PRIMEENERGY RESOURCES CORP - Annual Report: 2003 (Form 10-K)

U.S. SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

or

Commission File Number 0-7406

PrimeEnergy Corporation

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.

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. [  ]

Indicate by check mark whether the Registrant is an accelerated filer as defined in Exchange Act Rule 12-b-2

The aggregate market value of the voting stock of the Registrant held by non-affiliates, computed by reference to the average bid and asked price of such common equity as of the last business day of the Registrant’s most recently completed second fiscal quarter, was $9,664,585.

The number of shares outstanding of each class of the Registrant’s Common Stock as of March 25, 2004 was: Common Stock, $0.10 par value, 3,612,472

DOCUMENTS INCORPORATED BY REFERENCE

PrimeEnergy Corporation

FORM 10-K ANNUAL REPORT
For the Fiscal Year Ended
December 31, 2003

PART I

Item 1. 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 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, the Gulf of Mexico, New Mexico, and Louisiana. 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 onshore oil and gas wells in which the Company has an interest, as well as for third parties. The Company owns and operates properties in the Gulf of Mexico through its sixty percent owned subsidiary F-W Oil Exploration L.L.C. (“FW”). The Company is also active in the acquisition of producing oil and gas properties through joint ventures with industry partners. The Company’s wholly-owned subsidiary, PrimeEnergy Management Corporation (“PEMC”), acts as the managing general partner in 18 oil and gas limited partnerships (the “Partnerships”) of which two are publicly held, and acts as the managing trustee of two asset and income business trusts (“the Trusts”).

Exploration, Development and Acquisition Activities

          The Company’s activities include development and exploratory drilling. The Company’s strategy is to develop a balanced portfolio of drilling prospects that includes lower risk wells with a high probability of success and higher risk wells with greater economic potential.

        In 2003, the Company drilled 25 gross (10.504 net) wells in its onshore operating areas at a cost of approximately $7 million. The Company also spent $10 million to acquire and develop properties in the Gulf of Mexico owned through FW.

        In 2004, the Company expects to spend approximately $16 million on development and exploratory drilling. The Company plans to spend approximately 40% onshore and approximately 60% of its drilling expenditures on higher risk and potentially more prolific offshore prospects.

        The Company believes that its diversified portfolio approach to its drilling activities results in more consistent and predictable economic results than might be experienced with a less diversified or higher risk drilling program profile.

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          The Company attempts to assume the position of operator in all acquisitions of producing properties. 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, the Gulf of Mexico, New Mexico, 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., “Properties,” 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., “Properties – Reserves” below.

Well Operations

          The Company’s on-shore 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 1,533 oil and gas wells, 427 through the Houston office, 160 through the Midland office, 458 through the Oklahoma City office and 450 through the Charleston, West Virginia office. Substantially all of the wells operated by the Company are wells in which the Company has an interest. The Company’s off-shore operations are conducted through FW, also in Houston, Texas.

          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.

The Partnerships ,Trusts and Joint Ventures

          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 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. The aggregate number of limited partners in the Partnerships and beneficial owners of the Trusts now administered by PEMC is approximately 4,600. This number, as well as the number of remaining partnerships noted above, has decreased in recent years as the Company continues to buy back limited partner interests. The total funds invested by Joint Venture Partners was $27.6 million.

          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. The Company stopped sponsoring partnerships and trusts in 1992. Today there are only 18 partnerships and two trusts remaining.

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Regulation

Regulation of Transportation and Sale of Natural Gas:

          Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938, as amended (“NGA”), the Natural Gas Policy Act of 1978, as amended (“NGPA”), and regulations promulgated there under by the Federal Energy Regulatory Commission (“FERC”) and its predecessors. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at uncontrolled market prices, Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the NGPA. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act, as amended (the “Decontrol Act”). The Decontrol Act removed all NGA and NGPA price and non-price controls affecting wellhead sales of natural gas effective January 1, 1993.

          Since 1985, FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. FERC has stated that open access policies are necessary to improve the competitive structure of the interstate natural gas pipeline industry and to create a regulatory framework that will put natural gas sellers into more direct contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services. Beginning in 1992, FERC issued Order No. 636 and a series of related orders (collectively, “Order No. 636”) to implement its open access policies. As a result of the Order No. 636 program, the marketing and pricing of natural gas have been significantly altered. The interstate pipelines’ traditional role as wholesalers of natural gas has been eliminated and replaced by a structure under which pipelines provide transportation and storage service on an open access basis to others who buy and sell natural gas. Although FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.

