SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 ---------- FORM 10-K (Mark One) [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 2001 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 0-7406 PRIMEENERGY CORPORATION (Exact name of registrant as specified in its charter) DELAWARE 84-0637348 (state or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) ONE LANDMARK SQUARE 06901 STAMFORD, CONNECTICUT (Zip Code) (Address of principal executive offices) Registrant's telephone number, including area code: (203) 358-5700 Securities registered pursuant to Section 12(b) of the Act: NONE Securities registered pursuant to Section 12(g) of the Act: COMMON STOCK, PAR VALUE $.10 PER SHARE (Title of Class) Indicate whether Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ] Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-B is not contained herein, and will not be contained, to the best of Registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ] The Registrant's revenues for its most recent fiscal year were $42,408,000. The aggregate market value of the voting stock of the Registrant held by non-affiliates, computed on the average bid and asked prices of such stock in the over-the-counter market, as of March 25, 2002, was $6,816,007. The number of shares outstanding of each class of the Registrant's Common Stock as of March 25, 2002 was: Common Stock, $0.10 par value, 3,763,151. DOCUMENTS INCORPORATED BY REFERENCE Portions of the Registrant's proxy statement to be furnished to stockholders in connection with its Annual Meeting of Stockholders to be held in June, 2002, are incorporated by reference in Part III hereof. Transitional Small business Disclosure Format (check one) Yes No X --- ---
PRIMEENERGY CORPORATION FORM 10-K ANNUAL REPORT FOR THE FISCAL YEAR ENDED DECEMBER 31, 2001 PART I ITEM 1. DESCRIPTION OF BUSINESS. GENERAL This report contains forward-looking statements that are based on management's current expectations, estimates and projections. Words such as "expects," "anticipates," "intends," "plans," "believes," "projects" and "estimates," and variations of such words and similar expressions are intended to identify such forward-looking statements. These statements constitute "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, and are subject to the safe harbors created thereby. These statements are not guarantees of future performance and involve risks and uncertainties and are based on a number of assumptions that could ultimately prove inaccurate and, therefore, there can be no assurance that they will prove to be accurate. Actual results and outcomes may vary materially from what is expressed or forecast in such statements due to various risks and uncertainties. These risks and uncertainties include, among other things, volatility of oil and gas prices, competition, risks inherent in the Company's oil and gas operations, the inexact nature of interpretation of seismic and other geological and geophysical data, imprecision of reserve estimates, the Company's ability to replace and expand oil and gas reserves, and such other risks and uncertainties described from time to time in the Company's periodic reports and filings with the Securities and Exchange Commission. Accordingly, stockholders and potential investors are cautioned that certain events or circumstances could cause actual results to differ materially from those projected. PrimeEnergy Corporation (the "Company") was organized in March, 1973, under the laws of the State of Delaware. The Company is engaged generally in the oil and gas business through the acquisition, exploration, development, and production of crude oil and natural gas. The Company's properties are located primarily in Texas, Oklahoma, West Virginia and Louisiana. The Company's wholly-owned subsidiary, PrimeEnergy Management Corporation ("PEMC"), acts as the managing general partner in 45 oil and gas limited partnerships (the "Partnerships") of which four are publicly held, and acts as the managing trustee of two asset and income business trusts ("the Trusts"). The Company, through its wholly-owned subsidiaries Prime Operating Company, Southwest Oilfield Construction Company, Eastern Oil Well Service Company and EOWS Midland Company, acts as operator and provides well servicing support operations for many of the oil and gas wells in which the Partnerships, the Trusts and the Company have an interest, and also for third parties, primarily in Texas, Oklahoma and West Virginia. The Company is also active in the acquisition of producing oil and gas properties through joint ventures with industry partners and private investors. THE PARTNERSHIPS AND TRUSTS A substantial portion of the assets and revenues of PEMC are derived from the interest of PEMC in the oil and gas properties acquired by the Partnerships and Trusts. As the managing general partner in each of the Partnerships and managing trustee of the Trusts, PEMC receives approximately from 5% to 15% of the net revenues of each Partnership and Trust as a carried interest in the Partnership's and Trust's properties. The Company has also repurchased substantial limited partner interests in these entities. Since 1975, PEMC has sponsored a total of 59 limited partnerships, 22 of which were offered publicly and 37 of which were offered in private placements and two Delaware business trusts, both of which were offered publicly. The aggregate number of limited partners in the Partnerships and beneficial owners of the Trusts now administered by PEMC is approximately 4,800. The Partnership and Trust interests were sold by broker-dealers which are members of the National Association of Securities Dealers, Inc. through a managing dealer. The total funds contributed to the Partnerships and Trusts was about $157,550,000. A significant portion of the Company's business is conducted through the Partnerships and Trusts, either through its ownership of interests in various properties derived through the Partnerships and Trusts, or as operator of, and a provider of oilfield services to, oil and gas wells in which the Partnerships and Trusts have interests. 2
PEMC, as managing general partner of the Partnerships and managing trustee of the Trusts, is responsible for all Partnership and Trust activities, including the review and analysis of oil and gas properties for acquisition, the drilling of development wells and the production and sale of oil and gas from productive wells. PEMC also provides administration, accounting and tax preparation for the Partnerships and Trusts. PEMC is liable for all debts and liabilities of the Partnerships and Trusts, to the extent that the assets of a given limited partnership or trust are not sufficient to satisfy its obligations. JOINT VENTURES PEMC organizes and the Company participates in various joint ventures formed for the purpose of acquiring and developing oil and gas assets. The Company receives varying interests in the net revenues of each joint venture as a carried interest in the joint venture properties. The Company's participation in the joint ventures varies from none to approximately 78%. The Company's carried interest is generally 10% of funds contributed by outside investors. Since 1987, our joint venture partners have invested $27.6 million with the Company. WELL OPERATIONS The Company's operations are conducted through a central office in Houston, Texas, and district offices in Houston and Midland, Texas, Oklahoma City, Oklahoma, and Charleston, West Virginia. The Company currently operates 1,550 oil and gas wells, 411 through the Houston office, 181 through the Midland office, 463 through the Oklahoma City office and 495 through the Charleston, West Virginia office. Substantially all of the wells operated by the Company are wells in which the Company, the Partnerships, the Trusts or our joint venture partners have an interest. The Company operates wells pursuant to operating agreements which govern the relationship between the Company as operator and the other owners of working interests in the properties, including the Partnerships, Trusts and joint venture participants. For each operated well, the Company receives monthly fees that are competitive in the areas of operations and also is reimbursed for expenses incurred in connection with well operations. EXPLORATION, DEVELOPMENT AND ACQUISITION ACTIVITIES; OTHER MATTERS The Company continues to explore opportunities for the acquisition and development of producing oil and gas properties, and will continue to engage in exploratory operations and development drilling of properties in which it has an interest. The Company attempts to assume the position of operator in all acquisitions of producing properties. RECENT ACTIVITIES The Company participated in, and was operator of, four wells drilled on the East Wakita prospect in Oklahoma during 2001. Three of these wells were successfully completed, while 1 was a dry hole. Two additional wells were successfully completed on the prospect in the first quarter of 2002. The Company participated in, and was the operator of, two wells drilled on the DSR prospect in Oklahoma during 2001. One of these wells was successfully completed and one has been temporarily abandoned pending further evaluation. The Company participated in, and was the operator of, two wells that were successfully completed in the Weatherby field in Reagan County, Texas. The Company successfully completed eleven wells in Upton County, Texas during 2001. The Company participated in, and was the operator of, a successfully completed well on the Cadiz prospect in Bee County, Texas in March of 2001. In March of 2001, the Company successfully reentered and recompleted a well in the Tuleta East field in Bee County, Texas. The Company is committed to offer to repurchase the interests of the limited partners and trust unitholders in certain of the Partnerships, as described more fully in Note 7 of the Financial Statements. During 2001, the Company purchased such interests in an amount totaling $545,000. 3
The Company will continue to evaluate prospects for leasehold acquisitions and for exploration and development operations in areas in which it owns interests and is actively pursuing the acquisition of producing properties. In order to diversify and broaden its asset base, the Company will consider acquiring the assets or stock in other entities and companies in the oil and gas business. The main objective of the Company in making any such acquisitions will be to acquire income producing assets so as to increase the Company's net worth and increase the Company's oil and gas reserve base. The Company presently owns producing and non-producing properties located primarily in Texas, Oklahoma, West Virginia and Louisiana, and owns a substantial amount of well servicing equipment. The Company does not own any refinery or marketing facilities, and does not currently own or lease any bulk storage facilities or pipelines other than adjacent to and used in connection with producing wells and the interests in certain gas gathering systems. All of the Company's oil and gas properties and interests are located in the continental United States. In the past, the supply of gas has exceeded demand on a cyclical basis, and the Company is subject to a combination of shut-in and/or reduced takes of gas production during summer months. Prolonged shut-ins could result in reduced field operating income from properties in which the Company acts as operator. Exploration for oil and gas requires substantial expenditures particularly in exploratory drilling in undeveloped areas, or "wildcat drilling." As is customary in the oil and gas industry, substantially all of the Company's exploration and development activities are conducted through joint drilling and operating agreements with others engaged in the oil and gas business. Summaries of the Company's oil and gas drilling activities, oil and gas production, and undeveloped leasehold, mineral and royalty interests are set forth under Item 2., "Description of Property," below. Summaries of the Company's oil and gas reserves, future net revenue and present value of future net revenue are also set forth under Item 2., "Description of Property - Reserves" below. REGULATION The Company's oil and gas operations are subject to a wide variety of federal, state and local regulations. Administrative agencies in such jurisdictions may promulgate and enforce rules and regulations relating to, among other things, drilling and spacing of oil and gas wells, production rates, prevention of waste, conservation of natural gas and oil, pollution control, and various other matters, all of which may affect the Company's future operations and production of oil and gas. The Company's natural gas production and prices received for natural gas are regulated by the Federal Energy Regulatory Commission ("FERC"), the Natural Gas Act of 1938 ("NGA") and the Natural Gas Policy Act of 1978 ("NGPA") and various state regulations. The Company is also subject to state drilling and proration regulations affecting its drilling operations and production rates. Additional proposals and proceedings that might affect the natural gas industry are considered from time to time by Congress, the FERC, state regulatory bodies and the courts. The Company cannot predict when or if any such proposals might become effective, or their effect, if any, on the Company's operations. The natural gas industry historically has been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach recently pursued by the FERC and Congress will continue indefinitely into the future. In the event the Company conducts operations on federal, state or Indian oil and gas leases, such operations must comply with numerous regulatory restrictions, including various nondiscrimination statutes, and certain of such operations must be conducted pursuant to certain on-site security regulations and other appropriate permits issued by the Bureau of Land Management ("BLM") or Minerals Management Service ("MMS") or other appropriate federal or state agencies. The Mineral Leasing Act of 1930 ("Mineral Act") prohibits direct or indirect ownership of any interest in federal onshore oil and gas leases by a foreign citizen of a country that denies "similar or like privileges' to citizens of the United States. Such restrictions on citizens of a "non-reciprocal" country include ownership or holding or controlling stock in a corporation that holds a federal onshore oil and gas lease. If this restriction is violated, the corporation's lease can be canceled in a proceeding instituted by the United States Attorney General. Although the regulations of the BLM (which administers the Mineral Act) provide for agency designations of non-reciprocal countries, there are presently no such designations in effect. The Company owns interests in federal onshore oil and gas leases. It is possible that Common Stock could be acquired by citizens of foreign countries, which at some time in the future might be determined to be non-reciprocal under the Mineral Act. 4
