UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-K [ X ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the Fiscal Year Ended December 31, 2002 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the Transition Period from to ------------------- --------------------- Commission File Number 0-13546 APACHE OFFSHORE INVESTMENT PARTNERSHIP A Delaware IRS Employer General Partnership No. 41-1464066 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: NONE SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: PARTNERSHIP UNITS Indicate by check mark whether the Partnership (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 Partnership 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 Partnership'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. X ----- Indicate by check whether registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). [ ] Aggregate market value of the voting and non-voting common equity held by non-affiliates of registrant as of June 28, 2002................ $8,713,894 DOCUMENTS INCORPORATED BY REFERENCE: Portions of Apache Corporation's proxy statement relating to its 2003 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.................................................................................... 5 3. LEGAL PROCEEDINGS............................................................................. 6 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS........................................... 6 PART II 5. MARKET FOR THE PARTNERSHIP'S SECURITIES AND RELATED SECURITY HOLDER MATTERS.................................................................. 7 6. SELECTED FINANCIAL DATA....................................................................... 7 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS...................................................... 8 7A. MARKET RISK................................................................................... 13 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA................................................... 14 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE...................................................... 32 PART III 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE PARTNERSHIP........................................... 33 11. EXECUTIVE COMPENSATION........................................................................ 33 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT........................................................................... 33 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS................................................ 33 14. CONTROLS AND PROCEDURES....................................................................... 33 PART IV 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K............................... 34 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) or billion cubic feet (Bcf). 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 (bopd) and thousands of cubic feet of gas per day (Mcfd), respectively. With respect to information relating to the Partnership's working interest in wells or acreage, "net" oil and gas wells or acreage is determined by multiplying gross wells or acreage by the Partnership's working interest therein. Unless otherwise specified, all references to wells and acres are gross.
PART I ITEM 1. BUSINESS GENERAL Apache Offshore Investment Partnership (the Investment Partnership), a Delaware general partnership, was organized in October 1983, with public investors as Investing Partners and Apache Corporation (Apache), a Delaware corporation, as Managing Partner. The operations of the Investment Partnership are conducted by Apache Offshore Petroleum Limited Partnership (the Limited Partnership), a Delaware limited partnership, of which Apache is the sole general partner and the Investment Partnership is the sole limited partner. The Partnership does not maintain a website, so we do not make electronic access to our reports filed with the SEC available on or through a website. The Partnership will, however, provide paper copies of these filings, free of charge, to anyone so requesting. Any such requests should be made by mail to Apache Offshore Investment Partnership, 2000 Post Oak Blvd., Houston, Texas 77056, Attention: David Higgins, or by telephone at 713-296-6000. The Investing Partners purchased Units of Partnership Interests (Units) in the Investment Partnership at $150,000 per Unit, with five percent down and the balance in payments as called by the Investment Partnership. As of December 31, 2002, a total of $85,000 had been called for each Unit. In 1989, the Investment Partnership determined that the full $150,000 per Unit was not needed, fixed the total calls at $85,000 per Unit, and released the Investing Partners from liability for future calls. The Investment Partnership invested, and will continue to invest, its entire capital in the Limited Partnership. As used hereafter, the term "Partnership" refers to either the Investment Partnership or the Limited Partnership, as the case may be. The Partnership's business is participation in oil and gas exploration, development and production activities on federal lease tracts in the Gulf of Mexico, offshore Louisiana and Texas. Except for the Matagorda Island Block 681 and 682 interests, as described below, the Partnership acquired its oil and gas interests through the purchase of 85 percent of the working interests held by Apache as a participant in a venture (the Venture) with Shell Oil Company (Shell) and certain other companies. The Partnership owns working interests ranging from 6.29 percent to 9.44 percent in the Venture's properties. The Venture acquired substantially all of its oil and gas properties through bidding for leases offered by the federal government. The Venture members relied on Shell's knowledge and expertise in determining bidding strategies for the acquisitions. When Shell was successful in obtaining the properties, it generally billed participating members on a promoted basis (one-third for one-quarter) for the acquisition of exploratory leases and on a straight-up basis for the acquisition of leases defined as drainage tracts. All such billings were proportionately reduced to each member's working interest. In November 1992, Apache and the Partnership formed a joint venture to acquire Shell's 92.6 percent working interest in Matagorda Island Blocks 681 and 682 pursuant to a jointly-held contractual preferential right to purchase. Apache and the Partnership previously owned working interests in the blocks equal to 1.109 percent and 6.287 percent, respectively, and net revenue interests of .924 percent and 5.239 percent, respectively. To facilitate the acquisition, Apache and the Partnership contributed all of their interests in Matagorda Island Blocks 681 and 682 to a newly formed joint venture, and Apache contributed $64.6 million ($55.6 million net of purchase price adjustments) to the joint venture to finance the acquisition. The Partnership had neither the cash nor additional financing to fund a proportionate share of the acquisition and participated through an increased net revenue interest in the joint venture. Under the terms of the joint venture agreement, the Partnership's effective net revenue interest in the Matagorda Island Block 681 and 682 properties increased to 13.284 percent as a result of the acquisition, while its working interest was unchanged. The acquisition added approximately 7.5 Bcf of natural gas and 16 Mbbls of oil to the Partnership's reserve base without any incremental expenditures by the Partnership. Since the Venture is not expected to acquire any additional exploratory acreage, future acquisitions, if any, will be confined to those leases defined as drainage tracts. The current Venture members would pay their proportionate share of acquiring any drainage tracts on a non-promoted basis. 1
Offshore exploration differs from onshore exploration in that production from a prospect generally will not commence until a sufficient number of productive wells have been drilled to justify the significant costs associated with construction of a production platform. Exploratory wells usually are drilled from mobile platforms until there are sufficient indications of commercial production to justify construction of a permanent production platform. On an ongoing basis, the Partnership reviews the possible sale of lower value properties prior to incurring associated dismantlement and abandonment costs. Apache, as Managing Partner, manages the Partnership's operations. Apache uses a portion of its staff and facilities for this purpose and is reimbursed for actual costs paid on behalf of the Partnership, as well as for general, administrative and overhead costs properly allocable to the Partnership. 2002 RESULTS AND BUSINESS DEVELOPMENT The Partnership reported net income in 2002 of $3.5 million, or $2,259 per Investing Partner Unit. Natural gas production averaged 3,353 Mcf per day, while oil sales averaged 302 barrels per day. Production added through drilling in 2002 partially offset declines from natural depletion and weather-related downtime. During 2002, the Partnership participated in drilling six development wells at South Timbalier 295, with five completed as producing wells. The Partnership continued to participate in recompletion projects to maintain production and enhance recoverable reserves. During 2002, the Partnership participated in four recompletions at South Timbalier 295 and one at Matagorda 681/682. Since inception, the Partnership has acquired an interest in 49 prospects. As of December 31, 2002, 42 of those prospects have been surrendered or sold. As of December 31, 2002, 131 wells have been drilled on the Partnership's seven remaining developed fields. Of the 131 wells, 104 were productive and of those, 52 are currently producing. Two of the Partnership's producing wells are dual completions. The Partnership had, at December 31, 2002, estimated proved oil and gas reserves of 11.4 Bcfe, of which 55 percent was natural gas. MARKETING Apache, on behalf of the Partnership, seeks and negotiates oil and gas marketing arrangements with various marketers and purchasers. During 2002, the Partnership's spot market gas was purchased primarily by Cinergy Marketing and Trading, LLC. The Partnership's oil and condensate production during 2002 was purchased largely by Apache Crude Oil Marketing, Inc. (ACOM), a wholly-owned subsidiary of Apache. In 1998, Apache sold its interest in Producers Energy Marketing LLC (ProEnergy) (a gas marketing company formed by Apache and other natural gas producers) to Cinergy Corp., with ProEnergy being renamed Cinergy Marketing & Trading, LLC (Cinergy). In