          In 2000, FERC issued Order No. 637 and subsequent orders (collectively, “Order No. 637”), which imposed a number of additional reforms designed to enhance competition in natural gas markets. Among other things, Order No. 637 revised FERC pricing policy by waiving price ceilings for short-term released capacity for a two-year experimental period, and effected changes in FERC regulations relating to scheduling procedures, capacity segmentation, penalties, rights of first refusal and information reporting. Most major aspects of Order No. 637 have been upheld on judicial review, and most pipelines’ tariff filings to implement the requirements of Order No. 637 have been accepted by the FERC and placed into effect.

          The Outer Continental Shelf Lands Act (“OCSLA”), which FERC implements as to transportation and pipeline issues, requires that all pipelines operating on or across the outer continental shelf (“OCS”) provide open access, non-discriminatory transportation service. One of FERC’s principal goals in carrying out OCSLA’s mandate is to increase transparency in the market to provide producers and shippers on the OCS with greater assurance of open access service on pipelines located on the OCS and non-discriminatory rates and conditions of service on such pipelines.

          It should be noted that FERC currently is considering whether to reformulate its test for defining non-jurisdictional gathering in the shallow waters of the OCS and, if so, what form that new test should take. The stated purpose of this initiative is to devise an objective test that furthers the goals of the NGA by protecting producers from the unregulated market power of third-party transporters of gas, while providing incentives for investment in production, gathering and transportation infrastructure offshore. While we cannot predict whether FERC’s gathering test ultimately will be revised and, if so, what form such revised test will take, any test that refunctionalizes as FERC-jurisdictional transmission facilities currently classified as gathering would impose an increased regulatory burden on the owner of those facilities by subjecting the facilities to NGA certificate and abandonment requirements and rate regulation.

          We cannot accurately predict whether FERC’s actions will achieve the goal of increasing competition in markets in which our natural gas is sold. Additional proposals and proceedings that might affect the natural gas industry are pending before FERC and the courts. The natural gas industry historically has been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach recently pursued by FERC will continue. However, we do not believe that any action taken will affect us in a way that materially differs from the way it affects other natural gas producers, gatherers and marketers.

          Intrastate natural gas transportation is subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we

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operate and ship natural gas on an intrastate basis will not affect our operations in any way that is materially different from the effect of such regulation on our competitors.

Regulation of Transportation of Oil:

          Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. The transportation of oil in common carrier pipelines is also subject to rate regulation. FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. In general, interstate oil pipeline rates must be cost-based, although settlement rates agreed to by all shippers are permitted and market-based rates may be permitted in certain circumstances. Effective January 1, 1995, FERC implemented regulations establishing an indexing system (based on inflation) for transportation rates for oil that allowed for an increase or decrease in the cost of transporting oil to the purchaser. A review of these regulations by the FERC in 2000 was successfully challenged on appeal by an association of oil pipelines. On remand, the FERC in February 2003 increased the index slightly, effective July 2001. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is materially different from the effect of such regulation on our competitors.

          Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors.

Regulation of Production:

          The production of oil and natural gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and plugging and abandonment and reports concerning operations. The states in which we own and operate properties have regulations governing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing, and plugging and abandonment of wells. Many states also restrict production to the market demand for oil and natural gas, and states have indicated interest in revising applicable regulations. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.

          Some of our offshore operations are conducted on federal leases that are administered by Minerals Management Service (“MMS”) and are required to comply with the regulations and orders promulgated by MMS under OCSLA. Among other things, we are required to obtain prior MMS approval for any exploration plans we pursue and our development and production plans for these leases. MMS regulations also establish construction requirements for production facilities located on our federal offshore leases and govern the plugging and abandonment of wells and the removal of production facilities from these leases. Under limited circumstances, MMS could require us to suspend or terminate our operations on a federal lease.

          MMS also establishes the basis for royalty payments due under federal oil and natural gas leases through regulations issued under applicable statutory authority. State regulatory authorities establish similar standards for royalty payments due under state oil and natural gas leases. The basis for royalty payments established by MMS and the state regulatory authorities is generally applicable to all federal and state oil and natural gas lessees. Accordingly, we believe that the impact of royalty regulation on our operations should generally be the same as the impact on our competitors.

          The failure to comply with these rules and regulations can result in substantial penalties. The regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.

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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.

          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.

