidiaries............................................ (443,000) -- 440,654 ----------- ----------- ----------- NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES....................................... 234,474 (128,450) 377,789 ----------- ----------- ----------- NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS........ (18,383) 16,261 (1,548) CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR.............. 51,886 35,625 37,173 ----------- ----------- ----------- CASH AND CASH EQUIVALENTS AT END OF YEAR.................... $ 33,503 $ 51,886 $ 35,625 =========== =========== ===========
The accompanying notes to consolidated financial statements are an integral part of this statement. F-5 APACHE CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEET
DECEMBER 31, ------------------------- 2003 2002 ----------- ----------- (IN THOUSANDS) ASSETS CURRENT ASSETS: Cash and cash equivalents................................. $ 33,503 $ 51,886 Receivables, net of allowance............................. 639,055 527,687 Inventories............................................... 125,867 109,204 Drilling advances......................................... 58,062 45,298 Prepaid assets and other.................................. 42,585 32,706 ----------- ----------- 899,072 766,781 ----------- ----------- PROPERTY AND EQUIPMENT: Oil and gas, on the basis of full cost accounting: Proved properties....................................... 16,277,930 12,827,459 Unproved properties and properties under development, not being amortized.................................... 795,161 656,272 Gas gathering, transmission and processing facilities..... 828,169 784,271 Other..................................................... 239,548 194,685 ----------- ----------- 18,140,808 14,462,687 Less: Accumulated depreciation, depletion and amortization............................................ (6,880,723) (5,997,102) ----------- ----------- 11,260,085 8,465,585 ----------- ----------- OTHER ASSETS: Goodwill, net............................................. 189,252 189,252 Deferred charges and other................................ 67,717 38,233 ----------- ----------- $12,416,126 $ 9,459,851 =========== =========== LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES: Accounts payable.......................................... $ 300,598 $ 214,288 Accrued operating expense................................. 72,250 47,382 Accrued exploration and development....................... 212,028 146,871 Accrued compensation and benefits......................... 56,237 32,680 Accrued interest.......................................... 32,621 30,880 Accrued income taxes...................................... 18,936 44,256 Oil and gas derivative instruments........................ 63,542 -- Other..................................................... 64,166 15,878 ----------- ----------- 820,378 532,235 ----------- ----------- LONG-TERM DEBT.............................................. 2,326,966 2,158,815 ----------- ----------- DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES: Income taxes.............................................. 1,697,238 1,120,609 Advances from gas purchasers.............................. 109,207 125,453 Asset retirement obligation............................... 739,775 -- Oil and gas derivative instruments........................ 5,931 3,507 Other..................................................... 183,833 158,326 ----------- ----------- 2,735,984 1,407,895 ----------- ----------- PREFERRED INTERESTS OF SUBSIDIARIES......................... -- 436,626 ----------- ----------- 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 Common stock, $0.625 par, 430,000,000 shares authorized, 332,509,478 and 310,929,080 shares issued, respectively............................................ 207,818 194,331 Paid-in capital........................................... 4,038,007 3,427,450 Retained earnings......................................... 2,445,698 1,427,607 Treasury stock, at cost, 8,012,302 and 8,422,656 shares, respectively............................................ (105,169) (110,559) Accumulated other comprehensive loss...................... (151,943) (112,936) ----------- ----------- 6,532,798 4,924,280 ----------- ----------- $12,416,126 $ 9,459,851 =========== ===========
The accompanying notes to consolidated financial statements are an integral part of this statement. F-6 APACHE CORPORATION AND SUBSIDIARIES STATEMENT OF CONSOLIDATED SHAREHOLDERS' EQUITY
SERIES B SERIES C COMPREHENSIVE PREFERRED PREFERRED COMMON PAID-IN RETAINED INCOME STOCK STOCK STOCK CAPITAL EARNINGS ------------- --------- --------- -------- ---------- ---------- (IN THOUSANDS) BALANCE AT DECEMBER 31, 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 Comprehensive income (loss): Net income................................... $1,121,885 -- -- -- -- 1,121,885 Commodity hedges............................. (39,007) -- -- -- -- -- ---------- Comprehensive income........................... $1,082,878 ========== Cash dividends: Preferred.................................... -- -- -- -- (5,680) Common ($.22 per share)...................... -- -- -- -- (72,200) Five percent common stock dividend............. -- -- 581 25,333 (25,914) Common shares issued........................... -- -- 12,906 579,107 -- Treasury shares issued, net.................... -- -- -- 4,109 -- Other.......................................... -- -- -- 2,008 -- ------- --------- -------- ---------- ---------- BALANCE AT DECEMBER 31, 2003..................... $98,387 $ -- $207,818 $4,038,007 $2,445,698 ======= ========= ======== ========== ========== ACCUMULATED OTHER TOTAL TREASURY COMPREHENSIVE SHAREHOLDERS' STOCK INCOME (LOSS) EQUITY --------- ------------- ------------- (IN THOUSANDS) 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 ($.19 per share)...................... -- -- (56,565) Five percent common stock dividend............. -- -- -- Common shares issued........................... -- -- 27,284 Conversion of Series C Preferred Stock......... -- -- -- Treasury shares issued, net.................... 1,326 -- 1,992 Other.......................................... -- -- 691 --------- --------- ---------- BALANCE AT DECEMBER 31, 2002..................... (110,559) (112,936) 4,924,280 Comprehensive income (loss): Net income................................... -- -- 1,121,885 Commodity hedges............................. -- (39,007) (39,007) Comprehensive income........................... Cash dividends: Preferred.................................... -- -- (5,680) Common ($.22 per share)...................... -- -- (72,200) Five percent common stock dividend............. -- -- -- Common shares issued........................... -- -- 592,013 Treasury shares issued, net.................... 5,390 -- 9,499 Other.......................................... -- -- 2,008 --------- --------- ---------- BALANCE AT DECEMBER 31, 2003..................... $(105,169) $(151,943) $6,532,798 ========= ========= ==========
The accompanying notes to consolidated financial statements are an integral part of this statement. F-7 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Nature of Operations -- Apache Corporation (Apache or the Company) is an independent energy company that explores for, develops and produces natural gas, crude oil and natural gas liquids. The Company's North American exploration and production activities are divided into two U.S. operating regions (Central and Gulf Coast) and a Canadian region. Approximately 70 percent of the Company's proved reserves are located in North America. Internationally, Apache has exploration and production interests in Egypt, offshore Western Australia, in the United Kingdom North Sea (North Sea), offshore The People's Republic of China (China) and in Argentina. In 2003, we ceased operations in Poland. The Company's future financial condition and results of operations will depend upon prices received for its oil and natural gas production and the costs of finding, acquiring, developing and producing reserves. A substantial portion of the Company's production is sold under market-sensitive contracts. Prices for oil and natural gas are subject to fluctuations in response to changes in supply, market uncertainty and a variety of other factors beyond the Company's control. These factors include worldwide political instability (especially in the Middle East), the foreign supply of oil and natural gas, the price of foreign imports, the level of consumer demand, and the price and availability of alternative fuels. 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. Since the Company's January 22, 2003 public offering of 19.8 million shares of common stock occurred prior to the record date, an additional $26 million was reclassified from retained earnings to common stock and paid-in capital. No fractional shares were issued and cash payments totaling $1 million were made in lieu of fractional shares. Two-for-One Stock Split -- On December 18, 2003, the Company announced that holders of its common stock approved an increase in the number of authorized common shares to 430 million from 215 million in order to complete a previously announced two-for-one stock split. The record date for the stock split was December 31, 2003 and the additional shares were distributed on January 14, 2004. All share and per share information in these financial statements and notes thereto have been restated to reflect 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 F-8 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Company's crude oil and natural gas receivables are collected within two months. However, during 2001 and 2002, the Company 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 lessened the availability of U.S. dollars, resulting in an additional one to two month delay in receipts from EGPC. While hard currency shortages in Egypt could lead to further delays, we did not experience any further delays in 2003. 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, 2003 and 2002, the Company had an allowance for doubtful accounts of $30 million and $31 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. Apache capitalized $65 million, $52 million and $55 million of these internal costs in 2003, 2002 and 2001, 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. Prior to 2003, future development costs and dismantlement, restoration and abandonment costs, net of estimated salvage values, were added to the amortizable base. Beginning in 2003, Apache changed its method of accounting for dismantlement, restoration and abandonment costs (see Note 2). F-9 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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 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 2003 and 2002, the Company recorded approximately $13 million ($8 million after tax) and $20 million ($12 million after tax), respectively, in impairments of unproved property costs in Poland. 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" were $78 million and $259 million as of December 31, 2002 and December 31, 2003, respectively. The amounts related to business combinations and major asset purchases after June 30, 2001 that would be classified as "intangible developed mineral interest" were $332 million and $1.4 billion as of December 31, 2002 and December 31, 2003, 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 F-10 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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. 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 $309 million and $240 million at December 31, 2003 and 2002, respectively. Goodwill -- The Company adopted SFAS No. 142 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, 2003 and 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 remain in Canada and Egypt, respectively. Apache deemed the geographic areas to be the reporting unit. Apache recognized no impairment of goodwill during 2003 or 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 December 31, 2003 and 2002, are liabilities of approximately $78 million and $43 million, respectively, representing the amount by which checks issued, but not presented to the Company's banks for collection, exceeded balances in applicable bank accounts. Revenue Recognition -- Oil and gas revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collectibility of the revenue is probable. Apache uses the sales method of accounting for gas production imbalances. The volumes of gas sold may differ from the volumes to which Apache is entitled based on its interests in the properties. These differences create imbalances that are recognized as a liability only when the estimated remaining reserves will not be F-11 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) sufficient to enable the underproduced owner to recoup its entitled share through production. The Company's recorded liability of $4 million for gas imbalances on December 31, 2003 was unchanged from the prior year-end. The liability is reflected in other non-current liabilities. No receivables are recorded for those wells where Apache has taken less than its share of production. Gas imbalances are reflected as adjustments to proved gas reserves and future cash flows in the unaudited supplemental oil and gas disclosures. Adjustments for gas imbalances totaled less than one percent of Apache's proved gas reserves at December 31, 2003, 2002 and 2001. 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. Apache accounts for its derivative instruments in accordance with SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended. SFAS No. 133 establishes accounting and reporting standards requiring that all derivative instruments be recorded on the balance sheet as either an asset or liability measured at fair value (which is generally based on information obtained from independent parties) 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 under Revenues and Other in the statement of consolidated operations. 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 inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and gas prices). F-12 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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 are 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, our Canadian subsidiaries' functional currency was the Canadian dollar. Translation adjustments resulting from translating the Canadian subsidiaries' foreign currency financial statements into U.S. dollar equivalents were reported separately and accumulated in other comprehensive income. Some of the Company's Canadian subsidiaries had intercompany debt denominated in U.S. dollars. Prior to conversion, these transactions were long-term investments, and therefore, foreign currency gains and losses were recognized in other comprehensive income. 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. The Company accounts for foreign currency gains and losses in accordance with SFAS No. 52 "Foreign Currency Translation." Foreign currency translation gains and losses related to deferred taxes are recorded as a component of its provision for income taxes, while all other foreign currency gains and losses are reflected in Revenues and Other. In 2003, the Company recorded additional deferred tax expense of $172 million as a result of the weaker U.S. dollar (see Note 7, Income Taxes). Foreign currency gains and losses in 2003, reflected in Revenues and Other netted to a loss of $2 million. 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 -- On December 31, 2003, the Company had several stock-based employee compensation plans, which include the Stock Option Plans, the Performance Plan, the Share Appreciation Plan and restricted stock. These plans are defined and described more fully in Note 9. Prior to 2003, the Company accounted for those plans under the recognition and measurement provisions of APB Opinion No. 25, "Accounting for Stock Issued to Employees," and related Interpretations. No material stock-based employee compensation cost is reflected in 2002 and 2001 net income, as all options granted under those plans had an exercise price equal to the market value of the underlying common stock on the date of grant. Effective January 1, 2003, the Company adopted the fair value recognition provisions of SFAS No. 123, "Accounting for Stock-Based Compensation," as amended by SFAS No. 148, prospectively to all employee awards F-13 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) granted, modified, or settled after January 1, 2003. Therefore, the cost related to stock-based employee compensation included in the determination of net income for 2003 is less than that which would have been recognized if the fair value based method had been applied to all awards since the original effective date of SFAS No. 123, as amended. The following table illustrates the effect on income attributable to common stock and earnings per share had the fair value based provisions of SFAS No. 123, as amended, been applied to all outstanding and unvested awards for the Stock Option Plans, the Performance Plan, the Share Appreciation Plan and restricted stock.
FOR THE YEAR ENDED DECEMBER 31, ---------------------------------- 2003 2002 2001 ---------- -------- -------- (IN THOUSANDS) Income attributable to Common Stock, as reported............ $1,116,205 $543,514 $703,798 Add: Stock-based employee compensation expense included in reported net income, net of related tax effects........... 2,524 1,087 -- Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards (see Note 9), net of related tax effects.................. (23,001) (20,830) (22,463) ---------- -------- -------- Pro forma Income Attributable to Common Stock............... $1,095,728 $523,771 $681,335 ========== ======== ======== Net Income per Common Share: Basic: As reported............................................ $ 3.46 $ 1.83 $ 2.44 Pro forma.............................................. 3.40 1.76 2.37 Diluted: As reported............................................ $ 3.43 $ 1.80 $ 2.37 Pro forma.............................................. 3.37 1.72 2.29
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. The stock appreciation rights, described in Note 9, are not included in the above table because it is a cash based plan. 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 May 2003, the SEC issued Staff Accounting Bulletin No. 103, "Update of Codification of Staff Accounting Bulletins" (SAB No. 103) to update existing codification of all staff accounting bulletins. SAB No. 103 provided new guidance regarding the calculation of the "ceiling" or F-14 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) limitation on the amount of oil and gas properties that can be capitalized on the balance sheet under the full-cost method of accounting. The ceiling calculation dictates that prices and costs in effect as of the last day of the period are generally held constant indefinitely. SAB No. 103 codifies the view that using end-of-period prices, as adjusted for cash flow hedges, represents the best measure of estimated future cash flows to calculate the ceiling limitation. Consistent with the guidance in SAB No. 103, the Company now adjusts the end-of-period price by the effect of cash flow hedges. 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 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. Certain other prior period amounts have been reclassified to conform with current year presentations. 2. NEW ACCOUNTING PRONOUNCEMENTS In June 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 requires that an asset retirement obligation (ARO) associated with the retirement of a tangible long-lived asset be recognized as a liability in the period in which a legal obligation is incurred and becomes determinable, with an offsetting increase in the carrying amount of the associated asset. The cost of the tangible asset, including the initially recognized ARO, is depleted such that the cost of the ARO is recognized over the useful life of the asset. The ARO is recorded at fair value, and accretion expense will be recognized over time as the discounted liability is accreted to its expected settlement value. The fair value of the ARO is measured using expected future cash outflows discounted at the company's credit-adjusted risk-free interest rate. The Company adopted SFAS No. 143 on January 1, 2003, which resulted in an increase to net oil and gas properties of $410 million and additional liabilities related to asset retirement obligations of $369 million. These amounts reflect the ARO of the company had the provisions of SFAS No. 143 been applied since inception and resulted in a non-cash cumulative effect increase to earnings of $27 million ($41 million pretax). In accordance with the provisions of SFAS No. 143, Apache records an abandonment liability associated with its oil and gas wells and platforms when those assets are placed in service, rather than its past practice of accruing the expected undiscounted abandonment costs on a unit-of-production basis over the productive life of the associated full-cost pool. Under SFAS No. 143, depletion expense is reduced since a discounted ARO is depleted in the property balance rather than the undiscounted value previously depleted under the old rules. The lower depletion expense under SFAS No. 143 is offset, however, by accretion expense, which is recognized over time as the discounted liability is accreted to its expected settlement value. Inherent in the fair value calculation of ARO are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property balance. The $27 million ($41 million pretax) cumulative increase to earnings upon adoption did not take into consideration potential impacts of adopting SFAS No. 143 on previous full-cost property impairment tests. The Company chose not to re-calculate historical full-cost impairment tests (ceiling test) upon adoption even though historical oil and gas property balances would have been higher had the Company applied the provisions of the statement. Management believes this approach is appropriate because SFAS No. 143 is silent on this issue and was not effective during the prior ceiling test periods. Had the Company re-calculated the historical full-cost ceiling tests and included the impact as a component of the cumulative effect of adoption, the ultimate gain recognized would have potentially been reduced. A ceiling test calculation was performed upon adoption and at the end of each reporting period subsequent to adoption and no impairment was F-15 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) necessary. In calculating ceiling limitations, the Company includes 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, the Company nets the ARO liability against the property balance. The Company believes this is appropriate since there must be a comparable basis between the net book value of the properties and the full-cost ceiling limitation. The following table is a reconciliation of the asset retirement obligation liability since adoption (in thousands): Asset retirement obligation upon adoption on January 1, 2003...................................................... $368,537 Liabilities incurred........................................ 392,287 Liabilities settled......................................... (35,315) Accretion expense........................................... 37,763 Revisions in estimated liabilities.......................... (23,497) -------- Asset retirement obligation at December 31, 2003............ $739,775 ========
Liabilities incurred during the period primarily relate to asset retirement obligations assumed in connection with the BP p.l.c. (BP) Gulf of Mexico, BP North Sea and Shell Exploration and Production Company (Shell) property acquisitions. Liabilities settled during the period relate to individual properties plugged and abandoned, and approximately $2.8 million of liabilities associated with property sold. The downward revision to the estimated liability resulted primarily from having an independent review of expected obligations of abandoning the North Sea platforms, offset by the Company's annual reassessment of the expected cash outflows and assumptions inherent in the ARO calculation. The pro forma asset retirement obligation would have been approximately $334 million at January 1, 2002 had the Company adopted the provisions of SFAS 143 on January 1, 2002. The following table shows the pro forma effect of the implementation on the Company's Income Attributable to Common Stock and Net Income per Common Share had SFAS No. 143 been adopted by the Company on January 1, 2001.