July 1998, in connection with the sale of its interest, Apache entered into a gas purchase agreement with Cinergy to market most of its U.S. natural gas production for a ten-year period, with an option, after prior notice, to terminate after six years. Apache also sells most of the Partnership's natural gas production to Cinergy under the gas purchase agreement. Since 2001, Apache has been involved in an arbitration proceeding with Cinergy on issues arising from the gas sales agreement. Apache continues to market most of the Partnership's gas production through Cinergy; however, Apache is actively discussing with Cinergy its gas marketing relationship with Cinergy and a resolution of the related disputes. The Partnership does not expect the final resolution of these disputes to have a material effect on its financial position or future gas sales. The prices the Partnership receives for its gas production, in the opinion of Apache, approximate market prices. During 2002, ACOM purchased oil and condensate from the Partnership which accounted for approximately 17 percent of the Partnership's total oil and gas sales. The prices the Partnership received for these sales were based on third-party pricing indexes and, in the opinion of Apache, were comparable to prices that would have been received from a non-affiliated party. See Note (5) "Major Customer and Related Parties Information" to the Partnership's financial statements under Item 8. Because the Partnership's oil and gas products are commodities and the prices and terms of its sales reflect those of the market, the Partnership does not believe that the loss of any customer would have a material adverse affect 2
on the Partnership's business or results of operations. The Partnership is not in a position to predict future oil and gas prices. RISK FACTORS RELATED TO THE PARTNERSHIP'S BUSINESS AND OPERATIONS VOLATILE PRICES CAN MATERIALLY AFFECT THE PARTNERSHIP The Partnership continually analyzes forecasts and updates its estimates of energy prices for its internal use in planning, budgeting, and estimating and valuing reserves. The Partnership's future financial condition and results of operations will depend upon the prices received for the Partnership's oil and natural gas production and the costs of acquiring, finding, developing and producing reserves. Prices for oil and natural gas are subject to fluctuations in response to relatively minor changes in supply, market uncertainty and a variety of additional factors that are beyond the control of the Partnership. These factors include worldwide political instability (especially in the Middle East and other oil-producing regions), the foreign supply of oil and gas, the price of foreign imports, the level of drilling activity, the level of consumer product demand, government regulations and taxes, the price and availability of alternative fuels and the overall economic environment. A substantial or extended decline in oil and gas prices would have a material adverse effect on the Partnership's financial position, results of operations, quantities of oil and gas that may be economically produced, and access to capital. Oil and natural gas prices have historically been and are likely to continue to be volatile. This volatility makes it difficult to estimate with precision the value of producing properties in acquisitions and to budget and project the return on exploration and development projects involving the Partnership's oil and gas properties. UNCERTAINTY IN CALCULATING RESERVES; RATES OF PRODUCTION; DEVELOPMENT EXPENDITURES; CASH FLOWS There are numerous uncertainties inherent in estimating quantities of oil and natural gas reserves of any category and in projecting future rates of production and timing of development expenditures, which underlie the reserve estimates, including many factors beyond the Partnership's control. Reserve data represent only estimates. In addition, the estimates of future net cash flows from the Partnership's proved reserves and their present value are based upon various assumptions about future production levels, prices and costs that may prove to be incorrect over time. Any significant variance from the assumptions could result in the actual quantity of the Partnership's reserves and future net cash flows from them being materially different from the estimates. In addition, the Partnership's estimated reserves may be subject to downward or upward revision based upon production history, results of future exploration and development, prevailing oil and gas prices, operating and development costs and other factors. SUBSTANTIAL COSTS INCURRED RELATED TO ENVIRONMENTAL MATTERS The Partnership, as an owner or lessee of interests in oil and gas properties, is subject to various federal, state and local laws and regulations relating to the 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. The Partnership has made and will continue to make expenditures in its efforts to comply with these requirements. These costs are inextricably connected to normal operating expenses such that the Partnership is unable to separate the expenses related to environmental matters; however, the Partnership does not believe such expenditures are material to its financial position or results of operations. The Partnership does not believe that compliance with federal, state or local 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 and the competitive position of the Partnership, but 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. 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. Apache, as managing partner, maintains insurance against certain losses or liabilities arising from the Partnership's operations in accordance with 3
customary industry practices and in amounts that management believes to be prudent; however, insurance is not available to the Partnership's against all operational risks. COMPETITION WITH OTHER COMPANIES COULD HARM THE PARTNERSHIP The Partnership is a very minor factor in the oil and gas industry in the Gulf of Mexico area and faces strong competition from much larger producers for the marketing of its oil and gas. The Partnership's ability to compete for purchasers and favorable marketing terms will depend on the general demand for oil and gas from Gulf of Mexico producers. More particularly, it will depend largely on the efforts of Apache to find the best markets for the sale of the Partnership's oil and gas production. INVESTORS IN THE PARTNERSHIP'S 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, the Partnership's 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. We are required to file with the SEC periodic financial statements audited or reviewed by an independent public accountant. On March 29, 2002, the General Partner decided not to engage Arthur Andersen as the Partnership's independent auditors, and engaged Ernst & Young LLP to serve as our new independent auditors for 2002. However, included in this annual report on Form 10-K are financial data and other information for 2001 and 2000 that were audited by Arthur Andersen. Investors in the Partnership's 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. 4
ITEM 2. PROPERTIES ACREAGE Acreage is held by the Partnership pursuant to the terms of various leases. The Partnership does not anticipate any difficulty in retaining any of its desirable leases. A summary of the Partnership's gross and net acreage as of December 31, 2002, is set forth below: DEVELOPED ACREAGE ---------------------------------- LEASE BLOCK STATE GROSS ACRES NET ACRES ---------------------------------- ------- ----------- ------------ Ship Shoal 258, 259 LA 10,141 638 South Timbalier 276, 295, 296 LA 15,000 1,063 North Padre Island 969, 976 TX 10,080 714 Matagorda Island 681, 682, 683 TX 15,840 742 South Pass 83 LA 5,000 339 East Cameron 60 LA 5,000 472 Ship Shoal 201, 202 LA 10,000 -- ----------- ------------ 71,061 3,968 =========== ============ At December 31, 2002, the Partnership did not have an interest in any undeveloped acreage. PRODUCTIVE OIL AND GAS WELLS The number of productive oil and gas wells in which the Partnership had an interest as of December 31, 2002, is set forth below: GAS OIL -------------------- ------------------- LEASE BLOCK STATE GROSS NET GROSS NET ------------------------------- ------- -------------------- ------------------- Ship Shoal 258, 259 LA 5 .31 -- -- South Timbalier 276, 295, 296 LA 1 .07 29 2.05 North Padre Island 969, 976 TX 7 .50 -- -- Matagorda Island 681, 682,683 TX 5 .31 -- -- South Pass 83 LA 4 .27 -- -- East Cameron 60 LA -- -- -- -- Ship Shoal 201, 202 LA -- -- 1 -- --------- ------- --------- ------- 22 1.46 30 2.05 ========= ======= ========= ======= NET WELLS DRILLED 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 --------- --------------------------------------- ------------------------------------------- YEAR PRODUCTIVE DRY TOTAL PRODUCTIVE DRY TOTAL --------- ------------ ------- --------- ----------- ---------- ----------- 2002 -- -- -- .35 .07 .42 2001 -- -- -- .28 -- .28 2000 -- -- -- .28 .06 .34 5
PRODUCTION AND PRICING DATA The following table describes, for each of the last three fiscal years, oil and gas production for the Partnership, average production costs (including gathering and transportation expense) and average sales prices. PRODUCTION AVERAGE SALES PRICES ------------------------- AVERAGE ---------------------------- YEAR ENDED OIL GAS PRODUCTION OIL GAS DECEMBER 31, (MBBLS) (MMCF) COST PER MCFE (PER BBL) (PER MCF) ------------- --------- -------- --------------- ----------- ------------ 2002 110 1,224 $ .44 $ 25.03 $ 3.36 2001 112 1,705 .33 25.00 4.51 2000 119 2,320 .25 30.18 3.91 See the Supplemental Oil and Gas Disclosures under Item 8 for estimated proved oil and gas reserves quantities. ESTIMATED PROVED RESERVES AND FUTURE NET CASH FLOWS As of December 31, 2002, the Partnership had total estimated proved reserves of 849,000 barrels of crude oil and condensate and 6.3 Bcf of natural gas. Combined, these total estimated proved reserves are equivalent to 11.4 Bcf of gas. Estimated proved developed reserves comprise 99 percent of the Partnership's total estimated proved reserves on a Bcfe basis. The Partnership's estimates of proved reserves and proved developed reserves at December 31, 2002, 2001 and 2000, changes in proved reserves during the last three years, and estimates of future net cash flows and discounted future net cash flows from proved reserves are contained in the Supplemental Oil and Gas Disclosures (Unaudited), in the 2002 Consolidated Financial Statements under Item 8 of this Form 10-K. Proved oil and gas reserves are the estimated quantities of natural gas, crude oil and condensate 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 productibility 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. 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. The Partnership's estimate of proved oil and gas reserves are prepared by Ryder Scott Company, L.P. Petroleum Consultants, independent petroleum engineers, utilizing oil and gas price data and cost estimates provided by Apache as Managing Partner. ITEM 3. LEGAL PROCEEDINGS There are no material legal proceedings pending to which the Partnership is a party or to which the Partnership's interests are subject. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS There were no matters submitted to a vote of security holders during the fourth quarter of 2002. 6
PART II ITEM 5. MARKET FOR THE PARTNERSHIP'S SECURITIES AND RELATED SECURITY HOLDER MATTERS As of December 31, 2002, there were 1,084.9 of the Partnership's Units outstanding held by 899 investors of record. The Partnership has no other class of security outstanding or authorized. The Units are not traded on any security market. Cash distributions to Investing Partners totaled approximately $1.1 million, or $1,000 per Unit, during 2002 and approximately $4.5 million, or $4,000 per Unit, during 2001. As discussed in Item 7, an amendment to the Partnership Agreement in February 1994 created a right of presentment under which all Investing Partners have a limited and voluntary right to offer their Units to the Partnership twice each year to be purchased for cash. ITEM 6. SELECTED FINANCIAL DATA The following selected financial data for the five years ended December 31, 2002, should be read in conjunction with the Partnership's financial statements and related notes included under Item 8 below of this Form 10-K. The Partnership's financial statements for the years 1998 through 2001 were audited by Arthur Andersen LLP, independent public accountants. For a discussion of the risks relating to Arthur Andersen's audit of the Partnership's financial statements, please see "Factors That May Affect Future Results -- Risks Relating to Arthur Andersen LLP". AS OF OR FOR THE YEAR ENDED DECEMBER 31, --------------------------------------------------------------------------- 2002 2001 2000 1999 1998 ------------ ------------ ------------ ------------ ------------ (In thousands, except per Unit amounts) Total assets $ 9,834 $ 9,413 $ 8,715 $ 8,722 $ 9,841 ============ ============ ============ ============ ============ Partners' capital $ 9,610 $ 8,369 $ 7,728 $ 7,755 $ 9,080 ============ ============ ============ ============ ============ Oil and gas sales $ 6,868 $ 10,495 $ 12,641 $ 8,796 $ 8,118 ============ ============ ============ ============ ============ Net income $ 3,524 $ 7,264 $ 8,497 $ 4,351 $ 3,621 ============ ============ ============ ============ ============ Net income allocated to: Managing Partner $ 1,036 $ 1,731 $ 2,102 $ 1,269 $ 1,061 Investing Partners 2,488 5,533 6,395 3,082 2,560 ------------ ------------ ------------ ------------ ------------ $ 3,524 $ 7,264 $ 8,497 $ 4,351 $ 3,621 ============ ============ ============ ============ ============ Net income per Investing Partner Unit $ 2,259 $ 4,922 $ 5,654 $ 2,707 $ 2,193 ============ ============ ============ ============ ============ Cash distributions per Investing Partner Unit $ 1,000 $ 4,000 $ 5,750 $ 3,500 $ 1,500 ============ ============ ============ ============ ============ 7
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS OVERVIEW The Partnership's net income and net income per Investing Partner Unit decreased in 2002 on lower oil and gas production and lower gas prices. Daily gas volumes declined 28 percent from a year ago largely as a result of natural depletion, while daily oil production slid two percent with weather-related downtime. Distributions per Investing Partner Unit in 2002 also decreased as a result of the lower production and gas prices. There was only one distribution made to the Investing Partners in 2002 as a result of lower cash provided by operating activities during the first half of 2002. CRITICAL ACCOUNTING POLICIES The discussion and analysis of the Partnership's 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 the Partnership to make estimates and assumptions that affect the reported amount of assets, liabilities, revenues and expenses. Certain accounting policies involve judgments and uncertainties to such an extent that there is a reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. The Partnership bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances. Actual results may differ from the estimates and assumptions used in preparation of the financial statements. The following details the more significant accounting policies, estimates and judgments. Additional accounting policies and estimates made by management are discussed in Note 2 of Item 8 of this Form 10-K. Full Cost Method of Accounting for Oil and Gas Operations The accounting for the Partnership's business is subject to special accounting rules that are unique to the oil and gas industry. There are two allowable methods of accounting for oil and gas business activities: the successful efforts method and the full cost method. There are several significant differences between these methods. Under the successful efforts method, cost such as geological and geophysical (G&G), exploratory dry holes and delay rentals are expensed as incurred, where under the full-cost method these types of charges would be capitalized to oil and gas properties. In the measurement of impairment of oil and gas properties, the successful efforts method of accounting follows the guidance provided in SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets", where the first measurement for impairment is to compare the net book value of the related asset to its undiscounted future cash flows using commodity prices consistent with management expectations. Under the full-cost method the net book value (full-cost pool) is compared to the future net cash flows discounted at 10% using commodity prices in effect at the end of the reporting period. The Partnership has elected to use the full cost method to account for its investment in oil and gas properties. Under this method, the Partnership capitalizes all acquisition, exploration and development costs for the purpose of finding oil and gas reserves. Although some of these costs will ultimately result in no additional reserves, it expects the benefits of successful wells to more than offset the costs of any unsuccessful ones. As a result, the Partnership believes that the full cost method of accounting better reflects the true economics of exploring for and developing oil and gas reserves. The Partnership's financial position and results of operations would have been significantly different had it used the successful efforts method of accounting for oil and gas investments. Reserve Estimates The Partnership's estimate of proved reserves are 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, engineers 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 change. Any significant variance in these assumptions could materially affect the estimated quantity and value of the Partnership's reserves. 8
Despite the inherent imprecision in these engineering estimates, the Partnership's reserves have a significant impact on its financial statements. For example, the quantity of reserves could significantly impact the Partnership's DD&A expense. The Partnership's oil and gas properties are also subject to a "ceiling" limitation based in part on the quantity of our proved reserves. These reserves are the basis for our supplemental oil and gas disclosures. The Partnership's estimate of proved oil and gas reserves are prepared by Ryder Scott Company, L.P. Petroleum Consultants, independent petroleum engineers, utilizing oil and gas price data and cost estimates provided by Apache as Managing Partner. Asset Retirement Obligation The Partnership has obligations to remove tangible equipment and restore land or seabed at the end of oil and gas production operations. These obligations may be significant in light of the Partnership's limited operations and estimate of remaining reserves. The Partnership's removal and restoration obligations are primarily associated with plugging and abandoning wells and removal and disposal of offshore oil and gas platforms. The estimated undiscounted costs, net of salvage value, of dismantling and removing these facilities are accrued over the production life of the oil and gas property. Estimating the future asset removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as well as regulatory, political, environmental, safety and public relations considerations. In 2001, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 143 (SFAS No. 143), "Accounting for Asset Retirement Obligations." SFAS No. 143 significantly changed the method of accruing for cost, associated with the retirement of fixed asset an entity is legally obligated to incur. Primarily, the new statement requires the Partnership to record a separate liability for asset retirement obligations that represents the present value of the costs to be incurred. The separate liability is similar to the Partnership's previous estimates in that the obligations are based on expected cost estimates and expected economic lives of the asset retirements that occurs many years in the future, but the new rule now requires additional discounting assumptions to be considered by management. Revisions to the asset retirement obligation recorded upon adoption of SFAS No. 143 can potentially result from changes in the assumptions used to estimate the cash flows required to settle the obligation. Potential changes include adjustments in estimated probabilities, amounts, and timing of the settlement, as well as changes in the legal requirements of an asset retirement obligation. Any such changes that result in upward and downward revisions in the estimated cash flows will adjust the liability and the related capitalized asset on a prospective basis. The Partnership adopted this statement effective January 1, 2003 as discussed in Note 8 of Item 8 of this Form 10-K. RESULTS OF OPERATIONS NET INCOME AND REVENUE The Partnership reported net income of $3.5 million for 2002 versus $7.3 million in 2001. Net income per Investing Partner Unit declined from $4,922 in 2001 to $2,259 in 2002. Revenues decreased from $10.6 million in 2001 to $7 million in 2002. Interest income earned by the Partnership on short-term cash investments declined from last year as a result of lower interest rates and average investment balances in 2002. Natural gas sales accounted for 59 percent of the Partnership's total revenue in 2002, compared to 72 percent during 2001. 9
The Partnership's oil and gas production volume and price information is summarized in the following table: FOR THE YEAR ENDED DECEMBER 31, ----------------------------------- INCREASE 2002 2001 (DECREASE) ------------------------------------------------------ Gas volumes -- Mcf per day 3,353 4,672 (28%) Average gas price -- per Mcf $ 3.36 $ 4.51 (25%) Oil volume -- barrels per day 302 307 (2%) Average oil price -- per barrel $ 25.03 $ 25.00 -- Declines in oil and gas production can be expected in future years as a result of normal depletion. Given the small number of producing wells owned by the Partnership, and the fact that offshore wells tend to decline at a faster rate than onshore wells, the Partnership's future production will be subject to more volatility than those companies with greater reserves and longer-lived properties. It is not anticipated that the Partnership will acquire any additional exploratory leases or that significant exploratory drilling will take place on leases in which the Partnership currently holds interests. 2002 COMPARED TO 2001 OIL AND GAS SALES Natural gas sales for 2002 totaled $4.1 million, down 47 percent from 2001 on lower gas prices and production. While natural gas prices improved during the fourth quarter of 2002, a $1.15 per Mcf drop in the Partnership's average realized price from a year ago negatively impacted sales by $2 million. Natural gas production declined by 28 percent from last year, falling to 3,353 Mcf per day in 2002. The 1,319 Mcf per day decline in volume primarily reflected natural depletion. The Partnership's North Padre Island 969 production being shut-in for nearly nine months in 2002 for a dispute with a pipeline company on increased fees charged for the transportation of natural gas reduced current year sales by 426 Mcf per day, while Hurricane Isidore and Lili reduced 2002 sales by 58 Mcf per day. The North Padre Island 969 wells returned to production in late September 2002 after the Federal Energy Regulatory Commission (FERC) issued a ruling which established an unbundled gathering rate of approximately two cents per Mcf on the North Padre Island system as opposed to the 12 cents per Mcf rate demanded by the pipeline. The completion of five successful development wells at South Timbalier 295 during 2002 largely offset production declines in the field. The Partnership's crude oil sales for 2002 totaled $2.8 million, even with the prior year. A slight improvement in average realized oil prices in 2002 was offset by a two percent decline in production from a year ago. Weather-related downtime for hurricanes in 2002 drove the five barrel per day decline in production from last year. Production added through drilling at South Timbalier 295 offset natural depletion for the year. OTHER REVENUES During 2002, the Partnership recognized insurance recoveries totaling $99,300 for the estimated amount of proceeds recoupable under business interruption insurance policies. The amount reflects expected recoveries, after applicable deductibles, for the Partnership's share of lost oil and gas production resulting from hurricanes in 2002. OPERATING EXPENSES The Partnership's depreciation, depletion and amortization (DD&A) rate, expressed as a percentage of oil and gas sales, increased to 32 percent in 2002. The increase in DD&A rate from prior years reflected higher finding cost in 2002. Lease operating expense in 2002 increased approximately $96,000 from a year ago primarily as a result of higher repair and maintenance cost on platforms and compressors. Administrative expense declined seven percent from last year, dropping to $447,000. During 2002, the Partnership 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 operating expense. For comparative purposes, previously reported transportation 10
costs paid to third parties were reclassified as corresponding increases to oil and gas production revenues and operating expenses with no impact on net income. The decline in expense compared to a year ago reflected lower sales volumes in 2002. 2001 COMPARED TO 2000 OIL AND GAS SALES Natural gas sales for 2001 of $7.7 million declined 15 percent from 2000 as lower gas production more than offset the impact of higher gas prices. Gas production in 2001 decreased by 26 percent when compared to 2000, negatively impacting sales by $2.8 million. Production decreases in 2001 were attributable to natural production declines impacting all of the Partnership's properties. These decreases were partially offset by production added from drilling projects at South Timbalier 295 during 2001. The Partnership's average realized gas price increased $.60 per Mcf from last year, positively impacting sales by $1.4 million. While the Partnership's average gas price was up from the prior year, natural gas prices trended upward during most of 2001. The Partnership's crude oil sales for 2001 totaled $2.8 million, a 22 percent decrease from 2000. The average realized price for 2001 decreased $5.18 per barrel, or 17 percent, when compared to the $30.18 per barrel realized in 2000. Oil production in 2001 declined five percent from the prior year due to natural depletion. OPERATING EXPENSES The Partnership's DD&A rate, expressed as a percentage of oil and gas sales, was approximately 19 percent during 2001. The DD&A rate decreased from 2000 as a result of reserve additions recognized in 2001. Lease operating expense during 2001 of $.6 million increased by approximately $.1 million from the prior year as a result of higher repair and maintenance costs in 2001. Administrative expense declined 11 percent from 2000, while transportation cost declined from the prior year with reduced volumes. CASH FLOW, LIQUIDITY AND CAPITAL RESOURCES CAPITAL COMMITMENTS The Partnership's primary needs for cash are for operating expenses, drilling and recompletion expenditures, future dismantlement and abandonment costs, distributions to Investing Partners, and the purchase of Units offered by Investing Partners under the right of presentment. The Partnership had no outstanding debt, lease commitments or contractual obligations at December 31, 2002. During 2002, the Partnership's oil and gas property additions totaled $3.2 million. These additions primarily related to drilling projects at South Timbalier 295 where the Partnership participated in drilling six development wells of which five were completed as successful wells. The Partnership also participated in four recompletion projects at South Timbalier 295 and one at Matagorda 681/682. Capital expenditures during 2001 totaled $3 million as the Partnership participated in drilling four development wells and recompletions in South Timbalier 295, Matagorda 681/682 and East Cameron 60. During 2000, capital expenditures totaled $3.9 million as the Partnership participated in drilling five wells. Based on preliminary information provided by the operators of the properties in which the Partnership owns interests, the Partnership anticipates capital expenditures will total approximately $1 million in 2003 and will be directed primarily toward recompletion projects at South Timbalier 295. Such estimates may change based on realized oil and gas prices, drilling results, rates charged by drilling contractors or changes by the operator to the development plan. During 2002, the Partnership paid distributions to Investing Partners totaling approximately $1.1 million or $1,000 per Unit. The per Unit distribution in 2002 declined 75 percent from a year ago due to the decline in the Partnership's revenues in 2002. The amount of future distributions will be dependent on actual and expected production levels, realized and expected oil and gas prices, expected drilling and recompletion expenditures and prudent cash reserves for future dismantlement and abandonment costs that will be incurred after the Partnership's reserves are depleted. 11
The Partnership estimates that its share of undiscounted future dismantlement and abandonment costs for all of its remaining fields will total approximately $1.2 million. These expenditures will be funded by future cash flows from operations and cash held by the Partnership. Based on preliminary information from the operator, the Partnership expects that during 2003 the remaining wellbore in the East Cameron 60 field will be plugged and abandoned, and the platform removed from the site. The field has not produced since 2001. On an ongoing basis, the Partnership reviews the possible sale of lower value properties prior to incurring associated dismantlement and abandonment costs. In February 1994, an amendment to the Partnership Agreement created a right of presentment under which all Investing Partners have a limited and voluntary right to offer their Units to the Partnership twice each year to be purchased for cash. In 2002, the first right of presentment offer of $8,686 per Unit, plus interest to the date of payment, was made to Investing Partners based on a December 31, 2001 valuation date. The second right of presentment offer of $7,362 per Unit, plus interest to the date of payment, was made to the Investing Partners based on a valuation date of June 30, 2002. As a result, the Partnership acquired 25.4 Units for a total of $213,006 in cash. In 2001 and 2000, Investing Partners were paid $195,221 and $34,831, respectively, for a total of 22.2 Units. There will be two rights of presentment in 2003, but the Partnership is not in a position to predict how many Units will be presented for repurchase and cannot, at this time, determine if the Partnership will have sufficient funds available to repurchase Units. The Amended Partnership Agreement contains limitations on the number of Units that the Partnership can repurchase, including an annual limit on repurchases of 10 percent of outstanding Units. The Partnership has no obligation to repurchase any Units presented to the extent that it determines that it has insufficient funds for such repurchases. CAPITAL RESOURCES AND LIQUIDITY The Partnership's primary capital resource is net cash provided by operating activities, which totaled $4.9 million for 2002. Net cash provided by operating activities in 2002 decreased $5.3 million, or 52 percent, from a year ago with declines in oil and gas production and gas prices. Net cash provided by operating activities in 2001 declined nine percent from 2000 on declines in oil and gas production and oil prices. The Partnership's future financial condition, results of operations and cash from operating activities will largely depend upon prices received for its oil and natural gas production. A substantial portion of the Partnership'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 factors beyond the