TAXATION The Company's oil and gas operations are affected by federal income tax laws applicable to the petroleum industry. The Company is permitted to deduct currently, rather than capitalize, intangible drilling and development costs incurred or borne by it. As an independent producer, the Company is also entitled to a deduction for percentage depletion with respect to the first 1,000 barrels per day of domestic crude oil (and/or equivalent units of domestic natural gas) produced by it, if such percentage depletion exceeds cost depletion. Generally, this deduction is computed based upon the lesser of 100% of the net income, or 15% of the gross income from a property, without reference to the basis in the property. The amount of the percentage depletion deduction so computed which may be deducted in any given year is limited to 65% of taxable income. Any percentage depletion deduction disallowed due to the 65% of taxable income test may be carried forward indefinitely. The Company is entitled to credits for producing fuel from a non-conventional source under Section 29 of the Internal Revenue Code, primarily from certain of the Company's operations in West Virginia. See Notes 1 and 9 to the consolidated financial statements included in this Report for a discussion of accounting for income taxes and availability of federal tax net operating loss carryforwards and alternative minimum tax credit carryforwards. COMPETITION AND MARKETS The business of acquiring producing properties and non-producing leases suitable for exploration and development is highly competitive. Competitors of the Company in its efforts to acquire both producing and non-producing properties include oil and gas companies, independent concerns, income programs and individual producers and operators, many of which have financial resources, staffs and facilities substantially greater than those available to the Company. Furthermore, domestic producers of oil and gas must not only compete with each other in marketing their output, but must also compete with producers of imported oil and gas and alternative energy sources such as coal, nuclear power and hydroelectric power. Competition among petroleum companies for favorable oil and gas properties and leases can be expected to increase. The availability of a ready market for any oil and gas produced by the Company at acceptable prices per unit of production will depend upon numerous factors beyond the control of the Company, including the extent of domestic production and importation of oil and gas, the proximity of the Company's producing properties to gas pipelines and the availability and capacity of such pipelines, the marketing of other competitive fuels, fluctuation in demand, governmental regulation of production, refining, transportation and sales, general national and worldwide economic conditions, and use and allocation of oil and gas and their substitute fuels. There is no assurance that the Company will be able to market all of the oil or gas produced by it or that favorable prices can be obtained for the oil and gas production. Listed below are the percent of the Company's total oil and gas sales made to each of the customers whose purchases represented more than 10% of the Company's oil and gas sales. <Table> <S> <C> Texon Distributing L.P. 19.70% Unimark LLC 13.79% </Table> Although there are no long-term purchasing agreements with these purchasers, the Company believes that they will continue to purchase its oil and gas products and, if not, could be replaced by other purchasers. ENVIRONMENTAL MATTERS Over the past 30 years, the petroleum industry has been affected by a wide variety of environmental issues. Throughout the 1970's and 1980's federal and state environmental regulations have been enacted that affect all aspects of the Company's operations. These regulations have primarily focused on correcting existing environmental concerns and implementing preventive controls to reduce future pollution. The Company's activities are subject to existing federal, state and local laws and regulations governing environmental quality and pollution control. It is anticipated that, absent the occurrence of an extraordinary event, compliance with existing federal, state and local laws, rules and regulations regulating the release of materials in the environment or otherwise relating to the protection of the environment will not have a material effect upon the operations, capital expenditures, earnings or the competitive position of the Company. The Company cannot predict what effect additional regulation or legislation, enforcement policies thereunder, and claims for damages to property, employees, other persons and the environment resulting from the Company's operations or ownership of its property could have on its activities. 5
Activities of the Company with respect to oil and gas facilities, including the operation and construction of pipelines, plants and other facilities for transporting, processing, treating or storing oil and gas and other products, are subject to stringent environmental regulation by state and federal authorities including the Environmental Protection Agency ("EPA"). Such regulation can increase the cost of planning, designing, installing and operating such facilities. In most instances, the regulatory requirements relate to water and air pollution control measures. Although the Company believes that compliance with environmental regulations will not have a material adverse effect on it, risks of substantial costs and liabilities are inherent in oil and gas facility operations, and there can be no assurance that significant costs and liabilities will not be incurred. Moreover, it is possible that other developments, such as stricter environmental laws and regulations, and claims for damages to property or persons resulting from operation of oil and gas facilities, would result in substantial costs and liabilities to the Company. The Company currently owns or leases, and has in the past owned or leased, numerous properties that have been used for production of oil and gas for many years. Although the Company has utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by the Company. In addition, many of these properties have been operated by third parties over whom the Company had no control as to such entities' treatment of hydrocarbons or other wastes and the manner in which such substances may have been disposed of or released. State and federal laws applicable to oil and gas wastes and properties have gradually become stricter. Under these new laws, the Company could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination) or to perform remedial plugging operations to prevent future contamination. The Company may generate wastes, including hazardous wastes, that are subject to the Federal Resource Conservation and Recovery Act and comparable state statutes. The EPA has limited the disposal options for certain hazardous wastes and is considering the adoption of stricter disposal standards for non-hazardous wastes. Furthermore, certain wastes generated by the Company's oil and gas operations that are currently exempt from treatment as "hazardous wastes" may in the future be designated as "hazardous wastes," and therefore be subject to more rigorous and costly operating and disposal requirements. In addition, legislation has been proposed in Congress from time to time that would reclassify certain oil and gas exploration and production wastes as "hazardous wastes," which would make the reclassified wastes subject to much more stringent handling, disposal and clean-up requirements. If such legislation were to be enacted, it could have a significant impact on the operating costs of the Company, as well as the oil and gas industry in general. Initiatives to further regulate the disposal of oil and gas wastes are also pending in certain states, and these various initiatives could have a similar impact on the Company. The Federal Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), also known as the "Superfund" law, imposes joint and several liability, without regard to fault or the legality of the original conduct, on certain classes of persons with respect to the release of a "hazardous substance" into the environment. These persons include the current owner and operator of a site and persons that disposed of or arranged for the disposal of the hazardous substances found at a site. CERCLA also authorizes the EPA and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs of such action. In the course of its operations, the Company may have generated and may generate wastes that fall within CERCLA'S definition of "hazardous substances." The Company may also be an owner of sites on which "hazardous substances" have been released by previous owners or operators. The Company may be responsible under CERCLA for all or part of the costs to clean up sites at which such wastes have been released. Neither the Company nor, to its knowledge, its predecessors has been named a potentially responsible person under CERCLA, nor does the Company know of any prior owners or operators of its properties that are named as potentially responsible parties related to their ownership or operation of such property. The Company has a proactive environmental policy that management feels benefits the Company through increased operating profits, improved landowner relations and an overall enhanced Company image. To this end, the Company has also adopted a stringent environmental evaluation prior to purchasing a property. This pre-acquisition assessment, usually referred to as an Environmental Site Assessment, typically consists of a historical review of the property combined with a site inspection and limited testing, when necessary. The objective of this pre-acquisition assessment is to document conditions at the time of acquisition and to assign liability to the seller for past operations. EMPLOYEES At March 25, 2002, the Company had 196 full-time and 11 part-time employees, 19 of whom were employed by the Company at its principal offices in Stamford, Connecticut, 23 in Houston, Texas, at the offices of Prime Operating Company, Eastern Oil Well Service Company and EOWS Midland Company and 165 employees who were 6
primarily involved in the district operations of the Company in Houston and Midland, Texas, Oklahoma City, Oklahoma and Charleston, West Virginia. ITEM 2. DESCRIPTION OF PROPERTY. The Company's executive offices and those of PEMC, are located at One Landmark Square, Stamford, Connecticut, in leased premises of about 8,860 square feet. The executive offices of Prime Operating Company, Eastern Oil Well Service Company and EOWS Midland Company are located in leased premises in Houston, Texas, and the offices of Southwest Oilfield Construction Company are in Oklahoma City, Oklahoma. The Company maintains district offices in Houston and Midland, Texas, Oklahoma City, Oklahoma and Charleston, West Virginia, and has field offices in Carrizo Springs and Midland, Texas, Kingfisher and Garvin, Oklahoma and Orma, West Virginia. The Company owns several parcels of land in Oklahoma, on which oil and gas wells it owns and operates are located. These properties were purchased primarily to simplify operations of these properties. Substantially all of the Company's oil and gas properties are subject to a mortgage given to collateralize indebtedness of the Company, or are subject to being mortgaged upon request by the Company's lender for additional collateral. The information set forth below concerning the Company's properties, activities, and oil and gas reserves include the Company's interests in the Partnerships, Trusts and joint ventures. The following table sets forth the exploratory and development drilling experience with respect to wells in which the Company participated during the five years ended December 31, 2001. <Table> <Caption> 2001 2000 1999 1998 1997 ---- ---- ---- ---- ---- Gross Net Gross Net Gross Net Gross Net Gross Net ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- <S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> Exploratory: Oil 1 1.000 -- -- 1 .300 1 .468 -- -- Gas 1 .602 3 1.279 1 .683 2 .387 2 .8 Dry -- -- 2 .276 2 .510 2 .686 2 .509 Development: Oil 1 .500 -- -- -- -- 1 .145 5 .796 Gas 7 4.926 7 4.134 2 .015 5 .316 5 2.037 Dry 2 1.585 -- -- 2 .745 -- -- 3 1.030 Total: Oil 2 1.500 -- -- 1 .300 2 .613 5 .796 Gas 8 5.528 10 5.413 3 .698 7 .703 7 2.837 Dry 2 1.585 2 .276 4 1.255 2 .686 5 1.539 --- ----- --- ----- --- ----- --- ----- --- ----- 12 8.613 12 5.689 8 2.253 11 2.002 17 5.172 === ===== === ===== === ===== === ===== === ===== </Table> OIL AND GAS PRODUCTION As of December 31, 2001, the Company had ownership interests in the following numbers of gross and net producing oil and gas wells and gross and net producing acres (1). <Table> <Caption> Gross Net ------- ------ <S> <C> <C> Producing wells(1): Oil Wells ..................... 893 212.43 Gas Wells ..................... 1,139 249.28 Producing Acres .................... 252,292 61,009 </Table> (1) A gross well or gross acre is a well or an acre in which a working interest is owned. A net well or net is the sum of the fractional revenue interests owned in gross wells or gross acres. Wells are classified by their primary product. Some wells produce both oil and gas. The following table shows the Company's net production of crude oil and natural gas for each of the five years ended December 31, 2001. "Net" production is net after royalty interests of others are deducted and is determined by multiplying the gross production volume of properties in which the Company has an interest by percentage of the leasehold, mineral or royalty interest owned by the Company. 7
<Table> <Caption> 2001 2000 1999 1998 1997 --------- --------- -------- --------- --------- <S> <C> <C> <C> <C> <C> Oil (barrels) ...... 306,000 298,000 264,000 277,000 277,000 Gas (Mcf) .......... 3,764,000 3,930,000 3289,000 3,621,000 3,901,000 </Table> The following table sets forth the Company's average sales price per barrel of crude oil and average sales prices per one thousand cubic feet ("Mcf") of gas, together with the Company's average production costs per unit of production for the five years ended December 31, 2001. <Table> <Caption> 2001 2000 1999 1998 1997 ------ ----- ----- ----- ----- <S> <C> <C> <C> <C> <C> Average sales price per barrel ........................... $24.92 28.34 15.71 12.39 19.35 Average sales price Per Mcf .............................. $ 4.08 3.76 2.32 2.19 2.57 Average production costs per net equivalent barrel(1) ............................. $11.88 9.57 7.76 7.60 7.59 </Table> - ---------- (1) Net equivalent barrels are computed at a rate of 6 Mcf per barrel. UNDEVELOPED ACREAGE The following table sets forth the approximate gross and net undeveloped acreage in which the Company has leasehold, mineral and royalty interests as of December 31, 2001. "Undeveloped acreage" is that acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas, regardless of whether or not such acreage contains proved reserves. <Table> <Caption> Leasehold Mineral Royalty Interests Interests Interests ------------------------ ---------------------- ---------------------- Gross Net Gross Net Gross Net State Acres Acres Acres Acres Acres Acres ----- ------- ------- ------- ------- ------- ------- <S> <C> <C> <C> <C> <C> <C> Colorado -- -- 799 23 -- -- Montana -- -- 13,984 59 786 5 Nebraska -- -- 2,553 331 -- -- North Dakota -- -- 640 1 -- -- Oklahoma 22,935 6,477 320 1 -- -- Texas 15,014 4,925 680 16 -- -- Wyoming 1,000 125 5043 35 140 35 ------- ------- ------- ------- ------- ------- TOTAL 38,949 11,527 24,019 466 926 40 ======= ======= ======= ======= ======= ======= </Table> RESERVES The Company's interests in proved developed and undeveloped oil and gas properties have been evaluated by Ryder Scott & Company L.P. for the years ended December 31, 1997, 1998, 1999, 2000 and 2001. All of the Company's reserves are located within the continental United States. The following table summarizes the Company's oil and gas reserves at each of the respective dates (figures rounded): <Table> <Caption> Reserve Category ------------------------------------------------------- Proved Developed Proved Undeveloped Total ------------------------- ------------------------- ------------------------- As of Oil Gas Oil Gas Oil Gas 12-31 (bbls) (Mcf) (bbls) (Mcf) (bbls) (Mcf) - ------- ---------- ---------- ---------- ---------- ---------- ---------- <S> <C> <C> <C> <C> <C> <C> 1997 1,364,000 16,661,000 77,000 -- 1,441,000 16,661,000 1998 1,122,000 17,341,000 78,000 -- 1,200,000 17,341,000 1999 2,110,000 22,046,000 -- 156,000 2,110,000 22,202,000 2000 2,362,000 27,029,000 -- -- 2,362,000 27,029,000 2001 1,996,000 24,266,000 -- 453,000 1,996,000 24,719,000 </Table> The estimated future net revenue (using current prices and costs as of those dates, exclusive of income taxes) and the present value of future net revenue (at a 10% discount for estimated timing of cash flow) for the Company's proved developed and proved undeveloped oil and gas reserves at the end of each of the five years ended December 31, 2001, are summarized as follows (figures rounded): 8
<Table> <Caption> Proved Developed Proved Undeveloped Total ------------------------------ --------------------------- ----------------------------- Present Value Present Value Present Value As of Future Net Of Future Future Net Of Future Future Net Of Future 12-31 Revenue Net Revenue Revenue Net Revenue Revenue Net Revenue - ------- ------------ ------------- ---------- ------------- ----------- ------------- <S> <C> <C> <C> <C> <C> <C> 1997 $ 30,056,000 21,306,000 833,000 531,000 30,889,000 21,837,000 1998 $ 20,839,000 13,444,000 359,000 212,000 21,198,000 13,656,000 1999 $ 41,103,000 26,057,000 258,000 151,000 41,361,000 26,208,000 2000 $199,376,000 113,137,000 -- -- 199,376,000 113,137,000 2001 $ 41,086,000 24,653,000 957,000 629,000 42,043,000 25,282,000 </Table> "Proved developed" oil and gas reserves are reserves that can be expected to be recovered from existing wells with existing equipment and operating methods. "Proved undeveloped" oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. In accordance with FASB Statement No. 69, December 31 market prices are determined using the daily oil price or daily gas sales price ("spot price") adjusted for oilfield or gas gathering hub and wellhead price differentials (e.g. grade, transportation, gravity, sulfur, and BS&W) as appropriate. Also in accordance with SEC and FASB specifications, changes in market prices subsequent to December 31 are not considered. The spot price for gas at December 31, 2001 and 2000 were $2.63 and $9.23 per MMBTU, respectively. The range of spot prices during the year 2001 was a low of $1.77 and a high of $10.29 and the average was $3.94. The range during the first quarter of 2002 has been from $2.01 to $3.58 with an average of $2.50. The recent futures market prices have been in the $3.00 to $3.50 range. While it may reasonably be anticipated that the prices received by the Company for the sale of its production may be higher or lower than the prices used in this evaluation, as described above, and the operating costs relating to such production may also increase or decrease from existing levels, such possible changes in prices and costs were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation for the SEC case. Actual volumes produced, prices received and costs incurred by the Company may vary significantly from the SEC case. Since January 1, 2002, the Company has not filed any estimates of its oil and gas reserves with, nor were any such estimates included in any reports to, any federal authority or agency, other than the Securities and Exchange Commission, except Form EIA-23, Annual Survey of Domestic Oil and Gas Reserves, filed with The Energy Information Administration of the U.S. Department of Energy. ITEM 3. LEGAL PROCEEDINGS. From time to time, the Company is party to certain legal actions and claims arising in the ordinary course of business. While the outcome of these events cannot be predicted with certainty, management does not expect these matters to have a materially adverse effect on the financial position or results of operations of the Company. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY-HOLDERS. No matters were submitted during the fourth quarter of the fiscal year ended December 31, 2001, to a vote of the Company's security-holders through the solicitation of proxies or otherwise. PART II ITEM 5. MARKET FOR COMMON EQUITY AND RELATED STOCKHOLDER MATTERS. The Company's Common Stock is traded in the NASDAQ Stock Market, trading symbol "PNRG". The high and low bid quotations for each quarterly period during the two years ended December 31, 2001, were as follows: <Table> <Caption> 2000 High Low 2001 High Low - ------------- ------- ------- ------------- ------- ------- <S> <C> <C> <C> <C> <C> First Quarter $ 4.91 $ 4.83 First Quarter $ 6.56 $ 6.49 Second Quarter 4.56 4.40 Second Quarter 8.11 7.75 Third Quarter 5.84 5.78 Third Quarter 8.47 8.30 Fourth Quarter 7.38 7.23 Fourth Quarter 8.00 7.95 </Table> 9
The above quotations reflect inter-dealer prices, without retail mark-up, mark-down or commissions, and may not represent actual transactions. The approximate number of record holders of the Company's Common Stock as of March 25, 2002 was 1,051. No dividends have been declared or paid during the past two years on the Company's Common Stock. Provisions of the Company's line of credit agreement restrict the Company's ability to pay dividends. Such dividends may be declared out of funds legally available therefore, when and as declared by the Company's Board of Directors. ITEM 6. SELECTED FINANCIAL DATA The following table summarizes certain selected financial data to highlight significant trends in the Company's financial condition and results of operations for the periods indicated. The selected financial data should be read in conjunction with the Financial Statements and related notes included elsewhere in this Report. <Table> <Caption> 2001 2000 1999 1998 1997 ----------- ---------- ---------- ---------- ---------- <S> <C> <C> <C> <C> <C> Revenues $42,408,000 39,182,000 25,520,000 24,795,000 28,725,000 Income (loss) from operations $ 6,968,000 6,148,000 (2,116,000) (2,061,000) 842,000 Net Income (loss) $ 5,413,000 5,365,000 (2,138,000) (1,692,000) 1,024,000 Income (loss) per common share $ 1.39 1.26 (0.48) (0.38) 0.19 Net Cash provided by operations $12,313,000 11,498,000 7,677,000 6,846,000 8,773,000 Total Assets $35,816,000 35,094,000 30,475,000 28,611,000 34,668,000 Long-term obligations $16,958,000 18,213,000 19,217,000 16,505,000 18,865,000 Cash Dividends None None None None None </Table> ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OR PLAN OF OPERATION. This discussion should be read in conjunction with the financial statements of the Company and notes thereto. The Company's subsidiaries are defined in Note 1 of the financial statements. PEMC is the managing general partner or managing trustee in several Limited Partnerships and Trusts (collectively, the "Partnerships"). LIQUIDITY AND CAPITAL RESOURCES Net cash provided by operations was $12,313,000 in 2001, $11,498,000 in 2000, and $7,677,000 in 1999. The Company has been party to a series of credit agreements with its primary lender or its predecessors since 1983. The current agreement, entered into in April, 1995, provides for borrowings under a Master Note. Advances under the agreement, as amended, are limited to the borrowing base as defined in the agreement. The borrowing base is re-determined by the lender on a semi-annual basis. Since the beginning of 1999, the borrowing base has ranged from $20 million to $23.7 million. The credit agreement provides for interest on outstanding borrowings at the bank's base rate, as defined, payable monthly, or at rates ranging from 1 1/2% to 2% over the London Inter-Bank Offered Rate (LIBO rate) depending upon the Company's utilization of the available line of credit, payable at the end of the applicable interest period. The average interest rates paid on outstanding borrowings subject to interest at the bank's base rate during 2001 and 2000 were 6.92% and 9.46%, respectively. During the same periods, the average rates paid on outstanding borrowings bearing interest based upon the LIBO rate were 5.98% and 8.46%. As of December 31, 2001 and 2000, the total outstanding borrowings were $16,950,000 and $17,200,000, respectively, with an additional $6,050,000 and $1,750,000 available, and $14,950,000 and $13,500,000 of the amounts outstanding accruing interest at the LIBO rate option. The Company's oil and gas properties as well as certain receivables and equipment are pledged as security under the loan agreement. The agreement requires the Company to maintain, as defined, a minimum current ratio, tangible net worth, debt coverage ratio and interest coverage ratio, and restrictions are placed on the payment of dividends and the amount of treasury stock the Company may purchase. The Company spent approximately $1,386,000 developing the East Wakita field during 2001. Three successful wells were drilled on this property in 2001, and two more successful wells were drilled in the first quarter of 2002. Further development of this prospect is planned for the future. The Company spent $1,100,000 developing the DSR prospect in Garvin County, Oklahoma. First sales from this field occurred in January, 2002. Additional development of this field is planned for 2002. 10
In total, the Company spent $6,650,000 on the acquisition and development of oil and gas properties during 2001, including $545,000 spent to repurchase limited partnership interests from investors in its oil and gas partnerships. The Company spent $2,054,000 on field service equipment during 2001, and an additional $108,000 on computers, software and related equipment. The Company spent $3,156,000 to repurchase shares of its treasury stock in 2001. As of the date of this report, the Company had spent an additional $182,000 on treasury stock purchases in 2002. It is the goal of the Company to increase its oil and gas reserves and production through the acquisition and development of oil and gas properties. The Company also continues to explore and consider opportunities to further expand its oilfield servicing revenues through additional investment in field service equipment. However, the majority of the Company's capital spending is discretionary, and the ultimate level of expenditures will be dependent on the Company's assessment of the oil and gas business environment, the number and quality of oil and gas prospects available, the market for oilfield services, and oil and gas business opportunities in general. RESULTS OF OPERATIONS: 2001 AS COMPARED TO 2000 The Company had net income of $5,413,000 in 2001, as compared to $5,365,000 in 2000. Oil and gas production and revenue remained flat, and district operating income increased by 26% to $17,082,000, contributing to an 8% increase in overall revenues to $42,408,000. Oil and gas sales were $22,998,000 in 2001 as compared to $23,223,000 in 2000, a drop of less than 1%. A chart summarizing oil and gas production and revenue, including the Company's share of production and revenue from the Partnerships, follows. <Table> <Caption> 2001 2000 Increase (Decrease) ----------- ----------- ------------------- <S> <C> <C> <C> Barrels of Oil Produced 306,016 297,562 8,454 Average Price Received $ 24.9199 $ 28.3354 $ (3.4155) ----------- ----------- Oil Revenue $ 7,626,000 $ 8,432,000 $ (806,000) ----------- ----------- Mcf of Gas Produced 3,763,605 3,929,532 (165,927) Average Price Received $ 4.0843 $ 3.7641 $ 0.3202 ----------- ----------- Gas Revenue $15,372,000 $14,791,000 $ 581,000 ----------- ----------- Total Oil & Gas Revenue $22,998,000 $23,223,000 $ (225,000) =========== =========== </Table> The Company completed a successful well on its Cadiz field in Bee County, Texas during 2001. Two successful wells had been completed on this prospect in 2000. These three wells contributed 3,400 barrels of oil, 380,000 Mcf of gas and $1,624,000 in revenue in 2001, as compared to 1,200 barrels, 168,000 Mcf of gas and $853,000 in 2000. No further drilling is currently planned for this prospect. The Company spent $1,386,000 developing the East Wakita field in Oklahoma during 2001, including the drilling of three successful gas wells. Two additional successful wells were drilled on this prospect in the first quarter of 2002, and additional development is planned for the future. This prospect contributed $915,000 to oil and gas revenues in 2001. The Francis Martin well experienced a natural decline in gas and oil production and increase in water production as well as shut-ins for mechanical work during 2001. This well contributed 2,000 barrels of oil, 115,000 Mcf of gas and $654,000 in revenue in 2001, as compared to 6,000 barrels, 371,000 Mcf and $1,654,000 in 2000. District operating income increased 26% to $17,082,000 in 2001 as compared to $13,585,000 in 2000. This increase reflects the utilization of the over $2,000,000 in field service equipment the Company purchased during the year, and its focus on expanding the amount of work performed for third parties on wells not operated by the Company. This increase also reflects full administrative overhead charges on marginal properties where the Company had previously discounted such fees. 11
Lease operating expenses increased by 22% to $11,083,000 in 2001 as compared to $9,114,000 in 2000. Approximately $874,000 of this amount is attributable to properties purchased or developed during 2000 or 2001. The remainder of the difference is primarily attributable to an increase in repair and fix-up work performed, and a decrease in discounts received in administrative overhead due to the strong price environment in 2001. Administrative revenue, which represents the reimbursement of general and administrative overhead expended on behalf of the Partnerships and the Company's joint venture partners decreased by 7% to $1,535,000 in 2001 as compared to $1,655,000 in 2000. In both years, amounts received from certain of the Partnerships were substantially less than the amounts allocable to these Partnerships under the partnership agreements. The lower amounts reflect PEMC's continuing efforts to reduce costs, both incurred and allocated to the Partnerships. Reporting and management fees are earned from providing the accounting and reporting functions for certain of the Partnerships. The Company receives reimbursement for costs incurred related to the evaluation and acquisition of properties on behalf of the Partnerships and other joint venture partners. To the extent that these property acquisition costs are expended at the district level, the reimbursements are recorded as a reduction of total district operating expenses. When expenses are incurred at the corporate headquarters level, such reimbursements are recorded as a reduction of total general and administrative expenses. During 2001 and 2000, the Company's total reimbursements for property acquisition costs were approximately $558,000 and $1,100,000, respectively. General and administrative expenses increased 7% to $4,310,000 in 2001 as compared to $4,033,000 in 2000. This increase reflects the change in cost reimbursement offset by savings related to overhead efficiencies. Depreciation and depletion of oil and gas properties decreased by 11% to $4,522,000 in 2001 as compared to $5,060,000 in 2000, while impairments increased to $753,000 in 2001 as compared to $295,000 in 2000. Total depletion and impairment expense in 2001 was $5,275,000 in 2001 as compared to $5,355,000 in 2000, a decline of approximately 1%. Exploration costs of $509,000 in 2001 consist primarily of the cost of three dry holes drilled in 2001. Exploration costs of $1,797,000 in 2000 consisted primarily of dry hole costs relating to the drilling of two offshore wells in the fourth quarter of that year. Interest expense decreased by 40% to $895,000 in 2001 as compared to $1,500,000 in 2000 due to a combination of lower interest rates and lower average outstanding debt. The average interest rates paid on outstanding borrowings subject to interest at the bank's base rate during 2001 and 2000 were 6.92% and 9.46%, respectively. During the same periods, the average rates paid on outstanding borrowings bearing interest based upon the LIBO rate were 5.98% and 8.46%. As of December 31, 2001 and 2000, the total outstanding borrowings were $16,950,000 and $17,200,000, respectively, with an additional $6,050,000 and $1,750,000 available, and $14,950,000 and $13,500,000 of the amounts outstanding accruing interest at the LIBO rate option. Income tax expense increased by 112% to $1,721,000 in 2001 as compared to $811,000 in 2000. The effective rate was 24% in 2001 as compared to 13% in 2000. In both 1998 and 1999, the Company had large federal net operating losses. The value of these loss carryforwards was fully reserved against due to the uncertainty as to whether the Company would have future net income against which these losses could be offset. The use of these previously reserved against carryforwards were the primary reason for the low effective rate in 2000. Current tax expense in 2001 was $38,000, with the remainder of expense being attributable to an increase in the Company's deferred tax liability. The Company generates approximately $350,000 of federal tax credits under Internal Revenue Code Section 29 for producing fuel from a non-conventional source. These credits, which significantly lower current tax expense, are scheduled to expire after 2002. Another contributing factor to the extremely low current expense is that the Company is allowed to deduct currently for income tax purposes intangible drilling costs which are capitalized for financial reporting purposes. The Company had over $5,000,000 in such costs during 2001. The amount of intangible drilling costs which will be incurred in future years will depend on many factors and cannot be reliably predicted. 2000 AS COMPARED TO 1999 The Company had net income of $5,365,000 in 2000, as compared to a net loss of $2,138,000 in 1999. The improved results in 2000 are due to a combination of sharply higher prices received for the Company's oil and 12
gas production, increases in production volumes, and the expansion of the Company's oilfield services operations. The 1999 loss was caused primarily by a $2,703,000 impairment on the Ramrod Property, located in Matagorda County, Texas Oil and gas sales increased by 97%, to $23,223,000 in 2000 as compared to $11,763,000 in 1999, due to a combination of higher prices and increased production.. A chart summarizing oil and gas revenue in those two years, including the Company's share of production and revenue from the partnerships, follows. <Table> <Caption> 2000 1999 Increase ----------- ----------- ----------- <S> <C> <C> <C> Barrels of Oil Produced 297,562 263,980 33,582 Average Price Received $ 28.3354 $ 15.7111 $ 12.6243 ----------- ----------- Oil Revenue $ 8,432,000 $ 4,147,000 $ 4,285,000 ----------- ----------- Mcf of Gas Produced 3,929,532 3,289,463 640,069 Average Price Received $ 3.7641 $ 2.3153 $ 1.4488 ----------- ----------- Gas Revenue $14,791,000 $ 7,616,000 $ 7,175,000 ----------- ----------- Total Oil & Gas Revenue $23,223,000 $11,763,000 $11,460,000 =========== =========== </Table> On November 15, 1999, the Company purchased interests in approximately 131 oil and gas wells located in various counties in Oklahoma. These properties contributed 433,000 Mcf of gas, 29,000 barrels of oil and $2,215,000 of revenue in the year 2000, as compared to 72,000 Mcf of gas, 6,800 barrels of oil and $337,000 of revenue during the 1 1/2 months the Company owned these properties in 1999. In the second quarter of 2000 the Company completed the Brooks Trust #1 well in Bee County, Texas, and in the third quarter drilled the Brooks Trust # 2. These wells produced a combined 168,000 Mcf of gas, and contributed $853,000 in revenue net to the Company's interest in 2000. In August of 2000 the Company had first sales from a well drilled and completed on the East Wakita Prospect in Oklahoma. This well produced 147,000 Mcf of gas and contributed $597,000 of revenue net to the Company's interest through December 31, 2000. District operating income increased by 19% to $13,585,000 in 2000 as compared to $11,407,000 in 1999. This increase reflects the utilization of field service equipment purchased during the year, and the Company's continued focus on expanding its field service operations, particularly the amount of work performed on wells operated by third parties. The Company spent $1,582,000 to purchase equipment used in its field service operations in 2000. Lease operating expenses increased by 45% in 2000 to $9,114,000 as compared to $6,305,000 in 1999, primarily due to higher volumes produced and a greater amount of repair and fix up work performed in 2000 than in 1999, when prices were extremely depressed. The additional interests in Oklahoma properties purchased in November 1999 accounted for $382,000 of this increase. Administrative revenue, which represents the reimbursement of general and administrative overhead expended on behalf of the Partnerships and the Company's joint venture partners decreased slightly to $1,655,000 in 2000 as compared to $1,673,000 in 1999. In both years, amounts received from certain of the Partnerships were substantially less than the amounts allocable to these Partnerships under the partnership agreements. The lower amounts reflect PEMC's continuing efforts to reduce costs, both incurred and allocated to the Partnerships. Reporting and management fees are earned from providing the accounting and reporting functions for certain of the Partnerships. The Company receives reimbursement for costs incurred related to the evaluation and acquisition of properties on behalf of the Partnerships and other joint venture partners. To the extent that these property acquisition costs are expended at the district level, the reimbursements are recorded as a reduction of total district operating expenses. When expenses are incurred at the corporate headquarters level, such reimbursements are recorded as a reduction of total general and administrative expenses. During 2000 and 1999, the Company's total reimbursements for property acquisition costs were approximately $1,100,000 and $1,450,000, respectively. 13
General and administrative expenses increased 28% to $4,033,000 in 2000 as compared to $3,149,000 in 1999. The change in cost reimbursement, previously discussed, and increased compensation costs contributed to this increase. Compensation and benefit costs increased due to nonrecurring employee benefit costs related to the resignation of a company employee and generally higher compensation costs attributable to the expansion of the Company's operating activities. Depreciation and depletion of oil and gas properties increased by 10% to $5,060,000 in 2000 as compared to $4,581,000 in 1999 due to higher volumes produced. Impairment of oil and gas properties of $295,000 in 2000 related to several of the Company's less significant properties. The $2,703,000 impairment in 1999 related entirely to the impairment of a single property, the Ramrod field located in Matagorda County, Texas. Exploration costs of $1,797,000 in 2000 consisted primarily of dry hole costs relating to the drilling of two offshore wells in the fourth quarter of the year. 1999 costs of $869,000 consisted primarily of dry hole costs on wells which were part of the Company's 1998 drilling program. 1999 AS COMPARED TO 1998 The Company incurred a loss of $2,138,000 in 1999 as compared to a loss of $1,692,000 in 1998. The 1999 loss was caused by a $2,703,000 impairment on the Ramrod Property, located in Matagorda County, Texas. The 1998 loss was primarily caused by exploration costs of $1,706,000 combined with extremely low oil and gas prices. The Company sold 50% of its interest in the Ramrod field and turned over operations to the purchaser in November 1998. The new operator increased flow rates on the most significant well on this property, the St. George # 1, and soon afterwards the well began to experience mechanical problems. Despite several expensive attempts to repair this well throughout 1999, production rates at the end of 1999 were about an eighth of what they were before the mechanical problems began, and the estimated future reserves at January 1, 2000 declined drastically from the prior year estimates. Additionally, the Company incurred $1,582,000 in drilling costs on the property in 1999, and while some reserves were found, the future net revenue associated with these reserves is greatly below the costs incurred. Oil and gas sales increased by $409,000, to $11,763,000 in 1999 as compared to $11,354,000 in 1998, as increased prices more than offset production declines. Oil production declined by 13,000 barrels, to 264,000 barrels in 1999 as compared to 277,000 barrels in 1998, due primarily to natural decline curves on existing properties. Gas production declined by 332,000 Mcf to 3,289,000 Mcf in 1999 from 3,621,000 Mcf in 1998, as a drop of 561,000 Mcf in production from the Ramrod property and the natural decline curve of existing properties was only partially offset by production from additional interests in properties purchased during the year, and wells which came on line in 1999. The most significant well to come on line in 1999 was the Francis Martin well, which began production in January and produced 510,000 Mcf of gas during the year. The Company's participation in this well was subject to a provision whereby the Company's interest is reduced when it reaches payout and again upon reaching 200% of payout. These events occurred in August 1999 and February 2000. The Company's original 13.44% net revenue interest has been reduced to 9.33%. The Oklahoma properties purchased in November of 1999 produced 72,000 Mcf of gas and 6,800 barrels of oil during the 1 1/2 months the Company owned these properties in 1999. The average price received for a barrel of oil increased to $15.71 in 1999 as compared to $12.39 in 1998, and the average gas price received increased to $2.32 in 1999, as compared to $2.19 in 1998. Lease operating expenses decreased by $306,000 to $6,305,000 in 1999 as compared to $6,611,000 in 1998, due to lower volumes produced. District operating income increased by $462,000, to $11,407,000 in 1999 as compared to $10,945,000 in 1998, as the Company continued to expand its well servicing operations. Administrative revenue, which represents the reimbursement of general and administrative overhead expanded on behalf of the Partnerships and the Company's joint venture partners decreased by $50,000 to $1,673,000 in 1999 as compared to $1,723,000 in 1998. In both years, amounts received from certain of the 14
Partnerships were substantially less than the amounts allocable to these Partnerships under the partnership agreements. The lower amounts reflect PEMC's continuing efforts to reduce costs, both incurred and allocated to the Partnerships. Reporting and management fees are earned from providing the accounting and reporting functions for certain of the Partnerships. The Company receives reimbursement for costs incurred related to the evaluation and acquisition of properties on behalf of the Partnerships and other joint venture partners. To the extent that these property acquisition costs are expended at the district level, the reimbursements are recorded as a reduction of total district operating expenses. When expenses are incurred at the corporate headquarters level, such reimbursements are recorded as a reduction of total general and administrative expenses. During 1999 and 1998 the Company's total reimbursements for property acquisition costs were approximately $1,450,000 and $1,690,000 respectively. Depreciation and depletion of oil and gas properties decreased by $1,393,000 to $4,581,000 in 1999 as compared to $5,974,000 in 1998 due to lower volumes produced, and lower depletion rates on many properties due to increased reserve estimates at year-end. These increased reserve estimates were partly due to an increase in prices. Exploration costs of $869,000 in 1999 consisted primarily of dry hole costs on wells which were part of the Company's 1998 drilling program. ITEM 7a. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK. The Company is exposed to interest rate risk on its line of credit, which has variable rates based upon the lenders base rate, as defined, and the London Inter-Bank Offered rate. Based on the balance outstanding at December 31, 2001, a hypothetical 2% increase in the applicable interest rates would increase interest expense by approximately $339,000. Oil and gas prices have historically been extremely volatile, and have been particularly so in recent years. The Company did not enter into significant hedging transactions during 2001, and had no open hedging transactions at December 31, 2001. Declines in domestic oil and gas prices could have a material adverse effect on the Company's revenues, operating results and the estimates of economically recoverable reserves and the net revenue therefrom. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. Included on pages F-1 through F-26 of this Report. The Index to Financial Statements is at page F-1 of this Report. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE. None. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT Information relating to the Company's Directors, nominees for Directors and executive officers is included in the Company's definitive proxy statement relating to the Company's Annual Meeting of Stockholders to be held in June, 2002, which will be filed with the Securities and Exchange Commission within 120 days of December 31, 2001, and which is incorporated herein by reference. ITEM 11. EXECUTIVE COMPENSATION. Information relating to executive compensation is included in the Company's definitive proxy statement relating to the Company's Annual Meeting of Stockholders to be held in June, 2002, which will be filed with the Securities and Exchange Commission within 120 days of December 31, 2001, and which is incorporated herein by reference. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT. Information relating to security ownership of certain beneficial owners and management is included in the Company's definitive proxy statement relating to the Company's Annual Meeting of Stockholders to be held in June, 2002, which will be filed with the Securities and Exchange Commission within 120 days of December 31, 2001, and which is incorporated herein by reference. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS. Information relating to certain transactions by Directors and executive officers of the Company is included in the Company's definitive proxy statement relating to the Company's Annual Meeting of Stockholders to be held in June, 2002, which will be filed with the Securities and Exchange Commission within 120 days of December 31, 2001, and which is incorporated herein by reference. 15
PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K. (a) Exhibits: No. --- 3.1 Restated Certificate of Incorporation of PrimeEnergy Corporation. (Incorporated herein by reference to Exhibit 3.1 of PrimeEnergy Corporation Form 10-KSB for the year ended December 31, 1999) 3.2 Bylaws of PrimeEnergy Corporation. (Incorporated herein by reference to Exhibit 3.2 of PrimeEnergy Corporation Form 10-KSB for the year ended December 31, 1999) 10.1 PrimeEnergy Corporation 1983 Incentive Stock Option Plan (Incorporated herein by reference to Exhibit 10.1 of PrimeEnergy Corporation Form 10-KSB for the year ended December 31, 1994)(1) 10.3 Massachusetts Mutual Flexinvest 401(k) Plan as amended and restated. (Incorporated herein by reference to Exhibit 10.3 of PrimeEnergy Corporation Form 10-KSB for the year ended December 31, 1994)(1) 10.7 Credit Agreement dated April 26, 1995, between PrimeEnergy Corporation, PrimeEnergy Management Corporation and Bank One, Texas, National Association. (Incorporated herein by reference to Exhibit 10.7 to PrimeEnergy Corporation Form 8-K dated April 26, 1995) 10.7.1 First Amendment to Credit Agreement Among PrimeEnergy Corporation and PrimeEnergy Management Corporation, as Borrowers, Bank One, Texas, National Association, as Agent, and the Lenders Signatory Hereto, effective as of October 6, 1995. (Incorporated herein by reference to Exhibit 10.7.1 to PrimeEnergy Corporation Form 10-KSB for the year ended December 31, 1995) 10.7.2 Second Amendment to Credit Agreement Among PrimeEnergy Corporation and PrimeEnergy Management Corporation, as Borrowers, Bank One, Texas, National Association, as Agent, and the Lenders Signatory Hereto, effective as of February 6, 1997. (Incorporated by reference to Exhibit 10.7.2 of PrimeEnergy Corporation Form 10-KSB for the year ended December 31, 1996) 10.7.3 Third Amendment to Credit Agreement Among PrimeEnergy Corporation and PrimeEnergy Management Corporation, as Borrowers, Bank One, Texas, National Association, as Agent, and the Lenders Signatory Hereto, effective as of January 2, 1998 (Incorporated by reference to Exhibit 10.7.3 of PrimeEnergy Corporation Form 10-KSB for the year ended December 31, 1997) 10.8 Mortgage, Deed or Trust, Indenture, Security Agreement, Financing Statement and Assignment of Production dated May 27, 1994, as ratified and amended April 26, 1995, between PrimeEnergy Corporation, PrimeEnergy Management Corporation and Bank One, Texas, National Association. (Incorporated by reference to Exhibit 10.8 of PrimeEnergy Corporation Form 8-K dated April 26, 1995) 10.17 Amended Marketing Agreement between PrimeEnergy Management Corporation and Charles E. Drimal, Jr. (Incorporated herein by reference to Exhibit 10.17 of PrimeEnergy Corporation Form 10-KSB for the year ended December 31, 1994)(1) 10.18 Composite copy of Non-Statutory Option Agreements (Incorporated by reference to Exhibit 10.18 of PrimeEnergy Corporation for 10KSB for the year ended December 31, 1997)(1) 10.21 Purchase and Sale Agreement dated November 16, 1999 between Southern Pacific Petroleum U.S.A. and PrimeEnergy Corporation (Incorporated herein by reference to Exhibit 10.21 to PrimeEnergy Corporation Form 8-K dated November 24, 1999) 16
21 Subsidiaries. (filed herewith) 23 Consent of Ryder Scott & Company L.P. Company. (filed herewith) - ---------- (1) Management contract or compensatory plan or arrangement required to be filed as an Exhibit to this Form 10-K. (a) Reports on Form 8-K: None 17
SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 30th day of March, 2002. PrimeEnergy Corporation By: /s/ CHARLES E. DRIMAL, JR. --------------------------- Charles E. Drimal, Jr. President Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities indicated and on the 30th day of March, 2002. <Table> <S> <C> <C> <C> /s/ CHARLES E. DRIMAL, JR. Director and President; - -------------------------- The Principal Executive Officer Charles E. Drimal, Jr. /s/ BEVERLY A. CUMMINGS Director, Vice President and Treasurer; - -------------------------- The Principal Financial and Accounting Officer Beverly A. Cummings /s/ JAMES P. BOLDRICK Director /s/ CLINT HURT Director - -------------------------- -------------------- James P. Boldrick Clint Hurt /s/ SAMUEL R. CAMPBELL Director Director - -------------------------- -------------------- Samuel R. Campbell Robert de Rothschild Director /s/ JARVIS K. SLADE Director - -------------------------- -------------------- James E. Clark Jarvis Slade /s/ MATTHIAS ECKENSTEIN Director /s/ JAN K. SMEETS Director - -------------------------- -------------------- Matthias Eckenstein Jan K. Smeets /s/ H. GIFFORD FONG Director /s/ GAINES WEHRLE Director - -------------------------- -------------------- H. Gifford Fong Gaines Wehrle Director Director - -------------------------- -------------------- Thomas S.T. Gimbel Michael Wehrle </Table> 18
INDEX TO FINANCIAL STATEMENTS <Table> <S> <C> Financial Statements (Included herein at pages F-1 through F-23): Report of Independent Public Accountants F-2 Financial Statements Consolidated Balance Sheets -- December 31, 2001 and 2000 F-3 Consolidated Statements of Operations -- for the years ended December 31, 2001, 2000 and 1999 F-5 Consolidated Statements of Stockholders' Equity -- for the years ended December 31, 2001, 2000 and 1999 F-6 Consolidated Statements of Cash Flows -- for the years ended December 31, 2001, 2000 and 1999 F-7 Notes to Consolidated Financial Statements F-8 Supplementary Information: F-20 Capitalized Costs Relating to Oil and Gas Producing Activities December 31, 2001, 2000 and 1999 F-21 Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities, years ended December 31, 2001, 2000 and 1999 F-21 Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, years ended December 31, 2001, 2000 and 1999 F-22 Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Gas Reserves, years ended December 31, 2001, 2000 and 1999 F-23 Reserve Quantity Information, years ended December 31, 2001, 2000 and 1999 F-24 Results of Operations from Oil and Gas Producing Activities, years ended December 31, 2001, 2000 and 1999 F-25 Notes to Supplementary Information F-26 </Table> F-1
PUSTORINO, PUGLISI, & CO., LLP REPORT OF INDEPENDENT ACCOUNTANTS To the Board of Directors and Stockholders of PrimeEnergy Corporation: We have audited the accompanying consolidated balance sheets of PrimeEnergy Corporation and Subsidiaries as of December 31, 2001 and 2000, and the related consolidated statements of operations, stockholders' equity and cash flows for the years then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audits 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 financial statements referred to above present fairly, in all material respects, the consolidated financial position of PrimeEnergy Corporation and Subsidiaries as of December 31, 2001 and 2000, and the consolidated results of their operations and their cash flows for the years ended December 31, 2001, 2000 and 1999 in conformity with accounting principles generally accepted in the United States of America. /s/ PUSTORINO, PUGLISI & CO., LLP Pustorino, Puglisi & Co., LLP New York, New York March 29, 2002 F-2
PRIMEENERGY CORPORATION and SUBSIDIARIES CONSOLIDATED BALANCE SHEETS, December 31, 2001 and 2000 <Table> <Caption> 2001 2000 ------------ ------------ <S> <C> <C> ASSETS: Current assets: Cash and cash equivalents $ 85,000 $ 684,000 Restricted cash and cash equivalents (Note 12) 1,174,000 1,128,000 Accounts receivable, net (Note 3) 3,798,000 5,663,000 Due from related parties (less allowance for doubtful accounts of $800,000 in 2001 and 2000) (Note 11) 4,924,000 4,346,000 Prepaid expenses 64,000 112,000 Other current assets (Notes 4 and 9) 1,006,000 134,000 Deferred income taxes (Notes 1 and 9) 274,000 155,000 ------------ ------------ Total current assets 11,325,000 12,222,000 ------------ ------------ Property and equipment, at cost (Notes 1 and 2): Oil and gas properties (successful efforts method): Proved 63,418,000 57,439,000 Unproved 286,000 159,000 Furniture, fixtures and equipment including leasehold improvements 8,622,000 7,433,000 ------------ ------------ 72,326,000 65,031,000 Accumulated depreciation, depletion and amortization (48,039,000) (42,361,000) ------------ ------------ Net property and equipment 24,287,000 22,670,000 ------------ ------------ Other assets 204,000 202,000 ------------ ------------ Total assets $ 35,816,000 $ 35,094,000 ============ ============ </Table> The accompanying notes are an integral part of the consolidated financial statements. F-3
PRIMEENERGY CORPORATION and SUBSIDIARIES CONSOLIDATED BALANCE SHEETS, December 31, 2001 and 2000 <Table> <Caption> 2001 2000 ------------ ------------ <S> <C> <C> LIABILITIES and STOCKHOLDERS' EQUITY: Current liabilities: Accounts payable (Note 14) $ 5,788,000 $ 6,828,000 Current portion of other long-term obligations (Notes 6 and 7) 230,000 854,000 Accrued liabilities: Payroll, Benefits, and Related Items 1,157,000 934,000 Taxes -- 455,000 Interest and other 1,023,000 1,058,000 Due to related parties (Note 11) 983,000 1,265,000 ------------ ------------ Total current liabilities 9,181,000 11,394,000 Long-term bank debt (Note 5) 16,950,000 17,200,000 Other long-term obligations (Note 6) 8,000 1,013,000 Deferred income taxes (Note 9) 2,314,000 511,000 ------------ ------------ Total liabilities 28,453,000 30,118,000 ------------ ------------ Stockholders' equity: Preferred stock, $.10 par value, authorized 5,000,000 shares; none issued -- -- Common stock, $.10 par value, authorized 10,000,000 shares; issued 7,694,970 in 2001 and 7,607,970 in 2000 769,000 761,000 Paid in capital 11,024,000 10,902,000 Retained earnings 7,919,000 2,506,000 ------------ ------------ 19,712,000 14,169,000 Treasury stock, at cost, 3,909,102 common shares in 2001 and 3,488,942 in 2000 (12,349,000) (9,193,000) ------------ ------------ Total stockholders' equity 7,363,000 4,976,000 ------------ ------------ Total liabilities and equity $ 35,816,000 $ 35,094,000 ============ ============ </Table> The accompanying notes are an integral part of the consolidated financial statements. F-4
PRIMEENERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS of OPERATIONS for the years ended December 31, 2001, 2000 and 1999 <Table> <Caption> 2001 2000 1999 ------------ ------------ ------------ <S> <C> <C> <C> Revenue: Oil and gas sales $ 22,998,000 $ 23,223,000 $ 11,763,000 District operating income 17,082,000 13,585,000 11,407,000 Administrative revenue (Note 11) 1,535,000 1,655,000 1,673,000 Reporting and management fees (Note 11) 297,000 321,000 319,000 Interest income 138,000 169,000 146,000 Other income 358,000 229,000 212,000 ------------ ------------ ------------ 42,408,000 39,182,000 25,520,000 ------------ ------------ ------------ Costs and expenses: Lease operating expense 11,083,000 9,114,000 6,305,000 District operating expense 13,368,000 11,235,000 8,671,000 Depreciation and depletion of oil and gas properties 4,522,000 5,060,000 4,581,000 Impairment of oil and gas properties (Note 1) 753,000 295,000 2,703,000 General and administrative expense 4,310,000 4,033,000 3,149,000 Exploration costs 509,000 1,797,000 869,000 Interest expense (Note 5) 895,000 1,500,000 1,358,000 ------------ ------------ ------------ 35,440,000 33,034,000 27,636,000 ------------ ------------ ------------ Income (loss) from operations 6,968,000 6,148,000 (2,116,000) Other income: Gain on sale and exchange of assets 166,000 28,000 8,000 ------------ ------------ ------------ Income (loss) before provision for income taxes 7,134,000 6,176,000 (2,108,000) Provision for income taxes (Notes 1 and 9) 1,721,000 811,000 30,000 ------------ ------------ ------------ Net income (loss) $ 5,413,000 $ 5,365,000 $ (2,138,000) ============ ============ ============ Basic net income (loss) per common share (Notes 1 and 15) $ 1.39 $ 1.26 $ (0.48) ============ ============ ============ Diluted net income (loss) per common share (Notes 1 and 15) $ 1.18 $ 1.08 $ (0.48) ============ ============ ============ </Table> The accompanying notes are an integral part of the consolidated financial statements. F-5
PRIMEENERGY CORPORATION and SUBSIDIARIES CONSOLIDATED STATEMENT of STOCKHOLDERS' EQUITY for the years ended December 31, 2001, 2000 and 1999 <Table> <Caption> Retained Additional Earnings Common Stock Paid In (Accumulated Treasury Shares Amount Capital Deficit) Stock Total ------------ ------------ ------------ ------------ ------------ ------------ <S> <C> <C> <C> <C> <C> <C> Balance at December 31, 1998 7,607,970 $ 761,000 $ 10,902,000 $ (721,000) $ (7,323,000) $ 3,619,000 Purchased 107,687 shares of common stock (547,000) (547,000) Net loss (2,138,000) (2,138,000) ------------ ------------ ------------ ------------ ------------ ------------ Balance at December 31, 1999 7,607,970 $ 761,000 $ 10,902,000 $ (2,859,000) $ (7,870,000) $ 934,000 Purchased 222,879 shares of common stock (1,323,000) (1,323,000) Net income 5,365,000 5,365,000 ------------ ------------ ------------ ------------ ------------ ------------ Balance at December 31, 2000 7,607,970 $ 761,000 $ 10,902,000 $ 2,506,000 $ (9,193,000) $ 4,976,000 Exercised stock options 87,000 8,000 122,000 130,000 Purchased 420,160 shares of common stock (3,156,000) (3,156,000) Net income 5,413,000 5,413,000 ------------ ------------ ------------ ------------ ------------ ------------ Balance at December 31, 2001 7,694,970 $ 769,000 $ 11,024,000 $ 7,919,000 $(12,349,000) $ 7,363,000 ============ ============ ============ ============ ============ ============ </Table> The accompanying notes are an integral part of the consolidated financial statements. F-6
PRIMEENERGY CORPORATION and SUBSIDIARIES CONSOLIDATED STATEMENTS of CASH FLOWS for the years ended December 31, 2001, 2000 and 1999 ---------- <Table> <Caption> 2001 2000 1999 ------------ ------------ ------------ <S> <C> <C> <C> Cash flows from operating activities: Net income (loss) $ 5,413,000 $ 5,365,000 $ (2,138,000) Adjustments to reconcile net loss to net cash provided by operating activities: Depreciation, depletion and amortization 5,599,000 6,000,000 5,529,000 Impairment of oil and gas properties 753,000 295,000 2,703,000 Dry hole and abandonment costs 496,000 1,787,000 818,000 Gain on sale of properties (166,000) (28,000) (8,000) Provision (benefit) of deferred income taxes 1,684,000 356,000 (39,000) Changes in assets and liabilities: (Increase) decrease in accounts receivable 1,865,000 (2,028,000) (745,000) (Increase) decrease in due from related parties (578,000) (1,177,000) 108,000 (Increase) decrease in other assets (874,000) 36,000 120,000 (Increase) decrease in prepaid expenses 48,000 (28,000) (5,000) Increase (decrease) in accounts payable (1,086,000) (346,000) 811,000 Increase (decrease) in accrued liabilities (559,000) 944,000 311,000 Increase (decrease) in due to related parties (282,000) 322,000 212,000 ------------ ------------ ------------ Net cash provided by operating activities 12,313,000 11,498,000 7,677,000 ------------ ------------ ------------ Cash flows from investing activities: Proceeds from sale of properties and equipment 520,000 71,000 59,000 Additions to property and equipment (8,527,000) (11,632,000) (9,308,000) Proceeds from payment on notes receivable -- 453,000 28,000 ------------ ------------ ------------ Net cash used in investing activities (8,007,000) (11,108,000) (9,221,000) ------------ ------------ ------------ Cash flows from financing activities: Purchase of stock for treasury (3,156,000) (1,323,000) (547,000) Repayment of long-term bank debt and other long-term obligations (40,619,000) (27,844,000) (25,770,000) Increase in long-term bank debt and other long-term obligations 38,740,000 27,690,000 28,465,000 Proceeds from exercised stock options 130,000 -- -- ------------ ------------ ------------ Net cash provided by (used in) financing activities (4,905,000) (1,477,000) 2,148,000 ------------ ------------ ------------ Net increase (decrease) in cash (599,000) (1,087,000) 604,000 Cash and cash equivalents, beginning of year 684,000 1,771,000 1,167,000 ------------ ------------ ------------ Cash and cash equivalents, end of year $ 85,000 $ 684,000 $ 1,771,000 ============ ============ ============ Supplemental disclosures: Income taxes paid during the year $ 1,200,000 $ 53,000 $ -- Net income tax refunds received during the year $ -- $ -- $ 84,000 Interest paid during the year $ 901,000 $ 1,462,000 $ 1,367,000 Supplemental information of noncash investing and financing activities: In 1999, the Company recorded capital lease obligations in the amount of $22,000. </Table> The accompanying notes are an integral part of the consolidated financial statements. F-7
PRIMEENERGY CORPORATION and SUBSIDIARIES NOTES to CONSOLIDATED FINANCIAL STATEMENTS ---------- 1. DESCRIPTION OF OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES Nature of Operations: PrimeEnergy Corporation ("PEC"), a Delaware corporation, was organized in March 1973. PrimeEnergy Management Corporation ("PEMC"), a wholly-owned subsidiary, acts as the managing general partner, providing administration, accounting and tax preparation services for 45 private and publicly-held limited partnerships and 2 trusts (collectively, the "Partnerships"). PEC owns Eastern Oil Well Service Company ("EOWSC"), EOWS Midland Company and Southwest Oilfield Construction Company ("SOCC"), all of which perform oil and gas field servicing. PEC also owns Prime Operating Company ("POC"), which serves as operator for most of the producing oil and gas properties owned by the Company and affiliated entities. Field service revenues and the administrative overhead fees earned as operator are reported as 'District operating income' on the consolidated statement of operations. PrimeEnergy Corporation and its wholly-owned subsidiaries are herein referred to as the "Company." The Company is engaged in the development, acquisition and production of oil and natural gas properties. The Company owns leasehold, mineral and royalty interests in producing and non-producing oil and gas properties across the continental United States, including Colorado, Kansas, Louisiana, Mississippi, Montana, Nebraska, New Mexico, North Dakota, Oklahoma, Texas, Utah, West Virginia and Wyoming. The Company operates 1,550 wells and owns non-operating interests in over 800 additional wells. Additionally, the Company provides well-servicing support operations, site-preparation and construction services for oil and gas drilling and re-working operations, both in connection with the Company's activities and providing contract services for third parties. The Company is publicly traded on the NASDAQ under the symbol "PNRG." The markets for the Company's products are highly competitive, as oil and gas are commodity products and prices depend upon numerous factors beyond the control of the Company, such as economic, political and regulatory developments and competition from alternative energy sources. Principles of Consolidation: The consolidated financial statements include the accounts of PrimeEnergy Corporation and its wholly-owned subsidiaries. All material inter-company accounts and transactions between these entities have been eliminated. Oil and gas properties include ownership interests in the Partnerships. The statement of operations includes the Company's proportionate share of revenue and expenses related to oil and gas interests owned by the Partnerships. Use of Estimates: The preparation of financial statements in conformity with generally accepted accounting principles 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. Actual results could differ from those estimates. Estimates of oil and gas reserves, as determined by independent petroleum engineers, are continually subject to revision based on price, production history and other factors. Depletion expense, which is computed based on the units of production method, could be significantly impacted by changes in such estimates. Additionally, FAS 121 requires that if the expected future cash flow from an asset is less than its carrying cost, that asset must be written down to its fair market value. As the fair market value of an oil and gas property will usually be significantly less than the total future net revenue expected from that property, small changes in the estimated future net revenue from an asset could lead to the necessity of recording a significant impairment of that asset. F-8
PRIMEENERGY CORPORATION and SUBSIDIARIES NOTES to CONSOLIDATED FINANCIAL STATEMENTS ---------- Property and Equipment: The Company follows the "successful efforts" method of accounting for its oil and gas properties. Under the successful efforts method, costs of acquiring undeveloped oil and gas leasehold acreage, including lease bonuses, brokers' fees and other related costs are capitalized. Provisions for impairment of undeveloped oil and gas leases are based on periodic evaluations. Annual lease rentals and exploration expenses, including geological and geophysical expenses and exploratory dry hole costs, are charged against income as incurred. Costs of drilling and equipping productive wells, including development dry holes and related production facilities, are capitalized. Costs incurred by the Company related to the exploration, development and acquisition of oil and gas properties on behalf of the Partnerships or joint ventures are deferred and charged to the related entity upon the completion of the acquisition. To the extent that the Company acquires an interest in the property, an appropriate allocation of internal costs are capitalized as part of the depletable base of the property. All other property and equipment are carried at cost. Depreciation and depletion of oil and gas production equipment and properties are determined under the unit-of-production method based on estimated proved recoverable oil and gas reserves. Depreciation of all other equipment is determined under the straight-line method using various rates based on useful lives. The cost of assets and related accumulated depreciation is removed from the accounts when such assets are disposed of, and any related gains or losses are reflected in current earnings. Income Taxes: The Company records income taxes in accordance with Statement of Financial Accounting Standards ("SFAS") No. 109, "Accounting for Income Taxes." SFAS No. 109 is an asset and liability approach to accounting for income taxes, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been recognized in the Company's financial statements or tax returns. Deferred tax liabilities or assets are established for temporary differences between financial and tax reporting bases and are subsequently adjusted to reflect changes in the rates expected to be in effect when the temporary differences reverse. A valuation allowance is established for any deferred tax asset for which realization is not likely. General and Administrative Expenses: General and administrative expenses represent costs and expenses associated with the operation of the Company. Certain of the Partnerships sponsored by the Company reimburse general and administrative expenses incurred on their behalf. Income Per Common Share: Income per share of common stock has been computed based on the weighted average number of common shares outstanding during the respective periods in accordance with SFAS No. 128, "Earnings per Share". Statements of cash flows: For purposes of the consolidated statements of cash flows, the Company considers short-term, highly liquid investments with original maturities of less than ninety days to be cash equivalents. Concentration of Credit Risk: The Company maintains significant banking relationships with financial institutions in the State of Texas. The Company limits its risk by periodically evaluating the relative credit standing of these financial institutions. The Company's oil and gas production purchasers consist primarily of independent marketers and major gas pipeline companies. F-9
PRIMEENERGY CORPORATION and SUBSIDIARIES NOTES to CONSOLIDATED FINANCIAL STATEMENTS ---------- Hedging: From time to time, the Company may enter into futures contracts in order to reduce its exposure related to changes in oil and gas prices. In accordance with Statement of Financial Accounting Standards No. 133, any gain or loss on such contracts is treated as an adjustment to oil and gas revenue. Cash activity related to hedging transactions is treated as operating activity on the Statements of Cash Flows. Recently Issued Accounting Standards: In December 1999, the Securities and Exchange Commission issued Staff Accounting Bulletin No.101, Revenue Recognition in Financial Statements ("SAB No. 101"). SAB No. 101 provides guidance for revenue recognition under certain circumstances. The adoption of SAB 101 in 2000 did not have a significant impact on the Company's financial position, results of operations or cash flows. In July 2001, the Financial Accounting Standards Board ("FASB") issued SFAS No. 141, "Business Combinations." SFAS No. 141 is intended to improve the transparency of the accounting and reporting for business combinations by requiring that all business combinations be accounted for under a single method - the purchase method. SFAS 141 is effective for all transactions completed after June 30, 2001, except transactions using the pooling-of-interests method that were initiated prior to July 1, 2001. The adoption of SFAS 141 did not have an impact on the Company's consolidated financial statements. In July 2001, the FASB issued SFAS No. 142, "Goodwill and Other Intangible Assets." This statement applies to intangibles and goodwill acquired after June 30, 2001, as well as goodwill and intangibles previously acquired. Under this statement, goodwill as well as other intangibles determined to have an infinite life will no longer be amortized; however, these assets will be reviewed for impairment on a periodic basis. This statement is effective for the Company for the first quarter in the fiscal year ending December 31, 2002. Management does not believe that the adoption of this statement will have a material effect on the Company's financial statements. In August 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 requires the fair value of a liability for an asset retirement obligation to be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002. Management has not yet determined the impact of the adoption of this statement. In October 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." SFAS No. 144 requires that long-lived assets be measured at the lower of carrying amount or fair value less cost to sell, whether reported in continuing operations or in discontinued operations. Therefore, discontinued operations will no longer be measured at net realizable value or include amounts for operating losses that have not yet occurred. SFAS No. 144 is effective for financial statements issued for fiscal years beginning after December 15, 2001 and generally, is to be applied prospectively. Management does not believe that the adoption of this statement will have a material effect on the Company's financial statements. 2. SIGNIFICANT ACQUISITIONS AND DISPOSITIONS 2001 As more fully described in Note 7, the Company is committed to offer to repurchase the interests of the limited partners and trust unitholders in certain of the Partnerships. During 2001, the Company purchased such interests in an amount totaling $545,000. F-10
PRIMEENERGY CORPORATION and SUBSIDIARIES NOTES to CONSOLIDATED FINANCIAL STATEMENTS ---------- 2000 Effective January 1, 2000, the Company purchased additional interests in the San Pedro Ranch field of Dimmit and Maverick Counties, Texas for $150,000. Effective April 1, 2000, the Company purchased additional interest in the Eola Robberson field of Garvin County, Oklahoma for $400,000. These interests are related to certain contingency payments created at the time the Company made its original acquisition of the field in 1988, and are based on property performance. Effective July 1, 2000, the Company invested $265,000 in the purchase of various interests in five leases located in Garvin County, Oklahoma. These leases contain 26 producing wells and 5 salt-water injection wells. The Company assumed operation of the wells, which at the time of the acquisition were collectively producing 61 (26.63 net) barrels of oil per day. In September of 2000, the Company purchased nine wells in Upton Co. Texas. In October, the Company began a series of workovers to tap additional oil and gas behind pipe reserves in the wells. Through March, 2001 the Company has performed workovers on five of the nine wells, resulting in a three fold increase in oil production and over a six fold increase in gas production. Currently the acquisition is producing at a rate of 55 (39 net) barrels of oil per day and 250 (177 net) Mcf of gas per day. The Company owns from 94% to 100% working interest and 69% to 73% net revenue interest in the properties. As more fully described in Note 7, the Company is committed to offer to repurchase the interests of the limited partners and trust unitholders in certain of the Partnerships. During 2000, the Company purchased such interests in an amount totaling $1,257,000. 1999 On November 15, 1999, the Company purchased interests in approximately 131 oil and gas wells located in various counties in Oklahoma. The Company already owned, and was the operator of, the majority of the properties purchased. As more fully described in Note 7, the Company is committed to offer to repurchase the interests of the limited partners and trust unitholders in certain of the Partnerships. During 1999, the Company purchased such interests in an amount totaling $1,038,000. 3. ACCOUNTS RECEIVABLE Accounts receivable at December 31, 2001 and 2000 consisted of the following: <Table> <Caption> December 31, ---------------------------- 2001 2000 ----------- ----------- <S> <C> <C> Joint interest billing $ 1,372,000 $ 1,352,000 Trade receivables 1,151,000 967,000 Oil and gas sales 1,460,000 3,310,000 Other 154,000 180,000 ----------- ----------- 4,137,000 5,809,000 Less, allowance for doubtful accounts (339,000) (146,000) ----------- ----------- Total $ 3,798,000 $ 5,663,000 =========== =========== </Table> F-11
PRIMEENERGY CORPORATION and SUBSIDIARIES NOTES to CONSOLIDATED FINANCIAL STATEMENTS ---------- 4. OTHER CURRENT ASSETS Other current assets at December 31, 2001 and 2000 consisted of the following: <Table> <Caption> December 31, ------------------------- 2001 2000 ---------- ---------- <S> <C> <C> Tax overpayments $ 708,000 $ -- Field service inventory 268,000 127,000 Other 30,000 7,000 ---------- ---------- Total $1,006,000 $ 134,000 ========== ========== </Table> During 2001 the Company estimated that its liability for the 2001 tax year would be approximately $1,000,000, and made estimated tax payments accordingly. Due primarily to a significant investment in tax deductible intangible drilling costs, along with a sharp drop in oil and gas prices, the current estimate is substantially less. The Company expects to receive approximately $500,000 in tax refunds during the second quarter of 2002, with the remainder of the overpaid amount being applied to estimated 2002 tax year liabilities. See Note 9 for a further discussion of the company's tax situation. 5. LONG-TERM BANK DEBT The Company has been party to a series of credit agreements with its primary lender or its predecessors since 1983. The current agreement, entered into in April 1995, provides for borrowings under a Master Note. Advances under the agreement, as amended, are limited to the borrowing base as defined in the agreement. The borrowing base is re-determined by the lender on a semi-annual basis. Since the beginning of 1999, the borrowing base has ranged from $20 million to $23.7 million. The credit agreement provides for interest on outstanding borrowings at the bank's base rate, as defined, payable monthly, or at rates ranging from 1 1/2% to 2% over the London Inter-Bank Offered Rate (LIBO rate) depending upon the Company's utilization of the available line of credit, payable at the end of the applicable interest period. The average interest rates paid on outstanding borrowings subject to interest at the bank's base rate during 2001 and 2000 were 6.92% and 9.46%, respectively. During the same periods, the average rates paid on outstanding borrowings bearing interest based upon the LIBO rate were 5.98% and 8.46%. As of December 31, 2001 and 2000, the total outstanding borrowings were $16,950,000 and $17,200,000, respectively, with an additional $6,050,000 and $1,750,000 available, and $14,950,000 and $13,500,000 of the amounts outstanding accruing interest at the LIBO rate option. The Company's oil and gas properties as well as certain receivables and equipment are pledged as security under the loan agreement. The agreement requires the Company to maintain, as defined, a minimum current ratio, tangible net worth, debt coverage ratio and interest coverage ratio, and restrictions are placed on the payment of dividends and the amount of treasury stock the Company may purchase. 6. COMMITMENTS Operating Leases: The Company has several noncancelable operating leases, primarily for rental of office space, that have a term of more than one year. Capital Leases: The Company has one capital lease for office equipment in other long-term obligations. F-12
PRIMEENERGY CORPORATION and SUBSIDIARIES NOTES to CONSOLIDATED FINANCIAL STATEMENTS ---------- Future minimum lease payments under operating and capital leases are as follows: <Table> <Caption> Operating Capital Leases Leases ----------- ----------- <S> <C> <C> 2002 $ 488,000 $ 6,000 2003 434,000 6,000 2004 83,000 3,000 2005 5,000 -- Thereafter -- -- ----------- ----------- Total minimum payments $ 1,010,000 15,000 =========== Less imputed interest (2,000) ----------- Present value of minimum Lease payments $ 13,000 =========== </Table> 7. CONTINGENT LIABILITIES The Company, as managing general partner of the affiliated Partnerships, is responsible for all Partnership activities, including the review and analysis of oil and gas properties for acquisition, the drilling of development wells and the production and sale of oil and gas from productive wells. The Company also provides the administration, accounting and tax preparation work for the Partnerships, and is liable for all debts and liabilities of the affiliated Partnerships, to the extent that the assets of a given limited Partnership are not sufficient to satisfy its obligations. The Company is subject to environmental laws and regulations. Management believes that future expenses, before recoveries from third parties, if any, will not have a material effect on the Company's financial condition. This opinion is based on expenses incurred to date for remediation and compliance with laws and regulations which have not been material to the Company's results of operations. As a general partner, the Company is committed to offer to purchase the limited partners' interest in certain of its managed Partnerships at various annual intervals. Under the terms of a partnership agreement, the Company is not obligated to purchase an amount greater than 10% of the total partnership interest outstanding. In addition, the Company will be obligated to purchase interests tendered by the limited partners only to the extent of one hundred fifty percent of the revenues received by it from such partnership in the previous year. Purchase prices are based upon annual reserve reports of independent petroleum engineering firms discounted by a risk factor. Based upon historical production rates and prices, management estimates that if all such offers were to be accepted, the maximum annual future purchase commitment would be approximately $500,000. In connection with the purchase of oil and gas properties located in various counties in Oklahoma in November of 1999, the Company is committed to pay contingent consideration to the seller based upon the performance of the properties purchased. As of December 31, 2000, the total amount of contingent consideration estimated to be paid under the agreement was $1,850,000. $1,000,000 of this obligation was included in 'Other long-term obligations' with the remaining $850,000 included in 'Current portion of other long-term obligations'. In 2001 the total estimated amount of consideration to be paid was reduced by $862,000 to $988,000 of which $763,000 was paid during 2001, leaving a net estimated amount due of $225,000 as of December 31, 2001, all of which is included in 'Current portion of other long-term obligations'. F-13
PRIMEENERGY CORPORATION and SUBSIDIARIES NOTES to CONSOLIDATED FINANCIAL STATEMENTS, Continued ---------- 8. STOCK OPTIONS AND OTHER COMPENSATION In May 1989, non-statutory stock options were granted by the Company to four key executive officers for the purchase of shares of common stock. At December 31, 2001 and 2000, options on 767,500 shares were outstanding and exercisable at prices ranging from $1.00 to $1.25. On January 27, 1983, the Company adopted the 1983 Incentive Stock Option Plan. At December 31, 2000, options on 87,000 shares were exercisable at $1.50 per share. During July 2001, all outstanding options under this plan were exercised. PEMC has a marketing agreement with its current President to provide assistance and advice to PEMC in connection with the organization and marketing of oil and gas partnerships and joint ventures and other investment vehicles of which PEMC is to serve as general or managing partner. The Company had a similar agreement with its former Chairman. Although that agreement has expired, the former Chairman is still entitled to receive certain payments relating to partnerships formed during the time the agreement was in effect. The President is entitled to a percentage of the Company's carried interest depending on total capital raised and annual performance of the Partnerships and joint ventures. 9. INCOME TAXES The components of the provision for income taxes for the years ended December 31, 2001, 2000 and 1999 are as follows: <Table> <Caption> 2001 2000 1999 ---------- ---------- ---------- <S> <C> <C> <C> Federal: Current $ 25,000 $ 201,000 $ 32,000 Deferred 1,500,000 141,000 -- State: Current 13,000 254,000 37,000 Deferred 183,000 215,000 (39,000) ---------- ---------- ---------- Total $1,721,000 $ 811,000 $ 30,000 ========== ========== ========== </Table> F-14
PRIMEENERGY CORPORATION and SUBSIDIARIES NOTES to CONSOLIDATED FINANCIAL STATEMENTS, Continued ---------- The components of net deferred tax assets (liabilities) are as follows: <Table> <Caption> December 31, December 31, 2001 2000 ------------ ------------ <S> <C> <C> Current assets: Compensation and benefits $ 185,000 $ 147,000 Allowance for doubtful accounts 89,000 8,000 ----------- ----------- 274,000 155,000 ----------- ----------- Noncurrent assets: Depreciation 387,000 346,000 Due from related parties reserve 312,000 312,000 Federal net operating loss carryforwards 124,000 249,000 Percentage depletion carryforwards 367,000 597,000 Alternative minimum tax credits 943,000 918,000 ----------- ----------- 2,133,000 2,422,000 ----------- ----------- Noncurrent liabilities: Basis differences relating to limited partnerships (1,798,000) (1,751,000) Depletion (2,649,000) (1,182,000) ----------- ----------- (4,447,000) (2,933,000) ----------- ----------- Net deferred tax liabilities: $ 2,040,000 $ 356,000 =========== =========== </Table> The total provision for income taxes for the years ended December 31, 2001, 2000 and 1999 varies from the federal statutory tax rate as a result of the following: <Table> <Caption> December 31, December 31, December 31, 2001 2000 1999 ------------ ------------ ------------ <S> <C> <C> <C> Expected tax expense (benefit) $ 2,426,000 $ 2,100,000 $ (717,000) State income tax, net of federal benefit 196,000 469,000 (2,000) Overaccrual of prior year refunds receivable -- -- 32,000 Effect of valuation reserve against tax assets -- -- 717,000 Benefit from net operating losses and other carryforwards previously reserved against -- (1,670,000) -- Credit for producing fuel from a non-conventional source (299,000) (88,000) -- Percentage depletion (602,000) -- -- ----------- ----------- ----------- Tax expense $ 1,721,000 $ 811,000 $ 30,000 =========== =========== =========== </Table> In both 1998 and 1999 the Company had large federal net operating losses. The value of these loss carryforwards was fully reserved against due to the uncertainty as to whether the Company would have F-15
PRIMEENERGY CORPORATION and SUBSIDIARIES NOTES to CONSOLIDATED FINANCIAL STATEMENTS, Continued ---------- future net income against which these losses could be offset. The use of these previously reserved against carryforwards were the primary reason for the low federal rate in the 2000 tax year. Subject to certain limitations, the Company is allowed to deduct, rather than capitalize, intangible drilling costs incurred on successful wells. The Company incurred over $5,000,000 of intangible drilling costs in 2001, and these deductions are largely responsible for the extremely low current tax expense. However, the deduction of these items for tax, while they are capitalized for financial reporting purposes, create differences in the depletable basis of oil and gas properties which create deferred tax liability and expense. The Company has $366,000 of net operating loss carryforwards for both regular and alternate minimum tax purposes. These carryforwards expire in 2002. The Company currently generates approximately $350,000 per year in federal tax credits for producing fuel from a non-conventional source. These credits may be used to reduce the regular tax, but not the alternative minimum tax liability of the taxpayer. To the extent they cannot be utilized due to the alternative minimum tax, they become part of the Company's alternative minimum tax credit carryforward. This credit is scheduled to expire at the end of the 2002 tax year. The Company has percentage depletion carryforwards of approximately $942,000 for regular tax purposes and $168,000 for alternative minimum tax purposes. The Company has approximately $943,000 in alternative minimum tax credit carryforwards. Both the percentage depletion deductions and the alternative minimum tax credits may be carried forward indefinitely for tax purposes. 10. SEGMENT INFORMATION AND MAJOR CUSTOMERS The Company operates in one industry - oil and gas exploration, development, operation and servicing. The Company's oil and gas activities are entirely in the continental United States. The Company sells its oil and gas production to a number of purchasers. Listed below are the percent of the Company's total oil and gas sales made to each of the customers whose purchases represented more than 10% of the Company's oil and gas sales in the year 2001. <Table> <S> <C> Texon Distributing L.P. 19.70% Unimark LLC 13.79% </Table> Although there are no long-term oil and gas purchasing agreements with these purchasers, the Company believes that they will continue to purchase its oil and gas products and, if not, could be replaced by other purchasers. 11. RELATED PARTY TRANSACTIONS PEMC is a general partner in several oil and gas Partnerships in which certain directors have limited and general partnership interests. As the managing general partner in each of the Partnerships, PEMC receives approximately 5% to 15% of the net revenues of each Partnership as a carried interest in the Partnerships' properties. The Partnership agreements allow PEMC to receive management fees for various services to the Partnerships as well as a reimbursement for property acquisition and development costs incurred on behalf of the Partnerships and general and administrative overhead, which is reported in the statements of operations as administrative revenue. Due to related parties at December 31, 2001 and 2000 primarily represent receipts collected by the Company, as agent, from oil and gas sales net of expenses. The amount of such receipts due the F-16
PRIMEENERGY CORPORATION and SUBSIDIARIES NOTES to CONSOLIDATED FINANCIAL STATEMENTS, Continued ---------- affiliated Partnerships was $983,000 and $1,265,000 at December 31, 2001 and 2000, respectively. Receivables from related parties consist of reimbursable general and administrative costs, lease operating expenses and reimbursements for property acquisitions, development, and related costs. Treasury stock purchases in 2001 and 2000 included shares acquired from related parties. Purchases from related parties include a total of 228,800 shares purchased for a total consideration of $1,676,000 in 2001, and 40,700 shares purchased for a total consideration of $276,900 in 2000. 12. RESTRICTED CASH AND CASH EQUIVALENTS Restricted cash and cash equivalents includes $1,174,000 and $1,128,000 at December 31, 2001 and 2000, respectively, of cash primarily pertaining to unclaimed royalty payments. There were corresponding accounts payable recorded at December 31, 2001 and 2000 for these liabilities. 13. SALARY DEFERRAL PLAN The Company maintains a salary deferral plan (the "Plan") in accordance with Internal Revenue Code Section 401(k), as amended. The Plan provides for discretionary and matching contributions which approximated $255,000 and $226,000 in 2001 and 2000, respectively. 14. ACCOUNTS PAYABLE A summary of accounts payable at December 31, 2001 and 2000 is as follows: <Table> <Caption> 2001 2000 ---------- ---------- <S> <C> <C> Payables to unaffiliated interests $5,743,000 $6,783,000 Other 45,000 45,000 ---------- ---------- $5,788,000 $6,828,000 ========== ========== </Table> 15. EARNINGS PER SHARE Basic earnings per share are computed by dividing earnings available to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per share reflect per share amounts that would have resulted if dilutive potential common stock had been converted to common stock. The following reconciles amounts reported in the financial statements: <Table> <Caption> Year ended December 31, 2001 ---------------------------------------- Number of Per share Net Income Shares Amount ---------- ---------- ---------- <S> <C> <C> <C> Net income per common share $5,413,000 3,882,721 $ 1.39 Effect of dilutive securities: Options 709,384 ---------- ---------- ---------- Diluted net income per common share $5,413,000 4,592,105 $ 1.18 ========== ========== ========== </Table> F-17
PRIMEENERGY CORPORATION and SUBSIDIARIES NOTES to CONSOLIDATED FINANCIAL STATEMENTS, Continued ---------- <Table> <Caption> Year ended December 31, 2000 ---------------------------------------- Number of Per share Net Income Shares Amount ---------- ---------- ---------- <S> <C> <C> <C> Net income per common share $5,365,000 4,266,186 $ 1.26 Effect of dilutive securities: Options 686,057 ---------- ---------- ---------- Diluted net income per common share $5,365,000 4,952,243 $ 1.08 ========== ========== ========== </Table> <Table> <Caption> Year ended December 31, 1999 ---------------------------------------- Number of Per share Net Income Shares Amount ---------- ---------- ------------ <S> <C> <C> <C> Net loss per common share $(2,138,000) 4,423,838 $ (0.48) Effect of dilutive securities: Options(1) -- ----------- --------- ------------ Diluted net loss per common share $(2,138,000) 4,423,838 $ (0.48) =========== ========= ============ </Table> (1) For the year ended December 31, 1999, the number of options excluded from diluted loss per common share calculations was 706,604 as the conversion of these would have had an anti-dilutive effect on net loss per share. 16. SUBSEQUENT EVENTS In February of 2002, the Company reached a settlement regarding a claim for additional drilling costs incurred by the Company as a result of a third party's negligence. The $350,000 received in regard to this claim will be recognized as income in the first quarter of 2002. 17. SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED) <Table> <Caption> Year Ended December 31, Fourth Third Second First 2001 Quarter Quarter Quarter Quarter ----------- ----------- ----------- ----------- ----------- <S> <C> <C> <C> <C> <C> Revenue $42,408,000 $ 8,880,000 $10,103,000 $11,113,000 $12,312,000 Operating income 6,968,000 (67,000) 1,002,000 2,277,000 3,756,000 Net income 5,413,000 207,000 630,000 1,571,000 3,005,000 Net income per common share $ 1.39 $ .06 $ .16 $ .41 $ .76 Diluted net income per common share $ 1.18 $ .06 $ .14 $ .34 $ .64 </Table> F-18
PRIMEENERGY CORPORATION and SUBSIDIARIES NOTES to CONSOLIDATED FINANCIAL STATEMENTS, Continued ---------- <Table> <Caption> Year Ended December 31, Fourth Third Second First 2000 Quarter Quarter Quarter Quarter ----------- ----------- ----------- ----------- ----------- <S> <C> <C> <C> <C> <C> Revenue $39,182,000 $11,548,000 $11,113,000 $ 8,809,000 $ 7,712,000 Operating income 6,148,000 1,451,000 2,605,000 1,501,000 591,000 Net income 5,365,000 1,221,000 2,294,000 1,332,000 518,000 Net income per common share $ 1.26 $ .29 $ .54 $ .31 $ .12 Diluted net income per common share $ 1.08 $ .24 $ .47 $ .27 $ .10 </Table> F-19
PRIMEENERGY CORPORATION AND SUBSIDIARIES SUPPLEMENTARY INFORMATION ---------- (UNAUDITED) F-20
PRIMEENERGY CORPORATION and SUBSIDIARIES CAPITALIZED COSTS RELATING to OIL and GAS PRODUCING ACTIVITIES December 31, 2001, 2000 and 1999 ---------- (Unaudited) <Table> <Caption> 2001 2000 1999 ----------- ----------- ----------- <S> <C> <C> Developed oil and gas properties $63,418,000 $57,439,000 $49,249,000 Undeveloped oil and gas properties 286,000 159,000 235,000 ----------- ----------- ----------- 63,704,000 57,598,000 49,484,000 Accumulated depreciation, depletion and valuation allowance 42,924,000 37,686,000 32,342,000 ----------- ----------- ----------- Net capitalized costs $20,780,000 $19,912,000 $17,142,000 =========== =========== =========== </Table> COSTS INCURRED in OIL and GAS PROPERTY ACQUISITION, EXPLORATION and DEVELOPMENT ACTIVITIES Years ended December 31, 2001, 2000 and 1999 ---------- (Unaudited) <Table> <Caption> 2001 2000 1999 ---------- ---------- ----------- <S> <C> <C> Acquisition of properties: Developed $ 316,000 $4,679,000 $ 3,042,000 Undeveloped 164,000 106,000 189,000 Exploration costs 509,000 1,797,000 806,000 Development costs 5,661,000 3,351,000 4,473,000 </Table> See accompanying notes to supplementary information. F-21
PRIMEENERGY CORPORATION and SUBSIDIARIES STANDARDIZED MEASURE of DISCOUNTED FUTURE NET CASH FLOWS RELATING to PROVED OIL and GAS RESERVES Years ended December 31, 2001, 2000 and 1999 ---------- (Unaudited) <Table> <Caption> 2001 2000 1999 ------------- ------------- ------------ <S> <C> <C> Future cash inflows $ 102,916,000 $ 315,680,000 $100,177,000 Future production and development costs (60,841,000) (116,417,000) (58,807,000) Future income tax expenses (7,930,000) (59,914,000) (4,229,000) ------------- ------------- ------------ Future net cash flows 34,145,000 139,349,000 37,141,000 10% annual discount for estimated timing of cash flow (13,179,000) (59,339,000) (13,281,000) ------------- ------------- ------------ Standardized measure of discounted future net cash flow $ 20,966,000 $ 80,010,000 $23,860,000 ============= ============= ============ </Table> See accompanying notes to supplementary information. F-22
PRIMEENERGY CORPORATION and SUBSIDIARIES STANDARDIZED MEASURE of DISCOUNTED FUTURE NET CASH FLOWS and CHANGES THEREIN RELATING to PROVED OIL and GAS RESERVES Years ended December 31, 2001, 2000 and 1999 ---------- (Unaudited) The following are the principal sources of change in the standardized measure of discounted future net cash flows during 2001, 2000 and 1999: <Table> <Caption> 2001 2000 1999 ------------ ------------ ------------ <S> <C> <C> <C> Sales of oil and gas produced, net of production costs $(11,915,000) $(14,109,000) $(5,458,000) Net changes in prices and production costs (92,118,000) 69,822,000 3,192,000 Extensions, discoveries and improved recovery, less recovery costs 3,335,000 13,705,000 6,188,000 Revisions of previous quantity estimates 422,000 3,577,000 2,178,000 Reserves purchased, net of development costs 1,082,000 11,698,000 4,818,000 Net change in development costs (594,000) (99,000) 150,000 Accretion of discount 8,001,000 2,386,000 1,328,000 Net change in income taxes 33,127,000 (30,779,000) (1,973,000) Other (384,000) (51,000) 156,000 ------------ ------------ ------------ Net change (59,044,000) 56,150,000 10,579,000 Standardized measure of discounted future net cash flow: Beginning of year 80,010,000 23,860,000 13,281,000 ------------ ------------ ------------ End of year $ 20,966,000 $ 80,010,000 $23,860,000 ============ ============ ============ </Table> See accompanying notes to supplementary information F-23
PRIMEENERGY CORPORATION and SUBSIDIARIES RESERVE QUANTITY INFORMATION Years ended December 31, 2001, 2000 and 1999 ---------- (Unaudited) <Table> <Caption> 2001 2000 1999 ---------------------------- ---------------------------- ---------------------------- Gas Oil Gas Oil Gas Oil (Mcf) (bbls.) (Mcf) (bbls.) (Mcf) (bbls.) ----------- ----------- ----------- ----------- ----------- ----------- <S> <C> <C> <C> <C> <C> <C> Proved developed and undeveloped reserves: Beginning of year 27,029,000 2,362,000 22,202,000 2,110,000 17,341,000 1,200,000 Extensions, discoveries and improved recovery 2,764,000 136,000 1,961,000 13,000 1,732,000 554,000 Revisions of previous estimates (2,458,000) (307,000) 3,763,000 162,000 1,853,000 346,000 Purchases 1,148,000 111,000 3,034,000 375,000 4,565,000 274,000 Production (3,764,000) (306,000) (3,931,000) (298,000) (3,289,000) (264,000) ----------- ----------- ----------- ----------- ----------- ----------- End of year 24,719,000 1,996,000 27,029,000 2,362,000 22,202,000 2,110,000 =========== =========== =========== =========== =========== =========== Proved developed reserves 24,226,000 1,996,000 27,029,000 2,362,000 22,046,000 2,110,000 =========== =========== =========== =========== =========== =========== </Table> See accompanying notes to supplementary information F-24
PRIMEENERGY CORPORATION and SUBSIDIARIES RESULTS of OPERATIONS from OIL and GAS PRODUCING ACTIVITIES Years ended December 31, 2001, 2000 and 1999 ---------- (Unaudited) <Table> <Caption> 2001 2000 1999 ----------- ----------- ----------- <S> <C> <C> <C> <C> Revenue: Oil and gas sales $22,998,000 $23,223,000 $11,763,000 ----------- ----------- ----------- Costs and expenses: Lease operating expense 11,083,000 9,114,000 6,305,000 Exploration costs 509,000 1,717,000 869,000 Depreciation and depletion 4,544,000 5,060,000 4,581,000 Write down of oil and gas properties 753,000 295,000 2,703,000 Income tax expense 1,473,000 811,000 30,000 ----------- ----------- ----------- 18,362,000 16,997,000 $14,488,000 ----------- ----------- ----------- Results of operations from producing activities (excluding corporate overhead and interest costs) $ 4,636,000 $ 6,226,000 $(2,725,000) =========== =========== =========== </Table> See accompanying notes to supplementary information F-25
PRIMEENERGY CORPORATION and SUBSIDIARIES NOTES to SUPPLEMENTARY INFORMATION ---------- (Unaudited) 1. PRESENTATION OF RESERVE DISCLOSURE INFORMATION Reserve disclosure information is presented in accordance with the provisions of Statement of Financial Accounting Standards No. 69 ("SFAS 69"), "Disclosures About Oil and Gas Producing Activities". 2. DETERMINATION OF PROVED RESERVES The estimates of the Company's proved reserves were determined by an independent petroleum engineer in accordance with the provisions of SFAS 69. The estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development and other factors. Estimated future net revenues were computed by reserves, less estimated future development and production costs based on current costs. 3. RESULTS OF OPERATIONS FROM OIL AND GAS PRODUCING ACTIVITIES The results of operations from oil and gas producing activities were prepared in accordance with the provisions of SFAS 69. General and administrative expenses, interest costs and other unrelated costs are not deducted in computing results of operations from oil and gas activities. 4. STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS AND CHANGES THEREIN RELATING TO PROVED OIL AND GAS RESERVES The standardized measure of discounted future net flows relating oil and gas reserves and the changes of standardized measure of discounted future net cash flows relating to proved oil and gas reserves were prepared in accordance with the provisions of SFAS 69. Future cash inflows are computed as described in Note 2 by applying current prices to year-end quantities of proved reserves. Future production and development costs are computed estimating the expenditures to be incurred in developing and producing the oil and gas reserves at year-end, based on year-end costs and assuming continuation of existing economic conditions. Future income tax expenses are calculated by applying the year-end U.S. tax rate to future pre-tax cash inflows relating to proved oil and gas reserves, less the tax basis of properties involved. Future income tax expenses give effect to permanent differences and tax credits and allowances relating to the proved oil and gas reserves. Future net cash flows are discounted at a rate of 10% annually (pursuant to SFAS 69) to derive the standardized measure of discounted future net cash flows. This calculation does not necessarily represent an estimate of fair market value or the present value of such cash flows since future prices and costs can vary substantially from year-end and the use of a 10% discount figure is arbitrary. F-26
EXHIBIT INDEX <Table> <Caption> EXHIBIT NUMBER DESCRIPTION - ------- ----------- <S> <C> 3.1 Restated Certificate of Incorporation of PrimeEnergy Corporation. (Incorporated herein by reference to Exhibit 3.1 of PrimeEnergy Corporation Form 10-KSB for the year ended December 31, 1999) 3.2 Bylaws of PrimeEnergy Corporation. (Incorporated herein by reference to Exhibit 3.2 of PrimeEnergy Corporation Form 10-KSB for the year ended December 31, 1999) 10.1 PrimeEnergy Corporation 1983 Incentive Stock Option Plan (Incorporated herein by reference to Exhibit 10.1 of PrimeEnergy Corporation Form 10-KSB for the year ended December 31, 1994)(1) 10.3 Massachusetts Mutual Flexinvest 401(k) Plan as amended and restated. (Incorporated herein by reference to Exhibit 10.3 of PrimeEnergy Corporation Form 10-KSB for the year ended December 31, 1994)(1) 10.7 Credit Agreement dated April 26, 1995, between PrimeEnergy Corporation, PrimeEnergy Management Corporation and Bank One, Texas, National Association. (Incorporated herein by reference to Exhibit 10.7 to PrimeEnergy Corporation Form 8-K dated April 26, 1995) 10.7.1 First Amendment to Credit Agreement Among PrimeEnergy Corporation and PrimeEnergy Management Corporation, as Borrowers, Bank One, Texas, National Association, as Agent, and the Lenders Signatory Hereto, effective as of October 6, 1995. (Incorporated herein by reference to Exhibit 10.7.1 to PrimeEnergy Corporation Form 10-KSB for the year ended December 31, 1995) 10.7.2 Second Amendment to Credit Agreement Among PrimeEnergy Corporation and PrimeEnergy Management Corporation, as Borrowers, Bank One, Texas, National Association, as Agent, and the Lenders Signatory Hereto, effective as of February 6, 1997. (Incorporated by reference to Exhibit 10.7.2 of PrimeEnergy Corporation Form 10-KSB for the year ended December 31, 1996) 10.7.3 Third Amendment to Credit Agreement Among PrimeEnergy Corporation and PrimeEnergy Management Corporation, as Borrowers, Bank One, Texas, National Association, as Agent, and the Lenders Signatory Hereto, effective as of January 2, 1998 (Incorporated by reference to Exhibit 10.7.3 of PrimeEnergy Corporation Form 10-KSB for the year ended December 31, 1997) 10.8 Mortgage, Deed or Trust, Indenture, Security Agreement, Financing Statement and Assignment of Production dated May 27, 1994, as ratified and amended April 26, 1995, between PrimeEnergy Corporation, PrimeEnergy Management Corporation and Bank One, Texas, National Association. (Incorporated by reference to Exhibit 10.8 of PrimeEnergy Corporation Form 8-K dated April 26, 1995) 10.17 Amended Marketing Agreement between PrimeEnergy Management Corporation and Charles E. Drimal, Jr. (Incorporated herein by reference to Exhibit 10.17 of PrimeEnergy Corporation Form 10-KSB for the year ended December 31, 1994)(1) 10.18 Composite copy of Non-Statutory Option Agreements (Incorporated by reference to Exhibit 10.18 of PrimeEnergy Corporation for 10KSB for the year ended December 31, 1997)(1) 10.21 Purchase and Sale Agreement dated November 16, 1999 between Southern Pacific Petroleum U.S.A. and PrimeEnergy Corporation (Incorporated herein by reference to Exhibit 10.21 to PrimeEnergy Corporation Form 8-K dated November 24, 1999) 21 Subsidiaries. (filed herewith) 23 Consent of Ryder Scott & Company L.P. Company. (filed herewith) </Table> - ---------- (1) Management contract or compensatory plan or arrangement required to be filed as an Exhibit to this Form 10-K.