FOR THE YEAR ENDED DECEMBER 31, ---------------------- 2002 2001 --------- --------- (IN THOUSANDS, EXCEPT PER SHARE DATA) Income Attributable to Common Stock, as reported............ $543,514 $703,798 Effect on Net Income had SFAS No. 143 been applied.......... (986) (3,083) -------- -------- Income Attributable to Common Stock, as adjusted............ $542,528 $700,715 ======== ======== Basic Net Income per Common Share: Net Income, as reported................................... $ 1.83 $ 2.44 Effect on Net Income had SFAS No. 143 been applied........ -- (.01) -------- -------- Net Income, as adjusted................................... $ 1.83 $ 2.43 ======== ======== Diluted Net Income per Common Share: Net Income, as reported................................... $ 1.80 $ 2.37 Effect on Net Income had SFAS No. 143 been applied........ -- (.01) -------- -------- Net Income, as adjusted................................... $ 1.80 $ 2.36 ======== ========
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 F-16 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) interests) that is exposed to a majority of the entity's expected losses if they occur, receive a majority of the 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 generally effective for the first fiscal year or interim period beginning after December 31, 2003, to VIEs in which a company holds a variable interest that is acquired before February 1, 2003. This interpretation did not affect the Company's consolidated financial statements. In May 2003, the FASB issued SFAS No. 150 "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity." SFAS No. 150 establishes standards on how companies classify and measure certain financial instruments with characteristics of both liabilities and equity. The statement requires that the Company classify as liabilities the fair value of all mandatorily redeemable financial instruments that had previously been recorded as equity or elsewhere in the consolidated financial statements. This statement is effective for financial instruments entered into or modified after May 31, 2003, and otherwise effective for all existing financial instruments, except for minority interests in limited-life entities, beginning in the third quarter of 2003. As stated in Note 12, the Company paid off the Preferred Interests of Subsidiaries in September 2003; therefore, this statement did not have a material impact on the Company's financial statements. 3. ACQUISITIONS AND DIVESTITURES Acquisitions On January 13, 2003, Apache announced that it had entered into agreements to purchase producing properties in the North Sea and Gulf of Mexico from subsidiaries of BP for $1.3 billion, with $670 million allocated to the Gulf of Mexico properties and $630 million allocated to properties in the North Sea. The properties included estimated proved reserves of 233.2 million barrels of oil equivalent (MMboe), 147.6 MMboe located in the North Sea with the balance in the Gulf of Mexico. Both purchase agreements were effective as of January 1, 2003. As is customary, Apache assumed BP's abandonment obligation for the properties, which was considered in determining the purchase price. Both the Gulf of Mexico and North Sea assets acquired from BP were funded with net proceeds of approximately $554 million from the issuance of 19.8 million shares of common stock in January 2003, and proceeds from additional debt of approximately $604 million borrowed under existing lines of credit and commercial paper. Apache and BP closed the above referenced acquisition of the Gulf of Mexico properties on March 13, 2003, which included BP's interest in 56 producing fields, and 104 blocks. At closing, the $670 million purchase price was adjusted for normal closing items and preferential rights exercised by third parties. The exercise of preferential rights by third parties reduced the purchase price by $73 million and estimated reserves by 9.6 MMboe. The purchase price was further adjusted for various normal closing items, including revenues and expenditures related to the properties for the period between the effective and closing dates. As a result, cash consideration of $509 million was paid by Apache upon closing. In a separate transaction closed February 21, 2003, Apache purchased BP's interest in several other Gulf of Mexico properties with estimated proved reserves of 2.1 MMboe for an adjusted purchase price of $15 million. Including $4 million of transaction costs, total cash consideration for the two acquisitions of Gulf of Mexico properties from BP totaled $528 million. The acquisition of the UK North Sea properties closed on April 2, 2003, at which time Apache paid a purchase price, adjusted for normal closing and working capital adjustments, of $630 million. The acquisition of the North Sea properties includes a 96 percent interest in the Forties Field and establishes a new core area for the Company. In conjunction with the Forties acquisition, Apache may be required to issue a letter of credit to BP to cover the present value of related asset retirement obligations if the rating of the Company's senior unsecured debt is lowered by both Moody's and Standard and Poor's from its current ratings of A3 and F-17 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) A-, respectively. Should this occur, the initial letter of credit amount would be 175 million British pounds ($306 million U.S. at December 31, 2003). Apache has agreed to sell all of the North Sea production through December 2004 to BP at a combination of fixed and market sensitive prices pursuant to a contract entered into in connection with the North Sea purchase agreement. The BP purchase prices were allocated to the assets acquired and liabilities assumed based upon their estimated fair values as of the date of acquisition, as follows:
U.S. -- U.K. -- GULF OF MEXICO NORTH SEA TOTAL* -------------- --------- ---------- (IN THOUSANDS) Proved property......................................... $539,110 $ 854,835 $1,393,945 Unproved property....................................... 57,500 65,000 122,500 Working capital acquired, net........................... -- 10,957 10,957 Asset retirement obligation............................. (69,000) (250,887) (319,887) Deferred income tax liability........................... -- (50,381) (50,381) -------- --------- ---------- Cash consideration...................................... $527,610 $ 629,524 $1,157,134 ======== ========= ==========
* Property balance includes $12 million of transaction costs (U.S. -- $4 million; North Sea -- $8 million). --------------- On July 3, 2003, Apache announced that it had completed the acquisition of producing properties on the Outer Continental Shelf of the Gulf of Mexico from Shell for $200 million, subject to normal post-closing adjustments, including preferential rights. Prior to the transaction, Morgan Stanley Capital Group, Inc. (Morgan Stanley) paid Shell $300 million to acquire an overriding royalty interest in a portion of the reserves to be produced over the next four years. Shell's sale of an overriding royalty interest to Morgan Stanley is commonly known in the industry as a volumetric production payment (VPP). Under the terms of the VPP, Morgan Stanley is to receive a fixed volume of oil and gas production over approximately four years beginning in August 2003 for gas and November 2003 for oil. The VPP reserves and production will not be recorded by Apache. Apache recorded estimated proved reserves of 124.6 billion cubic feet (Bcf) of natural gas and 6.6 million barrels of oil. In addition, a $60 million liability for the future cost to produce and deliver volumes subject to the VPP will be recorded by the Company because the overriding royalties are not burdened by production costs. This liability will be amortized as the volumes are produced and delivered to Morgan Stanley. The purchase agreement was effective as of July 1, 2003. The acquisition included interests in 26 fields covering 50 blocks (approximately 209,000 acres) and interests in two onshore gas plants. Apache will operate 15 of the fields with 91 percent of the production. The purchase price was funded by borrowings under the Company's lines of credit and commercial paper program. In 2003, the Company also completed other acquisitions for cash consideration totaling $126 million. These acquisitions added approximately 28 MMboe to the Company's proved reserves. On December 17, 2002, Apache announced the acquisition of certain South Louisiana properties comprising 234,000 net acres (366 square miles) with net proved reserves of approximately 29.8 MMboe, 88 percent of which is natural gas, from a private company. The acquisition 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). F-18 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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 3.8 million restricted shares of Apache common stock issued to Shell Overseas Holdings (valued at $26.425 per share), 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 ========= ========
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. F-19 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The following unaudited pro forma information shows the effect on the Company's consolidated results of operations as if the acquisitions from BP occurred on January 1, 2002 and the Fletcher and Repsol transactions occurred on January 1, 2001. The pro forma information includes only significant acquisitions and numerous assumptions, and is not necessarily indicative of future results of operations:
FOR THE YEAR ENDED DECEMBER 31, ------------------------------------------------------------------------------ 2003 2002 2001 ------------------------ ------------------------ ------------------------ AS REPORTED PRO FORMA AS REPORTED PRO FORMA AS REPORTED PRO FORMA (UNAUDITED) ----------- ---------- ----------- ---------- ----------- ---------- (IN THOUSANDS, EXCEPT PER COMMON SHARE DATA) Revenues and other......... $4,190,299 $4,428,261 $2,559,873 $3,490,487 $2,809,391 $2,916,346 Net income................. 1,121,885 1,195,082 554,329 683,284 723,399 748,976 Preferred stock dividends................ 5,680 5,680 10,815 10,815 19,601 19,601 Income attributable to common stock............. 1,116,205 1,189,402 543,514 672,469 703,798 729,375 Net income per common share: Basic.................... $ 3.46 $ 3.68 $ 1.83 $ 2.12 $ 2.44 $ 2.52 Diluted.................. 3.43 3.64 1.80 2.09 2.37 2.45 Average common shares outstanding(1)........... 322,498 323,583 297,234 317,036 288,014 288,900
(1) Pro forma shares assume the issuance of 19.8 million common shares as of January 1, 2002. --------------- Each transaction described above has been accounted for using the purchase method of accounting and has been included in the consolidated financial statements of Apache since the date of acquisition. Divestitures During 2003, Apache sold marginal properties containing 6.9 MMboe of proved reserves, for $59 million. Apache used the sales proceeds to reduce bank debt. During 2002, Apache sold marginal properties containing 1.8 MMboe of proved reserves, for $7 million. Apache used the sales proceeds to reduce bank debt. 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. 4. DERIVATIVE INSTRUMENTS AND FIXED-PRICE PHYSICAL CONTRACTS Apache uses a variety of strategies to manage its exposure to fluctuations in commodity prices. As established by the Company's hedging policy, Apache primarily enters into cash flow hedges in connection with selected 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. During the first quarter of 2003, in conjunction with the acquisitions from BP and during the fourth quarter of 2002, in conjunction with the South Louisiana properties acquisition, Apache entered into, and designated as cash flow hedges, natural gas and crude oil fixed-price swaps and natural gas option collars. These positions were entered into in accordance with the Company's hedging policy and involved several F-20 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) counterparties which are rated A+ or better. As of December 31, 2003, the outstanding positions of our cash flow hedges were as follows:
TOTAL WEIGHTED FAIR VALUE VOLUMES AVERAGE ASSET/ PRODUCTION PERIOD INSTRUMENT TYPE (MMBTU/BBL) FLOOR/CEILING (LIABILITY) ----------------- -------------------- ----------- ------------- -------------- (IN THOUSANDS) 2004............................ Gas Collars 18,300,000 $3.25/5.81 $ (8,420) Gas Fixed-Price Swap 51,240,000 4.52 (46,099) Oil Fixed-Price Swap 1,550,000 26.59 (9,023) 2005............................ Gas Collars 9,050,000 3.25/5.20 (5,931)
In addition to the fixed-price swaps and option collars, Apache entered into a separate crude oil physical sales contract with BP. The sales contract is a normal purchase and sale under SFAS No. 133 and, therefore, the Company has designated and accounted for the contract under the accrual method. As of December 31, 2003, the outstanding terms of the contract were as follows:
CRUDE OIL FIXED-PRICE PHYSICAL SALES CONTRACT (BRENT) ---------------------------------------------------------- TOTAL VOLUMES AVERAGE PRODUCTION PERIOD (BARRELS) FIXED PRICE ----------------- ------------- ----------- 2004....................... 14,175,000 $22.24
A reconciliation of the components of accumulated other comprehensive income (loss) in the statement of consolidated shareholders' equity related to Apache's derivative activities is presented in the table below:
GROSS AFTER TAX --------- --------- (IN THOUSANDS) Unrealized loss on derivatives at December 31, 2002......... $ (7,141) $ (4,186) Net losses realized into earnings........................... 80,975 50,272 Net change in derivative fair value......................... (143,150) (89,279) --------- -------- Unrealized loss on derivatives at December 31, 2003......... $ (69,316) $(43,193) ========= ========
Based on current market prices, the Company recorded an unrealized loss in other comprehensive income of $69 million ($43 million after tax). Any loss will be realized in future earnings contemporaneously with the related sales of natural gas and crude oil production applicable to specific hedges. Were current prices to hold, a loss of $63 million ($39 million after tax) would be realized over the next 12 months. However, these amounts could vary materially as a result of changes in market conditions. The contracts designated as hedges qualified and continue to qualify for hedge accounting in accordance with SFAS No. 133, as amended. 2001 Unwind -- Prior to Apache's derivative activity during 2002, the Company had 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 Corporation 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"). F-21 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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 ACTIVITY CONTRACTS GAS 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 No. 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 were recognized in earnings as the original hedged production occurred. 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 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 and a loss of $336,000 during 2003. As of December 31, 2003, an immaterial amount remains and will be recognized in 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. 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 $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. F-22 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 6. DEBT Long-Term Debt
DECEMBER 31, ------------------------ 2003 2002 ---------- ---------- (IN THOUSANDS) Apache: Money market lines of credit.............................. $ 5,200 $ 8,900 Global credit facility -- U.S............................. -- -- Commercial paper.......................................... 130,000 271,400 6.25-percent debentures due 2012, net of discount......... 397,525 397,307 7-percent notes due 2018, net of discount................. 148,506 148,446 7.625-percent notes due 2019, net of discount............. 149,161 149,134 7.7-percent notes due 2026, net of discount............... 99,665 99,660 7.95-percent notes due 2026, net of discount.............. 178,636 178,614 7.375-percent debentures due 2047, net of discount........ 148,014 148,009 7.625-percent debentures due 2096, net of discount........ 149,175 149,175 ---------- ---------- 1,405,882 1,550,645 ---------- ---------- Subsidiary and other obligations: Money market lines of credit.............................. -- -- Global credit facility -- Canada.......................... -- -- Fletcher notes............................................ 5,356 5,356 Apache Finance Australia 6.5-percent notes due 2007, net of discount............................................ 169,390 169,260 Apache Finance Australia 7-percent notes due 2009, net of discount............................................... 99,597 99,535 Apache Finance Canada 4.375-percent notes due 2015, net of discount............................................... 349,688 -- Apache Finance Canada 7.75-percent notes due 2029, net of discount............................................... 297,053 297,019 Apache Clearwater notes due 2003.......................... -- 37,000 ---------- ---------- 921,084 608,170 ---------- ---------- Total debt.................................................. 2,326,966 2,158,815 Less: current maturities.................................... -- -- ---------- ---------- Long-term debt.............................................. $2,326,966 $2,158,815 ========== ==========
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: (i) maintain a consolidated tangible net worth, plus the aggregate amount of any non-cash write-downs, of at least $2.8 billion as of December 31, 2003, 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, 2003, 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, 2003. The five-year facilities are scheduled to mature on June 3, 2007 and the 364-day facility is currently scheduled to mature on May 28, 2004. 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 F-23 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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, 2003, 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, 2003 was $1.4 billion. At December 31, 2003, 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 $5.2 million was outstanding as of December 31, 2003. 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, 2003 and 2002 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 1.19 percent in 2003 and 1.85 percent in 2002. 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 May 15, 2003, Apache Finance Canada Corporation (Apache Finance Canada) issued $350 million of 4.375 percent, 12-year, senior unsecured notes in a private placement. On March 4, 2004, the Company completed an exchange offer with the holders of the notes, issuing publicly traded, registered notes of the same principal amount and with the same interest rates, payment terms and maturity. The notes are irrevocably and unconditionally guaranteed by Apache and are redeemable, as a whole or in part, at Apache Finance Canada's option, subject to a make-whole premium. Interest is payable semi-annually on May 15 and November 15 of each year commencing on November 15, 2003. The proceeds of the original note offering were used to reduce bank debt and outstanding commercial paper and for general corporate purposes. The Company does not have the right to redeem any of its notes or debentures (other than the Apache Corporation 6.25-percent notes due April 15, 2012, the Apache Finance Australia 6.5-percent notes due 2007 and the Apache Finance Canada 4.375-percent notes due 2015) prior to maturity. Under certain conditions, the Company has the right to advance maturity on the 7.7-percent notes, 7.95-percent notes, 7.375-percent debentures and 7.625-percent debentures. The notes issued by Apache Finance Pty Ltd (Apache Finance Australia) and Apache Finance Canada are irrevocably and unconditionally guaranteed by Apache and, in the case of Apache Finance Australia, by Apache North America, Inc., an indirect wholly-owned subsidiary of the Company. Under certain conditions related to changes in relevant tax laws, Apache Finance Australia and Apache Finance Canada have the right to redeem the notes prior to maturity. The Apache Finance Australia 6.5-percent notes and the Apache Finance Canada 4.375-percent notes may be redeemed at the Company's option subject to a make-whole premium (see Note 17). F-24 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) In August 2003, the Apache Clearwater, Inc. notes matured and were repaid using commercial paper. The $14 million of discounts on the Company's debt at December 31, 2003, is being amortized over the life of the debt issuances as additional interest expense. As of December 31, 2003 and 2002, the Company had approximately $22 million and $19 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) 2004........................................................ $ -- 2005........................................................ 830 2006........................................................ 274 2007........................................................ 307,590 2008........................................................ 353 Thereafter.................................................. 2,017,919 ---------- $2,326,966 ==========