Partnership'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. With natural gas accounting for 65 percent of the Partnership's 2002 production and 55 percent of total proved reserves, on an energy equivalent basis, the Partnership is affected more by fluctuations in natural gas prices than in oil prices. While future oil and gas prices cannot be predicted, prices in early 2003 are up from the comparable period in 2002 as a result of political tensions and lower average temperatures throughout much of the United States. The Partnership's oil and gas reserves and production will also significantly impact future results of operations and cash from operating activities. The Partnership's production is subject to fluctuations in response to remaining quantities of oil and gas reserves, weather, pipeline capacity, consumer demand, mechanical performance and workover, recompletion and drilling activities. Declines in oil and gas production can be expected in future years as a result of normal depletion and the Partnership not participating in acquisition or exploration activities. Based on production estimates from independent engineers and current market conditions, the Partnership expects it will be able to meet its liquidity needs for routine operations in the foreseeable future. The Partnership will reduce capital expenditures and distributions to partners as cash from operating activities decline. In the event that future short-term operating cash requirements are greater than the Partnership's financial resources, the Partnership may seek short-term, interest-bearing advances from the Managing Partner as needed. The Managing Partner, however, is not obligated to make loans to the Partnership. During 2002, the Partnership used available cash to reduce accrued operating expenses and the payable to Apache. Lower accrued development cost at December 31, 2002 reflected reduced activity since drilling was completed in early November at South Timbalier 295. 12
OFF-BALANCE SHEET ARRANGEMENTS The Partnership does not currently utilize any off-balance sheet arrangements with unconsolidated entities to enhance liquidity and capital resource positions, or any other purpose. Any future transactions involving off-balance sheet arrangements will be fully scrutinized by the Managing Partner and disclosed by the Partnership. ITEM 7A. MARKET RISK COMMODITY RISK The Partnership's major market risk exposure is in the pricing applicable to its oil and gas production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot prices applicable to its natural gas production. Prices received for oil and gas production have been and remain volatile and unpredictable. During 2002, monthly oil price realizations ranged from a low of $18.68 per barrel to a high of $28.46 per barrel. Gas price realizations ranged from a monthly low of $2.25 per Mcf to a monthly high of $4.35 per Mcf during the same period. Both oil and gas prices trended upward during most of 2002, with the Partnership realizing its highest prices of the year in the fourth quarter and its lowest prices in the first quarter. Based on the Partnership's average daily production for 2002, a $1.00 per barrel change in the weighted average realized price of oil would have increased or decreased revenues for the year by approximately $110,000 and a $.10 per Mcf change in the weighted average realized price of natural gas would have increased or decreased revenues for the year by approximately $122,000. The Partnership did not use derivative financial instruments or otherwise engage in hedging activities during the three-year period ended December 31, 2002. Due to the volatility of commodity prices, the Partnership is not in a position to predict future oil and gas prices. If oil and gas prices decline significantly in the future, even if only for a short period of time, it is possible that non-cash write-downs of the Partnership's oil and gas properties could occur under the full cost accounting rules of the SEC. Under these rules, the Partnership reviews the carrying value of its proved oil and gas properties each quarter to ensure the capitalized costs of proved oil and gas properties, net of accumulated depreciation, depletion and amortization 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. 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. FORWARD-LOOKING STATEMENTS AND RISK Certain statements in this report, including statements of the future plans, objectives, and expected performance of the Partnership, are forward-looking statements that are dependent upon certain events, risks and uncertainties that may be outside the Partnership's control, and which could cause actual results to differ materially from those anticipated. Some of these include, but are not limited to, the market prices of oil and gas, economic and competitive conditions, inflation rates, legislative and regulatory changes, financial market conditions, political and economic uncertainties of foreign governments, future business decisions, and other uncertainties, all of which are difficult to predict. There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and in projecting future rates of production and the timing of development expenditures. The total amount or timing of actual future production may vary significantly from reserves and production estimates. The drilling of development wells can involve risks, including those related to timing and cost overruns. Lease and rig availability, complex geology and other factors can affect these risks. Fluctuations in oil and gas prices, or a prolonged period of low prices, may substantially adversely affect the Partnership's financial position, results of operations and cash flows. 13
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA APACHE OFFSHORE INVESTMENT PARTNERSHIP INDEX TO FINANCIAL STATEMENTS PAGE NUMBER ------ Report of Independent Auditors -- 2002................................................................. 15 Report of Independent Public Accountants -- 2001 and 2000.............................................. 16 Statement of Consolidated Income for each of the three years in the period ended December 31, 2002..... 17 Statement of Consolidated Cash Flows for each of the three years in the period ended December 31, 2002 ................................................................................. 18 Consolidated Balance Sheet as of December 31, 2002 and 2001............................................ 19 Statement of Consolidated Changes in Partners' Capital for each of the three years in the period ended December 31, 2002............................................................................ 20 Notes to Consolidated Financial Statements............................................................. 21 Supplemental Oil and Gas Disclosures................................................................... 29 Supplemental Quarterly Financial Data................................................................ 31 Schedules -- All 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 financial statements or related notes thereto. 14
REPORT OF INDEPENDENT AUDITORS To the Partners of Apache Offshore Investment Partnership: We have audited the accompanying consolidated balance sheet of Apache Offshore Investment Partnership (a Delaware general partnership) and subsidiary as of December 31, 2002, and the related consolidated statements of income, cash flows and changes in partners' capital for the year then ended. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these financial statements based on our audit. The financial statements of Apache Offshore Investment Partnership as of December 31, 2001, and for each of the two years in the period then ended, were audited by other auditors who have ceased operations and whose report, dated March 1, 2002, expressed an unqualified opinion on those financial statements. We conducted our audit in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Apache Offshore Investment Partnership as of December 31, 2002, and the results of its operations and its cash flows for the year then ended in conformity with accounting principles generally accepted in the United States. As discussed above, the financial statements of Apache Offshore Investment Partnership as of December 31, 2001, and for each of the two years in the period then ended, were audited by other auditors who have ceased operations. As described in Note 2, 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 2 that were applied to revise the 2001 and 2000 consolidated statement of operations. In our opinion, such adjustments are appropriate and have been properly applied. However, we were not engaged to audit, review, or apply any procedures to the 2001 and 2000 financial statements of Apache Offshore Investment Partnership other than with respect to such adjustments and, accordingly, we do not express an opinion or any other form of assurance on the 2001 and 2000 financial statements taken as a whole. ERNST & YOUNG LLP Houston, Texas March 14, 2003 15
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Partners of Apache Offshore Investment Partnership: We have audited the accompanying consolidated balance sheet of Apache Offshore Investment Partnership (a Delaware general partnership) and subsidiary as of December 31, 2001 and 2000, and the related consolidated statements of income, cash flows and changes in partners' capital for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of the Partnership'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 Offshore Investment Partnership as of December 31, 2001 and 2000, and the results of its operations and its 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. ARTHUR ANDERSEN LLP Houston, Texas March 1, 2002 THIS IS A COPY OF AN ACCOUNTANT'S REPORT PREVIOUSLY ISSUED BY ARTHUR ANDERSEN LLP, AND HAS NOT BEEN REISSUED BY ARTHUR ANDERSEN. SEE PART II, ITEM 9 FOR FURTHER INFORMATION. 16
APACHE OFFSHORE INVESTMENT PARTNERSHIP STATEMENT OF CONSOLIDATED INCOME FOR THE YEAR ENDED DECEMBER 31, ----------------------------------------------------- 2002 2001 2000 --------------- --------------- ---------------- REVENUES: Oil and gas sales $ 6,867,523 $ 10,494,911 $ 12,640,530 Interest income 19,199 75,126 123,820 Other revenue 99,300 -- -- --------------- --------------- ---------------- 6,986,022 10,570,037 12,764,350 --------------- --------------- ---------------- OPERATING EXPENSES: Depreciation, depletion and amortization 2,181,189 2,042,461 2,971,525 Lease operating costs 731,416 635,049 532,433 Gathering and transportation expense 102,698 148,282 223,673 Administrative 447,000 480,000 540,000 --------------- --------------- ---------------- 3,462,303 3,305,792 4,267,631 --------------- --------------- ---------------- NET INCOME $ 3,523,719 $ 7,264,245 $ 8,496,719 =============== =============== =============== NET INCOME ALLOCATED TO: Managing Partner $ 1,035,747 $ 1,730,985 $ 2,102,310 Investing Partners 2,487,972 5,533,260 6,394,409 --------------- --------------- ---------------- $ 3,523,719 $ 7,264,245 $ 8,496,719 =============== =============== =============== NET INCOME PER INVESTING PARTNER UNIT $ 2,259 $ 4,922 $ 5,654 =============== =============== =============== WEIGHTED AVERAGE INVESTING PARTNER UNITS OUTSTANDING 1,101.5 1,124.1 1,130.9 =============== =============== =============== The accompanying notes to financial statements are an integral part of this statement 17
APACHE OFFSHORE INVESTMENT PARTNERSHIP STATEMENT OF CONSOLIDATED CASH FLOWS FOR THE YEAR ENDED DECEMBER 31, ---------------------------------------------------- 2002 2001 2000 --------------- --------------- --------------- CASH FLOWS FROM OPERATING ACTIVITIES: Net income $ 3,523,719 $ 7,264,245 $ 8,496,719 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion and amortization 2,181,189 2,042,461 2,971,525 Changes in operating assets and liabilities: (Increase) decrease in accrued revenues receivable (322,209) 731,343 (388,472) Increase (decrease) in accrued operating expenses (63,706) 27,400 (87,287) Increase (decrease) in payable to Apache Corporation (392,810) 125,507 192,624 --------------- --------------- --------------- Net cash provided by operating activities 4,926,183 10,190,956 11,185,109 --------------- --------------- --------------- CASH FLOWS FROM INVESTING ACTIVITIES: Additions to oil and gas properties (3,248,104) (3,030,327) (3,882,050) Proceeds from sales of oil and gas properties -- -- -- Increase (decrease) in accrued development costs (362,745) (96,442) (85,851) --------------- --------------- --------------- Net cash used in investing activities (3,610,849) (3,126,769) (3,967,901) --------------- --------------- --------------- CASH FLOWS FROM FINANCING ACTIVITIES: Repurchase of Partnership Units (213,006) (195,221) (34,831) Distributions to Investing Partners (1,095,189) (4,501,620) (6,500,003) Distributions to Managing Partner, net (974,634) (1,926,838) (1,988,308) --------------- --------------- --------------- Net cash used in financing activities (2,282,829) (6,623,679) (8,523,142) --------------- --------------- --------------- NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (967,495) 440,508 (1,305,934) CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR 1,883,386 1,442,878 2,748,812 --------------- --------------- --------------- CASH AND CASH EQUIVALENTS, END OF YEAR $ 915,891 $ 1,883,386 $ 1,442,878 =============== =============== =============== The accompanying notes to financial statements are an integral part of this statement 18
APACHE OFFSHORE INVESTMENT PARTNERSHIP CONSOLIDATED BALANCE SHEET DECEMBER 31, ---------------------------------- 2002 2001 --------------- --------------- ASSETS CURRENT ASSETS: Cash and cash equivalents $ 915,891 $ 1,883,386 Accrued revenues receivable 615,164 292,955 --------------- --------------- 1,531,055 2,176,341 --------------- --------------- OIL AND GAS PROPERTIES, on the basis of full cost accounting: Proved properties 179,656,827 176,408,723 Less -- Accumulated depreciation, depletion and amortization (171,353,743) (169,172,554) --------------- --------------- 8,303,084 7,236,169 --------------- --------------- $ 9,834,139 $ 9,412,510 =============== =============== LIABILITIES AND PARTNERS' CAPITAL CURRENT LIABILITIES: Accrued development costs $ 51,813 $ 414,558 Accrued operating expenses 48,478 112,184 Payable to Apache Corporation 123,952 516,762 --------------- --------------- 224,243 1,043,504 --------------- --------------- COMMITMENTS AND CONTINGENCIES (Note 7) PARTNERS' CAPITAL: Managing Partner 217,341 156,228 Investing Partners (1,084.9 and 1,110.3 Units outstanding, respectively) 9,392,555 8,212,778 --------------- --------------- 9,609,896 8,369,006 --------------- --------------- $ 9,834,139 $ 9,412,510 =============== =============== The accompanying notes to financial statements are an integral part of this statement 19
APACHE OFFSHORE INVESTMENT PARTNERSHIP STATEMENT OF CONSOLIDATED CHANGES IN PARTNERS' CAPITAL MANAGING INVESTING PARTNER PARTNERS TOTAL -------------- --------------- --------------- BALANCE, DECEMBER 31, 1999 $ 238,079 $ 7,516,784 $ 7,754,863 Distributions, net (1,988,308) (6,500,003) (8,488,311) Repurchase of Partnership Units -- (34,831) (34,831) Net income 2,102,310 6,394,409 8,496,719 -------------- --------------- --------------- BALANCE, DECEMBER 31, 2000 352,081 7,376,359 7,728,440 Distributions, net (1,926,838) (4,501,620) (6,428,458) Repurchase of Partnership Units -- (195,221) (195,221) Net income 1,730,985 5,533,260 7,264,245 -------------- --------------- --------------- BALANCE, DECEMBER 31, 2001 156,228 8,212,778 8,369,006 Distributions, net (974,634) (1,095,189) (2,069,823) Repurchase of Partnership Units -- (213,006) (213,006) Net income 1,035,747 2,487,972 3,523,719 -------------- --------------- --------------- BALANCE, DECEMBER 31, 2002 $ 217,341 $ 9,392,555 $ 9,609,896 =============== =============== =============== The accompanying notes to financial statements are an integral part of this statement 20
APACHE OFFSHORE INVESTMENT PARTNERSHIP NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (1) ORGANIZATION NATURE OF OPERATIONS -- Apache Offshore Investment Partnership was formed as a Delaware general partnership on October 31, 1983, consisting of Apache Corporation (Apache) as Managing Partner and public investors as Investing Partners. The general partnership invested its entire capital in Apache Offshore Petroleum Limited Partnership, a Delaware limited partnership formed to conduct oil and gas exploration, development and production operations. The accompanying financial statements include the accounts of both the limited and general partnerships. Apache is the general partner of both the limited and general partnerships, and holds slightly less than five percent of the 1,084.9 Investing Partner Units (Units) outstanding at December 31, 2002. The term "Partnership", as used hereafter, refers to the limited or the general partnership, as the case may be. The Partnership purchased, at cost, an 85 percent interest in offshore leasehold interests acquired by Apache as a co-venturer in a series of oil and gas exploration, development and production activities on 87 federal lease tracts in the Gulf of Mexico, offshore Louisiana and Texas. The remaining 15 percent interest was purchased by an affiliated partnership or retained by Apache. The Partnership acquired an increased net revenue interest in Matagorda Island Blocks 681 and 682 in November 1992, when the Partnership and Apache formed a joint venture to acquire a 92.6 percent working interest in the blocks. Since inception, the Partnership has participated in 14 federal offshore lease sales in which 49 prospects were acquired (through the same date 42 of those prospects have been surrendered/sold). The Partnership's working interests in the seven remaining venture prospects range from 6.29 percent to 9.44 percent. As of December 31, 2002, the Partnership held a remaining interest in 12 tracts acquired through federal lease sales and two tracts obtained through farmout arrangements. The Partnership's future financial condition and results of operations will depend largely upon prices received for its oil and natural gas production and the costs of acquiring, finding, developing and producing reserves. A substantial portion of the Partnership'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 factors beyond the Partnership'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. With natural gas accounting for 65 percent of the Partnership's 2002 production and 55 percent of total proved reserves, on an energy equivalent basis, the Partnership is affected more by fluctuations in natural gas prices than in oil prices. Under the terms of the Partnership Agreements, the Investing Partners receive 80 percent and Apache receives 20 percent of revenue. Lease operating, gathering and transportation and administrative expenses are allocated to the Investing Partners and Apache in the same proportion as revenues. The Investing Partners receive 100 percent of the interest income earned on short-term cash investments. The Investing Partners generally pay for 90 percent and Apache generally pays for 10 percent of exploration and development costs and expenses incurred by the Partnership. However, intangible drilling costs, interest costs and fees or expenses related to the loans incurred by the Partnership are allocated 99 percent to the Investing Partners and one percent to Apache until such time as the amount so allocated to the Investing Partners equals 90 percent of the total amount of such costs, including such costs incurred by Apache prior to the formation of the Partnerships. 21
APACHE OFFSHORE INVESTMENT PARTNERSHIP NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) RIGHT OF PRESENTMENT -- An amendment to the Partnership Agreements adopted in February 1994, created a right of presentment under which all Investing Partners have a limited and voluntary right to offer their Units to the Partnership twice each year to be purchased for cash. During 2002, the Investing Partners sold a total of 25.4 Units to the Partnership for a total of $213,006 in cash. The first right of presentment was based upon a valuation date of December 31, 2001 for a purchase price of $8,686 per Unit, plus interest to the date of payment. The second presentment offer was based on a valuation date of June 30, 2002 for a purchase price of $7,362 per Unit, plus interest to the payment date. During 2001 and 2000, the Partnership paid the Investing Partners $195,221 and $34,831, respectively, to acquire a total of 22.2 Units. The Partnership is not in a position to predict how many Units will be presented for repurchase during 2003, however, no more than 10 percent of the outstanding Units may be purchased under the right of presentment in any year. The Partnership has no obligation to purchase any Units presented to the extent that it determines that it has insufficient funds for such purchases. The table below sets forth the total repurchase price and the repurchase price per Unit for all outstanding Units at each presentment period, based on the right of presentment valuation formula defined in the amendment to the Partnership Agreement. The right of presentment offers, made twice annually, are based on a discounted Unit value formula. The discounted Unit value will be not less than the Investing Partner's share of: (a) the sum of (i) 70 percent of the discounted estimated future net revenues from proved reserves, discounted at a rate of 1.5 percent over prime or First National Bank of Chicago's base rate in effect at the time the calculation is made, (ii) cash on hand, (iii) prepaid expenses, (iv) accounts receivable less a reasonable reserve for doubtful accounts, (v) oil and gas properties other than proved reserves at cost less any amounts attributable to drilling and completion costs incurred by the Partnership and included therein, and (vi) the book value of all other assets of the Partnership, less the debts, obligations and other liabilities of all kinds (including accrued expenses) then allocable to such interest in the Partnership, all determined as of the valuation date, divided by (b) the number of Units, and fractions thereof, outstanding as of the valuation date. The discounted Unit value does not purport to be, and may be substantially different from, the fair market value of a Unit. RIGHT OF PRESENTMENT TOTAL REPURCHASE REPURCHASE PRICE VALUATION DATE PRICE PER UNIT ------------------------- ------------------- -------------------- December 31, 1999 $ 12,314,303 $ 8,874 June 30, 2000 10,934,084 6,431 December 31, 2000 13,460,392 9,928 June 30, 2001 13,984,141 10,460 December 31, 2001 9,644,386 8,686 June 30, 2002 9,157,842 7,362 INVESTING PARTNER UNITS OUTSTANDING: 2002 2001 2000 ------------- ------------- ------------- Balance, beginning of year 1,110.3 1,128.5 1,132.5 Repurchase of Partnership Units (25.4) (18.2) (4.0) ------------- ------------- ------------- Balance, end of year 1,084.9 1,110.3 1,128.5 ============= ============= ============= CAPITAL CONTRIBUTIONS -- A total of $85,000 per Unit, or approximately 57 percent, of investor subscription had been called through December 31, 2002. The Partnership determined the full purchase price of $150,000 per Unit was not needed, and upon completion of the last subscription call in November 1989, released the Investing Partners from their remaining liability. As a result of investors defaulting on cash calls and repurchases under the presentment offer discussed above, the original 1,500 Units have been reduced to 1,084.9 Units at December 31, 2002. 22
APACHE OFFSHORE INVESTMENT PARTNERSHIP NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) (2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES STATEMENT PRESENTATION -- The accounts of the Partnerships are maintained on a tax basis method of accounting in accordance with the Articles of Partnership and methods of reporting allowed for federal income tax purposes. The consolidated financial statements included in reports that the Partnership files with the Securities and Exchange Commission (SEC) are required to be prepared in conformity with generally accepted accounting principles. Accordingly, the accompanying consolidated financial statements include adjustments to convert from tax basis to the accrual basis method in conformity with accounting principles generally accepted in the United States. The accompanying consolidated financial statements include the accounts of Apache Offshore Investment Partnership and Apache Offshore Petroleum Limited Partnership after elimination of intercompany balances and transactions. CASH EQUIVALENTS -- The Partnership 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 market. OIL AND GAS PROPERTIES -- The Partnership uses the full cost method of accounting for its investment in oil and gas properties for financial statement purposes. Under this method, the Partnership capitalizes all acquisition, exploration and development costs incurred for the purpose of finding oil and gas reserves. The amounts capitalized under this method include dry hole costs, leasehold costs, engineering, geological, exploration, development and other similar costs. Costs associated with production and administrative functions are expensed in the period incurred. Unless a significant portion of the Partnership's reserve volumes are sold (greater than 25 percent), proceeds from the sale of oil and gas properties are accounted for as reductions to capitalized costs, and gains or losses are not recognized. Capitalized costs of oil and gas properties are amortized on the future gross revenue method whereby depreciation, depletion and amortization (DD&A) expense is computed quarterly by dividing current period oil and gas sales by estimated future gross revenue from proved oil and gas reserves (including current period oil and gas sales) and applying the resulting rate to the net cost of evaluated oil and gas properties, including estimated future development costs. The amortizable base includes estimated dismantlement, restoration and abandonment costs, net of estimated salvage values. Beginning in 2003, the Partnership changed its method of accounting for dismantlement, restoration and abandonment cost as described in Note 8. The Partnership limits the capitalized costs of proved oil and gas properties, net of accumulated DD&A, to the 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, if any. If capitalized costs exceed this limit, the excess is charged to DD&A expense. The Partnership has not recorded any write-downs of capitalized costs for the three years presented. Given the volatility of oil and gas prices, it is reasonably possible that the Partnership'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. 23
APACHE OFFSHORE INVESTMENT PARTNERSHIP NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) REVENUE RECOGNITION -- The Partnership uses the sales method of accounting for natural gas revenues. Under this method, revenues are recognized based on actual volumes of gas sold to purchasers. The volumes of gas sold may differ from the volumes to which the Partnership is entitled based on its interests in the properties. These differences create imbalances that are recognized as a liability only when the estimated remaining reserves will not be sufficient to enable the underproduced owner to recoup its entitled share through production. As of December 31, 2002 and 2001, the Partnership did not have any liabilities for gas imbalances in excess of remaining reserves. No receivables are recorded for those wells where the Partnership has taken less than its share of production. Gas imbalances are reflected as adjustments to proved gas revenues and future cash flows in the unaudited supplemental oil and gas disclosures. Adjustments for gas imbalances totaled less than one percent of the Partnership's proved gas reserves at December 31, 2002, 2001 and 2000. NET INCOME PER INVESTING UNIT -- The net income per Investing Partner Unit is calculated by dividing the aggregate Investing Partners' net income for the period by the number of weighted average Investing Partner Units outstanding for that period. INCOME TAXES -- The profit or loss of the Partnership for federal income tax reporting purposes is included in the income tax returns of the partners. Accordingly, no recognition has been given to income taxes in the accompanying financial statements. USE OF ESTIMATES -- The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and 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 a reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. The Partnership bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances. Actual results could differ from those estimates. 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 unaudited "Supplemental Oil and Gas Disclosures" below. PAYABLE TO APACHE -- The payable to Apache represents the net result of the Investing Partners' revenue and expenditure transactions in the current month. Generally, this amount will be transferred to Apache in the month after the Partnership's transactions are processed and the net results from operations are determined. MAINTENANCE AND REPAIRS -- Maintenance and repairs are charged to expense as incurred. 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 income. 24
APACHE OFFSHORE INVESTMENT PARTNERSHIP NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) (3) COMPENSATION TO APACHE Apache is entitled to the following types of compensation and reimbursement for costs and expenses. TOTAL REIMBURSED BY THE INVESTING PARTNERS FOR THE YEAR ENDED DECEMBER 31, ------------------------------------------ 2002 2001 2000 ----------- ----------- ----------- (In thousands) a. Apache is reimbursed for general, administrative and overhead expenses incurred in connection with the management and operation of the Partnership's business $ 358 $ 384 $ 432 =========== =========== =========== b. Apache is reimbursed for development overhead costs incurred in the Partnership's operations. These costs are based on development activities and are capitalized to oil and gas properties $ 129 $ 147 $ 190 =========== =========== =========== Apache operates certain Partnership properties. Billings to the Partnership are made on the same basis as to unaffiliated third parties or at prevailing industry rates. (4) OIL AND GAS PROPERTIES The following tables contain direct cost information and changes in the Partnership's oil and gas properties for each of the years ended December 31. All costs of oil and gas properties are currently being amortized. 2002 2001 2000 ------------- ------------- ------------- (In thousands) Oil and Gas Properties Balance, beginning of year $ 176,409 $ 173,378 $ 169,496 Costs incurred during the year: Development -- Investing Partners 3,174 2,962 3,696 Managing Partner 74 69 186 ------------- ------------- ------------- Balance, end of year $ 179,657 $ 176,409 $ 173,378 ============= ============= ============= 25
APACHE OFFSHORE INVESTMENT PARTNERSHIP NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) MANAGING INVESTING PARTNER PARTNERS TOTAL ------------- ------------- ------------- (In thousands) Accumulated Depreciation, Depletion and Amortization Balance, December 31, 1999 $ 20,298 $ 143,860 $ 164,158 Provision 167 2,805 2,972 ------------- ------------- ------------- Balance, December 31, 2000 20,465 146,665 167,130 Provision 116 1,927 2,043 ------------- ------------- ------------- Balance, December 31, 2001 20,581 148,592 169,173 Provision 101 2,080 2,181 ------------- ------------- ------------- Balance, December 31, 2002 $ 20,682 $ 150,672 $ 171,354 ============= ============= ============= The Partnership's aggregate DD&A expense as a percentage of oil and gas sales for 2002, 2001 and 2000 was 32 percent, 19 percent and 24 percent, respectively. (5) MAJOR CUSTOMER AND RELATED PARTIES INFORMATION Revenues received from major third party customers that exceeded 10 percent of oil and gas sales are discussed below. No other third party customers individually accounted for more than ten percent of oil and gas sales. Sales to Cinergy Marketing & Trading, LLC (Cinergy) accounted for 60 percent, 73 percent, and 71 percent of the Partnership's oil and gas sales in 2002, 2001 and 2000, respectively. In 1998, Apache formed a strategic alliance with Cinergy Corp. to market substantially all of Apache's natural gas production from North America and sold its 57 percent interest in Producers Energy Marketing LLC (ProEnergy) to Cinergy Corp. In July 1998, in connection with the sale of its interest, Apache entered into a gas purchase agreement with Cinergy to market most of Apache's North American natural gas production for 10 years, with an option, after prior notice, to terminate after six years. Apache also sells most of the Partnership's natural gas production to Cinergy under the gas purchase agreement. Since 2001, Apache has been involved in an arbitration proceeding with Cinergy on issues arising from the gas sales agreement. Apache continues to market most of the Partnership's gas production through Cinergy; however, Apache is actively discussing with Cinergy its gas marketing relationship with Cinergy and a resolution of the related disputes. The Partnership does not expect the final resolution of these disputes to have a material effect on its financial position or future sales. The prices the Partnership receives for its gas production, in the opinion of Apache, approximate market prices. Apache Crude Oil Marketing, Inc., a wholly-owned subsidiary of Apache, purchased oil and condensate from the Partnership which accounted for approximately 17 percent, 26 percent and 12 percent of the Partnership's total oil and gas sales in 2002, 2001 and 2000, respectively. The prices the Partnership received for these sales were based on third-party pricing indexes, and in the opinion of Apache, comparable to prices that would have been received from a non-affiliated party. Sales of oil and condensate to Chevron Texaco accounted for 21 percent of the Partnership's oil and gas sales in 2002 and sales to Williams Energy Marketing & Trading Company accounted for 10 percent of the Partnership's oil and gas sales in 2000. Effective November 1992, with Apache's and the Partnership's acquisition of an additional net revenue interest in Matagorda Island Blocks 681 and 682, a wholly-owned subsidiary of Apache purchased from Shell Oil Company (Shell) a 14.4 mile natural gas and condensate pipeline connecting Matagorda Island Block 681 to onshore markets. The Partnership paid the Apache subsidiary transportation fees totaling $43,785 in 2002, $45,147 in 2001 and $60,690 in 2000 for the Partnership's share of gas. The fees were at the same rates and terms as previously paid to Shell. 26
APACHE OFFSHORE INVESTMENT PARTNERSHIP NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) The Partnership'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. The Partnership has not experienced material credit losses on such sales. (6) FINANCIAL INSTRUMENTS The carrying amount of cash and cash equivalents, accrued revenues receivables and accrued costs included in the accompanying balance sheet approximated their fair values at December 31, 2002 and 2001 due to their short maturities. The Partnership did not use derivative financial instruments or otherwise engage in hedging activities during the three-year period ended December 31, 2002. (7) COMMITMENTS AND CONTINGENCIES Litigation -- The Partnership is involved in litigation and is subject to governmental and regulatory controls arising in the ordinary course of business. It is the opinion of the Apache's management that all claims and litigation involving the Partnership are not likely to have a material adverse effect on its financial position or results of operations. Environmental -- The Partnership, as an owner or lessee of interests in oil and gas properties, is subject to various federal, 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. Apache maintains insurance coverage on the Partnership's properties, which it believes, is customary in the industry, although it is not fully insured against all environmental risks. (8) NEW ACCOUNTING PRONOUNCEMENTS In 2001, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards (SFAS) No. 143 "Accounting for Asset Retirement Obligations." SFAS 143 addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. This statement requires companies to record the fair value of legal obligations associated with the retirement of tangible long-lived assets in the period in which it is incurred. The liability is capitalized as part of the related long-lived asset's carrying amount. Over time, accretion of the liability is recognized as an operating expense and the capitalized cost is depreciated over the expected useful life of the related asset. The Partnership's asset retirement obligations relate primarily to the plugging, dismantlement, removal, site reclamation and similar activities of its oil and gas assets. Prior to adoption of this statement, such obligations were accrued ratably over the productive lives of the assets through its depreciation, depletion and amortization for oil and gas properties without recording a separate liability for such amounts. Effective January 1, 2003, the Partnership adopted SFAS 143 which resulted in an increase to net oil and gas properties of $1.1 million and additional liabilities related to asset retirement obligations of $.8 million. These entries reflect the asset retirement obligation of the Partnership had the provisions of SFAS 143 been applied since inception. This resulted in a cumulative-effect increase in net income of $.3 million. (9) INSURANCE RECOVERIES During 2002, the Partnership recognized insurance recoveries totaling $99,300 for the estimated amount of proceeds recoupable under business interruption insurance policies. The estimated recoveries are included in other revenue in the accompanying Statement of Consolidated Income and reflect expected recoveries for the Partnership's share of lost oil and gas production resulting from hurricanes in 2002. 27
APACHE OFFSHORE INVESTMENT PARTNERSHIP NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) (10) TAX-BASIS FINANCIAL INFORMATION A reconciliation of ordinary income for federal income tax reporting purposes to net income under accounting principles generally accepted in the United States is as follows: 2002 2001 2000 ------------ ------------ ------------ Net partnership ordinary income for federal income tax reporting purposes $ 2,426,766 $ 6,199,485 $ 7,106,780 Plus: Items of current (income) expense for tax reporting purposes only -- Intangible drilling cost 2,638,051 2,457,181 3,358,567 (Gain) on disposition of equipment -- (258,053) -- Tax depreciation 640,091 908,093 1,002,897 ------------ ------------ ------------ 3,278,142 3,107,221 4,361,464 ------------ ------------ ------------ Less: full cost DD&A expense (2,181,189) (2,042,461) (2,971,525) ------------ ------------ ------------ Net income $ 3,523,719 $ 7,264,245 $ 8,496,719 ============ ============ ============ The Partnership's tax bases in net oil and gas properties at December 31, 2002 and 2001 was $2,221,960 and $1,074,660, respectively, lower than carrying value of oil and gas properties under full cost accounting. The difference reflects the timing deductions for depreciation, depletion and amortization and intangible drilling costs. For federal income tax reporting, the Partnership had capitalized syndication cost of $8,660,878 at December 31, 2002 and 2001. The Partnership's liabilities for each of the two years ended December 31, 2002 were the same for federal income tax reporting purposes as reported under accounting principles generally accepted in the United States. 28
APACHE OFFSHORE INVESTMENT PARTNERSHIP SUPPLEMENTAL OIL AND GAS DISCLOSURES (UNAUDITED) OIL AND GAS RESERVE INFORMATION -- Proved oil and gas reserve quantities are based on estimates prepared by Ryder Scott Company, L.P., Petroleum Consultants, independent petroleum engineers, in accordance with guidelines established by the SEC. These reserves are subject to revision due to the inherent imprecision in estimating reserves, and are revised as additional information becomes available. All the Partnership's reserves are located offshore Texas and Louisiana. There are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and timing of development expenditures. The following reserve data represents estimates only and should not be construed as being exact. (Oil in Mbbls and gas in MMcf) 2002 2001 2000 ------------------ ----------------- --------------------- OIL GAS OIL GAS OIL GAS ------- -------- ------- ------- -------- ---------- Proved Reserves Beginning of year 885 7,075 883 8,080 687 8,992 Extensions, discoveries and other additions 204 389 155 697 239 747 Revisions of previous estimates (130) 99 (41) 3 76 661 Production (110) (1,224) (112) (1,705) (119) (2,320) -------- -------- -------- -------- --------- --------- End of year 849 6,339 885 7,075 883 8,080 ======== ======== ======== ======== ========= ========= Proved Developed Beginning of year 767 6,685 736 7,462 613 8,679 ======== ======== ======== ======== ========= ========= End of year 849 6,230 767 6,685 736 7,462 ======== ======== ======== ======== ========= ========= 29
APACHE OFFSHORE INVESTMENT PARTNERSHIP SUPPLEMENTAL OIL AND GAS DISCLOSURES - (CONTINUED) (UNAUDITED) FUTURE NET CASH FLOWS -- The following table sets forth unaudited information concerning future net cash flows from proved oil and gas reserves. Future cash inflows are based on year-end prices. Operating costs and future development costs are based on current costs with no escalation. As the Partnership pays no income taxes, estimated future income tax expenses are omitted. This information does not purport to present the fair value of the Partnership's oil and gas assets, but does present a standardized disclosure concerning possible future net cash flows that would result under the assumptions used. Discounted Future Net Cash Flows Relating to Proved Reserves DECEMBER 31, ------------------------------------------------ 2002 2001 2000 ------------- ------------- ------------- (In thousands) Future cash inflows $ 56,471 $ 36,604 $ 104,319 Future production costs (4,623) (4,440) (3,705) Future development costs (4,115) (4,937) (5,958) ------------- ------------- ------------- Net cash flows 47,733 27,227 94,656 10 percent annual discount rate (16,908) (9,794) (29,333) ------------- ------------- ------------- Discounted future net cash flows $ 30,825 $ 17,433 $ 65,323 ============= ============= ============= The following table sets forth the principal sources of change in the discounted future net cash flows: