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U.S. SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549
   FORM 10-K (Mark One)þ
    
    ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THESECURITIES EXCHANGE ACT OF 1934For the fiscal year ended December 31, 2004oro
    
    TRANSITION REPORT PURSUANT TO SECTION 13 or 15(d) OF THESECURITIES EXCHANGE ACT OF 1934For 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. Employerincorporation or organization)
    
    Identification No.)One Landmark SquareStamford, Connecticut
    
    06901(Address of principal executive offices)
    
    (Zip Code)
 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 12 months (or for such shorter period that
the Registrant was required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes
þ No
o 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. o Indicate by check mark whether the Registrant is an accelerated filer as defined in Exchange Act
Rule 12-b-2 Yes
o No þ 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 $26,772,385. The number of shares outstanding of each class of the Registrants Common Stock as of March 28,
2005, was: 3,477,850 shares, Common Stock, $0.10 par value, DOCUMENTS INCORPORATED BY REFERENCE




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TABLE OF CONTENTS  PART IItem 1. BUSINESSItem 2. PROPERTIESItem 3. LEGAL PROCEEDINGSItem 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERSPART IIItem 5. MARKET FOR REGISTRANTS COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIESItem 6. SELECTED FINANCIAL DATAItem 7. MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONSItem 7a. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKItem 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATAItem 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSUREItem 9A. INTERNAL CONTROLS AND PROCEDURESItem 9B. OTHER INFORMATIONPART IIIItem 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTItem 11. EXECUTIVE COMPENSATIONItem 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERSItem 13. CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONSItem 14. PRINCIPAL ACCOUNTANT FEES AND SERVICESPART IVItem 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-KSIGNATURESRestated Certificate of IncorporationBylawsComposite Copy of Non-Statutory Option Agreements3rd Amendment to Credit Agreement4th Amendment to Credit AgreementCredit AgreementSecurity AgreementRatification of and Amendment to Act of Mortgage and Security AgreementRatification of and Amendment to Mortgage, Deed of Trust, Security AgreementSubsidiariesConsent of Ryder Scott & Co LPCertification of CEO Pursuant to Rule 13(a)-14(a)/15d-14(a)Certification of CFO Pursuant to Rule 13(a)-14(a)/15d-14(a)Certification of CEO Pursuant to 18 U.S.C. Section 1350Certification of CFO Pursuant to 18 U.S.C. Section 1350    Table of Contents  PrimeEnergy Corporation FORM 10-K ANNUAL REPORT
For the Fiscal Year Ended
December 31, 2004 
 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 of 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 Recent 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. As
of December, 2004, the Company had net capitalized costs related to
oil and gas properties of $48 million, including $13 million of
properties under evaluation. Total expenditures for the acquisition,
exploration and development of the Companys properties during
2004 was $25 million of which $5.5 million was related to exploration
costs expensed during 2004. Properties
under evaluation include $7.5 million invested in one offshore well
completed and tested during the third quarter of 2004, however, early
production tests have been inconclusive as to the commercial
viability of this prospect. Additional expenditures during 2005 will
be required to determine whether production rates and ultimate
recoverable reserves are sufficient to warrant the costs of setting a
platform and installing production facilities. If this well is
determined to be noncommercial, the write off of this investment in
2005 will have a significant negative impact on the Companys
earnings. As
of December 31, 2004, our offshore properties had net proved reserves of
10.2 BCFE and net capitalized costs of $18.7 million. Approximately
70% of these reserves are undeveloped and will require substantial
capital expenditures during 2005. As of March, 2005, the Company has
spent approximately $7.8 million drilling four successful wells in
the Gulf of Mexico as
part of our program to develop these properties. Our offshore
drilling budget for 2005 is $10 million and an additional $16 million
has been committed to pipeline and facility construction and
installation. Production from these wells, depending on flow rates
and the timing of the completion of the pipelines and facilities, may
add significant gas volumes to the Companys sales during the
fourth quarter of 2005. The Companys offshore
properties include a non-operated interest in producing and
undeveloped properties in the Breton Sound Block 41 Field. In
February 2005, a working interest owner in the field completed the
sale of their interest in this asset. The Company has not received an
offer to purchase our interest in the field, however, based on the
price of this transaction, the Companys ownership position has
an equivalent value of approximately $24 million. During
2004, onshore exploration and development expenditures totaled $9.3
million. Spending on projects in our core operating areas for 2005 is
budgeted at $15 million. As of March, 2005, the Company has drilled
four successful wells, one dry hole and is currently drilling two
wells in these areas. 2




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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. 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 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 1,542 oil and gas wells, 418 through the Houston office,
158 through the Midland office, 458 through the Oklahoma City office and 497 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 acted as managing general partner of various partnerships, trusts and
joint ventures. 3




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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. The aggregate number of
limited partners in the Partnerships and beneficial owners of the Trusts now administered by PEMC
is approximately 3,730. 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. 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. 4




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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
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. 5




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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. 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. Oil Purchasers:Texon Distributing L.P.
    
    
    26.65
    %Plains All American Inc.
    
    
    29.29
    %TEPPCO Crude Oil, L.L.C.
    
    
    16.20
    %LPC Crude Oil, Inc.
    
    
    16.10
    %Gas Purchasers:Unimark LLC
    
    
    10.29
    %
 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. 6




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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: 
    
    restrict the types, quantities and concentration of various substances that can be released
into the environment in connection with drilling and production activities;
    
    limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and
    
    impose substantial liabilities for pollution resulting from our operations.
 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: 
    
    unit production expenses primarily related to the control and limitation of air emissions
and the disposal of produced water;
    
    capital costs to drill exploration and development wells primarily related to the
management and disposal of drilling fluids and other oil and natural gas exploration wastes;
and
    
    capital costs to construct, maintain and upgrade equipment and facilities.
 Comprehensive
Environmental Response, Compensation and Liability Act of 1980
(CERCLA). 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: 7




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-
    
    to remove or remediate previously disposed wastes, including wastes disposed or released by prior owners or operators;-
    
    to clean up contaminated property, including contaminated groundwater; or to perform remedial operations to prevent
future contamination.
 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, 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 8




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##### Table of Contents



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. 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. 9




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##### Table of Contents



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 25, 2005, the Company had 190 full-time and 6 part-time employees, 16 of whom were
employed by the Company at its principal offices in Stamford, Connecticut, 20 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 160 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 in leased premises at One Landmark Square,
Stamford, Connecticut. 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. 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, 2004. 2004
    
    
    2003
    
    
    2002
    
    
    2001
    
    
    2000Gross
    
    
    Net
    
    
    Gross
    
    
    Net
    
    
    Gross
    
    
    Net
    
    
    Gross
    
    
    Net
    
    
    Gross
    
    
    NetExploratory:Oil
    
    

    2
    
    

    
    .400
    
    
    
    
    
    
    
    
    
    
    
    1
    
    
    
    1
    
    
    
    1
    
    
    
    1.000
    
    
    
    
    
    
    
    Gas
    
    

    10
    
    
    

    2.850
    
    
    
    4
    
    
    
    1.565
    
    
    
    1
    
    
    
    .25
    
    
    
    1
    
    
    
    .602
    
    
    
    3
    
    
    
    1.279Dry
    
    

    4
    
    
    

    1.594
    
    
    
    6
    
    
    
    1.400
    
    
    
    4
    
    
    
    2.50
    
    
    
    
    
    
    
    
    
    
    
    2
    
    
    
    .276Development:Oil
    
    

    
    
    
    

    
    
    
    
    6
    
    
    
    2.561
    
    
    
    2
    
    
    
    1.25
    
    
    
    1
    
    
    
    .500
    
    
    
    
    
    
    
    Gas
    
    

    7
    
    
    

    3.993
    
    
    
    8
    
    
    
    4.478
    
    
    
    10
    
    
    
    7.59
    
    
    
    7
    
    
    
    4.926
    
    
    
    7
    
    
    
    4.134Dry
    
    

    2
    
    
    

    1.594
    
    
    
    1
    
    
    
    .500
    
    
    
    6
    
    
    
    5.30
    
    
    
    2
    
    
    
    1.585
    
    
    
    
    
    
    
    Total:Oil
    
    
    2
    
    
    
    .400
    
    
    
    6
    
    
    
    2.56
    
    
    
    3
    
    
    
    2.25
    
    
    
    2
    
    
    
    1.500
    
    
    
    
    
    
    
    Gas
    
    
    17
    
    
    
    6.843
    
    
    
    12
    
    
    
    6.042
    
    
    
    11
    
    
    
    7.84
    
    
    
    8
    
    
    
    5.528
    
    
    
    10
    
    
    
    5.413Dry
    
    
    6
    
    
    
    2.722
    
    
    
    7
    
    
    
    1.900
    
    
    
    10
    
    
    
    7.80
    
    
    
    2
    
    
    
    1.585
    
    
    
    2
    
    
    
    .27625
    
    
    
    9.965
    
    
    
    25
    
    
    
    10.504
    
    
    
    24
    
    
    
    17.89
    
    
    
    12
    
    
    
    8.613
    
    
    
    12
    
    
    
    5.689
 10




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##### Table of Contents



Oil and Gas Production As of December 31, 2004, 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). Gross
    
    
    NetProducing wells (1)Oil Wells
    
    
    851
    
    
    
    320.99Gas Wells
    
    
    1,149
    
    
    
    399.47Producing Acres
    
    
    263,841
    
    
    
    92,539
   (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, 2004. 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. 2004
    
    
    2003
    
    
    2002
    
    
    2001
    
    
    2000Oil (barrels)
    
    
    371,000
    
    
    
    370,000
    
    
    
    321,000
    
    
    
    306,000
    
    
    
    298,000Gas (Mcf)
    
    
    5,138,000
    
    
    
    3,991,000
    
    
    
    3,540,000
    
    
    
    3,764,000
    
    
    
    3,930,000
 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, 2004. 2004
    
    
    2003
    
    
    2002
    
    
    2001
    
    
    2000Average sales price per barrel
    
    $
    40.45
    
    
    
    28.90
    
    
    
    23.37
    
    
    
    24.92
    
    
    
    28.34Average sales price Per Mcf
    
    $
    5.64
    
    
    
    4.80
    
    
    
    3.06
    
    
    
    4.08
    
    
    
    3.76Average production costs per net equivalent barrel (1)
    
    $
    12.17
    
    
    
    12.42
    
    
    
    11.80
    
    
    
    11.88
    
    
    
    9.57
   (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, 2004. 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. Leasehold
    
    
    Mineral
    
    
    RoyaltyInterests
    
    
    Interests
    
    
    InterestsGross
    
    
    Net
    
    
    Gross
    
    
    Net
    
    
    Gross
    
    
    NetState
    
    Acres
    
    
    Acres
    
    
    Acres
    
    
    Acres
    
    
    Acres
    
    
    AcresColorado
    
    
    
    
    
    
    
    
    
    
    799
    
    
    
    23Gulf of Mexico
    
    
    95,225
    
    
    
    54,489Montana
    
    
    
    
    
    
    
    
    
    
    13,984
    
    
    
    59
    
    
    
    786
    
    
    
    5Nebraska
    
    
    
    
    
    
    
    
    
    
    2,553
    
    
    
    331North Dakota
    
    
    
    
    
    
    
    
    
    
    640
    
    
    
    1Oklahoma
    
    
    5,011
    
    
    
    2,938
    
    
    
    320
    
    
    
    1Texas
    
    
    18,838
    
    
    
    8,518
    
    
    
    680
    
    
    
    16Wyoming
    
    
    1,000
    
    
    
    125
    
    
    
    5,043
    
    
    
    35
    
    
    
    14
    
    
    
    35TOTAL
    
    
    120,074
    
    
    
    66,070
    
    
    
    24,019
    
    
    
    466
    
    
    
    926
    
    
    
    40
 11




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##### Table of Contents



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, 2004. 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): Reserve CategoryProved Developed
    
    
    Proved Undeveloped
    
    
    TotalAs of
    
    Oil
    
    
    Gas
    
    
    Oil
    
    
    Gas
    
    
    Oil
    
    
    Gas12-31
    
    (bbls)
    
    
    (Mcf)
    
    
    (bbls)
    
    
    (Mcf)
    
    
    (bbls)
    
    
    (Mcf)2000
    
    
    2,362,000
    
    
    
    27,029,000
    
    
    
    
    
    
    
    
    
    
    
    2,362,000
    
    
    
    27,029,0002001
    
    
    1,996,000
    
    
    
    24,266,000
    
    
    
    
    
    
    
    453,000
    
    
    
    1,996,000
    
    
    
    24,719,0002002
    
    
    2,319,000
    
    
    
    29,917,000
    
    
    
    
    
    
    
    
    
    
    
    2,319,000
    
    
    
    29,917,0002003
    
    
    2,865,000
    
    
    
    34,045,000
    
    
    
    40,000
    
    
    
    4,960,000
    
    
    
    2,905,000
    
    
    
    39,005,0002004
    
    
    2,926,000
    
    
    
    37,728,000
    
    
    
    6,000
    
    
    
    7,142,000
    
    
    
    2,932,000
    
    
    
    44,870,000
 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, 2004, are summarized as
follows (figures rounded): Proved Developed
    
    
    Proved Undeveloped
    
    
    TotalPresent Value
    
    
    
    
    
    
    Present Value
    
    
    
    
    
    
    Present ValueAs of
    
    Future Net
    
    
    Of Future
    
    
    Future Net
    
    
    Of Future
    
    
    Future Net
    
    
    Of Future12-31
    
    Revenue
    
    
    Net Revenue
    
    
    Revenue
    
    
    Net Revenue
    
    
    Revenue
    
    
    Net Revenue2000
    
    $
    199,376,000
    
    
    
    113,137,000
    
    
    
    
    
    
    
    
    
    
    
    199,376,000
    
    
    
    113,137,0002001
    
    $
    41,086,000
    
    
    
    24,653,000
    
    
    
    957,000
    
    
    
    629,000
    
    
    
    42,043,000
    
    
    
    25,282,0002002
    
    $
    97,600,000
    
    
    
    56,855,000
    
    
    
    
    
    
    
    
    
    
    
    97,600,000
    
    
    
    56,855,0002003
    
    $
    141,194,000
    
    
    
    85,695,000
    
    
    
    22,891,000
    
    
    
    17,401,000
    
    
    
    164,085,000
    
    
    
    103,096,0002004
    
    $
    177,916,000
    
    
    
    107,116,000
    
    
    
    33,484,000
    
    
    
    26,796,000
    
    
    
    211,400,000
    
    
    
    133,912,000
 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, 2004 and 2003 was $6.18 and $5.97 per MMBTU,
respectively. The range of spot prices during the year 2004 was a low of $ 4.39 and a high of $7.96
and the average was $5.87. The range during the first quarter of 2005 has been from $ 5.56 to $
7.19 with an average of $6.38. The recent futures market prices have traded above $7.00 per
MMBTU. The NYMEX price for oil at December 31, 2004 and 2003 was $43.45 and $32.55 per barrel,
respectively. The range of NYMEX prices during the year 2004 was a low of $32.48 and a high of
$55.17 and the average was $41.31. Range during the first quarter of 2005 has been from $ 42.12 to
$56.72 with an average of $ 49.79. The recent futures market prices have fluctuated around $
54.00. 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. 12




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##### Table of Contents



Since January 1, 2005, 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, 2004
to a vote of the Companys security-holders through the solicitation of proxies or otherwise. 13




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##### Table of Contents



PART II 
 Item 5.
    
    MARKET FOR REGISTRANTS COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND
ISSUER PURCHASES OF EQUITY SECURITIES.
 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, 2004,
were as follows: 2004
    
    High
    
    
    LowFirst Quarter
    
    $
    15.15
    
    
    $
    15.05Second Quarter
    
    $
    18.16
    
    
    $
    17.91Third Quarter
    
    $
    19.21
    
    
    $
    19.06Fourth Quarter
    
    $
    19.64
    
    
    $
    18.61
 2003
    
    High
    
    
    LowFirst Quarter
    
    $
    9.43
    
    
    $
    8.00Second Quarter
    
    $
    9.70
    
    
    $
    8.05Third Quarter
    
    $
    10.56
    
    
    $
    9.50Fourth Quarter
    
    $
    14.61
    
    
    $
    9.43
 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, 2005 was 976. 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. Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities Maximum Number ofShares that May YetAverage Price Paid
    
    

Be Purchased Under The2004 Month
    
    Number of Shares
    
    
    per share
    
    
    Plan (1)January
    
    
    
    
    
    
    
    
    
    
    478,271February
    
    
    15,630
    
    
    

$        15.39
    
    
    
    462,641March
    
    
    3,500
    
    
    
    $        14.56
    
    
    
    459,141April
    
    
    8,992
    
    
    
    $        17.01
    
    
    
    450,149May
    
    
    15,874
    
    
    
    $        18.08
    
    
    
    434,275June
    
    
    4,794
    
    
    
    $        18.09
    
    
    
    429,481July
    
    
    35,952
    
    
    
    $        18.12
    
    
    
    393,529August
    
    
    2,885
    
    
    
    $        18.09
    
    
    
    390,644September
    
    
    340
    
    
    
    $        18.11
    
    
    
    390,304October
    
    
    10,600
    
    
    
    $        18.48
    
    
    
    379,704November
    
    
    12,438
    
    
    
    $        19.56
    
    
    
    367,266December
    
    
    25,972
    
    
    
    $        19.51
    
    
    
    341,294Total/Average
    
    
    136,977
    
    
    
    $        18.06
 (1) In December 1993, we announced that our Board of Directors authorized a stock repurchase
program whereby we may purchase outstanding shares of our common stock from time-to-time, in open
market transactions or negotiated sales. A total of 2,400,000 shares have been authorized, to date,
under this program. Through December 31, 2004 we repurchased a total of 2,058,706 shares under
this program for $12,929,848 at an average price of $6.28 per share. Additional purchases of
shares may occur as market conditions warrant. We expect future purchases will be funded with
internally generated cash flow or from working capital. 14




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##### Table of Contents



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. 2004
    
    
    2003
    
    
    2002
    
    
    2001
    
    
    2000Revenues
    
    $
    62,428,000
    
    
    
    46,719,000
    
    
    
    34,186,000
    
    
    
    42,408,000
    
    
    
    39,182,000Income from operations
    
    $
    10,223,000
    
    
    
    8,047,000
    
    
    
    2,168,000
    
    
    
    6,968,000
    
    
    
    6,148,000Net income
    
    $
    7,275,000
    
    
    
    5,702,000
    
    
    
    1,757,000
    
    
    
    5,413,000
    
    
    
    5,365,000Income per common share
    
    $
    2.04
    
    
    
    1.56
    
    
    
    0.47
    
    
    
    1.39
    
    
    
    1.26Diluted net
income per common share
    
    $
    1.70
    
    
    
    1.31
    
    
    
    0.40
    
    
    
    1.18
    
    
    
    1.08Net cash provided by operations
    
    $
    26,995,000
    
    
    
    19,622,000
    
    
    
    9,644,000
    
    
    
    12,313,000
    
    
    
    11,498,000Total assets
    
    $
    69,926,000
    
    
    
    58,255,000
    
    
    
    44,887,000
    
    
    
    35,816,000
    
    
    
    35,094,000Long-term obligations
    
    $
    30,290,000
    
    
    
    26,925,000
    
    
    
    23,734,000
    
    
    
    16,958,000
    
    
    
    18,213,000Cash dividends
    
    None
    
    
    None
    
    
    None
    
    
    None
    
    
    None
 
 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. 15




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##### Table of Contents



Liquidity And Capital
Resources: Cash flow provided by operations for the year ended December 31, 2004, increased by $5
million, compared to the prior year, primarily due to a 18.5% 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 2005 because
of higher projected production from new properties, combined with oil and gas prices consistent
with 2004 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. 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 $25 million for drilling expenditures in
2005. We project that we will spend $10 million in the Gulf of Mexico and $15 million on onshore
wells. In addition, we have committed approximately $16 million for offshore pipelines and production
facilities. 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. The Company has in place both a stock repurchase program and a limited partnership interest
repurchase program. Spending under these programs in 2004 was $4.5
million. The Company
expects to expend a similar amount in 2005. Effective March 2005, we agreed with our lenders to increase the Companys borrowing base to
$41,000,000. As of March 31, 2005, $21,500,000 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. 16




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##### Table of Contents



Results of Operations: 2004 as compared to 2003 The Company had net income of $7,275,000 in 2004 as compared to $5,702,000 in 2003. Oil and gas saleswere $ 43,967,000 in 2004 as compared to $29,855,000 in 2003. A chart
summarizing oil and gas production and revenue is presented below. 2004
    
    
    2003
    
    
    Increase (Decrease)Barrels of Oil Produced
    
    
    371,000
    
    
    
    370,000
    
    
    
    1,000Average Price Received
    
    $
    40.45
    
    
    $
    28.90
    
    
    $
    11.55Oil Revenue
    
    $
    15,006,000
    
    
    $
    10,693,000
    
    
    $
    4,313,000Mcf of Gas Produced
    
    
    5,138,000
    
    
    
    3,991,000
    
    
    
    1,147,000Average Price Received
    
    $
    5.64
    
    
    $
    4.80
    
    
    $
    0.84Gas Revenue
    
    $
    28,961,000
    
    
    $
    19,162,000
    
    
    $
    9,799,000Total Oil & Gas Revenue
    
    $
    43,967,000
    
    
    $
    29,855,000
    
    
    $
    14,112,000
 Field
Service Revenue increased 9% to $11,965,000 in 2004 from
$11,013,000 in 2003. This
increase reflects higher utilization of equipment during 2004 combined with an upward trend in
rates during the fourth quarter of 2004. Lease operating expensesincreased by 17% to $14,939,000 in 2004 as compared to $12,783,000 in
2003. The difference is attributable to production taxes related to higher prices combined with
costs on properties added during 2004 and repairs made to marginal wells currently economic due to
higher product price levels. General
and administrative expensesincreased to $7,536,000 in 2004 as compared to $6,995,000
in 2003. This increase reflects the addition of FWs costs for the full year and increased
ownership in the Partnerships. Depreciation
and depletionof oil and gas properties increased to $11,021,000
in 2004 from $6,283,000 in 2003. This increase is related to the additional capital expended during 2003 and 2004
combined with increased production. Exploration
costs in 2004 of $5,499,000 consist of dry hole expenditures and certain geological, geophysical and
seismic costs. Dry hole costs of $4,656,000 during 2004 were attributable to the drilling of one
offshore well and three wells onshore. Exploration costs of $519,000 were incurred during 2003
drilling seven dry holes. Interest expenseincreased to $1,136,000 in 2004 from $880,000 in 2003 due to increased
average outstanding debt. The average interest rates paid on
outstanding borrowings during 2004 and 2003 were 3.91% and 3.84%,
respectively.  As of December 31, 2004 and 2003, the total outstanding borrowings were $29,900,000 and
$27,280,000, respectively. Income
tax expenseof $3,023,000 in 2004 represents a 29% effective rate as compared to the
effective rate of 30% in 2003. Current tax expense in 2004 was $453,000 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 2004 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 2003 and 2004. 17




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##### Table of Contents



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 saleswere $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. 2003
    
    

2002
    
    

Increase (Decrease)Barrels of Oil Produced
    
    
    370,000
    
    
    
    321,000
    
    
    
    49,000Average Price Received
    
    $
    28.90
    
    
    $
    23.37
    
    
    $
    5.53Oil Revenue
    
    $
    10,693,000
    
    
    $
    7,510,000
    
    
    $
    3,183,000Mcf of Gas Produced
    
    
    3,991,000
    
    
    
    3,540,000
    
    
    
    451,000Average Price Received
    
    $
    4.80
    
    
    $
    3.06
    
    
    $
    1.74Gas Revenue
    
    $
    19,162,000
    
    
    $
    10,820,000
    
    
    $
    8,342,000Total Oil & Gas Revenue
    
    $
    29,855,000
    
    
    $
    18,330,000
    
    
    $
    11,525,000
 Field Service Revenueincreased to $11,013,000 in 2003 from $9,891,000 in 2002. This increase
reflects higher utilization of equipment during 2003. Lease operating expensesincreased 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. General
and administrative expensesincreased to $6,995,000 in 2003 as
compared to $6,007,000
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 depletionof 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 costsof $519,000 were incurred during 2003 drilling seven dry holes. Exploration
costs of $894,000 were incurred during 2002 drilling five dry holes. Interest expenseincreased 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 expenseof $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. 
 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, 2004 a hypothetical 2.5% increase in the applicable interest
rates would increase interest expense by approximately $727,000. 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 2004, and had
no open hedging transactions at December 31, 2004. 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. 18




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##### Table of Contents



Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. The financial statements and supplementary information included in this Report are
described in the Index to Financial statements at Page F-1 of this Report. 
 Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. 
 Item 9A. INTERNAL CONTROLS AND PROCEDURES. (a)  Evaluation
of disclosure controls and procedures. Our
management, with the participation of our chief executive officer and
chief financial officer, evaluated the effectiveness of our
disclosure controls and procedures pursuant to Rule 13a-15 under
the Securities Exchange Act of 1934 as of the end of the period
covered by this Annual Report on Form 10-K. The evaluation
included certain internal control areas in which we have made and are
continuing to make changes to improve and enhance controls. In
designing and evaluating the disclosure controls and procedures,
management recognized that any controls and procedures, no matter how
well designed and operated, can provide only reasonable assurance of
achieving the desired control objectives. In addition, the design of
disclosure controls and procedures must reflect the fact that there
are resource constraints and that management is required to apply its
judgment in evaluating the benefits of possible controls and
procedures relative to their costs. Based
on that evaluation, our chief executive officer and chief financial
officer concluded that our disclosure controls and procedures are
effective to provide reasonable assurance that information we are
required to disclose in reports that we file or submit under the
Exchange Act is recorded, processed, summarized and reported within
the time periods specified in Securities and Exchange Commission
rules and forms, and that such information is accumulated and
communicated to our management, including our chief executive officer
and chief financial officer, as appropriate, to allow timely
decisions regarding required disclosure. (b)  Changes in
internal control over financial reporting. There
were no changes in our internal control over financial reporting that
occurred during the period covered by this Annual Report on Form 10-K
that have materially affected, or are reasonably likely to materially
affect, our internal control over financial reporting. Management
is currently in the process of comprehensively documenting and
further analyzing our system of internal control over financial
reporting. We are in the process of designing enhanced processes and
controls to address any issues identified through this review. We
plan to continue this initiative as well as prepare for our first
management report on internal control over financial reporting, as
required by Section 404 of the Sarbanes-Oxley Act of 2002 for the
annual period ending December 31, 2006, which may result in
changes to our internal control over financial reporting. 
 Item 9B. OTHER INFORMATION No
information was required to be disclosed by Registrant in a report on
Form 8-K during the fourth quarter of the year covered by this Report. 
 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, 2005, which will be filed with the U.S. Securities and Exchange
Commission within 120 days of December 31, 2004 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, 2005, which
will be filed with the U.S. Securities and Exchange Commission within 120 days of December 31, 2004
and which is incorporated herein by reference. 19




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##### Table of Contents



Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
AND RELATED STOCKHOLDER MATTERS. 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, 2005 which will be filed with the U.S. Securities and Exchange
Commission within 120 days of December 31, 2004 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, 2005, which will be filed with the U.S. Securities and
Exchange Commission within 120 days of December 31, 2004 and which is incorporated herein by
reference. 
 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, 2005, which will be filed with the U.S. Securities and Exchange Commission within 120 days of
December 31, 2004 and which is incorporated herein by reference. 
 PART IV 
 Item 15. EXHIBITS AND
FINANCIAL STATEMENT SCHEDULES. The following documents are filed as part of this Report: 1. Financial statements (Index to Financial Statements at page F-1 of this Report) 2. Financial Statement Schedules (Index to Financial Statements  Supplementary Information) 3. Exhibits 3.1
    
    Restated Certificate of Incorporation of PrimeEnergy Corporation (filed herewith)3.2
    
    Bylaws of PrimeEnergy Corporation (filed herewith)10.3.1
    
    Adoption Agreement #003 dated 4/23/2002, MassMutual Life Insurance Company
Flexinvest Prototype Non-Standardized 401(k) Profit-Sharing Plan; EGTRRA
Amendment to the PrimeEnergy employees 401(k) Savings Plan; MassMutual
Retirement Services Flexinvest Defined Contribution Prototype Plan; Protected
Benefit Addendum; Addendum to the Administrative Services Agreement Loan
Agreement; Addendum to Administrative Services Agreement GUST Restatement
Provisions; General Trust Agreement (Incorporated by reference to Exhibit 10.3.1
of PrimeEnergy Corporation form 10-K for the year ended December 31, 2002) (1)10.18
    
    Composite copy of Non-Statutory Option Agreements (filed herewith)10.22
    
    Credit Agreement dated as of December 19, 2002 between PrimeEnergy Corporation,
PrimeEnergy Management Corporation, Prime Operating Company, Eastern Oil Well
Service Company, Southwest Oilfield Construction Company, EOWS Midland Company
and Guaranty Bank , FSB (incorporated by reference to Exhibit 10.22 of
PrimeEnergy Corporation 10-K for the year ended December 31, 2002)
 20




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##### Table of Contents



Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K. continued 10.22.1
    
    First Amendment to Credit Agreement effective as of
June 1, 2003 between PrimeEnergy Corporation, PrimeEnergy
Management Corporation, Prime Operating Company, Eastern Oil Well
Service Company, Southwest Oilfield Construction Company, EOWS
Midland Company and Guaranty Bank , FSB (Incorporated by reference
to Exhibit 10.22.1 of PrimeEnergy Corporation Form 10-K for the
year ended December 31, 2003)10.22.2
    
    Second Amendment to Credit Agreement effective as of September
22,2003 between PrimeEnergy Corporation, PrimeEnergy Management
Corporation, Prime Operating Company, Eastern Oil Well Service
Company, Southwest Oilfield Construction Company, EOWS Midland
Company, F-W Oil Exploration Company L.L.C. and Guaranty Bank ,
FSB (Incorporated by reference to exhibit 10.2.2 of PrimeEnergy
Corporation Form 10-K for the year ended December 31, 2003)10.22.3
    
    Third Amendment to Credit Agreement effective as of
February 17, 2004, between PrimeEnergy Corporation, PrimeEnergy Management
Corporation, Prime Operating Company, Eastern Oil Well Service
Company, Southwest Oilfield Construction Company, EOWS Midland
Company, F-W Oil Exploration Company, L.L.C. and Guaranty Bank,
FSB (filed herewith)10.22.4
    
    Fourth Amendment to Credit Agreement effective as of December 28,
2004, between PrimeEnergy Corporation, PrimeEnergy Management
Corporation, Prime Operating Company, Eastern Oil Well Service
Company, Southwest Oilfield Construction Company, EOWS Midland
Company and Guaranty Bank, FSB (filed herewith)10.23
    
    Mortgage, Deed of Trust, Security Agreement, Financing Statement
and Assignment of Production from PrimeEnergy Corporation and
PrimeEnergy Management Corporation for the benefit of Guaranty
Bank, FSB (Incorporated by reference to Exhibit 10.23 of
PrimeEnergy Corporation 10-K for the year ended December 31, 2002)10.23.1
    
    Mortgage, Deed of Trust, Security Agreement, Financing Statements
and Assignment of Production effective as of September 22,
2003, by and among F-W Oil Exploration L.L.C., PrimeEnergy
Corporation, PrimeEnergy Management Corporation, Prime Operating
Company, Eastern Oil Well Service Company, EOWS Midland Company
and Southwest Oilfield Construction Company for benefit of
Guaranty Bank, FSB (Incorporated by reference to exhibit 10.23.1
to PrimeEnergy Corporation Form 10-K for the year ended December
31, 2003)10.24
    
    Act of Mortgage and Security Agreement, by PrimeEnergy Corporation
and PrimeEnergy Management Corporation to Guaranty Bank, FSB
(Incorporated by reference to Exhibit 10.24 of PrimeEnergy
Corporation 10-K for the year ended December 31, 2002)10.25
    
    Credit Agreement dated December 28, 2004, between F-W Oil
Exploration L.L.C. and Guaranty Bank, FSB (filed herewith)10.26.1
    
    Security Agreement dated December 28, 2004, between F-W Oil
Exploration L.L. C. and Guaranty Bank, FSB (filed herewith)10.26.2
    
    Ratification of and Amendment to Act of Mortgage and Security
Agreement effective December 28, 2004,by F-W Oil Exploration
L.L.C. for the benefit of Guaranty Bank, FSB (filed herewith)10.26.3
    
    Ratification of and Amendment to Mortgage, Deed of Trust, Security
Agreement, Financing Statement, Fixture Filing and Assignment of
Production by F-W Oil Exploration L.L.C. for the benefit of
Guaranty Bank, FSB (filed herewith)21
    
    Subsidiaries (filed herewith)23
    
    Consent of Ryder Scott & Company L.P. Company (filed herewith)31.1
    
    Certification of Chief Executive Officer pursuant to
Rule13(a)-14(a)/15d-14(a) of the Securities Exchange Act of 1934,
as amended (filed herewith)31.2
    
    Certification of Chief Financial Officer pursuant to
Rule13(a)-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as
 21




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##### Table of Contents



amended (filed herewith)32.1
    
    Certification of Chief Executive Officer pursuant to 18 U.S.C.
Section 1350, adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002 (filed herewith)32.2
    
    Certification of Chief Financial Officer pursuant to 18 U.S.C.
Section 1350, adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002 (filed herewith)
 22




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##### Table of Contents



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 31st day of March, 2005. PrimeEnergy CorporationBy:
    
    /s/ CHARLES E. DRIMAL, JRCharles 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 31st day of March, 2005. /s/ CHARLES E. DRIMAL, JR.
    
    Director and President;The Principal Executive OfficerCharles E. Drimal, Jr./s/ BEVERLY A. CUMMINGS
    
    Director, Vice President and Treasurer;The Principal Financial and AccountingBeverly A. Cummings
    
    Officer/s/ MATTHIAS ECKENSTEIN
    
    
    
    /s/ CLINT HURTDirector
    
    
    
    DirectorMatthias Eckenstein
    
    
    
    Clint Hurt/s/ H. GIFFORD FONG
    
    
    
    /s/ JAN K. SMEETSDirector
    
    
    
    DirectorH. Gifford Fong
    
    
    
    Jan K. Smeets/s/ THOMAS S.T. GIMBEL
    
    
    
    /s/ GAINES WEHRLEDirector
    
    
    
    DirectorThomas S.T. Gimbel
    
    
    
    Gaines Wehrle
 23




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##### Table of Contents



INDEX TO FINANCIAL STATEMENTS Report of
Independent Registered Public Accounting Firm
    
    
    F-2Financial StatementsConsolidated Balance Sheets  December 31, 2004 and 2003
    
    
    F-3Consolidated Statements of Operations  for the years ended December 31, 2004, 2003 and 2002
    
    
    F-5Consolidated Statement of Stockholders Equity  for the years ended December 31, 2004, 2003 and 2002
    
    
    F-6Consolidated Statements of Cash Flows  for the years ended December 31, 2004, 2003 and 2002
    
    
    F-7Notes to Consolidated Financial Statements
    
    
    F-8Supplementary Information:Capitalized
Costs Relating to Oil and Gas Producing Activities, years ended December 31, 2004, 2003 and 2002
    
    
    F-19Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities, years ended
December 31, 2004, 2003 and 2002
    
    
    F-19Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, years
ended December 31, 2004, 2003 and 2002
    
    
    F-20Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil an
Gas Reserves, years ended December 31, 2004, 2003 and 2002
    
    
    F-21Reserve Quantity Information, years ended December 31, 2004, 2003 and 2002
    
    
    F-22Results of Operations from Oil and Gas Producing Activities, years ended December 31, 2004, 2003 and 2002
    
    
    F-23Notes to Supplementary Information
    
    
    F-24
 F-1




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##### Table of Contents



REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 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 (the Corporation) as of December 31, 2004 and 2003, and the related consolidated
statements of operations, stockholders equity, and cash flows for the years ended December 31
2004, 2003 and 2002. 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 the standards of the Public Company Accounting Oversight
Board (United States). Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material misstatement. An
audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the
financial statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material
respects, the consolidated financial position of PrimeEnergy Corporation and Subsidiaries as of
December 31, 2004 and 2003, and the consolidated results of its operations and cash flows for the
years ended December 31, 2004, 2003 and 2002 in conformity with U.S generally accepted accounting
principles. PUSTORINO, PUGLISI & CO., LLP
New York, New York
March 30, 2005 F-2




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PRIMEENERGY CORPORATION and SUBSIDIARIES CONSOLIDATED BALANCE SHEETS, December 31, 2004 and 2003 2004
    
    
    2003ASSETS:Current assets:Cash and cash equivalents
    
    $
    6,476,000
    
    
    $
    3,891,000Restricted cash and cash equivalents
    
    
    1,864,000
    
    
    
    1,479,000Accounts receivable, net
    
    
    8,694,000
    
    
    
    7,108,000Due from related parties
    
    
    
    
    
    
    209,000Prepaid expenses
    
    
    447,000
    
    
    
    336,000Other current assets
    
    
    433,000
    
    
    
    297,000Deferred income taxes
    
    
    409,000
    
    
    
    374,000Total current assets
    
    
    18,323,000
    
    
    
    13,694,000Property and equipment, at cost :Proved oil and gas properties at cost
    
    
    95,018,000
    
    
    
    91,012,000Unproved oil and gas properties at cost
    
    
    13,149,000
    
    
    
    3,091,000Less, accumulated depletion and depreciation
    
    
    (60,098,000
    )
    
    
    (53,196,000
    )48,069,000
    
    
    
    40,907,000Field and office equipment
    
    
    9,610,000
    
    
    
    9,389,000Less, accumulated depreciation
    
    
    (6,307,000
    )
    
    
    (5,964,000
    )3,303,000
    
    
    
    3,425,000Total net property and equipment
    
    
    51,372,000
    
    
    
    44,332,000Other assets
    
    
    231,000
    
    
    
    229,000Total assets
    
    $
    69,926,000
    
    
    $
    58,255,000
 The accompanying notes are an integral part of the consolidated financial statements. F-3




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##### Table of Contents



PRIMEENERGY CORPORATION and SUBSIDIARIES CONSOLIDATED BALANCE SHEETS, December 31, 2004 and 2003 2004
    
    
    2003LIABILITIES and STOCKHOLDERS EQUITY:Current liabilities:Accounts payable
    
    $
    9,929,000
    
    
    $
    8,528,000Current portion of other long-term obligations
    
    
    12,000
    
    
    
    692,000Accrued liabilities:Payroll, Benefits, Interest and Other
    
    
    3,228,000
    
    
    
    3,504,000Due to related parties
    
    
    600,000
    
    
    
    933,000Total current liabilities
    
    
    13,769,000
    
    
    
    13,657,000Long-term bank debt
    
    
    29,900,000
    
    
    
    26,613,000Other long-term obligations
    
    
    
    
    
    
    12,000Asset retirement obligations
    
    
    390,000
    
    
    
    300,000Deferred income taxes
    
    
    7,630,000
    
    
    
    4,237,000Total liabilities
    
    
    51,689,000
    
    
    
    44,819,000Stockholders 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
2004 and 2003
    
    
    769,000
    
    
    
    769,000Paid in capital
    
    
    11,024,000
    
    
    
    11,024,000Retained earnings
    
    
    22,653,000
    
    
    
    15,378,00034,446,000
    
    
    
    27,171,000Treasury stock, at cost 4,202,745 common shares in 2004 and 4,065,768 in 2003
    
    
    (16,209,000
    )
    
    
    (13,735,000
    )Total stockholders equity
    
    
    18,237,000
    
    
    
    13,436,000Total liabilities and stockholders equity
    
    $
    69,926,000
    
    
    $
    58,255,000
 The accompanying notes are an integral part of the consolidated financial statements. F-4




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##### Table of Contents



PRIMEENERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS of OPERATIONS for the years ended December 31, 2004, 2003 and 2002 2004
    
    
    2003
    
    
    2002Revenue:Oil and gas sales
    
    $
    43,967,000
    
    
    $
    29,855,000
    
    
    $
    18,330,000Field service revenue
    
    
    11,965,000
    
    
    
    11,013,000
    
    
    
    9,891,000Administrative overhead fees
    
    
    6,317,000
    
    
    
    5,723,000
    
    
    
    5,588,000Gains/(losses) on derivative instruments net
    
    
    
    
    
    
    (52,000
    )
    
    
    (113,000
    )Interest and other income
    
    
    179,000
    
    
    
    180,000
    
    
    
    490,00062,428,000
    
    
    
    46,719,000
    
    
    
    34,186,000Costs and expenses:Lease operating expense
    
    
    14,939,000
    
    
    
    12,783,000
    
    
    
    10,210,000Field service expense
    
    
    10,939,000
    
    
    
    9,970,000
    
    
    
    8,910,000Depreciation,
depletion and amortization
    
    
    12,156,000
    
    
    
    7,525,000
    
    
    
    5,231,000General and administrative expense
    
    
    7,536,000
    
    
    
    6,995,000
    
    
    
    6,007,000Exploration costs
    
    
    5,499,000
    
    
    
    519,000
    
    
    
    894,000Interest expense
    
    
    1,136,000
    
    
    
    880,000
    
    
    
    766,00052,205,000
    
    
    
    38,672,000
    
    
    
    32,018,000Income from operations
    
    
    10,223,000
    
    
    
    8,047,000
    
    
    
    2,168,000Other income:Gain on sale and exchange of assets
    
    
    75,000
    
    
    
    101,000
    
    
    
    32,000Income before provision for income taxes
    
    
    10,298,000
    
    
    
    8,148,000
    
    
    
    2,200,000Provision for income taxes
    
    
    3,023,000
    
    
    
    2,446,000
    
    
    
    443,000Net income
    
    $
    7,275,000
    
    
    $
    5,702,000
    
    
    $
    1,757,000Basic net income per common share
    
    $
    2.04
    
    
    $
    1.56
    
    
    $
    0.47Diluted net income per common share
    
    $
    1.70
    
    
    $
    1.31
    
    
    $
    0.40
 The accompanying notes are an integral part of the consolidated financial statements. F-5




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PRIMEENERGY CORPORATION and SUBSIDIARIES CONSOLIDATED STATEMENT of STOCKHOLDERS EQUITY for the years ended December 31, 2004, 2003 and 2002 AdditionalCommon Stock
    
    
    Paid In
    
    
    Retained
    
    
    TreasuryShares
    
    
    Amount
    
    
    Capital
    
    
    Earnings
    
    
    Stock
    
    
    TotalBalance at December 31, 2001
    
    
    7,694,970
    
    
    $
    769,000
    
    
    $
    11,024,000
    
    
    $
    7,919,000
    
    
    $
    (12,349,000
    )
    
    $
    7,363,000Purchased 92,862 shares of common stock
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (745,000
    )
    
    
    (745,000
    )Net income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    1,757,000
    
    
    
    
    
    
    
    1,757,000Balance at December 31, 2002
    
    
    7,694,970
    
    
    $
    769,000
    
    
    $
    11,024,000
    
    
    $
    9,676,000
    
    
    $
    (13,094,000
    )
    
    $
    8,375,000Purchased 63,804 shares of common stock
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (641,000
    )
    
    
    (641,000
    )Net income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    5,702,000
    
    
    
    
    
    
    
    5,702,000Balance at December 31, 2003
    
    
    7,694,970
    
    
    $
    769,000
    
    
    $
    11,024,000
    
    
    $
    15,378,000
    
    
    $
    (13,735,000
    )
    
    $
    13,436,000Purchased 136,977 shares of common stock
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (2,474,000
    )
    
    
    (2,474,000
    )Net income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    7,275,000
    
    
    
    
    
    
    
    7,275,000Balance at December 31, 2004
    
    
    7,694,970
    
    
    $
    769,000
    
    
    $
    11,024,000
    
    
    $
    22,653,000
    
    
    $
    (16,209,000
    )
    
    $
    18,237,000
 The accompanying notes are an integral part of the consolidated financial statements. F-6




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##### Table of Contents



PRIMEENERGY CORPORATION and SUBSIDIARIES CONSOLIDATED STATEMENT of CASH FLOWS for the years ended December 31, 2004, 2003 and 2002 2004
    
    
    2003
    
    
    2002Cash flows from operating activities:Net income
    
    $
    7,275,000
    
    
    $
    5,702,000
    
    
    $
    1,757,000Adjustments
to reconcile net income to net cash provided by operating activities:Depreciation, depletion and amortization
    
    
    12,156,000
    
    
    
    7,525,000
    
    
    
    5,231,000Dry hole and abandonment costs
    
    
    5,499,000
    
    
    
    519,000
    
    
    
    894,000Gain on sale of properties
    
    
    (75,000
    )
    
    
    (101,000
    )
    
    
    (32,000
    )Provision for deferred income taxes
    
    
    3,358,000
    
    
    
    1,580,000
    
    
    
    243,000Changes in assets and liabilities:(Increase) decrease in accounts receivable
    
    
    (1,586,000
    )
    
    
    (2,982,000
    )
    
    
    (328,000
    )(Increase) decrease in due from related parties
    
    
    209,000
    
    
    
    4,562,000
    
    
    
    153,000(Increase) decrease in other assets
    
    
    (137,000
    )
    
    
    3,000
    
    
    
    682,000(Increase) decrease in prepaid expenses
    
    
    (111,000
    )
    
    
    (97,000
    )
    
    
    (175,000
    )Increase (decrease) in accounts payable
    
    
    1,016,000
    
    
    
    1,699,000
    
    
    
    736,000Increase (decrease) in accrued liabilities
    
    
    (276,000
    )
    
    
    1,712,000
    
    
    
    (19,000
    )Increase (decrease) in due to related parties
    
    
    (333,000
    )
    
    
    (500,000
    )
    
    
    502,000Net cash provided by operating activities
    
    
    26,995,000
    
    
    
    19,622,000
    
    
    
    9,644,000Cash flows from investing activitiesProceeds from sale of properties and equipment
    
    
    75,000
    
    
    
    101,000
    
    
    
    32,000Additions to property and equipment
    
    
    (24,696,000
    )
    
    
    (19,835,000
    )
    
    
    (14,442,000
    )Net cash used in investing activities
    
    
    (24,621,000
    )
    
    
    (19,734,000
    )
    
    
    (14,410,000
    )Cash flows from financing activitiesPurchase of stock for treasury
    
    
    (2,474,000
    )
    
    
    (641,000
    )
    
    
    (745,000
    )Repayment of long-term bank debt and other long-term obligations
    
    
    (29,837,000
    )
    
    
    (43,679,000
    )
    
    
    (43,260,000
    )Increase in long-term bank debt and other long-term obligations
    
    
    32,522,000
    
    
    
    46,437,000
    
    
    
    50,572,000Net cash provided by (used in) financing activities
    
    
    211,000
    
    
    
    2,117,000
    
    
    
    6,567,000Net increase (decrease) in cash
    
    
    2,585,000
    
    
    
    2,005,000
    
    
    
    1,801,000Cash and cash equivalents, beginning of year
    
    
    3,891,000
    
    
    
    1,886,000
    
    
    
    85,000Cash and cash equivalents, end of year
    
    $
    6,476,000
    
    
    $
    3,891,000
    
    
    $
    1,886,000Supplemental disclosures:Income taxes paid during the year
    
    $
    
    
    
    $
    83,500
    
    
    $
    Net income tax refunds received during the year
    
    $
    172,000
    
    
    $
    
    
    
    $
    745,000Interest paid during the year
    
    $
    953,000
    
    
    $
    880,000
    
    
    $
    766,000
 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




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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. 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
United States, including Colorado, Kansas, Louisiana, Mississippi,
Montana, Nebraska, New Mexico, North Dakota, Oklahoma, Texas, Utah,
West Virginia and Wyoming and the Gulf of Mexico. The Company
operates 1,533 wells and owns non-operating interests in over 770
additional wells. Additionally, the Company provides well-servicing
support operations, site-preparation and construction services for
oil and gas drilling and reworking 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. PEC owns
Eastern Oil Well Service Company (EOWSC), EOWS Midland
Company (EMID)
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. During 2003 PEC acquired a sixty percent interest in F-W Oil Exploration LLC,
(FW), which owns and operates properties in the Gulf of Mexico. PrimeEnergy Corporation and
its subsidiaries are herein referred to as the Company.
PrimeEnergy Management Corporation (PEMC), a wholly-owned
subsidiary, acts as the managing general partner, providing
administration, accounting and tax preparation services for 18
private and publicly-held limited partnerships and 2 trusts
(collectively, the Partnerships). During the course of
2003 PrimeEnergy dissolved 20 private limited partnerships. 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. Consolidation
and Presentation: The consolidated financial statements include the accounts of PrimeEnergy Corporation, its
subsidiaries and the Partnerships, using the proportionate consolidation method, whereby our
proportionate share of each entitys assets, liabilities, revenue and expenses are included in
the appropriate classifications in the consolidated financial statements. Inter-company balances
and transactions are eliminated in preparing the consolidated
financial statements. Certain 2002 and 2003 amounts have been
reclassified where appropriate to conform with the 2004 presentation. These
reclassifications had no effect on the Companys  net income
(loss) or stockholders equity. 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 144 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




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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. 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. Asset Retirement Obligation: Effective January 1, 2003, the Company adopted SFAS No. 143, Accounting for Asset Retirement
Obligations. Our asset retirement obligation primarily represents the estimated present value
of the amount the Company will incur to plug, abandon and remediate our producing properties
(including removal of our offshore platforms) at the end of their productive lives, in
accordance with applicable state laws. The Company determined its asset retirement obligation
by calculating the present value of estimated cash flows related to the liability. The
retirement obligation is recorded as a liability at its estimated present value as of the
assets inception, with an offsetting increase to producing properties. Periodic accretion of
discount of the estimated liability is recorded as an expense in the income statement. 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. F-9




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PRIMEENERGY CORPORATION and SUBSIDIARIES NOTES to CONSOLIDATED FINANCIAL STATEMENTS 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. Hedging: The Company periodically enters into oil and gas financial instruments to manage its
exposure to oil and gas price volatility. The oil and gas reference prices upon which the
price hedging instruments are based reflect various market indices that have a high degree of
historical correlation with actual prices received by the Company. The financial instruments are accounted for in accordance with Financial Accounting Standards
(SFAS) No. 133, Accounting for Derivative Instruments and Hedging Activities, which
established new accounting and reporting requirements for derivative instruments and hedging
activities. SFAS No. 133, as amended by SFAS No. 138, requires that all derivative instruments
subject to the requirements of the statement be measured at fair market value and recognized
as assets or liabilities in the balance sheet. The accounting for changes in the fair value of
a derivative depends on the intended use of the derivative and the resulting designation is
generally established at the inception of a derivative. For derivatives designated as cash
flow hedges and meeting the effectiveness guidelines of SFAS No. 133, changes in fair value,
to the extent effective, are recognized in other comprehensive income until the hedged item is
recognized in earnings. Hedge effectiveness is measured at least quarterly based on the
relative changes in fair value between the derivative contract and the hedged item over time.
Any change in fair value of a derivative resulting from ineffectiveness or an excluded
component of the gain/loss is recognized immediately in the statement of operations. F-10




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PRIMEENERGY CORPORATION and SUBSIDIARIES NOTES to CONSOLIDATED FINANCIAL STATEMENTS Recently Issued Accounting Standards: In April 2002, the FASB issued SFAS No. 145, Rescission of FASB Statements No. 4, 44 and 64,
Amendment of FASB Statement No. 13 and Technical Corrections. Prior to the adoption of the
provisions of SFAS No. 145, generally accepted accounting principles required gains or losses on
the early extinguishment of debt be classified in a companys periodic consolidated statements of
operations as extraordinary gains or losses, net of associated income taxes, below the
determination of income or loss from continuing operations. SFAS No. 145 changes generally
accepted accounting principles to require, except in the case of events or transactions of a
highly unusual and infrequent nature, gains or losses from the early extinguishment of debt be
classified as components of a companys income or loss from continuing operations. The adoption
of the provisions of SFAS No. 145 in 2003 did not affect the Companys financial position or
results of operations. In June 2002, the FASB issued SFAS No. 146, Accounting for Costs Associated with Exit or
Disposal Activities. SFAS No. 146 requires that a liability for a cost associated with an exit
or disposal activity be recognized and measured initially at fair value only when the liability
is incurred. SFAS No. 146 is effective for exit or disposal activities that are initiated after
December 31, 2002. The adoption of SFAS No. 146 in 2003 did not effect on the Companys financial
position or results of operations. In November 2002, the FASB issued Financial Interpretation No. 45, Guarantors Accounting and
Disclosure Requirements for Guarantees, including Indirect Guarantee of Indebtedness of Others
(FIN 45). FIN 45 requires that upon issuance of a guarantee, the guarantor must recognize a
liability for the fair value of the obligation it assumes under that guarantee. FIN 45s
provisions for initial recognition and measurement should be applied on a prospective basis to
guarantees issued or modified after December 31, 2002. The guarantors previous accounting for
guarantees that were issued before the date of FIN 45s initial application may not be revised or
restated to reflect the effect of the recognition and measurement provisions of the
Interpretation. The disclosure requirements are effective for financial statements of both
interim and annual periods that end after December 15, 2002. The adoption of FIN 45 did not have
an impact on the Companys consolidated financial statements. In December 2002, the FASB issued SFAS 148, Accounting for Stock-Based CompensationTransition
and Disclosure. SFAS No. 148 amends FASB Statement No. 123, Accounting for Stock-Based
Compensation to provide alternative methods of transition for a voluntary change to the fair
value based method of accounting for stock-based employee compensation. In addition, this
Statement amends the disclosure for stock-based employee compensation and the effect of the
method used on the reported results. The provisions of SFAS 148 are effective for financial
statements with fiscal years ending after December 15, 2002. The adoption of this statement has
not impacted the Companys financial position or results of operations. In January 2003, the FASB issued Financial Interpretation No. 46, Consolidation of Variable
Interest Entitiesan interpretation of ARB No. 51 (FIN 46). FIN 46 is an interpretation of
Accounting Research Bulletin 51, Consolidated Financial Statements, and addresses consolidation
by business enterprises of variable interest entities (VIEs). The primary objective of FIN 46 is
to provide guidance on the identification of, and financial reporting for, entities over which
control is achieved through means other than voting rights; such entities are known as VIEs. FIN
46 requires an enterprise to consolidate a variable interest entity if that enterprise has a
variable interest that will absorb a majority of the entitys expected losses if they occur,
receive a majority of the entitys expected residual return if they occur, or both. An enterprise
shall consider the rights and obligations conveyed by its variable interests in making this
determination. This guidance applies immediately to variable interest entities created after
January 31, 2003, and to variable interest entities in which an enterprise obtains an interest
after that date. It applies in the first fiscal year or interim period beginning after June 15,
2003, to variable interest entities in which an enterprise holds a variable interest that it
acquired before February 1, 2003. The adoption of this interpretation did not have an effect on
the Companys financial position or results of operations. In December 2004, the FASB issued SFAS No. 123R, Share-Based Payment. SFAS 123R revises
SFAS 123, Accounting for Stock-Based Compensation, and focuses on accounting for share-based
payments for services by employer to employee. The statement requires companies to expense the
fair value of employee stock options and other equity-based compensation at the grant date. The
statement does not require a certain type of valuation model and either a binomial or
Black-Scholes model may be used. F-11




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PRIMEENERGY CORPORATION and SUBSIDIARIES NOTES to CONSOLIDATED FINANCIAL STATEMENTS The provisions of SFAS 123R are effective for financial statements for fiscal periods ending
after June 15, 2005. We are currently evaluating the method of adoption and the impact on our
operating results. Our future cash flows will not be impacted by the adoption of this standard. In February 2005, the FASB released for public comment proposed Staff Position FAS 19-a
Accounting for Suspended Well Costs. This proposed staff position would amend FASB Statement
No. 19 Financial Accounting and Reporting by Oil and Gas Producing Companies and provides
guidance about exploratory well costs to companies who use the successful efforts method of
accounting. The proposed position states that exploratory well costs should continue to be
capitalized if: 1) a sufficient quantity of reserves are discovered in the well to justify its
completion as a producing well and 2) sufficient progress is made in assessing the reserves and
the wells economic and operating feasibility. If the exploratory well costs do not meet both of
these criteria, these costs should be expensed, net of any salvage value. Additional disclosures
are required to provide information about managements evaluation of capitalized exploratory well
costs. In addition, the Staff Position requires the disclosure of: 1) net changes from period to
period of capitalized exploratory well costs for wells that are pending the determination of
proved reserves, 2) the amount of exploratory well costs that have been capitalized for a period
greater than one year after the completion of drilling and 3) an aging of exploratory well costs
suspended for greater than one year with the number of wells it related to. Further, the
disclosures should describe the activities undertaken to evaluate the reserves and the projects,
the information still required to classify the associated reserves as proved and the estimated
timing for completing the evaluation.  2.
    Significant Acquisitions, Dispositions and Property
Activity As more fully described in Note 7, the Company is committed to offer to repurchase the interests
of the partners and trust unit holders in certain of the Partnerships. The Company purchased such
interests in an amount totaling $ 2,038,305 in 2004, $695,673 in 2003 and $1,203,500 in 2002.
The Companys proportionate share of assets, liabilities and results of operations related to the
interests in the Partnerships are included in the consolidated financial statements. Properties
under evaluation include $7.5 million invested in one offshore well
completed and tested during the third quarter of 2004, however, early
production tests have been inconclusive as to the commercial
viability of this prospect. Additional expenditures during 2005 will
be required to determine whether production rates and ultimate
recoverable reserves are sufficient to warrant the costs of setting a
platform and installing production facilities. Effective August 15, 2003 the Company acquired a sixty percent interest in F-W Oil Exploration
L.L.C., a licensed Gulf of Mexico operator for a cost of $4,000,000. As of that date FW had
approximately 80,000 net acres to develop and a 12.5% working interest in two producing blocks in
the Gulf of Mexico. The Companys proportionate share of FWs assets, liabilities and results of
operations for the effective period are included in the consolidated financial statements.  3.
    Accounts Receivable Accounts receivable at December 31, 2004 and 2003 consisted of the following: December 31,2004
    
    
    2003Joint interest billing
    
    $
    1,048,000
    
    
    $
    1,174,000Trade receivables
    
    
    1,728,000
    
    
    
    1,607,000Oil and gas sales
    
    
    6,181,000
    
    
    
    3,878,000Other
    
    
    324,000
    
    
    
    906,0009,281,000
    
    
    
    7,565,000Less: allowance for doubtful accounts
    
    
    (587,000
    )
    
    
    (457,000Total
    
    $
    8,694,000
    
    
    $
    7,108,000
 F-12




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##### Table of Contents



PRIMEENERGY CORPORATION and SUBSIDIARIES NOTES to CONSOLIDATED FINANCIAL STATEMENTS  4.
    Other Current Assets Other current assets at December 31, 2004 and 2003 consisted of the following: December 31,2004
    
    
    2003Field service inventory
    
    $
    375,000
    
    
    $
    278,000Other
    
    
    58,000
    
    
    
    19,000$
    433,000
    
    
    $
    297,000
  5.
    Long-Term Bank Debt As of December 2002 the Company entered in to a credit agreement with a new primary lender. The
Company and the lender agreed to amend and restate in its entirety the credit agreement dated
April 26, 1995 between the Company and its predecessor lender. This agreement will continue to
provide 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. The borrowing base as of December 31, 2004, was $25 million and
included a Term Loan of $4 million. The Term Loan called for monthly installments of $66,667
beginning January 2003. The credit agreement provides for interest on outstanding borrowings at
the banks base rate, as defined, payable monthly, or at rates 2% over the London Inter-Bank
Offered Rate (LIBO rate) payable at the end of the applicable interest period. As of September 2003 the credit agreement was amended to add FW as an additional borrower. As of
December 31, 2003 the total outstanding balance owed by FW to the lender was $3,800,000. FWs oil
and gas properties are pledged as security under the loan agreement as collateral for amounts due
from FW to the lender. The Companys proportionate share of amounts owed by FW to the lender are
included in the consolidated financial statements. Total outstanding borrowings under the amended
loan agreement as of December 31, 2003 were $28,000,000. As of December 2004, FW entered into a stand-alone agreement with the same lender and the Company
agreement was amended to remove FW as a borrower and eliminate the Companys obligation on
amounts owed to the lender by FW. The total outstanding borrowings under the Companys amended
loan agreement as of December 31, 2004 were $23,600,000 with $12,679,992 of additional
availability. The total outstanding borrowings under the FW loan agreement as of December 31,
2004, were $10,500,000 with $2,500,000 of additional availability. The Companys proportionate
share of amounts owed by FW are included in the consolidated financial statements. Effective March 2005, the lender has agreed to convert the Term Loan into a revolving line of
credit with interest rate options to coincide with the existing line of credit. The Companys
borrowing base as of March 2005 was determined to be $41,000,000. The interest rates paid on outstanding borrowings subject to interest at the banks base rate as
of December 31, 2004 and 2003 were 5.25% and 4.5% respectively. During the same periods, the
average rates paid on outstanding borrowings bearing interest based upon the LIBO rate were 3.91%
and 3.84%. As of December 31, 2004 and 2003, the total outstanding consolidated borrowings were
$29,900,000 and $27,280,000, respectively. All borrowings under the
Companys credit agreements are due March, 2007. 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. F-13




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##### Table of Contents



NOTES to CONSOLIDATED FINANCIAL STATEMENTS 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 two capital leases for office equipment in other long-term obligations. Future
minimum lease payments under operating and capital leases are as follows: Operating
    
    
    CapitalLeases
    
    
    Leases2005
    
    
    349,000
    
    
    
    12,0002006
    
    
    344,000
    
    
    
    2007
    
    
    195,000
    
    
    
    2008
    
    
    187,500
    
    
    
    Thereafter
    
    
    15,500
    
    
    
    Total minimum payments
    
    $
    1,091,000
    
    
    
    12,000Less imputed interest
    
    
    
    
    
    
    (1,000
    )Present value of minimum Lease payments
    
    
    
    
    
    $
    11,000
  Asset Retirement Obligation: A reconciliation of our liability for plugging and abandonment
costs for the years ended December 31, 2004 and 2003 is as
follows: 2004
    
    2003Asset retirement
    obligation  beginning of period
    
    $
    300,000
    
    
    $
    Liabilities incurred
    
    
    90,000
    
    
    
    300,000Liabilities settled
    
    
    (4,900
    )
    
    
    (69,000
    )Accretion expense
    
    
    13,500
    
    
    
    4,500Change in estimate
    
    
    (8,600
    )
    
    
    (64,500
    )Asset retirement obligation  end
    of period
    
    $
    390,000
    
    
    $
    300,000 The Companys liability is determined using significant
assumptions, including current estimates of plugging and
abandonment costs, annual inflation of these costs, the
productive life of wells and our risk-adjusted interest rate.
Changes in any of these assumptions can result in significant
revisions to the estimated asset retirement obligation.
Revisions to the asset retirement obligation are recorded with
an offsetting change to producing properties, resulting in
prospective changes to depreciation, depletion and amortization
expense and accretion of discount. Because of the subjectivity
of assumptions and the relatively long life of most of our
wells, the costs to ultimately retire our wells may vary
significantly from previous estimates.  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. 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 $200,000. F-14




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##### Table of Contents



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, 2004 and 2003, options on
767,500 shares were outstanding and exercisable at prices ranging from $1.00 to $1.25.  9.
    Income Taxes The components of the provision for income taxes for the years ended December 31, 2004, 2003 and
2002 are as follows: 2004
    
    
    2003
    
    
    2002Federal:Current
    
    $
    187,000
    
    
    $
    696,000
    
    
    $
    95,000Deferred
    
    
    2,074,000
    
    
    
    1,460,000
    
    
    
    216,000State:Current
    
    
    266,000
    
    
    
    171,000
    
    
    
    104,000Deferred
    
    
    496,000
    
    
    
    119,000
    
    
    
    28,000Total
    
    $
    3,023,000
    
    
    $
    2,446,000
    
    
    $
    443,000
 The components of net deferred tax assets (liabilities) are as follows: December 31,
    
    
    December 31,2004
    
    
    2003Current assets:Compensation and benefits
    
    $
    196,000
    
    
    $
    196,000Allowance for doubtful accounts
    
    
    213,000
    
    
    
    178,000Total
current deferred income tax assets
    
    
    409,000
    
    
    
    374,000Noncurrent assets:Alternative minimum tax credits
    
    
    902,000
    
    
    
    393,000902,000
    
    
    
    393,000Noncurrent liabilities:Basis differences relating to partnerships
    
    
    468,000
    
    
    
    1,351,000Depletion
& depreciation
    
    
    8,064,000
    
    
    
    3,279,0008,532,000
    
    
    
    4,630,000Net
noncurrent deferred income tax liabilities
    
    $
    7,630,000
    
    
    $
    4,237,000
 F-15




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##### Table of Contents



PRIMEENERGY CORPORATION and SUBSIDIARIES NOTES to CONSOLIDATED FINANCIAL STATEMENTS, Continued The total provision for income taxes for the years ended December 31, 2004, 2003 and 2002 varies
from the federal statutory tax rate as a result of the following: December 31,
    
    
    December 31,
    
    
    December 31,2004
    
    
    2003
    
    
    2002Expected tax expense
    
    $
    3,501,000
    
    
    $
    2,770,000
    
    
    $
    748,000State income tax, net of federal benefit
    
    
    503,000
    
    
    
    195,000
    
    
    
    132,000Credit for producing fuel from a non-conventional source
    
    
    
    
    
    
    
    
    
    
    (134,000
    )Percentage depletion
    
    
    (811,000
    )
    
    
    (400,000
    )
    
    
    (303,000
    )Other
    
    
    (170,000
    )
    
    
    (119,000
    )
    
    
    Tax expense
    
    $
    3,023,000
    
    
    $
    2,446,000
    
    
    $
    443,000
 For many
years prior to 2003, the Companys current taxes were lowered due to the utilization of
federal net operating loss and percentage depletion carryforwards. With the filing of the 2002
federal income tax return, all of these carryforwards were used or expired. In 2002 and
prior tax years, the Company was allowed a federal tax credit for producing fuel from
a nonconventional source. This credit expired at the end of 2002. To the extent that the credit
for producing fuel from a nonconventional source could not be utilized due to the alternative
minimum tax, it became part of the Companys alternative minimum tax credit, which may be carried
forward indefinitely. Due to the factors discussed above, it is possible that the Companys
current tax liabilities in the future will be significantly greater than in past years. The primary reason that the Companys federal tax expense for both 2004 and 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 increases in
the Companys deferred tax liability in both 2004 and 2003. The Company is entitled to percentage depletion on certain of its wells, which is calculated
without reference to the basis of the property to the extent that such depletion exceeds a
propertys basis they represent a permanent difference which lowers the Companys effective rate.  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 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 2004. Oil Purchasers:
    
    
    
    
    
    Gas Purchasers:Texon Distributing L.P.
    
    
    26.65%
    
    
    Unimark LLC
    
    
    10.29%Plains All American Inc.
    
    
    29.29%TEPPCO Crude Oil, L.L.C.
    
    
    16.20%LPC Crude Oil, Inc.
    
    
    16.10%
 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. F-16




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##### Table of Contents



PRIMEENERGY CORPORATION and SUBSIDIARIES NOTES to CONSOLIDATED FINANCIAL STATEMENTS, Continued  11.
    Related Party Transactions PEMC acts as the managing general partner, providing administration, accounting and tax
preparation services for the Partnerships. Certain directors have limited and general partnership
interests in several of these Partnerships. 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. As more fully described in Note 7, the Company
is committed to offer to repurchase the interests of the partners and trust unit holders in
certain of the Partnerships. The Company purchased such interests in an amount totaling $
2,038,305 in 2004 and $695,673 in 2003. The Partnership agreements allow PEMC to receive reimbursement for property acquisition and
development costs and general and administrative overhead, incurred on behalf of the
Partnerships. Due to related parties at December 31, 2004 and 2003 primarily represents receipts collected by
the Company as agent, from oil and gas sales net of expenses. The amount of such receipts due the
affiliated Partnerships was $600,000 and $933,000 at December 31, 2004 and 2003, 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 2004 and 2003 included shares acquired from related parties.
Purchases from related parties include a total of 35,000 shares purchased for a total
consideration of $606,100 in 2004, and 37,350 shares purchased for a total consideration of
$398,838 in 2003.  12.
    Restricted Cash and Cash Equivalents Restricted cash and cash equivalents includes $1,864,000 and $1,479,000 at December 31, 2004 and
2003, respectively, of cash primarily pertaining to unclaimed royalty payments. There were
corresponding accounts payable recorded at December 31, 2004 and 2003 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 $292,000 and $278,000 in 2004 and 2003, respectively.  14.
    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: Year ended December 31, 2004Number of
    
    
    Per shareNet Income
    
    
    Shares
    
    
    AmountNet income per common share
    
    $
    7,275,000
    
    
    
    3,569,751
    
    
    $
    2.04Effect of dilutive securities:Options
    
    
    
    
    
    
    722,283Diluted net income per common share
    
    $
    7,275,000
    
    
    
    4,292,034
    
    
    $
    1.70
 Year ended December 31, 2003Number of
    
    
    Per shareNet Income
    
    
    Shares
    
    
    AmountNet income per common share
    
    $
    5,702,000
    
    
    
    3,664,627
    
    
    $
    1.56Effect of dilutive securities:Options
    
    
    
    
    
    
    683,409Diluted net income per common share
    
    $
    5,702,000
    
    
    
    4,348,036
    
    
    $
    1.31
 F-17




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##### Table of Contents



PRIMEENERGY CORPORATION and SUBSIDIARIES NOTES to CONSOLIDATED FINANCIAL STATEMENTS, Continued  14.
    Earnings per Share continued Year ended December 31, 2002Number of
    
    
    Per shareNet Income
    
    
    Shares
    
    
    AmountNet income per common share
    
    $
    1,757,000
    
    
    
    3,738,753
    
    
    $
    0.47Effect of dilutive securities:Options
    
    
    
    
    
    
    666,839Diluted net income per common share
    
    $
    1,757,000
    
    
    
    4,405,592
    
    
    $
    0.40
  15.
    Selected Quarterly Financial Information (Unaudited) December
    
    
    Fourth
    
    
    Third
    
    
    Second
    
    
    First31, 2004
    
    
    Quarter
    
    
    Quarter
    
    
    Quarter
    
    
    QuarterRevenue
    
    $
    62,428,000
    
    
    $
    18,530,000
    
    
    $
    15,540,000
    
    
    $
    14,987,000
    
    
    $
    13,371,000Operating income
    
    
    10,223,000
    
    
    
    3,910,000
    
    
    
    2,704,000
    
    
    
    1,975,000
    
    
    
    1,634,000Net income
    
    
    7,275,000
    
    
    
    3,133,000
    
    
    
    1,756,000
    
    
    
    1,232,000
    
    
    
    1,154,000Net income per common share
    
    $
    2.04
    
    
    $
    .89
    
    
    $
    0.50
    
    
    $
    0.34
    
    
    $
    0.32Diluted net income per common share
    
    $
    1.70
    
    
    $
    .74
    
    
    $
    0.41
    
    
    $
    0.29
    
    
    $
    0.27
 December
    
    
    Fourth
    
    
    Third
    
    
    Second
    
    
    First31, 2003
    
    
    Quarter
    
    
    Quarter
    
    
    Quarter
    
    
    QuarterRevenue
    
    $
    46,719,000
    
    
    $
    12,741,000
    
    
    $
    12,035,000
    
    
    $
    10,508,000
    
    
    $
    11,435,000Operating income
    
    
    8,047,000
    
    
    
    1,900,000
    
    
    
    2,041,000
    
    
    
    1,681,000
    
    
    
    2,425,000Net income
    
    
    5,702,000
    
    
    
    1,045,000
    
    
    
    1,765,000
    
    
    
    1,067,000
    
    
    
    1,826,000Net income per common share
    
    $
    1.56
    
    
    $
    0.29
    
    
    $
    0.48
    
    
    $
    0.29
    
    
    $
    0.49Diluted net income per common share
    
    $
    1.31
    
    
    $
    0.24
    
    
    $
    0.41
    
    
    $
    0.25
    
    
    $
    0.42
 F-18




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##### Table of Contents



PRIMEENERGY CORPORATION and SUBSIDIARIES SUPPLEMENTARY INFORMATION (Unaudited) PRIMEENERGY CORPORATION and SUBSIDIARIES CAPITALIZED COSTS RELATING to OIL and GAS PRODUCING ACTIVITIES December 31, 2004, 2003 and 2002 (Unaudited) 2004
    
    
    2003
    
    
    2002Developed oil and gas properties
    
    $
        95,018,000
    
    
    $
    91,012,000
    
    
    $
    74,319,000Undeveloped oil and gas properties
    
    
    13,149,000
    
    
    
    3,091,000
    
    
    
    1,134,000108,167,000
    
    
    
    94,103,000
    
    
    
    75,453,000Accumulated depreciation, depletion and valuation allowance
    
    
    60,098,000
    
    
    
    53,196,000
    
    
    
    46,912,000Net capitalized costs
    
    $
    48,069,000
    
    
    $
    40,907,000
    
    
    $
    28,541,000
 COSTS INCURRED in OIL and GAS PROPERTY ACQUISITION,
EXPLORATION and DEVELOPMENT ACTIVITIES Years ended December 31, 2004, 2003 and 2002 (Unaudited) 2004
    
    
    2003
    
    
    2002Acquisition of Properties Developed
    
    $
    2,038,000
    
    
    $
    5,023,000
    
    
    $
    1,668,000Undeveloped
    
    
    10,058,000
    
    
    
    873,000
    
    
    
    848,000Exploration Costs
    
    
    5,499,000
    
    
    
    519,000
    
    
    
    894,000Development Costs
    
    
    7,101,000
    
    
    
    12,294,000
    
    
    
    8,385,000
 See accompanying notes to supplementary information. F-19




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##### Table of Contents



PRIMEENERGY CORPORATION and SUBSIDIARIES STANDARDIZED MEASURE of DISCOUNTED FUTURE
NET CASH FLOWS RELATING to PROVED OIL and GAS RESERVES Years ended December 31, 2004, 2003 and 2002 (Unaudited) 2004
    
    
    2003
    
    
    2002Future cash inflows
    
    $
    378,639,000
    
    
    $
    302,876,000
    
    
    $
    201,750,000Future production and development costs
    
    
    (167,155,000
    )
    
    
    (138,929,000
    )
    
    
    (104,232,000
    )Future income tax expenses
    
    
    (62,819,000
    )
    
    
    (47,696,000
    )
    
    
    (24,230,000
    )Future net cash flows
    
    
    148,665,000
    
    
    
    116,251,000
    
    
    
    73,288,00010% annual discount for estimated timing of cash flow
    
    
    (54,254,000
    )
    
    
    (42,999,000
    )
    
    
    (30,512,000
    )Standardized measure of discounted future net cash flows
    
    $
        94,411,000
    
    
    $
    73,252,000
    
    
    $
    42,776,000
 See accompanying notes to supplementary information. F-20




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##### Table of Contents



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, 2004, 2003 and 2002 (Unaudited) The following are the principal sources of change in the standardized measure of discounted future
net cash flows during 2004, 2003 and 2002: 2004
    
    
    2003
    
    
    2002Sales of oil and gas produced, net of production costs
    
    $
    (29,028,000
    )
    
    $
    (17,072,000
    )
    
    $
    (8,120,000
    )Net changes in prices and production costs
    
    
    22,178,000
    
    
    
    24,732,000
    
    
    
    18,488,000Extensions, discoveries and improved recovery
    
    
    18,792,000
    
    
    
    14,133,000
    
    
    
    8,462,000Revisions of previous quantity estimates
    
    
    9,904,000
    
    
    
    2,491,000
    
    
    
    5,192,000Reserves purchased, net of development costs
    
    
    2,238,000
    
    
    
    9,667,000
    
    
    
    5,824,000Net change in development costs
    
    
    (14,000
    )
    
    
    8,217,000
    
    
    
    (311,000
    )Accretion of discount
    
    
    6,459,000
    
    
    
    4,278,000
    
    
    
    2,097,000Net change in income taxes
    
    
    (9,656,000
    )
    
    
    (15,705,000
    )
    
    
    (9,809,000
    )Other
    
    
    286,000
    
    
    
    (265,000
    )
    
    
    (13,000
    )Net change
    
    
    21,159,000
    
    
    
    30,476,000
    
    
    
    21,810,000Standardized measure of discounted future net cash flow:Beginning of year
    
    
    73,252,000
    
    
    
    42,776,000
    
    
    
    20,966,000End of year
    
    $
    94,411,000
    
    
    $
    73,252,000
    
    
    
    42,776,000
 See accompanying notes to
supplementary information. F-21




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##### Table of Contents



PRIMEENERGY CORPORATION and SUBSIDIARIES RESERVE QUANTITY INFORMATION Years ended December 31, 2004, 2003 and 2002 (Unaudited) 2004
    
    
    2003
    
    
    2002Oil
    
    
    Gas
    
    
    Oil
    
    
    Gas
    
    
    Oil
    
    
    Gas(bbls.)
    
    
    (Mcf)
    
    
    (bbls.)
    
    
    (Mcf)
    
    
    (bbls.)
    
    
    (Mcf)Proved developed and undeveloped reserves:Beginning of year
    
    
    2,905,000

    
    
    
    39,005,000

    
    
    
    2,319,000

    
    
    
    29,917,000

    
    
    
    1,996,000

    
    
    
    24,719,000Extensions, discoveries and improved recovery
    
    
    42,000

    
    
    
    7,268,000

    
    
    
    541,000

    
    
    
    4,245,000

    
    
    
    273,000


    
    
    
    3,011,000Revisions of previous estimates
    
    
    268,000

    
    
    
    2,806,000

    
    
    
    171,000

    
    
    
    263,000

    
    
    
    198,000

    
    
    
    2,798,000Purchases
    
    
    88,000

    
    
    
    929,000

    
    
    
    243,000

    
    
    
    8,571,000

    
    
    
    173,000

    
    
    
    2,929,000Production
    
    
    (371,000

    )
    
    
    (5,138,000

    )
    
    
    (370,000

    )
    
    

    (3,991,000

    )
    
    
    (321,000

    )
    
    

    (3,540,000

    )End of year
    
    

    2,932,000

    
    
    
    44,870,000
    
    
    
    2,905,000

    
    
    
    39,005,000

    
    
    
    2,319,000

    
    
    
    29,917,000Proved developed reserves
    
    
    2,926,000

    
    
    
    37,728,000

    
    
    
    2,865,000

    
    
    
    34,045,000

    
    
    
    2,319,000

    
    
    
    29,917,000
 See accompanying notes to
supplementary information. F-22




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##### Table of Contents



PRIMEENERGY CORPORATION and SUBSIDIARIES RESULTS of OPERATIONS from OIL and GAS PRODUCING ACTIVITIES Years ended December 31, 2004, 2003 and 2002 (Unaudited) 2004
    
    
    2003
    
    
    2002Revenue:Oil and gas sales
    
    $
    43,967,000
    
    
    $
    29,855,000
    
    
    $
    18,330,000Costs and expenses:Lease operating expense
    
    
    14,939,000
    
    
    
    12,783,000
    
    
    
    10,210,000Exploration costs
    
    
    5,499,000
    
    
    
    519,000
    
    
    
    894,000Depreciation and depletion
    
    
    11,021,000
    
    
    
    6,283,000
    
    
    
    3,988,000Income tax expense
    
    
    3,023,000
    
    
    
    2,446,000
    
    
    
    443,00034,482,000
    
    
    
    22,031,000
    
    
    
    15,535,000Results of operations from producing activities
    
    $
    9,485,000
    
    
    $
    7,824,000
    
    
    $
    2,735,000(excluding corporate overhead and interest costs)
 See accompanying notes to
supplementary information. F-23




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##### Table of Contents



PRIMEENERGY CORPORATION and SUBSIDIARIES NOTES to SUPPLEMENTARY INFORMATION (Unaudited)  1.
    Presentation of Reserve Disclosure InformationReserve 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 ReservesThe 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 ActivitiesThe 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 ReservesThe standardized measure of discounted future net cash flows
relating to proved 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-24