The Company made cash payments for interest, net of amounts capitalized, of $96 million, $99 million and $105 million for the years ended December 31, 2003, 2002 and 2001, respectively. 7. INCOME TAXES Income before income taxes is composed of the following:
FOR THE YEAR ENDED DECEMBER 31, ---------------------------------- 2003 2002 2001 ---------- -------- ---------- (IN THOUSANDS) United States............................................. $ 918,432 $286,840 $ 605,392 Foreign................................................... 1,003,825 612,130 593,862 ---------- -------- ---------- Total................................................... $1,922,257 $898,970 $1,199,254 ========== ======== ==========
The total provision for income taxes consists of the following:
FOR THE YEAR ENDED DECEMBER 31, --------------------------------- 2003 2002 2001 --------- --------- --------- (IN THOUSANDS) Current taxes: Federal................................................... $ 37,472 $ 25,657 $ 19,054 State..................................................... 2,296 1,564 4,995 Foreign................................................... 240,879 179,748 146,592 Deferred taxes.............................................. 546,357 137,672 305,214 -------- -------- -------- Total..................................................... $827,004 $344,641 $475,855 ======== ======== ========
F-25 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) A reconciliation of the U.S. federal statutory income tax amounts to the effective amounts is shown below:
FOR THE YEAR ENDED DECEMBER 31, --------------------------------- 2003 2002 2001 --------- --------- --------- (IN THOUSANDS) Statutory income tax........................................ $672,790 $314,639 $419,739 State income tax, less federal benefit...................... 22,961 7,171 15,135 Effect of foreign operations................................ 49,657 35,283 38,890 Canadian tax rate reduction................................. (71,340) -- -- Additional deferred taxes related to currency fluctuations.............................................. 171,930 -- -- Realized tax basis in investment............................ (23,234) (16,321) (1,350) All other, net.............................................. 4,240 3,869 3,441 -------- -------- -------- $827,004 $344,641 $475,855 ======== ======== ========
The net deferred tax liability is comprised of the following:
DECEMBER 31, ----------------------- 2003 2002 ---------- ---------- (IN THOUSANDS) Deferred tax assets: Deferred income........................................... $ (1,446) $ (1,120) Federal net operating loss carryforwards.................. (21,781) (40,700) State net operating loss carryforwards.................... (19,693) (16,436) Statutory depletion carryforwards......................... (5,723) (5,652) Alternative minimum tax credits........................... (9,141) (13,836) Foreign net operating loss carryforwards.................. (206,548) (9,764) Accrued expenses and liabilities.......................... (5,683) (5,818) Other..................................................... (5,401) (3,539) ---------- ---------- Total deferred tax assets.............................. (275,416) (96,865) Valuation allowance....................................... -- 9,764 ---------- ---------- Net deferred tax assets................................ (275,416) (87,101) ---------- ---------- Deferred tax liabilities: Depreciation, depletion and amortization.................. 1,972,654 1,207,710 Total deferred tax liabilities......................... 1,972,654 1,207,710 ---------- ---------- Net deferred income tax liability........................... $1,697,238 $1,120,609 ========== ==========
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, 2003, the undistributed earnings of the foreign subsidiaries amounted to approximately $3.2 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, 2003, the Company had U.S. federal net operating loss carryforwards of $62 million, state net operating loss carryforwards of $381 million and foreign net operating loss carryforwards of $8 million for China and $513 million for the United Kingdom. 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 for China has a 5-year carryover period while the United Kingdom loss has an unlimited carryover period. The F-26 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Company has alternative minimum tax (AMT) credit carryforwards of $9 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 $309 million, $171 million and $172 million for the years ended December 31, 2003, 2002 and 2001, 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, 2003 and 2002, advances of $109 and $125 million, respectively, were outstanding. Gas volumes delivered to the purchaser are reported as revenue at prices used to calculate the amount advanced, before imputed interest, plus or minus amounts paid or received by Apache applicable to the price swap agreements. Interest expense is recorded based on a rate of eight percent . In October and November 2001, Apache terminated the gas price swap contracts associated with these advances and received proceeds of $78 million. The effect of terminating these derivative instruments reduces future price risk exposure to natural gas price volatility by establishing a fixed price for the remaining quantities of gas to be delivered under the terms of the contracts. Upon termination, Apache designated the remaining contractual volumes of gas that will be delivered to the purchasers as a normal fixed-price physical sale. The prices used in settling the derivatives represented an average 51 percent increase over the prices reflected in the original contracts. No gain or loss was recognized 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. F-27 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 9. CAPITAL STOCK Common Stock Outstanding
2003 2002 2001 ----------- ----------- ----------- Balance, beginning of year............................. 302,506,424 287,916,676 285,596,268 Treasury shares issued (acquired), net................. 130,636 121,432 (1,923,564) Shares issued for: Public offering(3)................................... 19,803,000 -- -- Acquisition of Fletcher subsidiaries(1).............. -- -- 3,796,550 Conversion of Series C Preferred Stock(2)............ -- 13,109,730 -- Stock compensation plans............................. 2,101,844 1,358,586 484,940 Fractional shares repurchased........................ (44,728) -- (37,518) ----------- ----------- ----------- Balance, end of year(4)................................ 324,497,176 302,506,424 287,916,676 =========== =========== ===========
(1) 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. (2) In May 2002, we completed the mandatory conversion of our Series C preferred stock into approximately 13.1 million common shares. (3) 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. (4) On December 18, 2003, the Company announced that holders of its common stock approved a proposal to increase the number of authorized common shares to 430 million from 215 million in order to complete a previously announced two-for-one stock split. The record date for the stock split was December 31, 2003 and the additional shares were distributed on January 14, 2004. --------------- Net Income Per Common Share -- A reconciliation of the components of basic and diluted net income per common share for the years ended December 31, 2003, 2002 and 2001 is presented in the table below:
2003 2002 2001 -------------------------------- ------------------------------ ------------------------------ INCOME SHARES PER SHARE INCOME SHARES PER SHARE INCOME SHARES PER SHARE ---------- ------- --------- -------- ------- --------- -------- ------- --------- (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) BASIC: Income attributable to common stock............. $1,116,205 322,498 $3.46 $543,514 297,234 $1.83 $703,798 288,014 $2.44 ========= ========= ========= EFFECT OF DILUTIVE SECURITIES: Stock options and other.... -- 2,832 -- 2,566 -- 2,122 Series C Preferred Stock... -- -- 5,149 4,812 13,952 13,110 ---------- ------- -------- ------- -------- ------- DILUTED: Income attributable to common stock, including assumed conversions...... $1,116,205 325,330 $3.43 $548,663 304,612 $1.80 $717,750 303,246 $2.37 ========== ======= ========= ======== ======= ========= ======== ======= =========
During 2002, Apache began modifying its stock compensation plans in order to reflect the cost of these plans in the Statement of Consolidated Operations. As part of this effort, Apache issued stock appreciation rights and restricted stock and, effective January 1, 2003, adopted the expense provisions of SFAS No. 123, as amended, on a prospective basis for all stock options granted under the Company's existing option plans. Stock Option Plans -- On December 31, 2003, officers and employees have options to purchase shares of the Company's common stock under one or more employee stock option plans adopted in 1990, 1995, 1998 F-28 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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. A summary of the status of the plans described above as of December 31, 2003, 2002 and 2001, and changes during the years then ended, is presented in the table and narrative below (shares in thousands):
2003 2002 2001 ----------------- ----------------- ----------------- 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......... 11,328 $19.53 11,544 $17.62 10,354 $15.76 Granted................................ 280 30.97 1,786 27.99 2,402 24.95 Exercised.............................. (2,198) 8.54 (1,544) 14.88 (596) 13.66 Forfeited.............................. (269) 11.43 (458) 20.21 (616) 18.79 ------ ------ ------ Outstanding, end of year............... 9,141 20.59 11,328 19.53 11,544 17.62 ====== ====== ====== Exercisable, end of year............... 5,146 19.21 5,731 17.25 5,156 15.34 ====== ====== ====== Available for grant, end of year....... 3,042 1,068 2,558 ====== ====== ====== Weighted average fair value of options granted during the year(1)........... $10.14 $10.14 $10.44 ====== ====== ======
(1) The fair value of each option is estimated as of the date of grant using the Black-Scholes option-pricing model with the following weighted-average assumptions used for grants in 2003, 2002 and 2001, respectively: (i) risk-free interest rates of 2.86, 4.87 and 4.95 percent; (ii) expected lives of 4.5 years for 2003 and 2002 and five years for 2001 for the Stock Option Plans; (iii) expected volatility of 36.60, 37.17 and 41.39 percent; and (iv) expected dividend yields of .66, .68 and .51 percent. --------------- F-29 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The following table summarizes information about stock options covered by the plans described above that are outstanding at December 31, 2003 (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 ------------------------ ----------- ----------- -------- ----------- -------- $25.97 - $14.34......................... 855 3.32 $11.96 790 $11.97 14.34 - 15.21......................... 1,562 4.13 14.85 1,326 14.84 15.37 - 21.27......................... 3,066 4.50 18.03 1,400 19.92 23.02 - 38.90......................... 3,658 7.91 26.76 1,630 25.67 ----------- ----------- 9,141 5,146 =========== ===========
Stock Appreciation Rights -- During 2003, the Company began issuing stock appreciation rights (SARs) to non-executive employees in lieu of stock options. A total of 1,802,210 SARs were issued during 2003 and will be settled in cash upon exercise. The vesting period is over four years and the Company records compensation expense on the vested SARs outstanding as the price of the Company's common stock fluctuates. Total expense of $4 million ($2 million after-tax) was recorded in 2003 for SARs issued during the year. Restricted Stock -- In May 2002, Apache's board of directors approved an executive restricted stock plan for all executive officers and certain key employees in lieu of stock options. The Company awarded 121,000 and 229,950 restricted shares in 2003 and 2002, respectively, 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 2003 and 2002, $2 million and $538 thousand, respectively, was charged to expense. 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 (Share Price Goals) and/or a separate production goal (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 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 are based on achieving a closing share price of $43.29, $51.95 and $77.92 per share on any 10 days out of any 30 consecutive trading days before January 1, 2005. A summary of the number F-30 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) of shares contingently issuable under the Share Price Goals as of December 31, 2003, 2002 and 2001 is presented in the table below (shares in thousands):
SHARES SUBJECT TO CONDITIONAL GRANTS ------------------------------------- 2003 2002 2001 ------ ----------------- ------ Outstanding, beginning of year.............................. 6,234 6,390 5,764 Granted..................................................... 522 436 1,294 Forfeited................................................... (432) (592) (668) ------ ------ ------ Outstanding, end of year(1)................................. 6,324 6,234 6,390 ====== ====== ====== Exercisable, end of year.................................... -- -- -- ====== ====== ====== Weighted average fair value of conditional grants -- Share Price Goals(2)............................................ $ 6.75 $ 7.98 $ 9.31 ====== ====== ======
(1) Represents shares issuable upon attainment of $43.29, $51.95 and $77.92 per share price goals of 1,370,624 shares, 3,431,250 shares and 1,522,818 shares, respectively, in 2003, 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. (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 2003, 2002 and 2001, respectively: (i) risk-free interest rate of 2.77, 2.90 and 4.16 percent; (ii) expected volatility of 36.69, 38.77 and 46.27 percent; and (iii) expected dividend yield of .70, .70 and .77 percent. --------------- The Production Goal will be attained if and when the Company's average daily production equals or exceeds .67 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. Preferred Stock The Company has five million shares of no par preferred stock authorized, of which 25,000 shares have been designated as Series A Junior Participating Preferred Stock (the Series A Preferred Stock), 100,000 shares have been designated as the 5.68 percent Series B Cumulative Preferred Stock (the Series B Preferred Stock) and, from May 13, 1999 until December 16, 2003, 140,000 shares were designated as Series C Preferred Stock. The shares of Series A Preferred Stock are authorized for issuance pursuant to certain rights F-31 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) that trade with Apache common stock outstanding and are reserved for issuance upon the exercise of the Rights as defined and discussed below. Rights to Purchase Series A Preferred Stock -- In December 1995, the Company declared a dividend of one right (a Right) for each 2.31 shares (adjusted for the 10 percent and five percent stock dividends and the two-for-one stock split) of Apache common stock outstanding on January 31, 1996. Each full Right entitles the registered holder to purchase from the Company one ten-thousandth (1/10,000) of a share of Series A Preferred Stock at a price of $100 per one ten-thousandth of a share, subject to adjustment. The Rights are exercisable 10 calendar days following a public announcement that certain persons or groups have acquired 20 percent or more of the outstanding shares of Apache common stock or 10 business days following commencement of an offer for 30 percent or more of the outstanding shares of Apache common stock. In addition, if a person or group becomes the beneficial owner of 20 percent or more of Apache's outstanding common stock (flip in event), each Right will become exercisable for shares of Apache's common stock at 50 percent of the then market price of the common stock. If a 20 percent shareholder of Apache acquires Apache, by merger or otherwise, in a transaction where Apache does not survive or in which Apache's common stock is changed or exchanged (flip over event), the Rights become exercisable for shares of the common stock of the company acquiring Apache at 50 percent of the then market price for Apache common stock. Any Rights that are or were beneficially owned by a person who has acquired 20 percent or more of the outstanding shares of Apache common stock and who engages in certain transactions or realizes the benefits of certain transactions with the Company will become void. If an offer to acquire all of the Company's outstanding shares of common stock is determined to be fair by Apache's board of directors, the transaction will not trigger a flip in event or a flip over event. The Company may also redeem the Rights at $.01 per Right at any time until 10 business days after public announcement of a flip in event. The Rights will expire on January 31, 2006, unless earlier redeemed by the Company. Unless the Rights have been previously redeemed, all shares of Apache common stock issued by the Company after January 31, 1996 will include Rights. Unless and until the Rights become exercisable, they will be transferred with and only with the shares of Apache common stock. Series B Preferred Stock -- In August 1998, Apache issued 100,000 shares ($100 million) of Series B Preferred Stock in the form of one million depositary shares, each representing one-tenth (1/10) of a share of Series B Preferred Stock, for net proceeds of $98 million. The Series B Preferred Stock has no stated maturity, is not subject to a sinking fund and is not convertible into Apache common stock or any other securities of the Company. Apache has the option to redeem the Series B Preferred Stock at $1,000 per preferred share on or after August 25, 2008. Holders of the shares are entitled to receive cumulative cash dividends at an annual rate of $5.68 per depositary share when, and if, declared by Apache's board of directors. Series C Preferred Stock -- In May 1999, Apache issued 140,000 shares ($217 million) of Series C Preferred Stock in the form of seven million depositary shares each representing one-fiftieth (1/50) of a share of Series C Preferred Stock, for net proceeds of $211 million. Holders of the shares were entitled to receive cumulative cash dividends at an annual rate of 6.5 percent, or $2.015 per depositary share when, and if, declared by Apache's board of directors. In 2000, Apache bought back 75,900 depositary shares at an average price of $34.42 per share. The excess of the purchase price to reacquire the depositary shares over the original issuance price is reflected as a preferred stock dividend. The remaining depositary shares converted into 13,109,730 shares of Apache common stock in 2002. F-32 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Comprehensive Income -- Components of accumulated other comprehensive income (loss) consist of the following:
FOR THE YEAR ENDED DECEMBER 31, ----------------------------------- 2003 2002 2001 --------- --------- --------- (IN THOUSANDS) Currency translation adjustments................... $(108,750) $(108,750) $(114,078) Unrealized gain (loss) on available for sale securities....................................... -- -- 125 Unrealized gain (loss) on derivatives (Note 4)..... (43,193) (4,186) 12,136 --------- --------- --------- Accumulated other comprehensive loss............... $ 151,943 $(112,936) $(101,817) ========= ========= =========
The unrealized gain (loss) on available for sale securities at December 31, 2001 is net of income tax expense of $67,000. The currency translation adjustments are not adjusted for income taxes as they relate to a permanent investment in non-U.S. subsidiaries. 10. FINANCIAL INSTRUMENTS The following table presents the carrying amounts and estimated fair values of the Company's financial instruments at December 31, 2003 and 2002. See Note 6 for a discussion of the Company's derivative instruments.
2003 2002 -------------------- -------------------- CARRYING FAIR CARRYING FAIR AMOUNT VALUE AMOUNT VALUE -------- ----- -------- ----- (IN THOUSANDS) Long-term debt: Apache Money market lines of credit...................... $ 5,200 $ 5,200 $ 8,900 $ 8,900 Global credit facility -- U.S..................... -- -- -- -- Commercial paper.................................. 130,000 130,000 271,400 271,400 6.25-percent debentures........................... 397,525 445,600 397,307 448,880 7-percent notes................................... 148,506 175,725 148,446 179,445 7.625-percent notes............................... 149,161 183,660 149,134 180,990 7.7-percent notes................................. 99,665 121,840 99,660 122,890 7.95-percent notes................................ 178,636 224,910 178,614 226,926 7.375-percent debentures.......................... 148,014 179,640 148,009 177,090 7.625-percent debentures.......................... 149,175 179,220 149,175 179,205 Subsidiary and other obligations Money market lines of credit...................... -- -- -- -- Global credit facility -- Canada.................. -- -- -- -- Fletcher notes.................................... 5,356 5,731 5,356 6,065 Apache Finance Australia 6.5-percent notes........ 169,390 189,431 169,260 193,936 Apache Finance Australia 7-percent notes.......... 99,597 115,440 99,535 116,430 Apache Finance Canada 4.375-percent notes......... 349,688 329,770 -- -- Apache Finance Canada 7.75-percent notes.......... 297,053 374,730 297,019 380,280 Apache Clearwater notes........................... -- -- 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, 2003 and December 31, 2002. F-33 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Long-Term Debt -- The fair value of the notes and debentures is based upon an estimate provided to the Company by an independent investment banking firm. The carrying amount of the 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. 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 $47 million in damages, plus interest, 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 hearing was held in January 2004, and a decision is expected in the second quarter of 2004. 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. The Company is involved in litigation and is subject to governmental and regulatory controls arising in the ordinary course of business. The Company has an accrued liability of less than $8 million for legal 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 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 F-34 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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, 2003, 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, 2003, 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. Covered costs of $5 million have been paid by Apache through December 31, 2003. International Lease Concessions -- The Company, through its subsidiaries, has acquired or has been conditionally or unconditionally granted exploration rights in Australia, Egypt, China and the North Sea. In order to comply with the contracts and agreements granting these rights, the Company, through various wholly-owned subsidiaries, is committed to expend approximately $52 million through 2007. 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 401(k) savings plan and money purchase retirement plan. Additionally, Apache Energy Limited, Apache Canada Ltd. and Apache North Sea Limited maintain separate retirement plans, as required under the laws of Australia, Canada and the United Kingdom, respectively. Vesting in the Company's contributions to the 401(k) savings plan, the money purchase retirement plan and the non-qualified retirement/savings plan occurs at the rate of 20 percent per year. Upon a change in control of ownership, vesting is immediate. Total costs under all plans were $25 million, $18 million and $16 million for 2003, 2002 and 2001, respectively. The unfunded liability for all plans as of December 31, 2003 and 2002 has been recorded in other accrued expenses. Effective July 1, 2003, as part of the BP North Sea acquisition, Apache assumed a funded noncontributory defined benefit pension plan (U.K. Pension Plan) covering existing BP North Sea employees hired by the Company as part of the acquisition. Contributions made by Apache to BP's plan were immaterial prior to Apache's plan becoming effective. The pension plan provides defined benefits based on years of service and final average salary. The plan is closed to newly hired employees. F-35 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Apache also has a postretirement benefit plan covering substantially all of its U.S. employees. The postretirement benefit plan provides for medical benefits up until the age of 65. The plan is contributory with participants' contributions adjusted annually. The following tables set forth the benefit obligation, fair value of plan assets and funded status at December 31, 2003 and the underlying weighted average actuarial assumptions used for the UK Pension Plan and U.S. postretirement benefit plan. Apache uses a measurement date of December 31 for its pension and postretirement benefit plans. Although the postretirement benefit plan was in effect during 2002 and 2001, tabular information is not provided as the total provisions were immaterial to the Company.
POSTRETIREMENT PENSION BENEFITS BENEFITS 2003 2003 ---------------- -------------- (IN THOUSANDS) CHANGE IN PROJECTED BENEFIT OBLIGATION Projected benefit obligation beginning of period.......... $ 60,190 $ 7,117 Service cost.............................................. 2,668 780 Interest cost............................................. 1,562 525 Foreign currency exchange rate changes.................... 3,185 - Amendments................................................ -- -- Actuarial losses/(gains).................................. (3,963) 1,115 Effect of curtailment and settlements..................... -- -- Benefits paid............................................. -- (172) Retiree contributions..................................... -- 74 -------- ------- Projected benefit obligation at end of year............... 63,642 9,439 CHANGE IN PLAN ASSETS Fair value of plan assets at beginning of period.......... 47,572 -- Actual return on plan assets.............................. 688 -- Foreign currency exchange rate changes.................... 2,628 -- Employer contributions.................................... 1,532 98 Benefits paid............................................. -- (172) Retiree contributions..................................... -- 74 -------- ------- Fair value of plan assets at end of year.................. 52,420 -- RECONCILIATION OF FUNDED STATUS Funded status of plan..................................... (11,222) (9,439) Unrecognized actuarial (gain)/loss........................ (3,576) 4,072 Unrecognized prior service cost........................... -- -- Unrecognized net transition obligation.................... -- 573 -------- ------- Accrued benefit asset/(obligation)........................ (14,798) (4,794) WEIGHTED AVERAGE ASSUMPTIONS USED AS OF DECEMBER 31, 2003 Discount rate............................................. 5.50% 6.25% Salary increases.......................................... 3.75% N/A Expected return on assets................................. 6.50% N/A Healthcare cost trend -- Initial in 2004..................................... N/A 10.00% -- Ultimate in 2009.................................... N/A 5.00%
As of December 31, 2003, the accumulated benefit obligation for the pension plan was $46.7 million. The following table sets forth the components of the net periodic cost. F-36 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The following tables set forth the components of the net periodic cost and the underlying weighted average actuarial assumptions used for the pension and postretirement benefit plan for the 6-month and 12-month periods ended December 31, 2003, respectively.
POSTRETIREMENT PENSION BENEFITS BENEFITS 2003 2003 ---------------- -------------- (IN THOUSANDS) COMPONENTS OF NET PERIODIC BENEFIT COSTS Service cost.............................................. $ 2,668 $ 780 Interest cost............................................. 1,562 525 Expected return on assets................................. (1,260) -- Amortization of:.......................................... -- Prior service cost..................................... -- -- Transition obligation.................................. -- 44 Actuarial (gain)/loss.................................. - 203 Effect of curtailment and settlements..................... -- -- ------- ------ Net periodic benefit cost................................. $ 2,970 $1,552 WEIGHTED AVERAGE ASSUMPTIONS USED FOR PERIODS ENDED DECEMBER 31, 2003 Discount rate............................................. 5.50% 6.75% Salary increases.......................................... 3.75% N/A Expected return on assets................................. 6.50% N/A Healthcare cost trend -- Initial in 2003................................... N/A 10.00% -- Ultimate in 2006.................................. N/A 5.00%
Assumed health care cost trend rates effect amounts reported for postretirement benefits. A one-percentage-point change in assumed health care cost trend rates would have the following effects:
POSTRETIREMENT BENEFITS -------------------------- 1% INCREASE 1% DECREASE ----------- ----------- (IN THOUSANDS) Effect on service and interest cost components.............. $152 $(134) Effect on postretirement benefit obligation................. 905 (809)
Apache expects to contribute $5 million to its pension plan in 2004. The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid (in thousands): 2004........................................................ $ 9 2005........................................................ 108 2006........................................................ 128 2007........................................................ 388 2008........................................................ 778 Years 2009 -- 2013.......................................... 10,621
The Company does not anticipate any material contributions or benefit payments to be made in future years with respect to the postretirement benefit plan. Operating Lease and Other Commitments -- The Company has leases for buildings, facilities and equipment with varying expiration dates through 2013. Net rental expense was $17 million, $16 million and $18 million for 2003, 2002 and 2001, respectively. F-37 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) As of December 31, 2003, minimum rental commitments under long-term operating leases, net of sublease rentals, drilling rigs and long-term pipeline transportation commitments, ranging from one to 20 years, are as follows:
NET MINIMUM COMMITMENTS ---------------------------------------------------- PIPELINE TOTAL LEASES DRILLING RIGS TRANSMISSION -------- ------- ------------- ------------ (IN THOUSANDS) 2004.............................................. $108,285 $12,529 $68,677 $ 27,079 2005.............................................. 40,875 10,396 7,265 23,214 2006.............................................. 33,468 9,782 2,957 20,729 2007.............................................. 29,303 6,384 2,957 19,962 2008.............................................. 25,779 5,568 486 19,725 Thereafter........................................ 66,040 27,535 -- 38,505 -------- ------- ------- -------- $303,750 $72,194 $82,342 $149,214 ======== ======= ======= ========
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 were entitled to receive a weighted average return of 123 basis points above the prevailing LIBOR interest rate. The preferred stock and limited partner interests were repayable from the assets of the subsidiaries. Apache retained credit risks related to collection of proceeds from product sales and intercompany loans. Apache also had an obligation to contribute an aggregate amount not to exceed $250 million to fund present and future business operations of the subsidiaries. However, the investors were not entitled to receive more than their $443 million original investment, plus the agreed-upon return. One of the subsidiaries also issued $37 million of senior floating rate notes, which matured and were repaid in August 2003 (see Note 6). The limited partnership was scheduled to terminate as of August 9, 2021. However, the general partner, an Apache subsidiary, could elect to retire all or part of the limited partner's interest at any time without penalty. On September 26, 2003, Apache repurchased and retired the preferred interests issued by three of its subsidiaries for approximately $443 million, plus an additional $1 million for accrued dividends and distributions. The transactions involved the purchase of preferred stock issued by two of the Company's subsidiaries for approximately $82 million and the retirement of a limited partnership interest in a partnership controlled by a subsidiary of the Company for approximately $361 million. Apache funded the transactions with available cash on hand and by issuing commercial paper under its existing commercial paper facility. Prior to the early repurchase, the assets and liabilities of the subsidiaries were included in Apache's consolidated financial statements at historical costs, with the preferred stock and limited partner interests of the subsidiaries reflected as a preferred interests of subsidiaries in the consolidated balance sheet. The dividends paid on the preferred stock and distributions paid on the limited partner interests were reflected as preferred interests of subsidiaries in the statement of consolidated operations. F-38 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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. Under the terms of the original gas purchase agreement, ProEnergy, renamed Cinergy Marketing and Trading LLC (Cinergy), was to market Apache's North American natural gas production until June 30, 2008, with an option, following prior notice, to terminate on June 30, 2004. During this period, Apache was generally obligated to deliver most of its United States gas production to Cinergy and, under certain circumstances, reimburse Cinergy if certain gas throughput thresholds were not met. The prices received for its gas production under this agreement approximated market prices. In June 2003, Apache and Cinergy Marketing and Trading, LLC (Cinergy) agreed to terminate their agreement concerning marketing of Apache's U.S. natural gas production and to dismiss the arbitration between them. The parties reached an amicable settlement, the amounts of which were immaterial to Apache's financial position and results of operations. Consequently, the Company began marketing its U.S. natural gas production previously marketed by Cinergy beginning with July 2003 production. Related Parties -- George D. Lawrence, a member of the Company's board of directors and the former president and chief executive officer of Phoenix Resource Companies, Inc. (Phoenix), joined Apache's board in conjunction with the Company's acquisition of Phoenix by a merger (the "Merger") on May 20, 1996, through which Phoenix became a wholly-owned subsidiary of Apache. Merger consideration totaled $396.3 million, consisting of approximately 12,190,000 shares of Apache's common stock (28,158,900 shares after adjustment for the stock dividends and the two-for-one stock split) valued at $26.00 per share ($11.2554 after adjustment), $14.9 million of net value associated with Phoenix stock options assumed by Apache, and $64.5 million in cash. Upon consummation of the Merger, Apache assumed Phoenix stock options that remained outstanding on May 20, 1996, including those granted to Mr. Lawrence pursuant to Phoenix's 1990 Employee Stock Option Plan. In March 2003, Mr. Lawrence received 8,291 shares of Apache common stock (16,582 shares after adjustment for the stock split) as a result of the exercise of all of his remaining stock options from the Phoenix 1990 Employee Stock Option Plan. Such exercise was for 21,656 shares of Apache common stock at an exercise price of $21.50 per share (43,312 shares of Apache common stock at an exercise price of $10.75 per share after adjustment for the stock split). Mr. Lawrence paid the net exercise price of $466,000 and required taxes of $345,000 by surrendering 13,365 shares of Apache common stock valued at $60.65 per share (26,730 shares at $30.33 after adjustment for the stock split). In the ordinary course of business, Cimarex Energy, Co. (Cimarex), formerly Key Production Company, Inc., paid to Apache $4 million during 2003, $2 million during 2002 and $4 million during 2001 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 $6 million in 2003, $4 million in 2002, and $7 million in 2001 directly by Apache or related entities for its proportionate share of revenues from wells in which Cimarex marketed its revenues with Apache as operator. Apache paid to Cimarex approximately $1 million during 2003 and $217,000 during 2002 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 $2 million in 2003 and $785,000 in 2002 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 F-39 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) member of Apache's board of directors, is chairman of the board, chief executive officer and president of Cimarex. In the ordinary course of business, Matador Petroleum Corporation or related entities (Matador) paid to Apache approximately $793,000 during 2003 and $708,000 during 2002 for Matador's proportionate share of drilling and workover costs, mineral interests and routine expenses relating to oil and gas wells in which Matador owns interests and of which Apache is the operator. Matador was paid approximately $1 million in 2003 and 2002 directly by Apache for its proportionate share of revenues from wells in which Matador marketed its revenues with Apache as operator. Apache paid to Matador during 2003 and 2002 approximately $654,000 and $2 million, respectively, for Apache's proportionate share of drilling and workover costs, mineral interests and routine expenses relating to oil and gas wells in which Apache owns interests and of which Matador is the operator. Apache was paid approximately $915,000 and $621,000 in 2003 and 2002, respectively, directly by Matador for its proportionate share of revenues from wells in which Apache marketed its revenues with Matador as operator. Eugene C. Fiedorek, a member of Apache's board of directors, was a member of the board of directors of Matador until its acquisition by Tom Brown, Inc. in March 2003. During 2003, Apache and its subsidiaries made donations of $201,000, in cash, property and services, to the Ucross Foundation. During 2003, Apache also paid $40,000 to the Ucross Foundation for food, lodging and other expenses incurred in connection with executive retreats held at the Ucross Foundation's facilities. On February 5, 2004, Apache entered into an agreement to purchase the Clear Creek Hunting Preserve, Inc. from Ucross Foundation for a total purchase price of $77,000. The Ucross Foundation was founded in 1981 as a non-profit organization whose primary objectives include the restoration of the historic Clear Fork headquarters of the Pratt and Ferris Cattle Company of Wyoming, the promotion of the preservation of other historical sites in the area, and the maintenance of an artists-in-residence program for writers and other artists. To help ensure that the accomplishments of the Ucross Foundation are reasonably secure, Apache's board of directors has approved a conditional charitable contribution of $10,000,000 to be made to the Ucross Foundation upon a change of control of the Company, as defined in the Company's income continuance plan. Raymond Plank, chairman of Apache's board of directors, is chairman of the board of trustees of Ucross Foundation, and G. Steven Farris, a director and officer of Apache, and Roger B. Plank, an officer of Apache, are trustees of Ucross Foundation. During 2003, 2002 and 2001, Apache and its subsidiaries made donations of $500,000, $300,000 and $3 million, in cash, property and services, to The Fund for Teachers: A Foundation to Recognize, Stimulate and Enhance, which is a Texas non-profit corporation. In addition, during 2003, Apache accrued a $4,650,000 donation to the Fund for Teachers that was pledged in 2003 and will be paid in 2004. The Fund for Teachers seeks to provide resources directly to teachers to support learning experiences of their own design to increase their effectiveness with students, and is currently focused on funding summer sabbaticals for selected applicants. The Company's board of directors also authorized potential donations to The Fund for Teachers of up to $5,000,000 in cash, property and services to be made in each of 2004 and 2005. If a change of control of the Company occurs, as defined in the Company's income continuance plan, any and all of the donations that have not yet been made to the Fund for Teachers will become immediately due and payable to the Fund for Teachers. Raymond Plank, chairman of Apache's board of directors, is chairman of the board and president of The Fund for Teachers. In the ordinary course of business, Apache paid to Maralo, LLC or related entities ("Maralo") during 2002 approximately $9,000 in revenues relating to four oil and gas wells in which Maralo owns an interest and of which Apache is operator. During 2001, Apache paid Maralo approximately $70,000 in revenues relating to five oil and gas wells in which Maralo owns an interest and of which Apache is the operator. Maralo paid Apache approximately $1,000 in 2002 and $16,000 in 2001 for Maralo's share of routine expenses relating to such wells. Also during 2002 and 2001, Maralo sub-leased certain office space from Apache, for which Maralo F-40 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) paid Apache approximately $95,000 in both years. Mary Ralph Lowe, a member of Apache's board of directors through December 19, 2003, is president, chief executive officer and the sole stockholder of Maralo. During 2002, in the ordinary course of business, Aquila, Inc. ("Aquila") and related companies paid to Apache approximately $33 million for natural gas produced by Apache, primarily in Canada. Aquila was paid approximately $348,000 by Apache for gathering, transportation and compression services provided by Aquila. Janine McArdle, Vice-President -- Oil and Gas Marketing of Apache since October 2002, previously was employed by Aquila Europe. Major Customers -- In 2003, purchases by Cinergy and EGPC accounted for 12 percent and 15 percent of the Company's oil and gas production revenues, respectively. In 2002, purchases by Cinergy and EGPC accounted for 19 percent and 22 percent of the Company's oil and gas production revenues, respectively. In 2001, purchases by Cinergy and EGPC accounted for 35 percent and 17 percent of the Company's oil and gas production revenues, respectively. No other purchaser has accounted for more than 10 percent of revenues for 2003, 2002 or 2001. Concentration of Credit Risk -- The Company's revenues are derived principally from uncollateralized sales to customers in the oil and gas industry; therefore, customers may be similarly affected by changes in economic and other conditions within the industry. Apache has not experienced significant credit losses on such sales. Apache sells 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 lessened the availability of U.S. dollars, resulting in an additional one to two month delay in receipts from EGPC. While hard currency shortages in Egypt could lead to further delays, we did not experience any further delays in 2003. F-41 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 14. BUSINESS SEGMENT INFORMATION Apache has six reportable segments which are primarily in the business of crude oil and natural gas exploration and production. The accounting policies of the segments are the same as those described in the summary of significant accounting policies. The Company evaluates performance based on profit or loss from oil and gas operations before income and expense items incidental to oil and gas operations and income taxes. Apache's reportable segments are managed separately based on their geographic locations. Financial information by operating segment is presented below:
UNITED NORTH OTHER STATES CANADA EGYPT AUSTRALIA SEA INTERNATIONAL TOTAL ------------- ---------- ---------- --------- --------- ------------- ----------- (IN THOUSANDS) 2003 Oil and Gas Production Revenues................... $2,023,492 $ 823,273 $ 652,913 $391,968 $273,044 $ 34,230 $ 4,198,920 Operating Expenses: Depreciation, depletion and amortization............. 512,691 172,056 182,209 120,322 72,053 13,955 1,073,286 Asset retirement obligation accretion................ 18,861 5,275 -- 2,239 11,282 106 37,763 International impairments.............. -- -- -- -- -- 12,813 12,813 Lease operating costs...... 302,095 153,598 82,558 44,395 109,140 7,877 699,663 Gathering and transportation costs..... 21,128 28,154 -- -- 11,178 -- 60,460 Severance and other taxes.................... 52,651 20,183 -- 28,245 19,591 1,123 121,793 ---------- ---------- ---------- -------- -------- -------- ----------- Operating Income (Loss)...... $1,116,066 $ 444,007 $ 388,146 $196,767 $ 49,800 $ (1,644) 2,193,142 ========== ========== ========== ======== ======== ======== Other Income (Expense): Other...................... (8,621) Administrative, selling and other.................... (138,524) Financing costs, net....... (115,072) Preferred interests of subsidiaries............. (8,668) ----------- Income Before Income Taxes... $ 1,922,257 =========== Net Property and Equipment... $5,268,990 $2,727,620 $1,357,646 $891,567 $869,574 $144,688 $11,260,085 ========== ========== ========== ======== ======== ======== =========== Total Assets................. $5,621,681 $2,961,111 $1,744,164 $970,764 $941,577 $176,829 $12,416,126 ========== ========== ========== ======== ======== ======== =========== Additions to Net Property and Equipment.................. $1,486,895 $ 630,436 $ 276,293 $159,923 $941,629 $ 33,426 $ 3,528,602 ========== ========== ========== ======== ======== ======== ===========
F-42 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
UNITED NORTH OTHER STATES CANADA EGYPT AUSTRALIA SEA INTERNATIONAL TOTAL ------------- ---------- ---------- --------- --------- ------------- ----------- (IN THOUSANDS) 2002 Oil and Gas Production Revenues................... $1,101,388 $ 557,720 $ 560,099 $334,039 $ -- $ 6,502 $ 2,559,748 Operating Expenses: Depreciation, depletion and amortization............. 387,187 182,584 163,648 107,993 -- 2,467 843,879 International impairments.............. -- -- -- -- -- 19,600 19,600 Lease operating costs...... 239,837 110,078 69,160 37,107 -- 1,721 457,903 Gathering and transportation costs..... 17,311 21,256 -- -- -- -- 38,567 Severance and other taxes.................... 34,792 9,710 -- 22,807 -- -- 67,309 ---------- ---------- ---------- -------- -------- -------- ----------- Operating Income (Loss)...... $ 422,261 $ 234,092 $ 327,291 $166,132 $ -- $(17,286) 1,132,490 ========== ========== ========== ======== ======== ======== Other Income (Expense): Other...................... 125 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-43 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
UNITED NORTH OTHER STATES CANADA EGYPT AUSTRALIA SEA 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 90,938 49,449 31,728 -- 386 399,919 Gathering and transportation costs..... 15,790 18,794 -- -- -- -- 34,584 Severance and other taxes.................... 49,555 13,378 -- 11,789 -- -- 74,722 ---------- ---------- ---------- -------- -------- -------- ----------- Operating Income (Loss)...... $ 758,138 $ 327,087 $ 276,236 $131,204 $ -- $(64,762) 1,427,903 ========== ========== ========== ======== ======== ======== Other Income (Expense): Other...................... (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 ========== ========== ========== ======== ======== ======== ===========
F-44 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.
UNITED NORTH OTHER STATES CANADA EGYPT AUSTRALIA SEA INTERNATIONAL TOTAL ---------- -------- -------- --------- -------- ------------- ---------- (IN THOUSANDS) 2003 Oil and gas production revenues...................... $2,023,492 $823,273 $652,913 $391,968 $273,044 $ 34,230 $4,198,920 ---------- -------- -------- -------- -------- -------- ---------- Operating costs: Depreciation, depletion and amortization(1)............. 489,969 169,029 182,209 119,455 71,956 13,914 1,046,532 Asset retirement obligation accretion(3)................ 18,861 5,275 -- 2,239 11,282 106 37,763 International impairments..... -- -- -- -- -- 12,813 12,813 Lease operating expenses...... 302,095 153,598 82,558 44,395 109,140 7,877 699,663 Gathering and transportation costs....................... 21,128 28,154 -- -- 11,178 -- 60,460 Production taxes(2)........... 50,615 4,180 -- 28,245 19,591 1,123 103,754 Income tax.................... 427,809 201,421 186,310 67,196 21,456 (1,077) 903,115 ---------- -------- -------- -------- -------- -------- ---------- 1,310,477 561,657 451,077 261,530 244,603 34,756 2,864,100 ---------- -------- -------- -------- -------- -------- ---------- Results of operations........... $ 713,015 $261,616 $201,836 $130,438 $ 28,441 $ (526) $1,334,820 ========== ======== ======== ======== ======== ======== ========== Amortization rate per boe....... $ 7.13 $ 5.43 $ 6.62 $ 6.13 $ 6.67 $ 8.36 $ 6.59 ========== ======== ======== ======== ======== ======== ========== 2002 Oil and gas production revenues...................... $1,101,388 $557,720 $560,099 $334,039 $ -- $ 6,502 $2,559,748 ---------- -------- -------- -------- -------- -------- ---------- Operating costs: Depreciation, depletion and amortization(1)............. 369,864 181,087 163,648 107,194 -- 2,455 824,248 International impairments..... -- -- -- -- -- 19,600 19,600 Lease operating expenses...... 239,837 110,078 69,160 37,107 -- 1,721 457,903 Gathering and transportation costs....................... 17,311 21,256 -- -- -- -- 38,567 Production taxes(2)........... 33,336 4,221 -- 22,808 -- -- 60,365 Income tax.................... 165,390 104,869 157,100 56,756 -- (6,536) 477,579 ---------- -------- -------- -------- -------- -------- ---------- 825,738 421,511 389,908 223,865 -- 17,240 1,878,262 ---------- -------- -------- -------- -------- -------- ---------- Results of operations........... $ 275,650 $136,209 $170,191 $110,174 $ -- $(10,738) $ 681,486 ========== ======== ======== ======== ======== ======== ========== Amortization rate per boe....... $ 7.06 $ 5.71 $ 6.10 $ 5.36 $ -- $ 3.68 $ 6.29 ========== ======== ======== ======== ======== ======== ==========
F-45 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
UNITED NORTH OTHER STATES CANADA EGYPT AUSTRALIA SEA 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 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 90,938 49,449 31,728 -- 386 399,919 Gathering and transportation costs....................... 15,790 18,794 -- -- -- -- 34,584 Production taxes(2)........... 47,462 4,895 -- 11,789 -- -- 64,146 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 ========== ======== ======== ======== ======== ======== ==========
(1) This amount only reflects DD&A of capitalized costs of oil and gas proved properties and, therefore, does not agree with DD&A reflected on Note 14, Business Segment Information. (2) This amount only reflects amounts directly related to oil and gas producing properties and, therefore, does not agree with severance and other taxes reflected on Note 14, Business Segment Information. (3) Effective January 1, 2003, Apache adopted SFAS No. 143 "Asset Retirement Obligations." These amounts reflect current year activity only, as prior periods were adjusted through a one-time cumulative adjustment as described in Note 2, New Accounting Pronouncements. --------------- Costs Not Being Amortized -- The following table sets forth a summary of oil and gas property costs not being amortized at December 31, 2003, 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.
2000 TOTAL 2003 2002 2001 AND PRIOR -------- -------- -------- ------- --------- (IN THOUSANDS) Property acquisition costs............... $524,865 $240,741 $145,629 $29,247 $109,248 Exploration and development.............. 233,227 164,297 31,196 27,894 9,840 Capitalized interest..................... 37,069 5,467 10,346 6,104 15,152 -------- -------- -------- ------- -------- Total.................................. $795,161 $410,505 $187,171 $63,245 $134,240 ======== ======== ======== ======= ========
F-46 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:
UNITED OTHER STATES CANADA EGYPT AUSTRALIA NORTH SEA INTERNATIONAL TOTAL ---------- --------- -------- --------- --------- ------------- ---------- (IN THOUSANDS) 2003 Acquisitions(1)............... $ 846,736 $ 6,366 $ -- $ 27,105 $ 687,899 $ -- $1,568,106 Purchase of non-producing leases...................... 5,795 44,939 -- -- -- -- 50,734 Exploration................... 32,020 114,924 54,305 68,493 4,314 3,669 277,725 Development................... 401,726 419,632 188,347 59,768 55,890 31,429 1,156,792 Capitalized interest.......... 16,150 23,934 7,568 1,973 3,266 -- 52,891 ---------- --------- -------- -------- --------- ------- ---------- COSTS EXPENDED IN 2003........ 1,302,427 609,795 250,220 157,339 751,369 35,098 3,106,248 ---------- --------- -------- -------- --------- ------- ---------- Plus: Asset retirement obligation costs(2)......... 162,812 17,386 -- (3,589) 189,190 154 365,953 Less: Actual retirement expenditures(2)............. (21,840) (10,639) -- -- -- -- (32,479) ---------- --------- -------- -------- --------- ------- ---------- CAPITALIZED COSTS INCURRED.... $1,443,399 $ 616,542 $250,220 $153,750 $ 940,559 $35,252 $3,439,722 ========== ========= ======== ======== ========= ======= ========== Property sales................ $ (45,678) $ (13,266) $ -- $ -- $ -- $ -- $ (58,944) 2002 Acquisitions(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 ---------- --------- -------- -------- --------- ------- ---------- CAPITALIZED COSTS INCURRED.... $ 583,348 $ 356,753 $180,035 $ 94,037 $ -- $38,409 $1,252,582 ========== ========= ======== ======== ========= ======= ========== Property sales................ $ 873 $ 84 $ (8,000) $ -- $ -- $ -- $ (7,043) 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 ---------- --------- -------- -------- --------- ------- ---------- CAPITALIZED COSTS INCURRED.... $ 789,075 $ 985,965 $379,152 $ 92,204 $ -- $33,774 $2,280,170 ========== ========= ======== ======== ========= ======= ========== Property sales................ $ (200,445) $(147,851) $ -- $ -- $ -- $ -- $ (348,296)
(1) Acquisitions include unproved costs of $184 million, $70 million and $77 million for transactions completed in 2003, 2002 and 2001, respectively. (2) Effective January 1, 2003, Apache adopted SFAS No. 143 "Asset Retirement Obligations". The asset retirement obligation costs reflect abandonment obligations assumed during the year and related revisions. Actual retirement expenditures reflect plugging and abandonment costs during the year that are included in exploration and development activity. Prior periods presentation was not changed to reflect SFAS No. 143 because the amounts were adjusted through a one-time cumulative adjustment as described in Note 2, New Accounting Pronouncements. F-47 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Capitalized Costs -- The following table sets forth the capitalized costs and associated accumulated depreciation, depletion and amortization, including impairments, relating to the Company's oil and gas production, exploration and development activities:
UNITED NORTH OTHER STATES CANADA EGYPT AUSTRALIA SEA INTERNATIONAL TOTAL ----------- ---------- ---------- ---------- -------- ------------- ----------- (IN THOUSANDS) 2003 Proved properties........ $ 9,089,922 $3,052,856 $1,514,104 $1,136,718 $655,489 $ 214,373 $15,663,462 Asset retirement obligation costs(1).... 322,491 78,513 -- 22,487 189,190 1,787 614,468 Unproved properties...... 277,159 226,355 143,161 30,968 95,878 21,640 795,161 ----------- ---------- ---------- ---------- -------- --------- ----------- 9,689,572 3,357,724 1,657,265 1,190,173 940,557 237,800 17,073,091 Accumulated DD&A......... (4,521,062) (775,101) (663,224) (448,522) (71,956) (91,771) (6,571,636) ----------- ---------- ---------- ---------- -------- --------- ----------- $ 5,168,510 $2,582,623 $ 994,041 $ 741,651 $868,601 $ 146,029 $10,501,455 =========== ========== ========== ========== ======== ========= =========== 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 =========== ========== ========== ========== ======== ========= ===========
(1) Effective January 1, 2003, Apache adopted SFAS No. 143 "Asset Retirement Obligations." Prior year amounts do not reflect similar asset retirement obligation costs, as they were adjusted through a one-time cumulative adjustment as described in Note 2, New Accounting Pronouncements. F-48 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 2003, 2002 and 2001, their review covered 78 percent, 68 percent and 61 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 only represents estimates and should not be construed as being exact.
CRUDE OIL, CONDENSATE AND NATURAL GAS LIQUID -------------------------------------------------------------------- (THOUSANDS OF BARRELS) UNITED NORTH OTHER STATES CANADA EGYPT AUSTRALIA SEA INT'L TOTAL ------- ------- ------- --------- ------- ------ ------- PROVED DEVELOPED RESERVES: December 31, 2000.......................... 232,361 66,484 26,028 29,124 -- -- 353,997 December 31, 2001.......................... 230,017 76,250 59,188 45,628 -- 699 411,782 December 31, 2002.......................... 240,880 89,554 51,162 31,746 -- 1,033 414,375 December 31, 2003.......................... 265,135 91,501 54,881 26,999 147,880 7,293 593,689 TOTAL PROVED RESERVES: Balance December 31, 2000................... 314,704 113,390 39,101 55,278 -- -- 522,473 Extensions, discoveries and other additions................................ 54,533 21,121 17,121 12,320 -- -- 105,095 Purchases of minerals in-place............. 6,728 35,298 36,465 -- -- 1,099 79,590 Revisions of previous estimates............ (7,943) 814 2,621 -- -- -- (4,508) Production................................. (24,157) (9,916) (14,322) (8,595) -- (42) (57,032) Sales of properties........................ (22,428) (23,802) -- -- -- -- (46,230) ------- ------- ------- ------- ------- ------ ------- Balance December 31, 2001................... 321,437 136,905 80,986 59,003 -- 1,057 599,388 Extensions, discoveries and other additions................................ 20,082 31,366 18,227 4,221 -- 11,793 85,689 Purchases of minerals in-place............. 7,109 5,055 -- -- -- -- 12,164 Revisions of previous estimates............ 6,630 159 (8,140) 106 -- 40 (1,205) Production................................. (21,790) (9,846) (15,977) (11,082) -- (225) (58,920) Sales of properties........................ (46) -- (305) -- -- -- (351) ------- ------- ------- ------- ------- ------ ------- Balance December 31, 2002................... 333,422 163,639 74,791 52,248 -- 12,665 636,765 Extensions, discoveries and other additions................................ 35,378 15,649 15,090 11,712 14,489 640 92,958 Purchases of minerals in-place............. 48,886 574 -- 309 144,071 -- 193,840 Revisions of previous estimates............ 953 12 648 (2) -- (113) 1,498 Production................................. (28,098) (9,776) (17,356) (11,165) (10,680) (1,230) (78,305) Sales of properties........................ (1,176) (1,692) -- -- -- -- (2,868) ------- ------- ------- ------- ------- ------ ------- Balance December 31, 2003................... 389,365 168,406 73,173 53,102 147,880 11,962 843,888 ======= ======= ======= ======= ======= ====== ======= NATURAL GAS TOTAL ------------------------------------------------------------------------ ----------- (THOUSAND (MILLIONS OF CUBIC FEET) BARRELS UNITED NORTH OTHER OF OIL STATES CANADA EGYPT AUSTRALIA SEA INT'L TOTAL EQUIVALENT) --------- --------- ------- --------- ----- ------ --------- ----------- PROVED DEVELOPED RESERVES: December 31, 2000.......................... 1,579,865 660,334 93,205 331,390 -- -- 2,664,794 798,129 December 31, 2001.......................... 1,407,561 1,148,516 338,707 307,509 -- 1,524 3,203,817 945,751 December 31, 2002.......................... 1,444,677 1,255,068 246,529 256,790 -- 3,469 3,206,533 948,797 December 31, 2003.......................... 1,565,855 1,411,877 337,844 218,745 3,902 2,750 3,540,973 1,183,851 TOTAL PROVED RESERVES: Balance December 31, 2000................... 1,928,053 691,717 174,611 589,289 -- -- 3,383,670 1,086,418 Extensions, discoveries and other additions................................ 166,307 281,037 52,938 25,084 -- -- 525,366 192,656 Purchases of minerals in-place............. 34,827 512,927 247,302 -- -- 2,969 798,025 212,594 Revisions of previous estimates............ (61,522) 8,391 13,392 -- -- -- (39,739) (11,131) Production................................. (224,600) (108,925) (35,010) (42,684) -- (236) (411,455) (125,608) Sales of properties........................ (167,271) (83,265) -- -- -- -- (250,536) (87,986) --------- --------- ------- ------- ----- ------ --------- --------- Balance December 31, 2001................... 1,675,794 1,301,882 453,233 571,689 -- 2,733 4,005,331 1,266,943 Extensions, discoveries and other additions................................ 102,050 70,066 6,123 28,943 -- 3,355 210,537 120,779 Purchases of minerals in-place............. 154,459 66,113 -- -- -- -- 220,572 48,926 Revisions of previous estimates............ 37,944 20,900 (37,480) 22 -- 37 21,423 2,366 Production................................. (183,708) (120,210) (44,769) (42,998) -- (2,656) (394,341) (124,644) Sales of properties........................ (2,446) -- (6,440) -- -- -- (8,886) (1,832) --------- --------- ------- ------- ----- ------ --------- --------- Balance December 31, 2002................... 1,784,093 1,338,751 370,667 557,656 -- 3,469 4,054,636 1,312,538 Extensions, discoveries and other additions................................ 113,552 387,533 217,455 127,516 105 2,084 848,245 234,332 Purchases of minerals in-place............. 391,510 4,510 -- 38,638 4,423 -- 439,081 267,020 Revisions of previous estimates............ 6,073 (8,177) 4,292 -- -- 1 2,189 1,863 Production................................. (242,782) (116,263) (41,447) (40,537) (626) (2,607) (444,262) (152,349) Sales of properties........................ (23,054) (671) -- -- -- (196) (23,921) (6,855) --------- --------- ------- ------- ----- ------ --------- --------- Balance December 31, 2003................... 2,029,392 1,605,683 550,967 683,273 3,902 2,751 4,875,968 1,656,549 ========= ========= ======= ======= ===== ====== ========= =========
As of December 31, 2003, 2002 and 2001, on a barrel of equivalent basis 29, 28 and 25 percent of our worldwide reserves, respectively, were classified as proved undeveloped. Approximately 19 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-49 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Future Net Cash Flows -- Future cash inflows are based on year-end oil and gas prices except in those instances where future natural gas or oil sales are covered by physical contract terms providing for higher or lower amounts. Operating costs, production and ad valorem taxes and future development costs are based on current costs with no escalation. The following table sets forth unaudited information concerning future net cash flows for oil and gas reserves, net of income tax expense. Income tax expense has been computed using expected future tax rates and giving effect to tax deductions and credits available, under current laws, and which relate to oil and gas producing activities. This information does not purport to present the fair market value of the Company's oil and gas assets, but does present a standardized disclosure concerning possible future net cash flows that would result under the assumptions used.
UNITED OTHER STATES CANADA(1) EGYPT AUSTRALIA NORTH SEA INTERNATIONAL TOTAL ----------- ----------- ---------- ---------- ----------- ------------- ------------ (IN THOUSANDS) 2003 Cash inflows......... $23,117,256 $12,533,197 $3,999,829 $2,737,289 $ 4,193,438 $378,032 $ 46,959,041 Production costs..... (6,012,893) (3,049,847) (545,505) (658,132) (2,622,103) (63,384) (12,951,864) Development costs.... (1,152,182) (451,491) (397,493) (397,206) (593,778) (17,431) (3,009,581) Income tax expense... (4,834,389) (2,595,286) (997,847) (433,667) (195,756) (59,616) (9,116,561) ----------- ----------- ---------- ---------- ----------- -------- ------------ Net cash flows....... 11,117,792 6,436,573 2,058,984 1,248,284 781,801 237,601 21,881,035 10 percent discount rate............... (5,222,609) (3,353,451) (726,933) (536,921) (204,248) (59,029) (10,103,191) ----------- ----------- ---------- ---------- ----------- -------- ------------ Discounted future net cash flows(2)...... $ 5,895,183 $ 3,083,122 $1,332,051 $ 711,363 $ 577,553 $178,572 $ 11,777,844 =========== =========== ========== ========== =========== ======== ============ 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 =========== =========== ========== ========== =========== ======== ============
(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 $16.4 billion, $13.2 billion and $7.4 billion as of December 31, 2003, 2002 and 2001, respectively. F-50 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, ---------------------------------------- 2003 2002 2001 ----------- ----------- ------------ (IN THOUSANDS) Sales, net of production costs....................... $(3,312,728) $(1,994,631) $ (2,327,679) Net change in prices and production costs............ 224,609 4,767,785 (10,125,666) Discoveries and improved recovery, net of related costs.............................................. 2,808,283 1,885,266 1,760,299 Change in future development costs................... 48,531 222,160 182,816 Revision of quantities............................... 22,807 (15,400) (79,138) Purchases of minerals in-place....................... 2,743,936 603,608 1,332,244 Accretion of discount................................ 1,317,894 737,112 1,772,520 Change in income taxes............................... (795,143) (2,200,925) 3,949,890 Sales of properties.................................. (90,263) (14,502) (1,306,042) Change in production rates and other................. (341,703) (382,314) (1,563,433) ----------- ----------- ------------ $ 2,626,223 $ 3,608,159 $ (6,404,189) =========== =========== ============
Impact of Pricing -- The estimates of cash flows and reserve quantities shown above are based on year-end oil and gas prices, except in those cases where future natural gas or oil sales are covered by physical contracts at specified prices. Forward price volatility is largely attributable to supply and demand perceptions for natural gas and oil. Under full-cost accounting rules, the Company reviews the carrying value of its proved oil and gas properties each quarter on a country-by-country basis. Under these rules, capitalized costs of proved oil and gas properties, net of accumulated DD&A and deferred income taxes, may not exceed the present value of estimated future net cash flows from proved oil and gas reserves, discounted at 10 percent, plus the lower of cost or fair value of unproved properties included in the costs being amortized, net of related tax effects (the "ceiling"). These rules generally require pricing future oil and gas production at the unescalated oil and gas prices at the end of each fiscal quarter and require a write-down if the "ceiling" is exceeded. Given the volatility of oil and gas prices, it is reasonably possible that the Company's estimate of discounted future net cash flows from proved oil and gas reserves could change in the near term. If oil and gas prices decline significantly, even if only for a short period of time, it is possible that write-downs of oil and gas properties could occur in the future. F-51 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) 2003 Revenues.......................... $966,609 $1,054,356 $1,104,541 $1,064,793 $4,190,299 Expenses, net..................... 654,312 809,975 827,580 803,179 3,095,046 -------- ---------- ---------- ---------- ---------- Income before change in accounting principle....................... 312,297 244,381 276,961 261,614 1,095,253 Cumulative effect of change in accounting principle, net of income tax...................... 26,632 - - - 26,632 -------- ---------- ---------- ---------- ---------- Net income........................ $338,929 $ 244,381 $ 276,961 $ 261,614 $1,121,885 ======== ========== ========== ========== ========== Income attributable to common stock........................... $337,509 $ 242,961 $ 275,541 $ 260,194 $1,116,205 ======== ========== ========== ========== ========== Net income per common share (1)(2): Basic........................... $ 1.06 $ .75 $ .85 $ .80 $ 3.46 ======== ========== ========== ========== ========== Diluted......................... $ 1.05 $ .75 $ .84 $ .80 $ 3.43 ======== ========== ========== ========== ========== 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 ======== ========== ========== ========== ==========
(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 five percent stock dividend declared December 18, 2002, payable April 2, 2003 to shareholders of record on March 12, 2003, and the two-for-one stock split declared September 11, 2003, paid January 14, 2004, to shareholders of record on December 31, 2003. F-52 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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 Securities and Exchange Commission. Since these subsidiaries had no independent operations and qualified as "finance subsidiaries", they were exempted from these requirements. During 2001, Apache contributed stock of its Australian and Canadian operating subsidiaries to Apache Finance Australia and Apache Finance Canada, respectively. As a result of these contributions, they no longer qualify as finance subsidiaries. As allowed by the SEC rules, the following condensed consolidating financial statements are provided as an alternative to filing separate financial statements. Each of the companies presented in the condensed consolidating financial statements is wholly owned and has been consolidated in Apache Corporation's consolidated financial statements for all periods presented. As such, the condensed consolidating financial statements should be read in conjunction with the financial statements of Apache Corporation and subsidiaries and notes thereto of which this note is an integral part. F-53 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS FOR THE YEAR ENDED DECEMBER 31, 2003
ALL OTHER APACHE SUBSIDIARIES APACHE APACHE FINANCE APACHE OF APACHE CORPORATION NORTH AMERICA AUSTRALIA FINANCE CANADA CORPORATION ----------- ------------- --------- -------------- ------------ (IN THOUSANDS) Revenues and Other: Oil and gas production revenues......... $1,687,609 $ -- $ -- $ -- $2,729,966 Equity in net income of affiliates...... 597,020 21,189 33,117 111,274 (37,160) Other................................... (4,250) -- (25) -- (4,346) ---------- ------- ------- -------- ---------- 2,280,379 21,189 33,092 111,274 2,688,460 ---------- ------- ------- -------- ---------- Operating Expenses: Depreciation, depletion and amortization......................... 374,534 -- -- -- 698,752 Asset retirement obligation accretion... 15,944 -- -- -- 21,819 International impairments............... -- -- -- -- 12,813 Lease operating costs................... 264,311 -- -- -- 654,007 Gathering and transportation costs...... 19,558 -- -- -- 40,902 Severance and other taxes............... 50,899 -- -- 63 70,831 Administrative, selling and other....... 111,984 -- -- -- 26,540 Financing costs, net.................... 102,142 -- 18,047 40,064 (45,181) ---------- ------- ------- -------- ---------- 939,372 -- 18,047 40,127 1,480,483 ---------- ------- ------- -------- ---------- Preferred Interests of Subsidiaries....... (592) -- -- -- 9,260 ---------- ------- ------- -------- ---------- Income (Loss) Before Income Taxes......... 1,341,599 21,189 15,045 71,147 1,198,717 Provision (benefit) for income taxes.... 239,471 -- (6,144) (14,895) 608,572 ---------- ------- ------- -------- ---------- Income (Loss) Before Change in Accounting Principle............................... 1,102,128 21,189 21,189 86,042 590,145 Cumulative effect of change in accounting principle, net of income tax.................................. 19,757 -- -- -- 6,875 ---------- ------- ------- -------- ---------- Net Income................................ 1,121,885 21,189 21,189 86,042 597,020 Preferred stock dividends............... 5,680 -- -- -- -- ---------- ------- ------- -------- ---------- Income Attributable to Common Stock....... $1,116,205 $21,189 $21,189 $ 86,042 $ 597,020 ========== ======= ======= ======== ========== RECLASSIFICATIONS & ELIMINATIONS CONSOLIDATED ----------------- ------------ (IN THOUSANDS) Revenues and Other: Oil and gas production revenues......... $(218,655) $4,198,920 Equity in net income of affiliates...... (725,440) -- Other................................... -- (8,621) --------- ---------- (944,095) 4,190,299 --------- ---------- Operating Expenses: Depreciation, depletion and amortization......................... -- 1,073,286 Asset retirement obligation accretion... -- 37,763 International impairments............... -- 12,813 Lease operating costs................... (218,655) 699,663 Gathering and transportation costs...... -- 60,460 Severance and other taxes............... -- 121,793 Administrative, selling and other....... -- 138,524 Financing costs, net.................... -- 115,072 --------- ---------- (218,655) 2,259,374 --------- ---------- Preferred Interests of Subsidiaries....... - 8,668 --------- ---------- Income (Loss) Before Income Taxes......... (725,440) 1,922,257 Provision (benefit) for income taxes.... -- 827,004 --------- ---------- Income (Loss) Before Change in Accounting Principle............................... (725,440) 1,095,253 Cumulative effect of change in accounting principle, net of income tax.................................. -- 26,632 --------- ---------- Net Income................................ (725,440) 1,121,885 Preferred stock dividends............... -- 5,680 --------- ---------- Income Attributable to Common Stock....... $(725,440) $1,116,205 ========= ==========
F-54 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS FOR THE YEAR ENDED DECEMBER 31, 2002
ALL OTHER APACHE SUBSIDIARIES APACHE APACHE FINANCE APACHE OF APACHE CORPORATION NORTH AMERICA AUSTRALIA FINANCE CANADA CORPORATION ----------- ------------- --------- -------------- ------------ (IN THOUSANDS) Revenues and Other: Oil and gas production revenues................ $ 814,225 $ -- $ -- $ -- $ 1,906,009 Equity in net income of affiliates............. 391,295 20,976 32,905 76,707 (37,036) Other.......................................... 7,909 -- (25) -- (7,759) ---------- ------- -------- -------- ----------- 1,213,429 20,976 32,880 76,707 1,861,214 ---------- ------- -------- -------- ----------- Operating Expenses: Depreciation, depletion and amortization....... 211,291 -- -- -- 632,588 International impairments...................... -- -- -- -- 19,600 Lease operating costs.......................... 198,052 -- -- -- 420,337 Gathering and transportation costs............. 15,896 -- -- -- 22,671 Severance and other taxes...................... 34,015 -- -- 270 33,024 Administrative, selling and other.............. 87,860 -- -- -- 16,728 Financing costs, net........................... 72,721 -- 18,050 41,058 (18,996) ---------- ------- -------- -------- ----------- 619,835 -- 18,050 41,328 1,125,952 ---------- ------- -------- -------- ----------- Preferred Interests of Subsidiaries.............. -- -- -- -- 16,224 ---------- ------- -------- -------- ----------- Income (Loss) Before Income Taxes................ 593,594 20,976 14,830 35,379 719,038 Provision (benefit) for income taxes........... 39,265 -- (6,146) (16,221) 327,743 ---------- ------- -------- -------- ----------- Net Income....................................... 554,329 20,976 20,976 51,600 391,295 Preferred stock dividends...................... 10,815 -- -- -- -- ---------- ------- -------- -------- ----------- Income Attributable to Common Stock.............. $ 543,514 $20,976 $ 20,976 $ 51,600 $ 391,295 ========== ======= ======== ======== =========== RECLASSIFICATIONS & ELIMINATIONS CONSOLIDATED ----------------- ------------ (IN THOUSANDS) Revenues and Other: Oil and gas production revenues................ $(160,486) $ 2,559,748 Equity in net income of affiliates............. (484,847) -- Other.......................................... -- 125 --------- ----------- (645,333) 2,559,873 --------- ----------- Operating Expenses: Depreciation, depletion and amortization....... -- 843,879 International impairments...................... -- 19,600 Lease operating costs.......................... (160,486) 457,903 Gathering and transportation costs............. -- 38,567 Severance and other taxes...................... -- 67,309 Administrative, selling and other.............. -- 104,588 Financing costs, net........................... -- 112,833 --------- ----------- (160,486) 1,644,679 --------- ----------- Preferred Interests of Subsidiaries.............. -- 16,224 --------- ----------- Income (Loss) Before Income Taxes................ (484,847) 898,970 Provision (benefit) for income taxes........... -- 344,641 --------- ----------- Net Income....................................... (484,847) 554,329 Preferred stock dividends...................... -- 10,815 --------- ----------- Income Attributable to Common Stock.............. $(484,847) $ 543,514 ========= ===========
F-55 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 -- -- -- 648,207 Gathering and transportation costs...... 15,337 -- -- -- 19,247 Severance and other taxes............... 49,201 -- -- 36 25,485 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) 399,919 Gathering and transportation costs...... -- 34,584 Severance and other taxes............... -- 74,722 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-56 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS FOR THE YEAR ENDED DECEMBER 31, 2003
ALL OTHER APACHE SUBSIDIARIES APACHE APACHE FINANCE APACHE OF APACHE CORPORATION NORTH AMERICA AUSTRALIA FINANCE CANADA CORPORATION ----------- ------------- --------- -------------- ------------ (IN THOUSANDS) Cash Provided by (Used in) Operating Activities........ $ 1,136,019 $ -- $(19,604) $(39,675) $ 1,629,160 ----------- -------- -------- -------- ----------- Cash Flows from Investing Activities: Additions to property and equipment.................. (494,941) -- -- -- (1,099,995) Acquisitions......................................... (736,651) -- -- -- (628,538) Proceeds from sales of oil and gas properties........ 45,678 -- -- -- 13,266 Investment in and advances to subsidiaries, net...... (480,105) (18,113) -- -- (76,689) Other, net........................................... (33,763) -- -- -- (23,813) ----------- -------- -------- -------- ----------- Net Cash Used in Investing Activities.................. (1,699,782) (18,113) -- -- (1,815,769) ----------- -------- -------- -------- ----------- Cash Flows from Financing Activities: Long-term borrowings................................. 1,555,361 -- 1,491 2,102 (404,380) Payments on long-term debt........................... (1,419,788) -- -- -- (193,574) Dividends paid....................................... (72,832) -- -- -- -- Common stock activity................................ 582,865 18,113 18,113 37,447 1,127,530 Treasury stock activity, net......................... 5,350 -- -- -- -- Cost of debt and equity transactions................. (5,417) -- -- -- -- Repurchase of preferred interests of subsidiaries.... (82,000) -- -- -- (361,000) ----------- -------- -------- -------- ----------- Net Cash Provided by Financing Activities.............. 563,539 18,113 19,604 39,549 168,576 ----------- -------- -------- -------- ----------- Net Increase (Decrease) in Cash and Cash Equivalents... (224) -- -- (126) (18,033) Cash and Cash Equivalents at Beginning of Year......... 224 -- 2 127 51,533 ----------- -------- -------- -------- ----------- Cash and Cash Equivalents at End of Year............... $ -- $ -- $ 2 $ 1 $ 33,500 =========== ======== ======== ======== =========== RECLASSIFICATIONS & ELIMINATIONS CONSOLIDATED ----------------- ------------ (IN THOUSANDS) Cash Provided by (Used in) Operating Activities........ $ -- $ 2,705,900 ----------- ----------- Cash Flows from Investing Activities: Additions to property and equipment.................. -- (1,594,936) Acquisitions......................................... -- (1,365,189) Proceeds from sales of oil and gas properties........ -- 58,944 Investment in and advances to subsidiaries, net...... 574,907 -- Other, net........................................... -- (57,576) ----------- ----------- Net Cash Used in Investing Activities.................. 574,907 (2,958,757) ----------- ----------- Cash Flows from Financing Activities: Long-term borrowings................................. 626,296 1,780,870 Payments on long-term debt........................... -- (1,613,362) Dividends paid....................................... -- (72,832) Common stock activity................................ (1,201,203) 582,865 Treasury stock activity, net......................... -- 5,350 Cost of debt and equity transactions................. -- (5,417) Repurchase of preferred interests of subsidiaries.... -- (443,000) ----------- ----------- Net Cash Provided by Financing Activities.............. (574,907) 234,474 ----------- ----------- Net Increase (Decrease) in Cash and Cash Equivalents... -- (18,383) Cash and Cash Equivalents at Beginning of Year......... -- 51,886 ----------- ----------- Cash and Cash Equivalents at End of Year............... $ -- $ 33,503 =========== ===========
F-57 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 APACHE APACHE FINANCE APACHE OF APACHE CORPORATION NORTH AMERICA AUSTRALIA FINANCE CANADA CORPORATION ----------- ------------- --------- -------------- ------------ (IN THOUSANDS) Cash Provided by (Used in) Operating Activities.................................... $ 474,784 $ -- $(18,687) $(43,819) $ 968,440 ----------- -------- -------- -------- ----------- Cash Flows from Investing Activities: Additions to property and equipment........... (249,971) -- -- -- (787,397) Acquisitions.................................. (269,885) -- -- -- -- Proceeds from sales of oil and gas properties.................................. -- -- -- -- 7,043 Purchase of U.S. Government Agency Notes...... -- -- -- -- 101,723 Investment in and advances to subsidiaries, net......................................... (168,481) (18,050) -- -- (408,837) Other, net.................................... (15,105) -- -- -- (22,415) ----------- -------- -------- -------- ----------- Net Cash Used in Investing Activities........... (703,442) (18,050) -- -- (1,109,883) ----------- -------- -------- -------- ----------- Cash Flows from Financing Activities: Long-term borrowings.......................... 1,628,207 -- 637 2,826 225,518 Payments on long-term debt.................... (1,362,800) -- -- -- (190,671) Dividends paid................................ (68,879) -- -- -- -- Common stock activity......................... 30,708 18,050 18,050 41,120 128,889 Treasury stock activity, net.................. 1,991 -- -- -- -- Cost of debt and equity transactions.......... (6,728) -- -- -- -- ----------- -------- -------- -------- ----------- Net Cash Provided by Financing Activities....... 222,499 18,050 18,687 43,946 163,736 ----------- -------- -------- -------- ----------- Net Increase (Decrease) in Cash and Cash Equivalents................................... (6,159) -- -- 127 22,293 Cash and Cash Equivalents at Beginning of Year.......................................... 6,383 -- 2 -- 29,240 ----------- -------- -------- -------- ----------- Cash and Cash Equivalents at End of Year........ $ 224 $ -- $ 2 $ 127 $ 51,533 =========== ======== ======== ======== =========== RECLASSIFICATIONS & ELIMINATIONS CONSOLIDATED ----------------- ------------ (IN THOUSANDS) Cash Provided by (Used in) Operating Activities.................................... $ -- $ 1,380,718 --------- ----------- Cash Flows from Investing Activities: Additions to property and equipment........... -- (1,037,368) Acquisitions.................................. -- (269,885) Proceeds from sales of oil and gas properties.................................. -- 7,043 Purchase of U.S. Government Agency Notes...... -- 101,723 Investment in and advances to subsidiaries, net......................................... 595,368 -- Other, net.................................... -- (37,520) --------- ----------- Net Cash Used in Investing Activities........... 595,368 (1,236,007) --------- ----------- Cash Flows from Financing Activities: Long-term borrowings.......................... (389,259) 1,467,929 Payments on long-term debt.................... -- (1,553,471) Dividends paid................................ -- (68,879) Common stock activity......................... (206,109) 30,708 Treasury stock activity, net.................. -- 1,991 Cost of debt and equity transactions.......... -- (6,728) --------- ----------- Net Cash Provided by Financing Activities....... (595,368) (128,450) --------- ----------- Net Increase (Decrease) in Cash and Cash Equivalents................................... -- 16,261 Cash and Cash Equivalents at Beginning of Year.......................................... -- 35,625 --------- ----------- Cash and Cash Equivalents at End of Year........ $ -- $ 51,886 ========= ===========
F-58 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 SUBSIDIARIES APACHE APACHE APACHE APACHE OF APACHE CORPORATION NORTH AMERICA FINANCE 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-59 APACHE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) CONDENSED CONSOLIDATING BALANCE SHEET FOR THE YEAR ENDED DECEMBER 31, 2003
ALL OTHER APACHE APACHE APACHE SUBSIDIARIES APACHE NORTH FINANCE FINANCE OF APACHE CORPORATION AMERICA AUSTRALIA CANADA CORPORATION ----------- ------------- --------- -------------- ------------ (IN THOUSANDS) ASSETS Current Assets: Cash and cash equivalents............................ $ -- $ -- $ 2 $ 1 $ 33,500 Receivables, net of allowance........................ 204,078 -- -- -- 434,977 Inventories.......................................... 17,646 -- -- -- 108,221 Drilling advances and other.......................... 60,159 -- -- -- 40,488 ---------- -------- -------- ---------- ---------- 281,883 -- 2 1 617,186 ---------- -------- -------- ---------- ---------- Property and Equipment, Net............................ 5,235,717 -- -- -- 6,024,368 ---------- -------- -------- ---------- ---------- Other Assets: Intercompany receivable, net......................... 1,291,503 -- (1,961) 93,768 (1,383,310) Goodwill, net........................................ -- -- -- -- 189,252 Equity in affiliates................................. 3,077,152 183,617 437,860 1,084,711 (803,409) Deferred charges and other........................... 36,672 -- -- 4,767 26,278 ---------- -------- -------- ---------- ---------- $9,922,927 $183,617 $435,901 $1,183,247 $4,670,365 ========== ======== ======== ========== ========== LIABILITIES AND SHAREHOLDERS' EQUITY Current Liabilities: Accounts payable..................................... $ 189,031 $ -- $ -- $ -- $ 111,567 Other accrued expenses............................... 238,555 -- 1,621 1,803 277,801 ---------- -------- -------- ---------- ---------- 427,586 -- 1,621 1,803 389,368 ---------- -------- -------- ---------- ---------- Long-Term Debt......................................... 1,405,882 -- 268,987 646,741 5,356 ---------- -------- -------- ---------- ---------- Deferred Credits and Other Noncurrent Liabilities: Income taxes......................................... 879,044 -- (18,324) (842) 837,360 Advances from gas purchasers......................... 109,207 -- -- -- -- Asset retirement obligation.......................... 401,349 -- -- -- 338,426 Oil and gas derivative instruments................... 5,931 -- -- -- -- Other................................................ 161,130 -- -- -- 22,703 ---------- -------- -------- ---------- ---------- 1,556,661 -- (18,324) (842) 1,198,489 ---------- -------- -------- ---------- ---------- Preferred Interests of Subsidiaries.................... -- -- -- -- -- ---------- -------- -------- ---------- ---------- Commitments and Contingencies Shareholders' Equity..... 6,532,798 183,617 183,617 535,545 3,077,152 ---------- -------- -------- ---------- ---------- $9,922,927 $183,617 $435,901 $1,183,247 $4,670,365 ========== ======== ======== ========== ========== RECLASSIFICATIONS & ELIMINATIONS CONSOLIDATED ----------------- ------------ (IN THOUSANDS) ASSETS Current Assets: Cash and cash equivalents............................ $ -- $ 33,503 Receivables, net of allowance........................ -- 639,055 Inventories.......................................... -- 125,867 Drilling advances and other.......................... -- 100,647 ----------- ----------- -- 899,072 ----------- ----------- Property and Equipment, Net............................ -- 11,260,085 ----------- ----------- Other Assets: Intercompany receivable, net......................... -- -- Goodwill, net........................................ -- 189,252 Equity in affiliates................................. (3,979,931) -- Deferred charges and other........................... -- 67,717 ----------- ----------- $(3,979,931) $12,416,126 =========== =========== LIABILITIES AND SHAREHOLDERS' LIABILITI EQUITY Current Liabilities: Accounts payable..................................... $ -- $ 300,598 Other accrued expenses............................... -- 519,780 ----------- ----------- -- 820,378 ----------- ----------- Long-Term Debt......................................... -- 2,326,966 ----------- ----------- Deferred Credits and Other Noncurrent Liabilities: Income taxes......................................... -- 1,697,238 Advances from gas purchasers......................... -- 109,207 Asset retirement obligation.......................... -- 739,775 Oil and gas derivative instruments................... -- 5,931 Other................................................ -- 183,833 ----------- ----------- -- 2,735,984 ----------- ----------- Preferred Interests of Subsidiaries.................... -- -- ----------- ----------- Commitments and Contingencies Shareholders' Equity..... (3,979,931) 6,532,798 ----------- ----------- $(3,979,931) $12,416,126 =========== ===========
F-60 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 Drilling advances and other................ 19,468 -- -- -- 58,536 156,611 -- 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 Drilling advances and other................ -- 78,004 -- 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' LIAB EQUITY 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-61 BOARD OF DIRECTORS FREDERICK M. BOHEN(3)(5) Executive Vice President and Chief Operating Officer, The Rockefeller University G. STEVEN FARRIS(1) President, Chief Executive Officer and Chief Operating Officer, Apache Corporation RANDOLPH M. FERLIC, M.D.(1)(2) Founder and Former President, Surgical Services of the Great Plains, P.C. EUGENE C. FIEDOREK(2) Private Investor, Former Managing Director, EnCap Investments L.C. A. D. FRAZIER, JR.(3)(5) 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. 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 JOHN J. CHRISTMANN Vice President -- Business Development MATTHEW W. DUNDREA Vice President and Treasurer ROBERT J. DYE Vice President -- Investor Relations ERIC L. HARRY Vice President and Associate General Counsel JANICE K. HARTRICK 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 W. KREGG OLSON Vice President -- Corporate Reservoir Engineering JON W. SAUER Vice President -- Tax CHERI L. PEPER Corporate Secretary --------------- (1) Executive Committee (2) Audit Committee (3) Management, Development and Compensation Committee (4) Corporate Governance and Nominating Committee (5) Stock Option Plan Committee SHAREHOLDER INFORMATION Stock Data
Dividends Price Range* per Share* --------------- ----------------- HIGH LOW DECLARED PAID ------ ------ -------- ------ 2003 First Quarter........ $32.15 $26.26 $.0475 $.0475 Second Quarter....... 34.60 28.13 .0500 .0500 Third Quarter........ 35.04 30.41 .0600 .0500 Fourth Quarter....... 41.68 34.05 .0600 .0600 2002 First Quarter........ $27.71 $21.12 $.0475 $.0475 Second Quarter....... 28.61 25.03 .0475 .0475 Third Quarter........ 28.57 21.46 .0475 .0475 Fourth Quarter....... 28.88 23.53 .0475 .0475
* Per share prices and dividend amounts have been adjusted to reflect the effects of 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 39 consecutive years through December 31, 2003. Future dividend payments will depend upon the Company's level of earnings, financial requirements and other relevant factors. Apache common stock is listed on the New York and Chicago stock exchanges and the NASDAQ National Market (symbol APA). At December 31, 2003, the Company's shares of common stock outstanding were held by approximately 8,000 shareholders of record and 157,000 beneficial owners. Also listed on the New York Stock Exchange are: o Apache Finance Canada's 7.75% notes, due 2029 (symbol APA 29) CORPORATE OFFICES One Post Oak Central 2000 Post Oak Boulevard Suite 100 Houston, Texas 77056-4400 (713) 296-6000 INDEPENDENT PUBLIC ACCOUNTANTS Ernst & Young LLP Five Houston Center 1401 McKinney Street, Suite 1200 Houston, Texas 77010-2007 STOCK TRANSFER AGENT AND REGISTRAR Wells Fargo Bank, N.A. Attn: Shareowner Services P.O. Box 64854 South St. Paul, Minnesota 55164-0854 (651) 450-4064 or (800) 468-9716 Communications concerning the transfer of shares, lost certificates, dividend checks, duplicate mailings or change of address should be directed to the stock transfer agent. Shareholders can access account information on the web site: http://www.shareowneronline.com. DIVIDEND REINVESTMENT PLAN Shareholders of record may invest their dividends automatically in additional shares of Apache common stock at the market price. Participants may also invest up to an additional $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, N.A. DIRECT REGISTRATION Shareholders of record may hold their shares of Apache common stock in book-entry form. This eliminates costs related to safekeeping or replacing paper stock certificates. In addition, shareholders of record may request electronic movement of book-entry shares between your account with the Company's stock transfer agent and your broker. Stock certificates may be converted to book-entry shares at any time. Questions regarding this service may be directed to the Company's stock transfer agent, Wells Fargo Bank, N.A. ANNUAL MEETING Apache will hold its annual meeting of shareholders on Thursday, May 6, 2004, at 10 a.m. in the Ballroom, Doubletree Hotel Houston -- Post Oak, 2001 Post Oak Boulevard, Houston, Texas. Apache plans to web cast the annual meeting live; connect through the Apache web site: http://www.apachecorp.com. STOCK HELD IN "STREET NAME" The Company maintains a direct mailing list to ensure that shareholders with stock held in brokerage accounts receive information on a timely basis. Shareholders wanting to be added to this list should direct their requests to Apache's Public and International Affairs Department, 2000 Post Oak Boulevard, Suite 100, Houston, Texas, 77056-4400, by calling (713) 296-6157 or by registering on Apache's web site: http://www.apachecorp.com. FORM 10-K REQUEST Shareholders and other persons interested in obtaining, without cost, a copy of the Company's Form 10-K filed with the Securities and Exchange Commission may do so by writing to Cheri L. Peper, Corporate Secretary, 2000 Post Oak Boulevard, Suite 100, Houston, Texas, 77056-4400. INVESTOR RELATIONS Shareholders, brokers, securities analysts or portfolio managers seeking information about the Company are welcome to contact Robert J. Dye, Vice President of Investor Relations, at (713) 296-6662. Members of the news media and others seeking information about the Company should contact Apache's Public and International Affairs Department at (713) 296-6107. WEB SITE: HTTP://WWW.APACHECORP.COM INDEX TO EXHIBITS
EXHIBIT NO. DESCRIPTION ------- ----------- 2.1 -- Agreement and Plan of Merger among Registrant, YPY Acquisitions, Inc. and The Phoenix Resource Companies, Inc., dated March 27, 1996 (incorporated by reference to Exhibit 2.1 to Registrant's Registration Statement on Form S-4, Registration No. 333-02305, filed April 5, 1996). 2.2 -- Purchase and Sale Agreement by and between BP Exploration & Production Inc., as seller, and Registrant, as buyer, dated January 11, 2003 (incorporated by reference to Exhibit 2.1 to Registrant's Current Report on Form 8-K, dated and filed January 13, 2003, SEC File No. 1-4300). 2.3 -- Sale and Purchase Agreement by and between BP Exploration Operating Company Limited, as seller, and Apache North Sea Limited, as buyer, dated January 11, 2003 (incorporated by reference to Exhibit 2.2 to Registrant's Current Report on Form 8-K, dated and filed January 13, 2003, SEC File No. 1-4300). *3.1 -- Restated Certificate of Incorporation of Registrant, dated February 11, 2004, as filed with the Secretary of State of Delaware on February 12, 2004. *3.2 -- Bylaws of Registrant, as amended February 5, 2004. 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 to Registrant's Current Report on Form 8-K, dated and filed April 18, 1998, SEC File No. 1-4300). 4.3 -- Form of Certificate for Registrant's Automatically Convertible Equity Securities, Conversion Preferred Stock, Series C (incorporated by reference to Exhibit 99.8 to Amendment No. 1 on Form 8-K/A to Registrant's Current Report on Form 8-K, dated and filed April 29, 1999, SEC File No. 1-4300). 4.4 -- Rights Agreement, dated January 31, 1996, between Registrant and Norwest Bank Minnesota, N.A., rights agent, relating to the declaration of a rights dividend to Registrant's common shareholders of record on January 31, 1996 (incorporated by reference to Exhibit (a) to Registrant's Registration Statement on Form 8-A, dated January 24, 1996, SEC File No. 1-4300). 10.1 -- 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, dated June 13, 1997, 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).
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, dated June 13, 1997, 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 Administrative 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, dated June 13, 1997, 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).
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 January 1, 2003 (incorporated by reference to Exhibit 10.18 to Registrant's Annual Report on Form 10-K, as amended by Form 10-K/A, for year ended December 31, 2002, SEC File No. 1-4300). +10.19 -- 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 January 1, 2003 (incorporated by reference to Exhibit 10.20 to Registrant's Annual Report on Form 10-K for year ended December 31, 2002, SEC File No. 1-4300). +10.21 -- Non-Qualified Retirement/Savings Plan of Apache Corporation, restated January 1, 1997, and amendments effective January 1, 1997, January 1, 1998 and January 1, 1999 (incorporated by reference to Exhibit 10.17 to Registrant's Annual Report on Form 10-K for year ended December 31, 1998, SEC File No. 1-4300).
EXHIBIT NO. DESCRIPTION ------- ----------- +10.22 -- Amendment to Non-Qualified Retirement/Savings Plan of Apache Corporation, dated February 22, 2000, effective January 1, 1999 (incorporated by reference to Exhibit 4.7 to Registrant's Registration Statement on Form S-8, Registration No. 333-31092, filed February 25, 2000); and Amendment dated July 27, 2000 (incorporated by reference to Exhibit 4.8 to Amendment No. 1 to Registrant's Registration Statement on Form S-8, Registration No. 333-31092, filed August 18, 2000). +10.23 -- Amendment to Non-Qualified Retirement/Savings Plan of Apache Corporation, dated August 3, 2001, effective September 1, 2000 and July 1, 2001 (incorporated by reference to Exhibit 10.13 to Registrant's Quarterly Report on Form 10-Q, as amended by Form 10-Q/A, for the quarter ended June 30, 2001, SEC File No. 1-4300). +*10.24 -- Amendment to Non-Qualified Retirement/Savings Plan of Apache Corporation, dated December 18, 2003, effective January 1, 2004. +10.25 -- 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). +10.26 -- Apache Corporation 1995 Stock Option Plan, as amended and restated September 13, 2001 (incorporated by reference to Exhibit 10.02 to Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2001, as amended by Form 10-Q/A, SEC File No. 1-4300). +*10.27 -- Apache Corporation 2000 Share Appreciation Plan, as amended and restated February 5, 2004. +10.28 -- 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). +10.29 -- 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). +10.30 -- 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). +*10.31 -- Apache Corporation 2003 Stock Appreciation Rights Plan, dated and effective May 1, 2003. +10.32 -- 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). +10.33 -- 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). +10.34 -- Apache Corporation Deferred Delivery Plan, as amended and restated December 18, 2002, effective May 2, 2002 (incorporated by reference to Exhibit 4.5 to Post-Effective Amendment No. 2 to Registrant's Registration Statement on Form S-8, Registration No. 333-31092, filed March 11, 2003). +10.35 -- Apache Corporation Executive Restricted Stock Plan, as amended and restated December 18, 2002, effective May 2, 2002 (incorporated by reference to Exhibit 4.5 to Post Effective Amendment No. 1 to Registrant's Registration Statement on Form S-8, Registration No. 333-97403, filed December 30, 2002). +10.36 -- Apache Corporation Non-Employee Directors' Compensation Plan, as amended and restated May 1, 2003, effective July 1, 2003 (incorporated by reference to Exhibit 10.1 to Registrant's Quarterly Report on Form 10-Q, as amended by Form 10-Q/A, for the quarter ended June 30, 2003, SEC File No. 1-4300).
EXHIBIT NO. DESCRIPTION ------- ----------- +10.37 -- 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). +*10.38 -- 1.1 Apache Corporation Equity Compensation Plan for Non-Employee Directors, as amended and restated February 5, 2004. +10.39 -- 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). +10.40 -- 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). +10.41 -- 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). +10.42 -- 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). +10.43 -- 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). 10.44 -- Amended and Restated Gas Purchase Agreement, effective July 1, 1998, by and among Registrant and MW Petroleum Corporation, as seller, and Producers Energy Marketing, LLC, as buyer (incorporated by reference to Exhibit 10.1 to Registrant's Current Report on Form 8-K, dated June 18, 1998, filed June 23, 1998, SEC File No. 1-4300). 10.45 -- Deed of Guaranty and Indemnity, dated January 11, 2003, made by Registrant in favor of BP Exploration Operating Company Limited (incorporated by reference to Registrant's Current Report on Form 8-K, dated and filed January 13, 2003, SEC File No. 1-4300). *12.1 -- Statement of Computation of Ratios of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividends *14.1 -- Code of Business Conduct *21.1 -- Subsidiaries of Registrant *23.1 -- Consent of Ernst & Young LLP *23.2 -- Consent of Ryder Scott Company L.P., Petroleum Consultants *24.1 -- Power of Attorney (included as a part of the signature pages to this report) *31.1 -- Certification of Chief Executive Officer *31.2 -- Certification of Chief Financial Officer *32.1 -- Certification of Chief Executive Officer and Chief Financial Officer
--------------- * Filed herewith. + Management contracts or compensatory plans or arrangements required to be filed herewith pursuant to Item 15 hereof. NOTE: Debt instruments of the Registrant defining the rights of long-term debt holders in principal amounts not exceeding 10 percent of the Registrant's consolidated assets have been omitted and will be provided to the Commission upon request.