          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

          Various federal, state and local laws and regulations governing the protection of the environment, such as the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (“CERCLA”), the Federal Water Pollution Control Act of 1972, as amended (the “Clean Water Act”), and the Federal Clean Air Act, as amended (the “Clean Air Act”), affect our operations and costs. In particular, our exploration, development and production operations, our activities in connection with storage and transportation of oil and other hydrocarbons and our use of facilities for treating, processing or otherwise handling hydrocarbons and related wastes may be subject to regulation under these and similar state legislation. These laws and regulations:

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Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal fines and penalties or the imposition of injunctive relief. Changes in environmental laws and regulations occur regularly, and any changes that result in more stringent and costly waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations and financial position, as well as those in the oil and natural gas industry in general. While we believe that we are in substantial compliance with current applicable environmental laws and regulations and that continued compliance with existing requirements would not have a material adverse impact on us, there is no assurance that this trend will continue in the future.

     As with the industry generally, compliance with existing regulations increases our overall cost of business. The areas affected include:

     Superfund. CERCLA, also known as “Superfund,” imposes liability for response costs and damages to natural resources, without regard to fault or the legality of the original act, on some classes of persons that contributed to the release of a “hazardous substance” into the environment. These persons include the “owner” or “operator” of a disposal site and entities that disposed or arranged for the disposal of the hazardous substances found at the site. CERCLA also authorizes the Environmental Protection Agency (“EPA”) and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In the course of our ordinary operations, we may generate waste that may fall within CERCLA’s definition of a “hazardous substance.” We may be jointly and severally liable under CERCLA or comparable state statutes for all or part of the costs required to clean up sites at which these wastes have been disposed.

     We currently own or lease properties that for many years have been used for the exploration and production of oil and natural gas. Although we and our predecessors have used operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed or released on, under or from the properties owned or leased by us or on, under or from other locations where these wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose actions with respect to the treatment and disposal or release of hydrocarbons or other wastes were not under our control. These properties and wastes disposed on these properties may be subject to CERCLA and analogous state laws. Under these laws, we could be required:

     At this time, we do not believe that we are associated with any Superfund site and we have not been notified of any claim, liability or damages under CERCLA.

     Oil Pollution Act of 1990. The Oil Pollution Act of 1990, as amended (the “OPA”) and regulations there under impose liability on “responsible parties” for damages resulting from oil spills into or upon navigable waters, ad adjoining shorelines or in the exclusive economic zone of the United States. Liability under OPA is strict, and under certain circumstances joint and several, and potentially unlimited. A “responsible party” includes the owner or operator of an onshore facility and the lessee or permittee of the area in which an offshore facility is located. The OPA also requires the lessee or permittee of the offshore area in which a covered offshore facility is located to establish and maintain evidence of financial responsibility in the amount of $35.0 million ($10.0 million if the offshore facility is located landward of the seaward boundary of a state) to cover liabilities related to an oil spill for which such person is statutorily responsible. The amount of required financial responsibility may be increased above the minimum amounts to an amount not exceeding $150.0 million depending on the risk represented by the quantity or quality of oil that is handled by the facility. We carry insurance coverage to meet these obligations, which we believe is customary for comparable companies in our industry. A failure to comply with OPA’s requirements or inadequate cooperation during a spill response action may subject a responsible party to civil or criminal enforcement actions. We are not aware of any action or event that would subject us to liability under OPA,

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and we believe that compliance with OPA’s financial responsibility and other operating requirements will not have a material adverse effect on us.

     U.S. Environmental Protection Agency. U.S. Environmental Protection Agency regulations address the disposal of oil and natural gas operational wastes under three federal acts more fully discussed in the paragraphs that follow. The Resource Conservation and Recovery Act of 1976, as amended (“RCRA”), provides a framework for the safe disposal of discarded materials and the management of solid and hazardous wastes. The direct disposal of operational wastes into offshore waters is also limited under the authority of the Clean Water Act. When injected underground, oil and natural gas wastes are regulated by the Underground Injection Control program under Safe Drinking Water Act. If wastes are classified as hazardous, they must be properly transported, using a uniform hazardous waste manifest, documented, and disposed at an approved hazardous waste facility. We have coverage under the Region VI National Production Discharge Elimination System Permit for discharges associated with exploration and development activities. We take the necessary steps to ensure all offshore discharges associated with a proposed operation, including produced waters, will be conducted in accordance with the permit.

     Resource Conservation Recovery Act. RCRA, is the principal federal statute governing the treatment, storage and disposal of hazardous wastes. RCRA imposes stringent operating requirements, and liability for failure to meet such requirements, on a person who is either a “generator” or “transporter” of hazardous waste or an “owner” or “operator” of a hazardous waste treatment, storage or disposal facility. At present, RCRA includes a statutory exemption that allows most oil and natural gas exploration and production waste to be classified as nonhazardous waste. A similar exemption is contained in many of the state counterparts to RCRA. As a result, we are not required to comply with a substantial portion of RCRA’s requirements because our operations generate minimal quantities of hazardous wastes. At various times in the past, proposals have been made to amend RCRA to rescind the exemption that excludes oil and natural gas exploration and production wastes from regulation as hazardous waste. Repeal or modification of the exemption by administrative, legislative or judicial process, or modification of similar exemptions in applicable state statutes, would increase the volume of hazardous waste we are required to manage and dispose of and would cause us to incur increased operating expenses.

     Clean Water Act. The Clean Water Act imposes restrictions and controls on the discharge of produced waters and other wastes into navigable waters. Permits must be obtained to discharge pollutants into state and federal waters and to conduct construction activities in waters and wetlands. Certain state regulations and the general permits issued under the Federal National Pollutant Discharge Elimination System program prohibit the discharge of produced waters and sand, drilling fluids, drill cuttings and certain other substances related to the oil and natural gas industry into certain coastal and offshore waters. Further, the EPA has adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain permits for storm water discharges. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans. The Clean Water Act and comparable state statutes provide for civil, criminal and administrative penalties for unauthorized discharges for oil and other pollutants and impose liability on parties responsible for those discharges for the costs of cleaning up any environmental damage caused by the release and for natural resource damages resulting from the release. We believe that our operations comply in all material respects with the requirements of the Clean Water Act and state statutes enacted to control water pollution.

     Safe Drinking Water Act. Underground injection is the subsurface placement of fluid through a well, such as the reinjection of brine produced and separated from oil and natural gas production. The Safe Drinking Water Act of 1974, as amended establishes a regulatory framework for underground injection, with the main goal being the protection of usable aquifers. The primary objective of injection well operating requirements is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. Hazardous-waste injection well operations are strictly controlled, and certain wastes, absent an exemption, cannot be injected into underground injection control wells. In Louisiana and Texas, no underground injection may take place except as authorized by permit or rule. We currently own and operate various underground injection wells. Failure to abide by our permits could subject us to civil and/or criminal enforcement. We believe that we are in compliance in all material respects with the requirements of applicable state underground injection control programs and our permits.

     Marine Protected Areas. Executive Order 13158, issued on May 26, 2000, directs federal agencies to safeguard existing Marine Protected Areas (“MPAs”)in the United States and establish new MPAs. The order requires federal agencies to avoid harm to MPAs to the extent permitted by law and to the maximum extent practicable. It also directs the EPA to propose new regulations under the Clean Water Act to ensure appropriate levels of protection for the marine environment. This order has the potential to adversely affect our operations by restricting areas in which we may carry out future development and exploration projects and/or causing us to incur increased operating expenses.

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     Marine Mammal and Endangered Species. Federal Lease Stipulations address the reduction of potential taking of protected marine species (sea turtles, marine mammals, Gulf Sturgen and other listed marine species). MMS permit approvals will be conditioned on collection and removal of debris resulting from activities related to exploration, development and production of offshore leases. MMS has issued Notices to Lessees and Operators (“NTL”) 2003-G06 advising of requirements for posting of signs in prominent places on all vessels and structures and of an observing training program.

     Consideration of Environmental Issues in Connection with Governmental Approvals. Our operations frequently require licenses, permits and/or other governmental approvals. Several federal statutes, including OCSLA, the National Environmental Policy Act (“NEPA”), and the Coastal Zone Management Act (“CZMA”) require federal agencies to evaluate environmental issues in connection with granting such approvals and/or taking other major agency actions. OCSLA, for instance, requires the U.S. Department of Interior (“DOI”) to evaluate whether certain proposed activities would cause serious harm or damage to the marine, coastal or human environment. Similarly, NEPA requires DOI and other federal agencies to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency would have to prepare an environmental assessment and, potentially, an environmental impact statement. CZMA, on the other hand, aids states in developing a coastal management program to protect the coastal environment from growing demands associated with various uses, including offshore oil and natural gas development. In obtaining various approvals from the DOI, we must certify that we will conduct our activities in a manner consistent with an applicable program.

     Lead-Based Paints. Various pieces of equipment and structures owned by us may have been coated with lead-based paints as was customary in the industry at the time these pieces of equipment were fabricated and constructed. These paints may contain lead at a concentration high enough to be considered a regulated hazardous waste when removed. If we need to remove such paints in connection with maintenance or other activities and they qualify as a regulated hazardous waste, this would increase the cost of disposal. High lead levels in the paint might also require us to institute certain administrative and/or engineering controls required by the Occupational Safety and Health Act and MMS to ensure worker safety during paint removal.

     Air Pollution Control. The Clean Air Act and state air pollution laws adopted to fulfill its mandates provide a framework for national, state and local efforts to protect air quality. Our operations utilize equipment that emits air pollutants subject to federal and state air pollution control laws. These laws require utilization of air emissions abatement equipment to achieve prescribed emissions limitations and ambient air quality standards, as well as operating permits for existing equipment and construction permits for new and modified equipment. Air emissions associated with offshore activities are projected using a matrix and formula supplied by MMS, which has primacy from the Environmental Protection Agency for regulating such emissions.

     Naturally Occurring Radioactive Materials (“NORM”). NORM are materials not covered by the Atomic Energy Act, whose radioactivity is enhanced by technological processing such as mineral extraction or processing through exploration and production conducted by the oil and natural gas industry. NORM wastes are regulated under the RCRA framework, but primary responsibility for NORM regulation has been a state function. Standards have been developed for worker protection; treatment, storage and disposal of NORM waste; management of waste piles, containers and tanks; and limitations upon the release of NORM contaminated land for unrestricted use. We believe that our operations are in material compliance with all applicable NORM standards established by the states, as applicable.

Employees

     At March 23, 2004, the Company had 200 full-time and 10 part-time employees, 15 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, EOWS Midland Company and F-W Oil Exploration L.L.C., and 172 employees who were primarily involved in the district operations of the Company in Houston and Midland, Texas, Oklahoma City, Oklahoma and Charleston, West Virginia.

Item 2. PROPERTIES.

     The Company’s executive offices are located at One Landmark Square, Stamford, Connecticut, in leased premises of about 6265 square feet. The executive offices of Prime Operating Company, Eastern Oil Well Service Company, EOWS Midland Company and F-W Oil Exploration L.L.C. 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.

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          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 affiliated entities.

          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, 2003.

Oil and Gas Production

          As of December 31, 2003, 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).

     The following table shows the Company’s net production of crude oil and natural gas for each of the five years ended December 31, 2003. “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.

10

          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, 2003.

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, 2003. “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.

Reserves

          The Company’s interests in proved developed and undeveloped oil and gas properties have been evaluated by Ryder Scott Company, L.P. for each of the five years ended December 31, 2003. 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):

          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, 2003, are summarized as follows (figures rounded):

11

          “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, 2003 and 2002 were $5.97 and $4.75 per MMBTU, respectively. The range of spot prices during the year 2003 was a low of $3.96 and a high of $12.20 and the average was $5.48. The range during the first quarter of 2004 has been from $5.08 to $7.01 with an average of $5.65. The recent futures market prices have been in the around $5.50.

          The NYMEX price for oil at December 31, 2003 and 2002 was $32.55 and $31.23 per barrel, respectively. The range of NYMEX prices during the year 2003 was a low of $22.00 and a high of $34.50 and the average was $27.67 Range during the first quarter of 2004 has been from $29.50 to $34.75 with an average of $31.95 The recent futures market prices have fluctuated around $37.00.

          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, 2004, 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, 2003 to a vote of the Company’s security-holders through the solicitation of proxies or otherwise.

12

PART II

     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, 2003, were as follows:

The above quotations reflect inter-dealer prices, without retail mark-up, mark-down or commissions, and may not represent actual transactions.

     The number of record holders of the Company’s Common Stock as of March 25, 2004 was 998.

     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.

Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

     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.

Liquidity And Capital Resources

     Cash flow provided by operations for the year ended December 31, 2003,increased by $10 million, compared to the prior year, primarily due to a 14% increase in production and an increase in oil and gas prices throughout the entire year, combined with changes in our working capital accounts. We expect sufficient cash flow to be provided by operations during 2004 because of higher projected production from new properties, combined with oil and gas prices consistent with 2003 and steady operating, general and administrative, interest and financing costs.

     Excluding the effects of significant unforeseen expenses or other income, our cash flow from operations fluctuates primarily because of variations in oil and gas production and prices or changes in working capital accounts. Our oil and gas production will vary based on actual well performance but may be curtailed due to factors beyond our control. Hurricanes in the Gulf of Mexico may shut down our production for the duration of the storm’s presence in the Gulf or damage production facilities so that we cannot produce from a particular property for an extended amount of time. In addition, downstream activities on major pipelines in the Gulf of Mexico can also cause us to shut-in production for various lengths of time.

13

     Our realized oil and gas prices vary due to world political events, supply and demand of products, product storage levels, and weather patterns. We sell the vast majority of our production at spot market prices. Accordingly, product price volatility will affect our cash flow from operations. To mitigate price volatility we sometimes lock in prices for some portion of our production through the use of financial instruments. Currently we have no such arrangements in place.

     We expect to continue to make significant capital expenditures over the next several years as part of our long-term growth strategy. We have budgeted $16 million for drilling expenditures in 2004. We project that we will spend $10 million in the Gulf of Mexico and $6 million on onshore wells.

     If our exploratory drilling results in significant new discoveries, we will have to expend additional capital in order to finance the completion, development, and potential additional opportunities generated by our success. We believe that, because of the additional reserves resulting from the success and our record of reserve growth in recent years, we will be able to access sufficient additional capital through additional bank financing.

     Effective February 2004, we agreed with our lenders to increase the borrowing base from $28,999,996 million to $47,066,662 million and to extend the maturity of the loan facility from March 2005 to March 2007. As of December 31, 2003, $28,800,000 million was borrowed under the facility. The banks review the borrowing base semi-annually and, at their discretion, may decrease or propose an increase to the borrowing base relative to a redetermined estimate of proved oil and gas reserves. Our oil and gas properties are pledged as collateral for the line of credit and we are subject to certain financial covenants defined in the agreement. We are currently in compliance with these financial covenants. If we do not comply with these covenants on a continuing basis, the lenders have the right to refuse to advance additional funds under the facility and/or declare all principal and interest immediately due and payable.

     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:

     2003 as compared to 2002

     The Company had net income of $5,702,000 in 2003 as compared to $1,757,000 in 2002

     Oil and gas sales were $29,855,000 in 2003 as compared to $18,330,000 in 2002. A chart summarizing oil and gas production and revenue is presented below.

     District operating income increased to $16,630,000 in 2003 from $15,308,000 in 2002. This increase reflects higher utilization of equipment during 2003.

14

     Lease operating expenses increased by 25% to $12,783,000 in 2003 as compared to $10,210,000 in 2002. The difference is attributable to production taxes related to higher prices combined with costs on properties added during 2003 and repairs made to marginal wells currently economic due to higher product price levels.

     Administrative revenue, which represents the reimbursement of general and administrative overhead expended on behalf of the Partnerships and the Company’s joint venture partners remained unchanged. 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 2003 and 2002, the Company’s total reimbursements for property acquisition costs were approximately $327,000 and $450,000, respectively.

     General and administrative expenses increased to $5,135,000 in 2003 as compared to $ 4,888,000 in 2002 . This increase reflects the addition of FW’s costs and increased ownership in the Partnerships offset by savings related to reduced personnel costs in the Connecticut office

     Depreciation and depletion of oil and gas properties increased by 57 % to $ 6,283,000 in 2003 from $3,988,000 in 2002. This increase is related to the additional capital costs expended in 2003 combined with increased production.

     Exploration costs of $519,000 were incurred during 2003 drilling seven dry holes. Exploration costs of $894,000 were incurred during 2002 drilling five dry holes.

     Interest expense increased to $880,000 in 2003 from $766,000 in 2002 due to increased average outstanding debt. The average interest rates paid on outstanding borrowings subject to interest at the bank’s base rate during 2003 and 2002 were 4.50%. During the same periods, the average rates paid on outstanding borrowings bearing interest based upon the LIBO rate were 3.84% and 3.59%. As of December 31, 2003 and 2002, the total outstanding borrowings were $27,280,000 and $24,500,000, respectively.

     Income tax expense of $2,446,000 in 2003 represents a 30% effective rate as compared to the effective rate of 20% in 2002. Current tax expense in 2003 was $867,000 with the remainder being attributable to an increase in the Company’s deferred tax liability.

     The primary reason that the Company’s federal tax expense for 2003 is well below the statutory rate is that the Company is allowed to deduct currently, rather than capitalize, intangible drilling costs as incurred. The current deduction of these costs, which are capitalized for financial accounting purposes, is also the primary reason for the increase in the Company’s deferred tax liability between 2002 and 2003.

15

     2002 as compared to 2001

     The Company had net income of $1,757,000 in 2002 as compared to $5,413,000 in 2001. The decrease in net income is primarily due to lower commodity prices.

     Oil and gas sales were $18,330,000 in 2002 as compared to $22,998,000 in 2001 A chart summarizing oil and gas production and revenue, including the Company’s share of production and revenue from the Partnerships, follows.

     District operating income decreased from $17,082,000 in 2001 to $15,308,000 in 2002 This decrease is due to reduced utilization of equipment combined with discounted rates in effect during the first half of 2002.

     Lease operating expenses decreased by 8% to $10,210,000 in 2002 as compared to $11,083,000 in 2001. The difference is attributable to production taxes related to lower prices combined with discounts on expenses due to the weak price environment in the first half of 2002

     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 4% to $1,473,000 in 2002 as compared to $1,535,000 in 2001. 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 2002 and 2001, the Company’s total reimbursements for property acquisition costs were approximately $450,000 and $558,000, respectively.

     General and administrative expenses increased to $4,888,000 in 2002 as compared to $4,310,000 in 2001. This increase reflects the change in cost reimbursement combined with an increase in the Company’s share of general and administrative expenses incurred by the Partnerships.

     Depreciation and depletion of oil and gas properties decreased by 12% to $3,988,000 in 2002 as compared to $4,522,000 in 2001 as a result of increases in estimates of proved reserves.

     Exploration costs of $894,000 were incurred during 2002 drilling five dry holes. Exploration costs of $509,000 in 2001 consist primarily of the cost of three dry holes drilled in 2001.

16

     Interest expense declined to $766,000 in 2002 as compared to $895,000 in 2001 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 2002 and 2001 were 4.25% and 6.92%, respectively. During the same periods, the average rates paid on outstanding borrowings bearing interest based upon the LIBO rate were 3.58% and 5.98% As of December 31, 2002 and 2001, the total outstanding borrowings were$24,500,000 and $16,950,000, respectively.

     Income tax expense of $443,000 in 2002 represents a 20% effective rate as compared to the effective rate of 24% in 2001. Current tax expense in 2002 was $199,000 with the remainder being attributable to an increase in the Company’s deferred tax liability. The low current tax expense is primarily attributable to federal tax credits for producing fuel from a nonconventional source, percentage depletion deductions, larger depreciation deductions allowed for tax purposes, and the utilization of federal net operating loss carry forward.

     All of the Company’s net operating loss carry forwards will have been used or expired as of the end of 2002, and under current law the credit for producing fuel from a nonconventional source will no longer be allowed after 2002, it is possible that the company’s current and overall tax rates may be significantly higher in future years

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, 2003, a hypothetical 2% increase in the applicable interest rates would increase interest expense by approximately $401,000.

     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 2003, and had no open hedging transactions at December 31, 2003. Declines in domestic oil and gas prices could have a material adverse effect on the Company’s revenues, operating results, estimates of economically recoverable reserves and the net revenue there from.

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.

17

Item 9A. INTERNAL CONTROLS AND PROCEDURES.

     Based upon an evaluation within the 90 days prior to the filing date of this report, our Chief Executive Officer and Chief Financial Officer have each concluded that our disclosure controls and procedures as defined in Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934, as amended, are effective, as of the evaluation date, in timely alerting them to material information relating to our Company required to be included in our reports filed or submitted under the Exchange Act. Since the date of the evaluation, there have been no significant changes in our internal controls or in other factors that could significantly affect such controls, including any corrective actions with regard to significant deficiencies and material weaknesses.

     Our management, including the Chief Executive Officer and Chief Financial Officer, does not expect that our disclosure controls and procedures or our internal controls will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons or by collusion of two or more people. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions; over time, controls may become inadequate because of changes in conditions, or the degree of compliance with the policies or procedures may deteriorate. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. Accordingly, our disclosure controls and procedures are designed to provide reasonable, not absolute, assurance that the objectives of our disclosure control system are met and, as set forth above, our Chief Executive Officer and Chief Financial Officer have concluded, based on their evaluation as of the end of the period, that our disclosure controls and procedures were sufficiently effective to provide reasonable assurance that the objectives of our disclosure control system were met.

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 the Company’s Annual Meeting of Stockholders to be held in June, 2004, which will be filed with the U.S. Securities and Exchange Commission within 120 days of December 31, 2003 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, 2004, which will be filed with the U.S. Securities and Exchange Commission within 120 days of December 31, 2003 and which is incorporated herein by reference.

     Information relating to security ownership of certain beneficial owners and management is included in the Company’s definitive proxy statement relating the Company’s Annual Meeting of Stockholders to be held in June, 2004, which will be filed with the U.S. Securities and Exchange Commission within 120 days of December 31, 2003 and which is incorporated herein by reference.

Item 13. CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS.

     Information relating to certain transactions by Directors and executive officers of the Company is included in the Company’s definitive proxy statement relating the Company’s Annual Meeting of Stockholders to be held in June, 2004, which will be filed with the U.S. Securities and Exchange Commission within 120 days of December 31, 2003 and which is incorporated herein by reference.

18

Item 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES.

     Information relating to principal accountant fees and services is included in the Company’s definitive proxy statement relating to the Company’s Annual Meeting of Stockholders to be held in June, 2004, which will be filed with the U.S. Securities and Exchange Commission within 120 days of December 31, 2003 and which is incorporated herein by reference.

19

PART IV

Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.

20

Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K. continued

21

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, 2004.

     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, 2004.

22

INDEX TO FINANCIAL STATEMENTS

F-1

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Board of Directors and Stockholders of
      PrimeEnergy Corporation and Subsidiaries:

We have audited the accompanying consolidated balance sheets of PrimeEnergy Corporation and Subsidiaries as of December 31, 2003 and 2002, and the related consolidated statements of operations, stockholders’ equity, and cash flows for the years ended December 31 2003, 2002 and 2001. These financial statements are the responsibility of the Corporation’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of PrimeEnergy Corporation and Subsidiaries as of December 31, 2003 and 2002, and the consolidated results of its operations and cash flows for the years ended December 31, 2003, 2002 and 2001 in conformity with accounting principles generally accepted in the United States of America.

PUSTORINO, PUGLISI & CO., LLP
New York, New York
March 30, 2004

F-2

PRIMEENERGY CORPORATION and SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS, December 31, 2003 and 2002

The accompanying notes are an integral part of the consolidated financial statements.

F-3

PRIMEENERGY CORPORATION and SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS, December 31, 2003 and 2002

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, 2003, 2002 and 2001

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, 2003, 2002 and 2001

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, 2003, 2002 and 2001

Supplemental information of noncash investing and financing activities:

     In 2002, the Company recorded capital lease obligations in the amount of $59,000.

The accompanying notes are an integral part of the consolidated financial statements.

F-7

PRIMEENERGY CORPORATION and SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

F-8

PRIMEENERGY CORPORATION and SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

F-9

PRIMEENERGY CORPORATION and SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

F-10

PRIMEENERGY CORPORATION and SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

F-11

PRIMEENERGY CORPORATION and SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

F-12

PRIMEENERGY CORPORATION and SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

F-13

PRIMEENERGY CORPORATION and SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

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 two capital leases for office equipment in other long-term obligations. Future minimum lease payments under operating and capital leases are as follows:

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.

PrimeEnergy Corporation and each of its subsidiaries are borrowers under a credit agreement with the Company’s lender, as more fully described in Footnote 5. The pledge of properties owned by FW is limited to the amounts available to FW. The Company’s assets are pledged as security under that agreement to all outstanding borrowings including FW’s. The lender reviews the assets of FW in conjunction with the semi-annual borrowing base determinations and limits amounts available to FW to a level consistent with the ability of FW to repay such borrowings. The Company is liable to the extent that the assets of FW are not sufficient to satisfy FW’s obligations under the agreement. Based on the borrowing base determination as of February 2004 the maximum additional amount the Company would be committed to pay is $4,048,000.

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.

The Company owns approximately a 27% interest in a limited partnership which owns a shopping center in Alabama. The Company is a guarantor on a mortgage secured by the shopping center. The Company believes the cash flow from the center is sufficient to service the mortgage. The market value of the center is currently substantially higher than the balance owed on the mortgage. If the partnership were unable to pay its obligations under the mortgage agreement, the maximum amount the Company is committed to pay is $300,000.

F-14

PRIMEENERGY CORPORATION and SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS,

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, 2003 and 2002, 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 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 expired, the former Chairman was still entitled to receive certain payments relating to partnerships formed during the time the agreement was in effect. In October 2002, the President and the former Chairman sold and assigned all rights, title and interest related to certain Partnerships formed under these marketing agreements to the Company. The President is still entitled to a percentage of the Company’s carried interest depending on total capital raised and annual performance of other Partnerships and joint ventures.

9. Income Taxes

The components of the provision for income taxes for the years ended December 31, 2003, 2002 and 2001 are as follows:

F-15

PRIMEENERGY CORPORATION and SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS, Continued

The components of net deferred tax assets (liabilities) are as follows:

The total provision for income taxes for the years ended December 31, 2003, 2002 and 2001 varies from the federal statutory tax rate as a result of the following: